UGI UTILITIES INC - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INC	ex31112-31x16ugiutilities1.htm
EX-32 - EXHIBIT 32 - UGI UTILITIES INC	ex3212-31x16ugiutilities10q.htm
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INC	ex31212-31x16ugiutilities1.htm
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INC	ex12112-31x16ugiutilities1.htm

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2016



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-1398

UGI UTILITIES, INC.

(Exact name of registrant as specified in its charter)



Pennsylvania		23-1174060
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

UGI UTILITIES, INC.

2525 N. 12th Street, Suite 360

Reading, PA

(Address of principal executive offices)

19612

(Zip Code)

(610) 796-3400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

At January 31, 2017, 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.

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

TABLE OF CONTENTS



	Page

Part I Financial Information

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets as of December 31, 2016, September 30, 2016 and December 31, 2015	1

Condensed Consolidated Statements of Income for the three months ended December 31, 2016 and 2015	2

Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2016 and 2015	3

Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2016 and 2015	4

Notes to Condensed Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3. Quantitative and Qualitative Disclosures About Market Risk	22

Item 4. Controls and Procedures	22

Part II Other Information

Item 1A. Risk Factors	23

Item 6. Exhibits	23

Signatures	24

- i -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Thousands of dollars)



	December 31, 2016			September 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	9,838		$	2,819		$	15,585
Restricted cash	—			583			6,324
Accounts receivable (less allowances for doubtful accounts of $5,518, $3,946 and $5,283, respectively)	97,188			44,692			78,954
Accounts receivable — related parties	1,886			398			2,671
Accrued utility revenues	55,616			12,753			30,776
Inventories	39,693			42,340			49,365
Prepaid income taxes	2,013			1,956			31,465
Regulatory assets	1,635			3,208			3,905
Derivative instruments	7,077			4,263			234
Prepaid expenses & other current assets	26,131			22,009			28,670
Total current assets	241,077			135,021			247,949
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $987,850, $975,374 and $940,655, respectively)	2,071,718			2,023,541			1,870,732
Goodwill	182,145			182,145			182,145
Regulatory assets	391,229			391,933			297,914
Other assets	12,354			10,451			5,428
Total assets	$	2,898,523		$	2,743,091		$	2,604,168
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	39,981		$	19,986		$	174,924
Short-term borrowings	98,400			112,500			217,700
Accounts payable	70,703			65,180			51,954
Accounts payable — related parties	11,385			3,995			7,069
Regulatory liability — deferred fuel and power refunds	23,809			22,299			28,083
Derivative instruments	295			310			10,351
Other current liabilities	115,489			109,640			112,528
Total current liabilities	360,062			333,910			602,609
Long-term debt	731,030			651,455			372,945
Deferred income taxes	566,519			550,229			524,287
Deferred investment tax credits	3,189			3,268			3,513
Pension and postretirement benefit obligations	181,809			184,516			132,899
Other noncurrent liabilities	96,178			94,976			58,469
Total liabilities	1,938,787			1,818,354			1,694,722
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	473,580			473,580			471,952
Retained earnings	456,781			422,516			388,494
Accumulated other comprehensive loss	(30,884		)	(31,618		)	(11,259		)
Total common stockholder’s equity	959,736			924,737			909,446
Total liabilities and stockholder’s equity	$	2,898,523		$	2,743,091		$	2,604,168

See accompanying notes to condensed consolidated financial statements.

- 1 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Thousands of dollars)



	Three Months Ended
	December 31,
	2016		2015
Revenues	$	261,413	$	197,982
Costs and expenses:
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)	109,471		75,439
Operating and administrative expenses	46,037		48,027
Operating and administrative expenses — related parties	2,564		2,180
Taxes other than income taxes	3,679		3,769
Depreciation	16,862		15,827
Amortization	529		874
Other operating expense, net	35		3,570
	179,177		149,686
Operating income	82,236		48,296
Interest expense	10,028		9,494
Income before income taxes	72,208		38,802
Income taxes	27,943		15,451
Net income	$	44,265	$	23,351

See accompanying notes to condensed consolidated financial statements.

- 2 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Thousands of dollars)



	Three Months Ended
	December 31,
	2016		2015
Net income	$	44,265	$	23,351
Other comprehensive income:
Net gains on derivative instruments (net of tax of $0 and $(1,332), respectively)	—		1,877
Reclassifications of net losses on derivative instruments (net of tax of $(351) and $(276), respectively)	495		390
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(169) and $(113), respectively)	239		160
Other comprehensive income	734		2,427
Comprehensive income	$	44,999	$	25,778

See accompanying notes to condensed consolidated financial statements.

- 3 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Thousands of dollars)



	Three Months Ended
	December 31,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	44,265		$	23,351
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	17,391			16,701
Deferred income tax expense	14,049			15,607
Provision for uncollectible accounts	2,442			1,930
Other, net	4,117			4,331
Net change in:
Accounts receivable and accrued utility revenues	(99,289		)	(46,757		)
Inventories	2,647			2,351
Deferred fuel and power costs, net of changes in unsettled derivatives	(1,000		)	(6,788		)
Accounts payable	19,358			(3,642		)
Other current assets	(4,122		)	(4,767		)
Other current liabilities	4,888			6,449
Net cash provided by operating activities	4,746			8,766
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(69,639		)	(60,457		)
Net costs of property, plant and equipment disposals	(4,061		)	(3,150		)
Decrease in restricted cash	583			278
Net cash used by investing activities	(73,117		)	(63,329		)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments of dividends	(10,000		)	(7,000		)
Issuances of long-term debt, net of issuance costs	99,490			—
Repayments of long-term debt	—			(72,000		)
(Decrease) increase in short-term borrowings	(14,100		)	146,000
Other	—			49
Net cash provided by financing activities	75,390			67,049
Cash and cash equivalents increase	$	7,019		$	12,486
CASH AND CASH EQUIVALENTS
End of period	$	9,838		$	15,585
Beginning of period	2,819			3,099
Increase	$	7,019		$	12,486

See accompanying notes to condensed consolidated financial statements.

- 4 -

Table of Contents

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.”

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

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or the “Company”). We eliminate intercompany accounts when we consolidate.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2016, 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, 2016 (“the Company’s 2016 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 UGI Utilities (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 (loss) (“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 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Deferred Debt Issuance Costs. During the fourth quarter of Fiscal 2016, we adopted new accounting guidance regarding the classification of deferred debt issuance costs. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with line of credit facilities continue to be classified as “other assets” on our Condensed Consolidated Balance Sheets. As a result of the retrospective application of new accounting guidance adopted, the Company has reflected $2,131 of such costs as a reduction to long-term debt, including current maturities, on the accompanying December 31, 2015 Condensed Consolidated Balance Sheet. Previously, these costs were presented within “other assets.”

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.

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

Note 3 — Accounting Changes

Adoption of New Accounting Standard

Employee Share-based Payments. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of 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. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements.

Accounting Standards Not Yet Adopted

Goodwill Impairment. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-04, “Simplifying the Test for Goodwill Impairment.” Under the new accounting guidance, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Instead, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. In addition, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment, if applicable. The provisions of the new accounting guidance are required to be applied prospectively. The new accounting guidance is effective for the Company for goodwill impairment tests performed in fiscal years beginning after December 15, 2019 (Fiscal 2021). Early adoption is permitted for goodwill impairment tests performed after January 1, 2017. The Company is in the process of assessing the impact on its financial statements from the adoption of the new accounting guidance.

Cash Flow Classification. In August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The Company expects to adopt the new guidance in Fiscal 2017. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements.

In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance.

- 6 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

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 on our consolidated financial statements from the adoption of this guidance.

Note 4 — Inventories

Inventories comprise the following:



	December 31, 2016		September 30, 2016		December 31, 2015
Gas Utility natural gas	$	25,777	$	29,223	$	35,923
Materials, supplies and other	13,916		13,117		13,442
Total inventories	$	39,693	$	42,340	$	49,365

At December 31, 2016, UGI Utilities was a party to four principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Three of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 12) and one of the SCAAs is with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of gas storage inventories released under the SCAAs at December 31, 2016, September 30, 2016 and December 31, 2015, comprising 7.8 billion cubic feet (“bcf”), 8.1 bcf and 8.9 bcf of natural gas, were $17,700, $18,773 and $22,061, respectively. At December 31, 2016, September 30, 2016 and December 31, 2015, UGI Utilities held a total of $15,000, $19,100 and $15,100, respectively, of security deposits received 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 -

Table of Contents

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 2016 Annual Report. Other than removal costs, 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:



	December 31, 2016		September 30, 2016		December 31, 2015
Regulatory assets:
Income taxes recoverable	$	117,777	$	115,643	$	117,396
Underfunded pension and postretirement plans	179,364		183,129		138,294
Environmental costs	61,437		59,397		17,643
Removal costs, net	27,062		27,956		22,346
Other	7,224		9,016		6,140
Total regulatory assets	$	392,864	$	395,141	$	301,819
Regulatory liabilities:
Postretirement benefits	$	17,259	$	17,519	$	20,314
Deferred fuel and power refunds	23,809		22,299		28,083
State tax benefits — distribution system repairs	15,579		15,086		13,712
Other	2,021		665		1,073
Total regulatory liabilities (a)	$	58,668	$	55,569	$	63,182


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

Deferred fuel and power 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 gains (losses) on such contracts at December 31, 2016, September 30, 2016, and December 31, 2015, were $6,927, $4,263 and $(4,488), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2016, September 30, 2016, and December 31, 2015, substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (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 for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at December 31, 2016, September 30, 2016, and December 31, 2015, were not material.

- 8 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

and operations necessary to maintain safe and reliable natural gas service. PNG requested that the new gas rates become effective March 20, 2017. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. Although this review process is expected to last up to nine months, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27,000 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.

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 distribution charges billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero, in 2014. 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. To date, no action has been taken by the PUC on either of these petitions. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenue collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an administrative law judge. To commence recovery of revenue under the mechanism, UGI Gas must first place into service a threshold level of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is not likely to occur prior to September 30, 2017.

Note 6 — Debt

Pursuant to a Note Purchase Agreement, in October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due October 2046 (the “4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives; and (2) for general corporate purposes. The 4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.

Note 7 — Commitments and Contingencies

Contingencies

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 also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania.

Each of UGI Utilities and its subsidiaries, CPG, and PNG, has entered into an agreement with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania (each a “COA”). The UGI Gas COA was executed in May 2016 and has an effective date of October 1, 2016. The COAs require UGI Gas, CPG and PNG 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 previously operated (“MGP Properties”) and, in the case of CPG, to plug a minimum number of non-producing natural gas wells per year. Under these agreements, in any calendar year, required environmental expenditures relating to the MGP Properties and, with respect to CPG, the natural gas wells, are capped at $2,500, $1,800, and $1,100, for UGI Gas, CPG and PNG, respectively. The COAs for UGI Gas, CPG and PNG are scheduled to terminate

- 9 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

at the end of 2031, 2018, and 2019, respectively, but each COA may be terminated by either party effective at the end of any two-year period beginning with the original effective date of such COA. At December 31, 2016, September 30, 2016 and December 31, 2015, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Gas, CPG and PNG totaled $55,300, $55,063, and $11,679, respectively. UGI Gas, 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 does not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas, 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.

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 December 31, 2016, September 30, 2016 and December 31, 2015, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities MGP sites outside of Pennsylvania was material.

In addition to the matters described above, there are other 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 December 31,	2016			2015			2016			2015
Service cost	$	2,023		$	1,732		$	61		$	46
Interest cost	5,539			5,817			108			116
Expected return on assets	(7,497		)	(7,167		)	(164		)	(149		)
Amortization of:
Prior service cost (benefit)	81			87			(160		)	(160		)
Actuarial loss	3,707			2,393			28			24
Net benefit cost (income)	3,853			2,862			(127		)	(123		)
Change in associated regulatory liabilities	—			—			(122		)	878
Net benefit cost (income) after change in regulatory liabilities	$	3,853		$	2,862		$	(249	)	$	755

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 Corporation Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During the three months ended December 31, 2016 and 2015, the Company made

- 10 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

contributions to the Pension Plan of $2,849 and $2,467, respectively. The Company expects to make additional discretionary cash contributions of approximately $8,500 to the Pension Plan during the remainder of Fiscal 2017.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 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 December 31, 2016, September 30, 2016 and December 31, 2015:



	Asset (Liability)
	Level 1			Level 2			Level 3		Total
December 31, 2016:
Assets:
Commodity contracts	$	7,077		$	—		$	—	$	7,077
Liabilities:
Commodity contracts	$	—		$	(295	)	$	—	$	(295	)
September 30, 2016:
Assets:
Commodity contracts	$	4,506		$	4		$	—	$	4,510
Liabilities:
Commodity contracts	$	(263	)	$	(294	)	$	—	$	(557	)
December 31, 2015:
Assets:
Commodity contracts	$	234		$	—		$	—	$	234
Interest rate contracts	$	—		$	572		$	—	$	572
Liabilities:
Commodity contracts	$	(4,986	)	$	(1,557	)	$	—	$	(6,543	)
Interest rate contracts	$	—		$	(4,380	)	$	—	$	(4,380	)

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. At December 31, 2016, the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs), were

- 11 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

$775,000 and $800,504, respectively. At September 30, 2016, the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs), were $675,000 and $770,781, respectively. At December 31, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs), were $550,000 and $615,213, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2).

Note 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 December 31, 2016, September 30, 2016 and December 31, 2015, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.7 million dekatherms, 18.4 million dekatherms and 12.4 million dekatherms, respectively. At December 31, 2016, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 9 months. Gains and losses on natural gas futures contracts and 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. At December 31, 2016, September 30, 2016 and December 31, 2015, substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception.

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 on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5). At December 31, 2016, September 30, 2016 and December 31, 2015, the total volumes associated with FTRs totaled 36.2 million kilowatt hours, 58.3 million kilowatt hours and 172.6 million kilowatt hours, respectively. At December 31, 2016, the maximum period over which we are economically hedging electricity congestion is 5 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At December 31, 2016, September 30, 2016 and December 31, 2015, the total volumes associated with gasoline futures contracts were not material.

Interest Rate Risk

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

- 12 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

2016 and September 30, 2016, we had no unsettled IRPAs. At December 31, 2015, the notional amount of our unsettled IRPA contracts was $290,000. At December 31, 2016, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,451.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2016, there was no restricted cash in brokerage accounts. At September 30, 2016 and December 31, 2015, restricted cash in brokerage accounts totaled $583 and $6,324, 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.

- 13 -

Table of Contents

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 December 31, 2016, September 30, 2016 and December 31, 2015:



	December 31, 2016			September 30, 2016			December 31, 2015
Derivative assets:
Derivatives designated as hedging instruments:
Interest rate contracts	$	—		$	—		$	572
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	6,926			4,472			234
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	151			38			—
Total derivative assets — gross	7,077			4,510			806
Gross amounts offset in the balance sheet	—			(247		)	(572		)
Total derivative assets — net	$	7,077		$	4,263		$	234

Derivative liabilities:
Derivatives designated as hedging instruments:
Commodity contracts
Interest rate contracts	$	—		$	—		$	(4,380	)
Derivatives subject to PGC and DS mechanisms:
Commodity contracts	(295		)	(499		)	(6,278		)
Derivatives not subject to PGC and DS mechanisms:
Commodity contracts	—			(58		)	(265		)
Total derivative liabilities — gross	(295		)	(557		)	(10,923		)
Gross amounts offset in the balance sheet	—			247			572
Total derivative liabilities — net	$	(295	)	$	(310	)	$	(10,351	)

Effect of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2016 and 2015:



	Gain Recognized in AOCI					Loss Reclassified from AOCI into Income						Location of Loss Reclassified from AOCI into Income
Three Months Ended December 31,	2016		2015			2016			2015			Location of Loss Reclassified from AOCI into Income
Cash Flow Hedges:
Interest rate contracts	$	—	$	3,209		$	(846	)	$	(666	)	Interest expense

	Gain (Loss) Recognized in Income					Location of Gain (Loss) Recognized in Income
Three Months Ended December 31,	2016		2015
Derivatives Not Subject to PGC and DS Mechanisms:
Gasoline contracts	$	130	$	(65	)	Operating and administrative expenses

- 14 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

Note 11 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2016 and 2015:



	Postretirement Benefit Plans			Derivative Instruments			Total
Three Months Ended December 31, 2016
AOCI - September 30, 2016	$	(11,834	)	$	(19,784	)	$	(31,618	)
Reclassifications of benefit plans actuarial losses and prior service costs	239			—			239
Reclassifications of net losses on IRPAs	—			495			495
AOCI - December 31, 2016	$	(11,595	)	$	(19,289	)	$	(30,884	)
Three Months Ended December 31, 2015
AOCI - September 30, 2015	$	(9,276	)	$	(4,410	)	$	(13,686	)
Net gains on IRPAs	—			1,877			1,877
Reclassifications of benefit plans actuarial losses and prior service costs	160			—			160
Reclassifications of net losses on IRPAs	—			390			390
AOCI - December 31, 2015	$	(9,116	)	$	(2,143	)	$	(11,259	)

Note 12 — Related Party Transactions

UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as “operating and administrative expenses - related parties” in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During the three months ended December 31, 2016 and 2015, these payments were not material. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $2,294 and $1,870 during the three months ended December 31, 2016, and 2015, respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “other current liabilities” on the Condensed Consolidated Balance Sheets, were $11,000 at December 31, 2016, and $8,100 as of September 30, 2016 and December 31, 2015.

- 15 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

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 values of these gas storage inventories at December 31, 2016, September 30, 2016 and December 31, 2015, comprising approximately 5.9 bcf, 4.6 bcf and 5.1 bcf of natural gas, were $12,851, $11,148 and $12,684, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three months ended December 31, 2016 and 2015, totaled $30,510 and $27,364, respectively.

From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2016 and 2015, revenues associated with such sales to Energy Services totaled $10,972 and $8,766, respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one-year agreements. During the three months ended December 31, 2016 and 2015, such purchases totaled $22,023 and $8,192, 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 accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2016 Annual Report. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.

Financial information by business segment follows:

Three Months Ended December 31, 2016:



			Reportable Segments
	Total		Gas Utility		Electric Utility
Revenues	$	261,413	$	237,100	$	24,313
Cost of sales — gas, fuel and purchased power	$	109,471	$	95,567	$	13,904
Depreciation and amortization	$	17,391	$	16,155	$	1,236
Operating income	$	82,236	$	78,967	$	3,269
Interest expense	$	10,028	$	9,583	$	445
Income before income taxes	$	72,208	$	69,384	$	2,824
Capital expenditures (including the effects of accruals)	$	64,096	$	61,742	$	2,354

As of December 31, 2016
Total assets (at period end)	$	2,898,523	$	2,736,908	$	161,615
Goodwill (at period end)	$	182,145	$	182,145	$	—

- 16 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Thousands of dollars)

Three Months Ended December 31, 2015:



			Reportable Segments
	Total		Gas Utility		Electric Utility
Revenues	$	197,982	$	176,942	$	21,040
Cost of sales — gas, fuel and purchased power	$	75,439	$	64,229	$	11,210
Depreciation and amortization	$	16,701	$	15,504	$	1,197
Operating income	$	48,296	$	45,820	$	2,476
Interest expense	$	9,494	$	9,066	$	428
Income before income taxes	$	38,802	$	36,754	$	2,048
Capital expenditures (including the effects of accruals)	$	61,464	$	59,270	$	2,194

As of December 31, 2015
Total assets (at period end)	$	2,604,168	$	2,460,482	$	143,686
Goodwill (at period end)	$	182,145	$	182,145	$	—

- 17 -

Table of Contents

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, environmental, 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) customer, counterparty, supplier, or vendor defaults; (11) increased uncollectible accounts expense; (12) liability for uninsured claims and for claims in excess of insurance coverage, including those for personal injury and property damage arising from explosions, terrorism, and other catastrophic events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas; (13) transmission or distribution system service interruptions; (14) political, regulatory and economic conditions in the United States; (15) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash collateral requirements; and (17) the interruption, disruption, failure, malfunction, or breach of our information technology systems, including due to cyber attack.

These factors, and those factors set forth in Item 1A. Risk Factors in the Company’s 2016 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.

- 18 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended December 31, 2016 (“2016 three-month period”) with the three months ended December 31, 2015 (“2015 three-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 December 31,	2016			2015			Increase (Decrease)
(Dollars in millions)
Gas Utility:
Revenues	$	237.1		$	176.9		$	60.2		34.0	%
Total margin (a)	$	141.5		$	112.7		$	28.8		25.6	%
Operating and administrative expenses	$	44.2		$	45.4		$	(1.2	)	(2.6	)%
Operating income	$	79.0		$	45.8		$	33.2		72.5	%
Income before income taxes	$	69.4		$	36.8		$	32.6		88.6	%
System throughput — billions of cubic feet (“bcf”)
Core market	23.0			17.4			5.6			32.2	%
Total	66.2			49.9			16.3			32.7	%
Heating degree days — % (warmer) than normal (b)	(6.3		)%	(25.3		)%	—			—
Electric Utility:
Revenues	$	24.3		$	21.0		$	3.3		15.7	%
Total margin (a)	$	9.1		$	8.7		$	0.4		4.6	%
Operating and administrative expenses	$	4.4		$	4.8		$	(0.4	)	(8.3	)%
Operating income	$	3.3		$	2.5		$	0.8		32.0	%
Income before income taxes	$	2.8		$	2.0		$	0.8		40.0	%
Distribution sales — millions of kilowatt-hours (“gwh”)	240.6			225.0			15.6			6.9	%

(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 $1.1 million during the three months ended December 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.

Temperatures in Gas Utility’s service territory during three months ended December 31, 2016 based upon heating degree days were 6.3% warmer than normal but 25.4% colder than during the three months ended December 31, 2015. Gas Utility core market volumes increased 5.6 bcf (32.2%) principally reflecting the effects of the colder 2016 three-month period weather. Total Gas Utility distribution system throughput increased 16.3 bcf reflecting the higher core market volumes and higher large firm 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 others. Electric Utility kilowatt-hour sales were 6.9% higher than in the prior-year period principally reflecting the impact of the colder weather on Electric Utility heating-related sales.

UGI Utilities revenues increased $63.4 million principally reflecting a $60.2 million increase in Gas Utility revenues and a $3.3 million increase in Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market revenues ($48.0 million), higher large firm delivery service revenues ($6.1 million) and higher off-system sales revenues ($5.2 million). The $48.0 million increase in Gas Utility core market revenues principally reflects the effects of the higher core market throughput ($37.1 million), higher average retail core market PGC rates ($6.0 million) and the increase in UGI Gas base rates effective October 19, 2016 ($4.9 million). The higher Electric Utility revenues principally reflect the higher Electric Utility volumes ($1.9 million) and slightly higher average DS rates ($1.4 million). Because Gas Utility and Electric Utility are subject to reconcilable PGC and DS recovery mechanisms, increases or decreases in the actual cost of gas or electricity associated with customers who purchase their gas or electricity from UGI Utilities impact revenues and cost of sales but have no direct effect on total margin. UGI Utilities cost of sales was $109.5 million in the three-months ended December 31, 2016 compared with $75.4 million in the three months

- 19 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

ended December 31, 2015, an increase of $34.1 million, principally reflecting the higher Gas Utility retail core-market volumes ($18.1 million), higher average retail core market PGC rates ($6.0 million) and higher cost of sales associated with Gas Utility off-system sales ($5.2 million). In addition, the higher cost of sales reflects an increase in Electric Utility cost of sales of $2.7 million resulting from the higher volumes sold and the slightly higher average DS rates.

UGI Utilities total margin increased $29.2 million principally reflecting higher total margin from Gas Utility core market customers ($23.9 million) and higher large firm delivery service total margin ($4.9 million). The increase in Gas Utility core market margin reflects the higher core market throughput ($19.0 million) due to the colder weather and the increase in UGI Gas base rates effective October 19, 2016 ($4.9 million). Electric Utility total margin increased $0.4 million principally reflecting the higher volume sales as a result of the colder weather.

UGI Utilities operating income increased $33.9 million principally reflecting the increase in total margin ($29.2 million) and lower other operating expense, net ($3.5 million) which includes, among other things, lower environmental matters expense. The slight decrease in operating and administrative costs principally reflects lower distribution system expenses. Income before income taxes increased $33.4 million reflecting the increase in operating income ($33.9 million) partially offset by slightly higher interest expense principally due to higher average long-term debt outstanding.

Interest Expense and Income Taxes

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

FINANCIAL CONDITION AND LIQUIDITY

We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities. Our cash and cash equivalents at December 31, 2016, totaled $9.8 million compared to $2.8 million at September 30, 2016.

UGI Utilities’ total debt outstanding at December 31, 2016, was $869.4 million, which includes $98.4 million of short-term borrowings, compared with total debt outstanding of $783.9 million at September 30, 2016, which includes $112.5 million of short-term borrowings. Total long-term debt outstanding at December 31, 2016, comprises $675.0 million of Senior Notes and $100.0 million of Medium-Term Notes, and is net of $4.0 million of unamortized debt issuance costs.

Pursuant to a Note Purchase Agreement, in October 2016, UGI Utilities issued $100 million aggregate principal amount of 4.12% Senior Notes due October 2046 (the “4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives; and (2) for general corporate purposes.

UGI Utilities has an unsecured revolving credit agreement (the “UGI Utilities 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 Credit Agreement are classified as “short-term borrowings” on the Condensed Consolidated Balance Sheets. During the 2016 and 2015 three-month periods, average daily short-term borrowings under the UGI Utilities Credit Agreement were $96.6 million and $154.6 million, respectively, and peak short-term borrowings totaled $137.0 million and $220.0 million, respectively. At December 31, 2016, UGI Utilities’ available borrowing capacity under the UGI Utilities Credit Agreement was $199.6 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, is generally greatest.

We believe that we have sufficient liquidity in the forms of cash and cash equivalents on hand, cash expected to be generated from Gas Utility and Electric Utility operations, short-term borrowings available under the UGI Utilities 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 Credit Agreement to manage seasonal cash flow needs.

- 20 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

Cash provided by operating activities was $4.7 million in the 2016 three-month period compared to $8.8 million in the prior-year period. Cash flow from operating activities before changes in operating working capital was $82.3 million in the 2016 three-month period compared to $61.9 million recorded in the prior-year period. The greater cash flow from operations before changes in operating working capital in the 2016 three-month period principally reflects the increase in operating results. Changes in operating working capital used $77.5 million of operating cash flow during the 2016 three-month period compared to $53.2 million of cash used during the prior-year period. The higher cash required to fund changes in accounts receivable partially offset by the higher cash provided from changes in accounts payable reflects, in large part, the impact of the higher volumes resulting from the colder weather and, to a lesser extent, higher natural gas costs.

Investing activities. Cash used by investing activities was $73.1 million in the 2016 three-month period compared to $63.3 million in the 2015 three-month period. Total cash capital expenditures were $69.6 million in the 2016 three-month period compared with $60.5 million recorded in the prior-year period. The increase in cash capital expenditures during the 2016 three-month period principally reflects higher information technology capital expenditures. Changes in restricted cash in futures brokerage accounts provided $0.6 million of cash in the 2016 three-month period compared with $0.3 million in the prior-year period.

Financing activities. Cash provided by financing activities was $75.4 million in the 2016 three-month period compared with $67.0 million in the 2015 three-month period. Financing activity cash flows are primarily the result of net borrowings and repayments under revolving credit agreements, net borrowings and repayments of long-term debt and cash dividends paid to UGI. UGI Utilities issued $100 million of 4.12% Senior Notes during the 2016 three-month period and used the net proceeds principally to reduce short-term borrowings. During the 2016 three-month period there were net credit agreement repayments of $14.1 million compared with net credit agreement borrowings of $146.0 million during the prior-year period. Cash dividends in the 2016 three-month period totaled $10.0 million compared to cash dividends of $7.0 million in the prior-year period.

REGULATORY MATTERS

Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 million. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. PNG requested that the new gas rates become effective March 20, 2017. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. Although this review process is expected to last up to nine months, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 million annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016.

- 21 -

Table of Contents

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 retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. The change in market value of natural gas futures contracts can require daily deposits of cash in futures accounts. At December 31, 2016, the fair values of our natural gas futures and option contracts were gains of $6.9 million.

Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At December 31, 2016, all of our Electric Utility’s forward electricity purchase contracts were subject to the NPNS exception. At December 31, 2016, 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 contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes in fair value reflected in “operating and administrative expenses”. The amount of unrealized losses on these contracts and associated volumes under contract at December 31, 2016 were not material.

Interest Rate Risk

In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate debt, from time to time we enter into IRPAs. There were no unsettled IRPAs outstanding at December 31, 2016.

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.

- 22 -

Table of Contents

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, 2016, 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

12.1	Computation of ratio of earnings to fixed charges

31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 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 December 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 December 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

- 23 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		UGI Utilities, Inc. (Registrant)
Date:	February 3, 2017	By:	/s/ Daniel J. Platt
			Daniel J. Platt Vice President - Finance and Chief Financial Officer


Date:	February 3, 2017	By:	/s/ Megan Mattern
			Megan Mattern Controller & Principal Accounting Officer

- 24 -

Table of Contents

UGI UTILITIES, INC. AND SUBSIDIARIES

EXHIBIT INDEX




12.1	Computation of ratio of earnings to fixed charges.

31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 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 December 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 December 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

Attached files

UGI UTILITIES INC Reports

Also read