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EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INCex3123-31x16ugiutilities10q.htm
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INCex1213-31x16ugiutilities10q.htm
EX-10.2 - EXHIBIT 10.2 - UGI UTILITIES INCex102ugiutilities10q.htm
EX-32 - EXHIBIT 32 - UGI UTILITIES INCex323-31x16ugiutilities10q.htm
EX-10.1 - EXHIBIT 10.1 - UGI UTILITIES INCex101ugiutilities10q.htm
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INCex3113-31x16ugiutilities10q.htm

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

FORM 10-Q

þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact name of registrant as specified in its charter)
Pennsylvania
 
23-1174060
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
UGI UTILITIES, INC.
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
 
Accelerated filer o
 
Non-accelerated filer þ
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
At April 30, 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
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
 
March 31,
2016
 
September 30,
2015
 
March 31,
2015
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
26,406

 
$
3,099

 
$
16,040

Restricted cash
3,909

 
6,602

 
5,578

Accounts receivable (less allowances for doubtful accounts of $8,232, $5,599 and $11,889, respectively)
102,125

 
55,659

 
183,046

Accounts receivable — related parties
1,271

 
1,271

 
2,709

Accrued utility revenues
24,052

 
12,051

 
42,056

Inventories
16,685

 
51,716

 
19,533

Deferred income taxes

 
24,694

 
25,168

Income taxes receivable

 
10,026

 

Regulatory assets
3,229

 
4,105

 
625

Derivative instruments
881

 
934

 
612

Prepaid expenses & other current assets
27,632

 
23,903

 
15,648

Total current assets
206,190

 
194,060

 
311,015

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $952,478, $929,130 and $911,289, respectively)
1,900,806

 
1,824,369

 
1,753,197

Goodwill
182,145

 
182,145

 
182,145

Regulatory assets
344,983

 
300,103

 
251,945

Other assets
7,463

 
7,501

 
7,741

Total assets
$
2,641,587

 
$
2,508,178

 
$
2,506,043

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

 
$
247,000

 
$
92,000

Short-term borrowings
155,000

 
71,700

 
30,500

Accounts payable
42,681

 
58,135

 
54,612

Accounts payable — related parties
6,710

 
4,430

 
14,979

Regulatory liability — deferred fuel and power refunds
30,838

 
36,638

 
40,542

Derivative instruments
3,370

 
12,591

 
5,464

Other current liabilities
152,479

 
103,265

 
166,879

Total current liabilities
391,078

 
533,759

 
404,976

Long-term debt
550,000

 
375,000

 
550,000

Deferred income taxes
526,937

 
512,497

 
472,343

Deferred investment tax credits
3,429

 
3,597

 
3,765

Pension and postretirement benefit obligations
130,915

 
135,003

 
94,332

Derivative instruments

 

 
75

Other noncurrent liabilities
99,029

 
57,702

 
51,262

Total liabilities
1,701,388

 
1,617,558

 
1,576,753

Commitments and contingencies (Note 7)

 

 

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

 
60,259

 
60,259

Additional paid-in capital
472,715

 
471,904

 
471,653

Retained earnings
436,788

 
372,143

 
404,516

Accumulated other comprehensive loss
(29,563
)
 
(13,686
)
 
(7,138
)
Total common stockholder’s equity
940,199

 
890,620

 
929,290

Total liabilities and stockholder’s equity
$
2,641,587

 
$
2,508,178

 
$
2,506,043

See accompanying notes to condensed consolidated financial statements.

- 1 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)
 
Three Months Ended
 
Six Months Ended
 
March 31,
 
March 31,
 
2016
 
2015
 
2016
 
2015
Revenues
$
322,047

 
$
500,573

 
$
520,029

 
$
787,879

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
137,434

 
278,336

 
212,873

 
421,388

Operating and administrative expenses
45,125

 
58,917

 
93,152

 
105,465

Operating and administrative expenses — related parties
3,798

 
4,138

 
5,978

 
6,920

Taxes other than income taxes
4,448

 
4,803

 
8,217

 
8,907

Depreciation
16,146

 
14,757

 
31,973

 
29,315

Amortization
884

 
887

 
1,758

 
1,754

Other operating (income) loss, net
(269
)
 
(3,964
)
 
3,301

 
(4,209
)
 
207,566

 
357,874

 
357,252

 
569,540

Operating income
114,481

 
142,699

 
162,777

 
218,339

Interest expense
9,270

 
10,611

 
18,764

 
21,260

Income before income taxes
105,211

 
132,088

 
144,013

 
197,079

Income taxes
41,917

 
52,499

 
57,368

 
78,651

Net income
$
63,294

 
$
79,589

 
$
86,645

 
$
118,428

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
 
Six Months Ended
 
March 31,
 
March 31,
 
2016
 
2015
 
2016
 
2015
Net income
$
63,294

 
$
79,589

 
$
86,645

 
$
118,428

Other comprehensive income (loss):
 
 
 
 
 
 
 
Net losses on derivative instruments (net of tax of $13,348, $0, $12,016 and $0, respectively)
(18,820
)
 

 
(16,943
)
 

Reclassifications of net losses on derivative instruments (net of tax of $(253), $(278), $(529) and $(556), respectively)
356

 
392

 
746

 
783

Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(114), $(92), $(227) and $(183), respectively)
160

 
129

 
320

 
260

Other comprehensive (loss) income
(18,304
)
 
521

 
(15,877
)
 
1,043

Comprehensive income
$
44,990

 
$
80,110

 
$
70,768

 
$
119,471

See accompanying notes to condensed consolidated financial statements.


- 3 -


UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
 
Six Months Ended
 
March 31,
 
2016
 
2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
86,645

 
$
118,428

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
Depreciation and amortization
33,731

 
31,069

Deferred income tax expense (benefit)
48,905

 
(13,888
)
Provision for uncollectible accounts
5,572

 
8,979

Other, net
2,138

 
2,521

Net change in:
 
 
 
Accounts receivable and accrued utility revenues
(66,130
)
 
(154,515
)
Inventories
35,031

 
75,686

Deferred fuel and power costs, net of changes in unsettled derivatives
(7,789
)
 
55,760

Accounts payable
(3,882
)
 
8,013

Other current assets
(2,529
)
 
(921
)
Other current liabilities
20,691

 
66,025

Net cash provided by operating activities
152,383

 
197,157

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Expenditures for property, plant and equipment
(116,778
)
 
(102,020
)
Net costs of property, plant and equipment disposals
(5,101
)
 
(3,694
)
Decrease (increase) in restricted cash
2,693

 
(1,986
)
Net cash used by investing activities
(119,186
)
 
(107,700
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Payment of dividends
(22,000
)
 
(30,600
)
Repayments of long-term debt
(72,000
)
 

Increase (decrease) in short-term borrowings
83,300

 
(55,800
)
Other
810

 
582

Net cash used by financing activities
(9,890
)
 
(85,818
)
Cash and cash equivalents increase
$
23,307

 
$
3,639

CASH AND CASH EQUIVALENTS
 
 
 
End of period
$
26,406

 
$
16,040

Beginning of period
3,099

 
12,401

Increase
$
23,307

 
$
3,639

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 (for which NPNS has not been elected) 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 10.

- 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, the September 30, 2015 and March 31, 2015 Condensed Consolidated Balance Sheets included herein have not been adjusted.

Accounting Standards Not Yet Adopted

Share-Based Payments. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2016 (Fiscal 2018). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

Debt Issuance Costs. In April 2015, the FASB issued 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.” The guidance provided under this ASU, as amended, 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. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (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.


- 6 -

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


Note 4 — Inventories
Inventories comprise the following:
 
March 31, 2016
 
September 30, 2015
 
March 31, 2015
Gas Utility natural gas
$
3,786

 
$
37,510

 
$
6,260

Materials, supplies and other
12,899

 
14,206

 
13,273

Total inventories
$
16,685

 
$
51,716

 
$
19,533


At March 31, 2016, UGI Utilities was a party to two principal storage contract administrative agreements (“SCAAs”) having terms of three years. One of the SCAAs was with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 12) and one of the SCAAs was with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.
The carrying value of gas storage inventories released under the SCAAs at March 31, 2016, September 30, 2015 and March 31, 2015, comprising 1.1 billion cubic feet (“bcf”), 9.0 bcf and 1.0 bcf of natural gas, was $2,593, $22,694 and $4,082, respectively. At March 31, 2016, September 30, 2015 and March 31, 2015, UGI Utilities held a total of $15,100, $17,700 and $17,700, 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 12.


- 7 -

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 2015 Annual Report. UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:
 
March 31, 2016
 
September 30, 2015
 
March 31, 2015
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
118,160

 
$
115,946

 
$
111,441

Underfunded pension and postretirement plans
135,825

 
140,762

 
105,539

Environmental costs (a)
60,494

 
19,983

 
14,110

Removal costs, net
25,030

 
21,223

 
18,377

Other
8,703

 
6,294

 
3,103

Total regulatory assets
$
348,212

 
$
304,208

 
$
252,570

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
19,307

 
$
19,975

 
$
19,323

Deferred fuel and power refunds
30,838

 
36,638

 
40,542

State tax benefits — distribution system repairs
14,158

 
13,266

 
10,621

Other
2,500

 
1,125

 
2,099

Total regulatory liabilities (b)
$
66,803

 
$
71,004

 
$
72,585


(a)
Environmental costs at March 31, 2016, include amounts probable of recovery recorded in conjunction with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 7).
(b)
Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and other 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 that 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 (losses) on such contracts at March 31, 2016, September 30, 2015, and March 31, 2015, were $(1,900), $(3,262) and $(3,381), respectively.

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 March 31, 2016, September 30, 2015, and March 31, 2015, the fair values of Electric Utility’s electricity supply contracts were (losses) of $(231), $(533) and $(1,168), respectively. These amounts are reflected in 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 10).

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

- 8 -

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


for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at March 31, 2016, September 30, 2015, and March 31, 2015, were not material.

Preliminary Stage Information Technology Costs. During the three months ended March 31, 2016, it was determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the three months ended March 31, 2016, we capitalized $5,830 of such project costs ($5,734 of which had been expensed in prior periods) and recorded associated increases to utility property, plant and equipment ($2,755) and regulatory assets ($3,075).

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 requested that the new gas rates become effective March 19, 2016. The PUC entered an Order dated February 11, 2016, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last approximately nine months from the date of filing; however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. Also in March 2016, UGI Gas sought PUC approval to initiate a DSIC effective November 2017 after rates from the pending rate case become effective, along with a petition, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on any of these petitions. The Company cannot predict the timing or outcome of these petitions. The impact of the DSIC charge at PNG and CPG did not have a material effect on Gas Utility results of operations.

Note 6 — Debt

In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) which provides for the private placement of (1) $100,000 aggregate principal amount of 2.95% Senior Notes due June 30, 2026; (2) $200,000 aggregate principal amount of 4.12% Senior Notes due September 30, 2046; and (3) $100,000 aggregate principal amount of 4.12% Senior Notes due October 31, 2046. These Senior Notes are expected to be issued in June 2016, September 2016 and October 2016, respectively. These Senior Notes, when issued, will be unsecured and will rank equally with UGI Utilities’ existing outstanding senior debt. The Company expects to use the net proceeds from the issuance of the Senior Notes to refinance existing debt and for general corporate purposes. Because UGI Utilities intends to use a portion of the net proceeds from the issuance of $200,000 Senior Notes in September 2016 to repay UGI Utilities’ currently outstanding $175,000 principal amount of 5.75% Senior Notes due September 30, 2016, the 5.75% Senior Notes have been classified as long-term on the March 31, 2016, Condensed Consolidated Balance Sheet.


- 9 -

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


Note 7 — Commitments and Contingencies

Contingencies

Environmental Matters

From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. 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 has also acquired two subsidiaries (CPG and PNG) which have similar histories of owning, and in some cases operating, MGPs in Pennsylvania.
UGI Utilities and its subsidiaries have entered into agreements with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At March 31, 2016 and 2015, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,766 and $9,610, respectively. CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 5).
 
UGI Utilities’ UGI Gas division has negotiated a Consent Order and Agreement (“UGI Gas-COA”) with the DEP and is awaiting execution thereof. The UGI Gas-COA would be effective October 1, 2016 and would be scheduled to terminate in September 2031. The UGI Gas-COA would require UGI Gas to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties would be capped at $2,500 in any calendar year. At March 31, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the UGI Gas-COA totaled $43,767. UGI Gas has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (See Note 5).
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 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. UGI Gas has proposed a similar environmental cost tracking mechanism that will address the costs incurred under the UGI Gas-COA.

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. At March 31, 2016, neither the undiscounted nor the accrued

- 10 -

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


liability for environmental investigation and cleanup costs for UGI Gas MGP sites outside of Pennsylvania was material for UGI Utilities.

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

Note 8 — Defined Benefit Pension and Other Postretirement Plans

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

Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
1,732

 
$
1,740

 
$
45

 
$
49

Interest cost
 
5,818

 
5,628

 
117

 
118

Expected return on assets
 
(7,168
)
 
(7,225
)
 
(149
)
 
(153
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
87

 
87

 
(160
)
 
(160
)
Actuarial loss
 
2,393

 
2,198

 
25

 
31

Net benefit cost (income)
 
2,862

 
2,428

 
(122
)
 
(115
)
Change in associated regulatory liabilities
 

 

 
876

 
938

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

 
$
2,428

 
$
754

 
$
823

 
 
 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
Service cost
 
$
3,464

 
$
3,481

 
$
91

 
$
97

Interest cost
 
11,635

 
11,255

 
233

 
237

Expected return on assets
 
(14,335
)
 
(14,449
)
 
(298
)
 
(306
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
174

 
174

 
(320
)
 
(320
)
Actuarial loss
 
4,786

 
4,396

 
49

 
63

Net benefit cost (income)
 
5,724

 
4,857

 
(245
)
 
(229
)
Change in associated regulatory liabilities
 

 

 
1,754

 
1,875

Net benefit cost after change in regulatory liabilities
 
$
5,724

 
$
4,857

 
$
1,509

 
$
1,646


Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. During the six months ended March 31, 2016 and 2015, the Company made contributions to the Pension Plan of $4,934 and $5,566, respectively. The Company expects to make additional discretionary cash contributions of approximately $5,000 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

- 11 -

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


future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the six months ended March 31, 2016 and 2015.

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 9 — Fair Value Measurements

Derivative Instruments

The following table presents on a gross basis our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2016, September 30, 2015 and March 31, 2015:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,179

 
$

 
$

 
$
1,179

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(3,281
)
 
$
(387
)
 
$

 
$
(3,668
)
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
)
March 31, 2015:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
612

 
$
1

 
$

 
$
613

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

 
$
(5,540
)

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 March 31, 2016, were $550,000 and $637,016, respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at March 31, 2015, were $642,000 and $740,729, respectively. 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).


- 12 -

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


Note 10 — Derivative Instruments and Hedging Activities

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

Commodity Price Risk

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At March 31, 2016 and 2015, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 10.0 million dekatherms and 9.7 million dekatherms, respectively. At March 31, 2016, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 11 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 liabilities on 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 March 31, 2016 and 2015, the volumes associated with Electric Utility’s forward electricity purchase contracts for which NPNS has not been elected were 23.6 million kilowatt hours and 384.4 million kilowatt hours, respectively. At March 31, 2016, the maximum period over which these contracts extend is 8 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5). At March 31, 2016 and 2015, the total volumes associated with FTRs totaled 69.2 million kilowatt hours and 58.1 million kilowatt hours, respectively. At March 31, 2016, the maximum period over which we are economically hedging electricity congestion is 2 months.

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

Interest Rate Risk

Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. On March 31, 2016,

- 13 -

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


concurrent with the pricing of the Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities agreed to settle all of its then-existing IRPA contracts associated with such debt at a loss of $35,975 (which amount was paid in early April 2016 and is included in other current liabilities on the March 31, 2016 Condensed Consolidated Balance Sheet). Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs has been recorded in AOCI and will be recognized in interest expense as the associated future interest expense impacts earnings. See Note 6 for additional information on the 2016 Note Purchase Agreement. As of March 31, 2016 and 2015, we had no unsettled IRPAs. At March 31, 2016, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,073.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2016 and 2015, restricted cash in brokerage accounts totaled $3,909 and $5,578, respectively.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on the 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 the 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.


- 14 -

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


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 March 31, 2016 and 2015:
 
 
March 31, 2016
 
March 31, 2015
Derivative assets:
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
Commodity contracts
 
$
1,179

 
$
613

Total derivative assets - gross
 
1,179

 
613

Gross amounts offset in the balance sheet
 
(298
)
 
(1
)
Total derivative assets - net
 
$
881

 
$
612

 
 
 
 
 
Derivative liabilities:
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 

Commodity contracts
 
$
(3,466
)
 
$
(5,168
)
Derivatives not subject to PGC and DS mechanisms:
 
 

 
 

Commodity contracts
 
(202
)
 
(372
)
Total derivative liabilities - gross
 
(3,668
)
 
(5,540
)
Gross amounts offset in the balance sheet
 
298

 
1

Total derivative liabilities - net
 
$
(3,370
)
 
$
(5,539
)

- 15 -

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 and six months ended March 31, 2016 and 2015:

 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$
(32,168
)
 
$

 
$
(609
)
 
$
(670
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in Income
 
Location of Loss Recognized in Income
 
 
 
 
Three Months Ended March 31,
 
2016
 
2015
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(55
)
 
$
(4
)
 
Operating expenses/other operating income, net
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Six Months Ended March 31,
 
2016
 
2015
 
2016
 
2015
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$
(28,959
)
 
$

 
$
(1,275
)
 
$
(1,339
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in Income
 
Location of Loss Recognized in Income
 
 
 
 
Six Months Ended March 31,
 
2016
 
2015
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(120
)
 
$
(526
)
 
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.


- 16 -

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


Note 11 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three and six months ended March 31, 2016 and 2015:
 
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
Three Months Ended March 31, 2016
 
 
 
 
 
 
AOCI - December 31, 2015
 
$
(9,116
)
 
$
(2,143
)
 
$
(11,259
)
Net losses on IRPAs
 

 
(18,820
)
 
(18,820
)
Reclassifications of benefit plan actuarial losses and prior service cost
 
160

 

 
160

Reclassifications of net losses on IRPAs
 

 
356

 
356

AOCI - March 31, 2016
 
$
(8,956
)
 
$
(20,607
)
 
$
(29,563
)
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
 
 
 
 
 
AOCI - December 31, 2014
 
$
(6,180
)
 
$
(1,479
)
 
$
(7,659
)
Reclassifications of benefit plan actuarial losses and prior service cost
 
129

 

 
129

Reclassifications of net losses on IRPAs
 

 
392

 
392

AOCI - March 31, 2015
 
$
(6,051
)
 
$
(1,087
)
 
$
(7,138
)
 
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
Six Months Ended March 31, 2016
 
 
 
 
 
 
AOCI - September 30, 2015
 
$
(9,276
)
 
$
(4,410
)
 
$
(13,686
)
Net losses on IRPAs
 

 
(16,943
)
 
(16,943
)
Reclassifications of benefit plan actuarial losses and prior service costs
 
320

 

 
320

Reclassifications of net losses on IRPAs
 

 
746

 
746

AOCI - March 31, 2016
 
$
(8,956
)
 
$
(20,607
)
 
$
(29,563
)
Six Months Ended March 31, 2015
 
 
 
 
 
 
AOCI - September 30, 2014
 
$
(6,311
)
 
$
(1,870
)
 
$
(8,181
)
Reclassifications of benefit plan actuarial losses and prior service costs
 
260

 

 
260

Reclassifications of net losses on IRPAs
 

 
783

 
783

AOCI - March 31, 2015
 
$
(6,051
)
 
$
(1,087
)
 
$
(7,138
)

Note 12 — Related Party Transactions

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses - related parties on 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

- 17 -

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


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 $159 and $2,029 during the three and six months ended March 31, 2016, respectively, and $251 and $5,207 during the three and six months ended March 31, 2015, 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 $10,700 as of March 31, 2016, September 30, 2015 and March 31, 2015, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption inventories. The carrying value of these gas storage inventories at March 31, 2016, September 30, 2015 and March 31, 2015, comprising approximately 0.9 bcf, 5.0 bcf and 0.9 bcf of natural gas, were $2,074, $12,889 and $3,391, 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 and six months ended March 31, 2016 totaled $31,691 and $59,055, respectively. During the three and six months ended March 31, 2015 such transactions totaled $19,286 and $43,033, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2016, revenues associated with such sales to Energy Services totaled $12,854 and $21,620, respectively. During the three and six months ended March 31, 2015, revenues associated with such sales to Energy Services totaled $46,227 and $62,417, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three and six months ended March 31, 2016, such purchases totaled $14,912 and $23,104, respectively. During the three and six months ended March 31, 2015, such purchases totaled $49,750 and $71,525, respectively.

Note 13 — Segment Information
We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The HVAC Business, 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.

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


Financial information by business segment follows:
Three Months Ended March 31, 2016:
 
 
 
Reportable Segments
 
Total
 
Gas Utility
 
Electric Utility
Revenues
$
322,047

 
$
298,088

 
$
23,959

Cost of sales
$
137,434

 
$
123,702

 
$
13,732

Depreciation and amortization
$
17,030

 
$
15,822

 
$
1,208

Operating income
$
114,481

 
$
111,004

 
$
3,477

Interest expense
$
9,270

 
$
8,847

 
$
423

Income before income taxes
$
105,211

 
$
102,157

 
$
3,054

Capital expenditures (including the effects of accruals)
$
48,113

 
$
46,003

 
$
2,110

Three Months Ended March 31, 2015:
 
 
 
Reportable Segments
 
 
 
Total
 
Gas Utility
 
Electric Utility
 
Other
Revenues
$
500,573

 
$
468,000

 
$
32,323

 
$
250

Cost of sales
$
278,336

 
$
258,155

 
$
20,181

 
$

Depreciation and amortization
$
15,644

 
$
14,489

 
$
1,155

 
$

Operating income (loss)
$
142,699

 
$
139,303

 
$
3,510

 
$
(114
)
Interest expense
$
10,611

 
$
10,104

 
$
507

 
$

Income (loss) before income taxes
$
132,088

 
$
129,199

 
$
3,003

 
$
(114
)
Capital expenditures (including the effects of accruals)
$
41,280

 
$
39,202

 
$
2,078

 
$


Six Months Ended March 31, 2016:
 
 
 
Reportable Segments
 
Total
 
Gas Utility
 
Electric Utility
Revenues
$
520,029

 
$
475,030

 
$
44,999

Cost of sales
$
212,873

 
$
187,931

 
$
24,942

Depreciation and amortization
$
33,731

 
$
31,326

 
$
2,405

Operating income
$
162,777

 
$
156,824

 
$
5,953

Interest expense
$
18,764

 
$
17,913

 
$
851

Income before income taxes
$
144,013

 
$
138,911

 
$
5,102

Capital expenditures (including the effects of accruals)
$
109,577

 
$
105,273

 
$
4,304

 
 
 
 
 
 
As of March 31, 2016
 
 
 
 
 
Total assets (at period end)
$
2,641,587

 
$
2,488,191

 
$
153,396

Goodwill (at period end)
$
182,145

 
$
182,145

 
$



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


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

 
$
728,478

 
$
58,746

 
$
655

Cost of sales
$
421,388

 
$
385,363

 
$
36,025

 
$

Depreciation and amortization
$
31,069

 
$
28,769

 
$
2,300

 
$

Operating income
$
218,339

 
$
211,149

 
$
7,229

 
$
(39
)
Interest expense
$
21,260

 
$
20,234

 
$
1,026

 
$

Income before income taxes
$
197,079

 
$
190,915

 
$
6,203

 
$
(39
)
Capital expenditures (including the effects of accruals)
$
96,309

 
$
92,694

 
$
3,615

 
$

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

 
$
2,359,060

 
$
146,983

 
$

Goodwill (at period end)
$
182,145

 
$
182,145

 
$

 
$



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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.


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UGI UTILITIES, INC. AND SUBSIDIARIES


ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended March 31, 2016 (“2016 three-month period”) with the three months ended March 31, 2015 (“2015 three-month period”) and the six months ended March 31, 2016 (“2016 six-month period”) with the six months ended March 31, 2015 (“2015 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 13 to the condensed consolidated financial statements.

2016 three-month period compared with 2015 three-month period
Three Months Ended March 31,
 
2016
 
2015
 
Increase (Decrease)
(Dollars in millions)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
298.1

 
$
468.0

 
$
(169.9
)
 
(36.3
)%
Total margin (a)
 
$
174.4

 
$
209.8

 
$
(35.4
)
 
(16.9
)%
Operating and administrative expenses
 
$
45.0

 
$
57.1

 
$
(12.1
)
 
(21.2
)%
Operating income
 
$
111.0

 
$
139.3

 
$
(28.3
)
 
(20.3
)%
Income before income taxes
 
$
102.2

 
$
129.2

 
$
(27.0
)
 
(20.9
)%
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
34.0

 
44.3

 
(10.3
)
 
(23.3
)%
Total
 
72.1

 
81.0

 
(8.9
)
 
(11.0
)%
Heating degree days — % (warmer) colder than normal (b)
 
(9.7
)%
 
20.4
%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
24.0

 
$
32.3

 
$
(8.3
)
 
(25.7
)%
Total margin (a)
 
$
8.9

 
$
10.4

 
$
(1.5
)
 
(14.4
)%
Operating and administrative expenses
 
$
3.9

 
$
5.6

 
$
(1.7
)
 
(30.4
)%
Operating income
 
$
3.5

 
$
3.5

 
$

 
 %
Income before income taxes
 
$
3.1

 
$
3.0

 
$
0.1

 
3.3
 %
Distribution sales — millions of kilowatt-hours (“gwh”)
 
265.2

 
299.9

 
(34.7
)
 
(11.6
)%

(a)
Gas Utility’s total margin represents total revenues less total cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.3 million and $1.7 million during the three months ended March 31, 2016 and 2015, 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 during the 2016 three-month period based upon heating degree days were 9.7% warmer than normal and 23.6% warmer than the 2015 three-month period. Core market volumes declined 10.3 bcf (23.3%) reflecting the effects of the significantly warmer weather. Total Gas Utility distribution system throughput decreased 8.9 bcf (11.0%) principally reflecting the lower core market volumes partially offset by higher interruptible delivery service volumes. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.
Gas Utility revenues decreased $169.9 million principally reflecting a decrease in core market revenues ($128.3 million), lower off-system sales revenues ($39.3 million), and, to a much lesser extent, lower delivery service revenues. The decrease in Gas Utility core market revenues reflects the effects of the lower core market throughput ($85.6 million) and lower average PGC rates ($42.7 million) during the 2016 three-month period. Because Gas Utility is subject to a reconcilable PGC recovery mechanism, 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 $123.7 million in the 2016 three-month period compared with $258.2 million in the 2015 three-month

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UGI UTILITIES, INC. AND SUBSIDIARIES


period, a decrease of $134.5 million, principally reflecting the combined effects of the lower retail core-market volumes and lower average Gas Utility PGC rates ($96.3 million), and lower cost of sales associated with off-system sales ($39.3 million).
Gas Utility 2016 three-month period total margin decreased $35.4 million principally reflecting lower total margin from core market customers ($32.0 million) and lower total margin from delivery service customers. The decrease in Gas Utility core market margin reflects the lower core market throughput.
Gas Utility operating income and income before income taxes decreased $28.3 million and $27.0 million, respectively. The decreases in operating income and income before income taxes during the 2016 three-month period principally reflects the decrease in total margin ($35.4 million), higher depreciation expense ($1.3 million) and lower other operating income ($3.6 million) reflecting, among other things, lower margin from off-system sales and higher interest on deferred fuel overcollections. Partially offsetting these decreases in operating income was a $12.1 million decrease in operating and administrative expenses primarily reflecting lower preliminary stage expenses associated with a UGI Utilities information technology (“IT”) project and lower uncollectible accounts and system maintenance expenses. During the three months ended March 31, 2016, we determined that certain preliminary stage costs associated with the IT project were probable of future recovery in rates in accordance with GAAP related to rate regulated entities. As a result, Gas Utility capitalized $5.2 million of such IT costs that had been expensed in prior periods (including $1.2 million of such costs that had been expensed during the 2015 three-month period) and recorded associated increases to utility plant and regulatory assets (see Note 5 to condensed consolidated financial statements). The change in Gas Utility 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 2016 three-month period were approximately 12.1% warmer than normal and approximately 24.3% warmer than the prior-year period. Total kilowatt-hour sales decreased by 11.6% principally reflecting the impact of the warmer weather on heating-related sales. The lower Electric Utility revenues principally resulted from the lower sales volumes and lower DS rates in the 2016 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 $13.7 million in the 2016 three-month period from $20.2 million in the 2015 three-month period, reflecting the lower volumes sold and lower DS rates.
Electric Utility total margin decreased $1.5 million principally reflecting the lower volume sales as a result of the warmer 2016 three-month period weather.
Notwithstanding the decrease in total margin, Electric Utility operating income and income before income taxes in the 2016 three-month period were about equal to the prior-year period reflecting a decrease in operating and administrative expenses principally reflecting lower IT preliminary stage expenses. As previously mentioned, during the three months ended March 31, 2016, we determined that certain preliminary stage costs associated with the IT project were probable of future recovery in rates in accordance with GAAP related to rate regulated entities. As a result, Electric Utility capitalized $0.6 million of such IT costs that had been expensed in prior periods (including $0.1 million of such costs that had been expensed during the 2015 three-month period).

Interest Expense and Income Taxes

Our interest expense in the 2016 three-month period decreased principally reflecting lower average long-term debt outstanding. Our effective income tax rate for the three months ended March 31, 2016 was comparable with the prior-year three-month period.

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UGI UTILITIES, INC. AND SUBSIDIARIES


2016 six-month period compared with 2015 six-month period
Six Months Ended March 31,
 
2016
 
2015
 
Decrease
(Dollars in millions)
 
 
 
 
 
 
 
 
Gas Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
475.0

 
$
728.5

 
$
(253.5
)
 
(34.8
)%
Total margin (a)
 
$
287.1

 
$
343.1

 
$
(56.0
)
 
(16.3
)%
Operating and administrative expenses
 
$
90.4

 
$
102.1

 
$
(11.7
)
 
(11.5
)%
Operating income
 
$
156.8

 
$
211.1

 
$
(54.3
)
 
(25.7
)%
Income before income taxes
 
$
138.9

 
$
190.9

 
$
(52.0
)
 
(27.2
)%
System throughput — billions of cubic feet (“bcf”)
 
 
 
 
 
 
 
 
Core market
 
51.4

 
67.5

 
(16.1
)
 
(23.9
)%
Total
 
122.0

 
137.8

 
(15.8
)
 
(11.5
)%
Heating degree days — % (warmer) colder than normal (b)
 
(16.1
)%
 
10.6
%
 

 

Electric Utility:
 
 
 
 
 
 
 
 
Revenues
 
$
45.0

 
$
58.7

 
$
(13.7
)
 
(23.3
)%
Total margin (a)
 
$
17.6

 
$
19.5

 
$
(1.9
)
 
(9.7
)%
Operating and administrative expenses
 
$
8.7

 
$
9.6

 
$
(0.9
)
 
(9.4
)%
Operating income
 
$
6.0

 
$
7.2

 
$
(1.2
)
 
(16.7
)%
Income before income taxes
 
$
5.1

 
$
6.2

 
$
(1.1
)
 
(17.7
)%
Distribution sales — millions of kilowatt-hours (“gwh”)
 
490.3

 
544.7

 
(54.4
)
 
(10.0
)%

(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 $2.4 million and $3.2 million during the six months ended March 31, 2016 and 2015, respectively. For financial statement purposes, revenue-related taxes are included in taxes other than income taxes on 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 during the 2016 six-month period based upon heating degree days were 16.1% warmer than normal and 23.4% warmer than the 2015 six-month period. In particular, Gas Utility temperatures in the critical heating-season month of December were 37% warmer than normal. Core market volumes declined 16.1 bcf (23.9%) reflecting the effects of the significantly warmer weather. Total Gas Utility distribution system throughput decreased 15.8 bcf (11.5%) principally reflecting the lower core market volumes.
Gas Utility revenues decreased $253.5 million principally reflecting a decrease in core market revenues ($200.3 million), lower off-system sales revenues ($48.7 million) and, to a much lesser extent, lower large firm delivery service revenues. The decrease in Gas Utility core market revenues reflects the effects of the lower core market throughput ($138.2 million) and lower average PGC rates during the 2016 six-month period ($62.0 million). Gas Utility cost of sales was $187.9 million in the 2016 six-month period compared with $385.4 million in the 2015 six-month period principally reflecting the combined effects of the lower Gas Utility retail core-market volumes sold and lower average Gas Utility PGC rates ($149.5 million) and lower cost of sales associated with off-system sales ($48.7 million).
Gas Utility 2016 six-month period total margin decreased $56.0 million principally reflecting lower Gas Utility total margin from core market customers ($50.8 million) and lower total margin from large firm delivery service customers. The decrease in Gas Utility core market margin reflects the lower core market throughput.
Gas Utility operating income and income before income taxes decreased $54.3 million and $52.0 million, respectively. The decreases in operating income and income before income taxes during the 2016 six-month period principally reflects the decrease in total margin ($56.0 million), higher depreciation expense ($2.6 million) and lower other operating income ($7.4 million) which includes, among other things, higher environmental matters expense ($3.9 million), higher interest on PGC overcollections and lower margin from off-system sales. Gas Utility operating and administrative expenses were $11.7 million lower than the prior-year period primarily reflecting lower preliminary stage expenses associated with a UGI Utilities IT project and, to a lesser extent,

- 24 -

UGI UTILITIES, INC. AND SUBSIDIARIES


lower uncollectible accounts and system maintenance expenses. As previously mentioned, during the three months ended March 31, 2016, we determined that certain preliminary stage costs associated with the IT project were probable of future recovery in rates in accordance with GAAP related to rate regulated entities. As a result, during the six months ended March 31, 2016, Gas Utility capitalized $4.8 million of such IT costs that had been expensed in prior periods (including $2.1 million of such costs that had been expensed during the 2015 six-month period). 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 2016 six-month period were approximately 18.4% warmer than normal and approximately 23.5% warmer than the prior-year period. Total kilowatt-hour sales decreased by 10.0% 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 2016 six-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 $24.9 million in the 2016 six-month period from $36.0 million in the 2015 six-month period, reflecting the lower volumes sold and lower DS rates.
Electric Utility total margin, net of gross receipts taxes, decreased $1.9 million principally reflecting the lower volume sales as a result of the warmer 2016 six-month period weather.
Electric Utility operating income and income before income taxes in the 2016 six-month period each decreased $1.2 million and $1.1 million, respectively, reflecting the decrease in total margin partially offset by lower net operating and administrative expenses including lower preliminary stage expenses associated with an IT project. During the six months ended March 31, 2016, Electric Utility capitalized $0.5 million of such IT costs that had been expensed in prior periods (including $0.2 million of such costs that had been expensed during the 2015 six-month period).

Interest Expense and Income Taxes

Our interest expense in the 2016 six-month period decreased principally reflecting lower average long-term debt outstanding. Our effective income tax rate for the six months ended March 31, 2016 was comparable with the prior-year six-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 March 31, 2016, was $705.0 million, which includes $155.0 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 March 31, 2016, comprises $450.0 million of Senior Notes and $100.0 million of Medium-Term Notes.

In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) which provides for the private placement of (1) $100 million aggregate principal amount of 2.95% Senior Notes due June 30, 2026; (2) $200 million aggregate principal amount of 4.12% Senior Notes due September 30, 2046; and (3) $100 million aggregate principal amount of 4.12% Senior Notes due October 31, 2046. These Senior Notes are expected to be issued in June 2016, September 2016 and October 2016, respectively. These Senior Notes, when issued, will be unsecured and will rank equally with UGI Utilities’ existing outstanding senior debt. The Company expects to use the net proceeds from the issuance of the Senior Notes to refinance existing debt and for general corporate purposes. Because UGI Utilities intends to use a portion of the net proceeds from the issuance of $200 million Senior Notes in September 2016 to repay UGI Utilities’ currently outstanding $175 million principal amount of 5.75% Senior Notes due September 30, 2016, the 5.75% Senior Notes have been classified as long-term on the March 31, 2016, Condensed Consolidated Balance Sheet.

On March 31, 2016, concurrent with the pricing of the Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities agreed to settle all of its then-existing IRPA contracts associated with such debt at a loss of $36.0 million (which amount was paid in early April 2016 and is included in other current liabilities on the March 31, 2016 Condensed Consolidated Balance Sheet). Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs has been recorded in AOCI and will be recognized in interest expense as future interest expense impacts earnings.

- 25 -

UGI UTILITIES, INC. AND SUBSIDIARIES



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 are classified as short-term borrowings on the Condensed Consolidated Balance Sheets. During the 2016 and 2015 six-month periods, average daily short-term borrowings under the UGI Utilities 2015 Credit Agreement and a predecessor agreement were $177.6 million and $108.9 million, respectively, and peak short-term borrowings totaled $232.0 million and $163.6 million, respectively. At March 31, 2016, UGI Utilities’ available borrowing capacity under the UGI Utilities 2015 Credit Agreement was $143 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 2016 six-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.

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 $152.4 million in the 2016 six-month period compared to $197.2 million in the prior-year period. Cash flow from operating activities before changes in operating working capital was $177.0 million in the 2016 six-month period compared to $147.1 million recorded in the prior-year period. Changes in operating working capital used $24.6 million of operating cash flow during the 2016 six-month period compared to $50.0 million of cash provided during the prior-year period. The lower cash used for changes in accounts receivable, and the lower cash provided by changes in accounts payable and inventories, reflects in large part the impact on these items from declines in natural gas costs and the lower volumes resulting from the warmer weather. In addition, changes in working capital include net refunds of UGI Utilities purchased gas and electricity costs of $7.8 million compared with net overcollections of such costs in the prior-year six-month period of $55.8 million. During the 2015 six-month period, changes in operating working capital also included higher cash flow from changes in accrued income taxes.
  
Investing activities. Cash used by investing activities was $119.2 million in the 2016 six-month period compared to $107.7 million in the 2015 six-month period. Total cash capital expenditures were $116.8 million in the 2016 six-month period compared with $102.0 million recorded in the prior-year period. The increase in cash capital expenditures during the 2016 six-month period principally reflects higher Gas Utility maintenance and betterment capital expenditures. Changes in restricted cash in futures brokerage accounts provided $2.7 million of cash in the 2016 six-month period compared with cash used of $2.0 million in the prior-year period.

Financing activities. Cash used by financing activities was $9.9 million in the 2016 six-month period compared with $85.8 million in the 2015 six-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 2016 six-month period there were net credit agreement borrowings of $83.3 million compared with net credit agreement repayments of $55.8 million during the prior-year period. During the 2016 six-month period, UGI Utilities repaid $72.0 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 under the 2016 Note Purchase Agreement later in Fiscal 2016 to refinance these and other scheduled debt repayments on a long-term basis. Cash dividends in the 2016 six-month period totaled $22.0 million compared to cash dividends of $30.6 million in the prior-year period.

REGULATORY MATTERS

Preliminary Stage Information Technology Costs. During the three months ended March 31, 2016, it was determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the three months ended March 31,

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UGI UTILITIES, INC. AND SUBSIDIARIES


2016, we capitalized $5.8 million of such project costs, substantially all of which had been expensed in prior periods, and recorded associated increases to utility property, plant and equipment and regulatory assets (see Note 5 to condensed consolidated financial statements).

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 requested that the new gas rates become effective March 19, 2016. The PUC entered an Order dated February 11, 2016, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last approximately nine months from the date of filing; however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.
Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. Also in March 2016, UGI Gas sought PUC approval to initiate a DSIC effective November 2017 after rates from the pending rate case become effective, along with a petition, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on any of these petitions. The Company cannot predict the timing or outcome of these petitions. The impact of the DSIC charge at PNG and CPG did not have a material effect on Gas Utility results of operations.

UGI Gas Consent Order and Agreement. UGI Utilities’ UGI Gas division has negotiated a Consent Order and Agreement (“UGI Gas-COA”) with the DEP and is awaiting execution thereof. The UGI Gas-COA would be effective October 1, 2016 and would be scheduled to terminate in September 2031. The UGI Gas-COA would require UGI Gas to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties would be capped at $2.5 million in any calendar year. At March 31, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the UGI Gas-COA totaled $43.8 million. UGI Gas has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (See Note 7 to condensed consolidated financial statements).

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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 March 31, 2016 and 2015, the fair values of our natural gas futures and option contracts were losses of $1.9 million and $3.4 million, respectively.
Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At March 31, 2016 and 2015, the fair values of Electric Utility’s electricity supply contracts not accounted for as NPNS were losses of $0.2 million and $1.2 million, respectively. At March 31, 2016 and 2015, 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 March 31, 2016, UGI Utilities had $3.9 million of restricted cash in commodity brokerage accounts. At March 31, 2015, UGI Utilities had $5.6 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. There were no unsettled IRPAs outstanding at March 31, 2016 and 2015.

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 (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and last date of the period for which it was filed, and the exhibit number in such filing):
Exhibit No.
Exhibit
Registrant
Filing
Exhibit
 
 
 
 
 
4.1
Form of Note Purchase Agreement dated April 22, 2016 between the Company and the purchasers listed as signatories thereto.
Utilities
Form 8-K (4/22/16)
4.1
 
 
 
 
 
10.1
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2016.
 
 
 
 
 
 
 
 
10.2
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2016.
 
 
 
 
 
 
 
 
12.1
Computation of ratio of earnings to fixed charges
 
 
 
 
 
 
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2016, 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 March 31, 2016, 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 March 31, 2016, 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:
May 6, 2016
By:  
/s/ Daniel J. Platt
 
 
 
Daniel J. Platt
Vice President - Finance and
Chief Financial Officer
 
 
 
 
 
 
 
 
 
 
Date:
May 6, 2016
By:  
/s/ Ann P. Kelly  
 
 
 
Ann P. Kelly
Controller


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UGI UTILITIES, INC. AND SUBSIDIARIES


EXHIBIT INDEX

10.1
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2016.
 
 
10.2
Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2016.
 
 
12.1
Computation of ratio of earnings to fixed charges.
 
 
31.1
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2016, 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 March 31, 2016, 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 March 31, 2016, 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