UGI UTILITIES INC, 10-Q filed on 03 Feb 17
Document and Entity Information
3 Months Ended
Dec. 31, 2016
Jan. 31, 2017
Document and Entity Information [Abstract]
 
 
Entity Registrant Name
UGI UTILITIES INC 
 
Entity Central Index Key
0000100548 
 
Document Type
10-Q 
 
Document Period End Date
Dec. 31, 2016 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q1 
 
Current Fiscal Year End Date
--09-30 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
26,781,785 
Condensed Consolidated Balance Sheets (unaudited) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Sep. 30, 2016
Dec. 31, 2015
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 
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 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2016
Sep. 30, 2016
Dec. 31, 2015
Statement of Financial Position [Abstract]
 
 
 
Allowance for doubtful accounts
$ 5,518 
$ 3,946 
$ 5,283 
Accumulated depreciation and amortization
$ 987,850 
$ 975,374 
$ 940,655 
Common stock, par value (in usd per share)
$ 2.25 
$ 2.25 
$ 2.25 
Common stock, shares authorized (in shares)
40,000,000 
40,000,000 
40,000,000 
Common stock, shares issued (in shares)
26,781,785 
26,781,785 
26,781,785 
Common stock, shares outstanding (in shares)
26,781,785 
26,781,785 
26,781,785 
Condensed Consolidated Statements of Income (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Income Statement [Abstract]
 
 
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 
Total costs and expenses
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 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
 
 
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 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
 
 
Net losses on derivative instruments, tax
$ 0 
$ (1,332)
Reclassifications of net losses on derivative instruments, tax
(351)
(276)
Benefit plans reclassifications of actuarial losses and prior service costs, tax
$ (169)
$ (113)
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2016
Dec. 31, 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 
Nature of Operations
Nature of Operations
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.
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
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.


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.
Accounting Changes
Accounting Changes
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.

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.
Inventories
Inventories
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.
Regulatory Assets and Liabilities and Regulatory Matters
Regulatory Assets and Liabilities and Regulatory Matters
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.

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 $21,700. 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 $27,000 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.
Debt
Debt
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.
Commitments and Contingencies
Commitments and Contingencies
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 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.
Defined Benefit Pension and Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
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 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.
Fair Value Measurements
Fair Value Measurements
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 $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).
Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities
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, 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.

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
 
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
 
 
 
 


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.
Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income
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
)
Related Party Transactions
Related Party Transactions
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.
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.
Segment Information
Segment Information
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

 
$


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

 
$

Summary of Significant Accounting Policies (Policies)
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.
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.
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.
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.

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.
Inventories (Tables)
Schedule of 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

Regulatory Assets and Liabilities and Regulatory Matters (Tables)
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.
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.
Defined Benefit Pension and Other Postretirement Plans (Tables)
Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs
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

Fair Value Measurements (Tables)
Schedule of Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis
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
)


Derivative Instruments and Hedging Activities (Tables)
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
)


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
 
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
 
 
 
 
Accumulated Other Comprehensive Income (Tables)
Schedule of Changes in 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
)
Segment Information (Tables)
Schedule of Segment Information
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

 
$


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

 
$

Nature of Operations (Details)
3 Months Ended
Dec. 31, 2016
county
Organization, Consolidation and Presentation of Financial Statements [Abstract]
 
Number of counties of operation
Summary of Significant Accounting Policies (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2015
Accounting Policies [Abstract]
 
Debt issuance costs
$ 2,131 
Inventories - Schedule of Inventories (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Sep. 30, 2016
Dec. 31, 2015
Public Utilities, Inventory
 
 
 
Total inventories
$ 39,693 
$ 42,340 
$ 49,365 
Gas Utility natural gas
 
 
 
Public Utilities, Inventory
 
 
 
Total inventories
25,777 
29,223 
35,923 
Materials, supplies and other
 
 
 
Public Utilities, Inventory
 
 
 
Total inventories
$ 13,916 
$ 13,117 
$ 13,442 
Inventories - Narrative (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2016
Bcf
agreement
Sep. 30, 2016
Bcf
Dec. 31, 2015
Bcf
Dec. 31, 2016
Other Current Liabilities
Sep. 30, 2016
Other Current Liabilities
Dec. 31, 2015
Other Current Liabilities
Dec. 31, 2016
Minimum
Dec. 31, 2016
Maximum
Public Utilities, Inventory
 
 
 
 
 
 
 
 
Number of storage agreements
 
 
 
 
 
 
 
Term of agreements (in years)
 
 
 
 
 
 
1 year 
3 years 
Number of storage agreements with Energy Services
 
 
 
 
 
 
 
Number of storage agreements with non-affiliates
 
 
 
 
 
 
 
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf)
7.8 
8.1 
8.9 
 
 
 
 
 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
$ 17,700 
$ 18,773 
$ 22,061 
 
 
 
 
 
Security deposit liability
 
 
 
$ 15,000 
$ 19,100 
$ 15,100 
 
 
Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2016
Sep. 30, 2016
Dec. 31, 2015
Regulatory Assets
 
 
 
Regulatory assets
$ 392,864 
$ 395,141 
$ 301,819 
Regulatory Liabilities
 
 
 
Regulatory liabilities
58,668 1
55,569 1
63,182 1
Postretirement benefits
 
 
 
Regulatory Liabilities
 
 
 
Regulatory liabilities
17,259 
17,519 
20,314 
Deferred fuel and power refunds
 
 
 
Regulatory Liabilities
 
 
 
Regulatory liabilities
23,809 
22,299 
28,083 
State tax benefits — distribution system repairs
 
 
 
Regulatory Liabilities
 
 
 
Regulatory liabilities
15,579 
15,086 
13,712 
Other
 
 
 
Regulatory Liabilities
 
 
 
Regulatory liabilities
2,021 
665 
1,073 
Income taxes recoverable
 
 
 
Regulatory Assets
 
 
 
Regulatory assets
117,777 
115,643 
117,396 
Underfunded pension and postretirement plans
 
 
 
Regulatory Assets
 
 
 
Regulatory assets
179,364 
183,129 
138,294 
Environmental costs
 
 
 
Regulatory Assets
 
 
 
Regulatory assets
61,437 
59,397 
17,643 
Removal costs, net
 
 
 
Regulatory Assets
 
 
 
Regulatory assets
27,062 
27,956 
22,346 
Other
 
 
 
Regulatory Assets
 
 
 
Regulatory assets
$ 7,224 
$ 9,016 
$ 6,140 
Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) (USD $)
In Thousands, unless otherwise specified
0 Months Ended 3 Months Ended 1 Months Ended 3 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended
Oct. 14, 2016
Pennsylvania PUC
Dec. 31, 2016
Pennsylvania PUC
Mar. 31, 2016
Pennsylvania PUC
Maximum
Dec. 31, 2016
Pennsylvania PUC
Maximum
Sep. 30, 2014
Pennsylvania PUC
Maximum
Apr. 1, 2015
Pennsylvania PUC
Maximum
PNG
Mar. 31, 2016
Pennsylvania PUC
Maximum
PNG
Apr. 1, 2016
Pennsylvania PUC
Maximum
CPG
Mar. 31, 2016
Pennsylvania PUC
Maximum
CPG
Jan. 19, 2017
Pennsylvania PUC
Subsequent Event
Dec. 31, 2016
Gas Utility
Sep. 30, 2016
Gas Utility
Dec. 31, 2015
Gas Utility
Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of unrealized gains (losses)
 
 
 
 
 
 
 
 
 
 
$ 6,927 
$ 4,263 
$ (4,488)
Requested operating revenue increase
 
 
 
 
 
 
 
 
 
21,700 
 
 
 
Requested rate change, review process period