UGI UTILITIES INC, 10-Q filed on 06 Feb 18
Document and Entity Information
3 Months Ended
Dec. 31, 2017
Jan. 31, 2018
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, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2018 
 
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, 2017
Sep. 30, 2017
Dec. 31, 2016
Current assets:
 
 
 
Cash and cash equivalents
$ 7,289 
$ 5,203 
$ 9,838 
Restricted cash
3,665 
3,046 
Accounts receivable (less allowances for doubtful accounts of $6,398, $4,052 and $5,518, respectively)
105,141 
53,720 
97,188 
Accounts receivable — related parties
1,406 
2,807 
1,886 
Accrued utility revenues
95,854 
13,296 
55,616 
Inventories
49,717 
53,309 
39,693 
Prepaid income taxes
1,977 
7,711 
2,013 
Regulatory assets
605 
8,338 
1,635 
Derivative instruments
678 
1,354 
7,077 
Prepaid expenses & other current assets
23,066 
16,406 
26,131 
Total current assets
289,398 
165,190 
241,077 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,026,450, $1,010,781 and $987,850, respectively)
2,327,664 
2,274,548 
2,071,718 
Goodwill
182,145 
182,145 
182,145 
Regulatory assets
362,237 
360,591 
391,229 
Other assets
13,249 
11,541 
12,354 
Total assets
3,174,693 
2,994,015 
2,898,523 
Current liabilities:
 
 
 
Current maturities of long-term debt
144,374 
39,996 
39,981 
Short-term borrowings
181,500 
170,000 
98,400 
Accounts payable
69,697 
71,559 
70,703 
Accounts payable — related parties
13,420 
6,890 
11,385 
Regulatory liabilities
17,091 
12,988 
25,830 
Derivative instruments
2,244 
1,071 
295 
Other current liabilities
106,177 
110,978 
113,468 
Total current liabilities
534,503 
413,482 
360,062 
Long-term debt
711,242 
711,105 
731,030 
Deferred income taxes
340,772 
635,465 
566,519 
Deferred investment tax credits
2,870 
2,950 
3,189 
Pension and postretirement benefit obligations
140,224 
143,674 
181,809 
Regulatory liabilities, Noncurrent
340,391 
36,242 
32,838 
Other noncurrent liabilities
62,670 
63,192 
63,340 
Total liabilities
2,132,672 
2,006,110 
1,938,787 
Commitments and contingencies (Note 8)
   
   
   
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 
473,580 
Retained earnings
534,161 
480,857 
456,781 
Accumulated other comprehensive loss
(25,979)
(26,791)
(30,884)
Total common stockholder’s equity
1,042,021 
987,905 
959,736 
Total liabilities and stockholder’s equity
$ 3,174,693 
$ 2,994,015 
$ 2,898,523 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Dec. 31, 2017
Sep. 30, 2017
Dec. 31, 2016
Statement of Financial Position [Abstract]
 
 
 
Allowance for doubtful accounts
$ 6,398 
$ 4,052 
$ 5,518 
Accumulated depreciation and amortization
$ 1,026,450 
$ 1,010,781 
$ 987,850 
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, 2017
Dec. 31, 2016
Income Statement [Abstract]
 
 
Revenues
$ 323,105 
$ 261,413 
Costs and expenses:
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
151,774 
109,471 
Operating and administrative expenses
51,984 
49,716 
Operating and administrative expenses — related parties
2,689 
2,564 
Depreciation and amortization
20,354 
17,391 
Other operating expense, net
35 
Total costs and expenses
226,810 
179,177 
Operating income
96,295 
82,236 
Interest expense
10,939 
10,028 
Income before income taxes
85,356 
72,208 
Income taxes
17,053 
27,943 
Net income
$ 68,303 
$ 44,265 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
 
 
Net income
$ 68,303 
$ 44,265 
Other comprehensive income:
 
 
Reclassifications of net losses on derivative instruments (net of tax of $(279) and $(351), respectively)
592 
495 
Benefit plans reclassifications of actuarial losses and net prior service credits (net of tax of $(104) and $(169), respectively)
220 
239 
Other comprehensive income
812 
734 
Comprehensive income
$ 69,115 
$ 44,999 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
 
 
Net losses on derivative instruments, tax
$ 0 
$ 0 
Reclassifications of net losses on derivative instruments, tax
(279)
(351)
Benefit plans reclassifications of actuarial losses and prior service costs, tax
$ (104)
$ (169)
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2017
Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 68,303 
$ 44,265 
Adjustments to reconcile net income to net cash (used) provided by operating activities:
 
 
Depreciation and amortization
20,354 
17,391 
Deferred income tax expense
4,328 
14,049 
Provision for uncollectible accounts
3,459 
2,442 
Other, net
1,161 
4,117 
Net change in:
 
 
Accounts receivable and accrued utility revenues
(136,036)
(99,289)
Inventories
3,592 
2,647 
Deferred fuel and power costs, net of changes in unsettled derivatives
11,572 
(1,000)
Accounts payable
21,655 
19,358 
Other current assets
(6,661)
(4,122)
Other current liabilities
1,172 
4,888 
Net cash (used) provided by operating activities
(7,101)
4,746 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(88,686)
(69,639)
Net costs of property, plant and equipment disposals
(2,382)
(4,061)
(Increase) decrease in restricted cash
(619)
583 
Net cash used by investing activities
(91,687)
(73,117)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Payments of dividends
(15,000)
(10,000)
Issuances of long-term debt, net of issuance costs
124,374 
99,490 
Repayments of long-term debt
(20,000)
Increase (decrease) in short-term borrowings
11,500 
(14,100)
Net cash provided by financing activities
100,874 
75,390 
Cash and cash equivalents increase
2,086 
7,019 
CASH AND CASH EQUIVALENTS
 
 
End of period
7,289 
9,838 
Beginning of period
5,203 
 
Increase
$ 2,086 
$ 7,019 
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 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 herein as an abbreviated reference to UGI Utilities, Inc., or collectively 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, 2017, 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, 2017 (“the Company’s 2017 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 on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. 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. From time to time we enter into derivative instruments that are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values 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 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. We do not currently have derivative instruments that are designated and qualify as cash flow hedges. 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 11.
Use of Estimates. The preparation of financial statements 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

Accounting Standards Not Yet Adopted

Pension and Other Postretirement Benefit Costs. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). The amendments in the ASU should generally 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.

Restricted Cash. 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 are required to 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 and determining the period in which the new guidance will be adopted.

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 and determining the period in which the new guidance will be adopted 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” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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.

The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue.

The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.
Inventories
Inventories
Note 4 — Inventories
Inventories comprise the following:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Gas Utility natural gas
$
34,587

 
$
39,486

 
$
25,777

Materials, supplies and other
15,130

 
13,823

 
13,916

Total inventories
$
49,717

 
$
53,309

 
$
39,693



At December 31, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) which have terms of up to three years. Four of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 13) and one of the SCAAs was with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.
The carrying values of gas storage inventories released under the SCAAs at December 31, 2017, September 30, 2017 and December 31, 2016, comprising 7.8 billion cubic feet (“bcf”), 9.1 bcf and 7.8 bcf of natural gas, were $22,191, $26,064 and $17,700, respectively. At December 31, 2017, September 30, 2017 and December 31, 2016, UGI Utilities held a total of $13,840, $15,040 and $15,000, 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 13.
Income Taxes (Notes)
Income Tax Disclosure
Note 5 — Income Tax Reform

On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted into law. The significant changes resulting from the law that impact UGI Utilities include a reduction in the U.S. federal income tax rate from 35% to 21% effective January 1, 2018 (resulting in a blended rate of 24.5% for Fiscal 2018) and the elimination of bonus depreciation for regulated utilities.
In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three months ended December 31, 2017, contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when issued. We will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by recent guidance issued by the SEC, these adjustments will occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment.
As a result, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities by $223,660 due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of enactment. Because a significant amount of the reduction relates to our regulated utility plant assets, most of the reduction to our excess deferred income taxes is not being recognized immediately in income tax expense. During the three months ended December 31, 2017, the amount of the reduction in our net deferred income tax liabilities that reduced income tax expense totaled $8,122.
In order for utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. At December 31, 2017, we have recorded a regulatory liability of $216,098 associated with the excess deferred federal income taxes related to our regulated utility plant assets. This regulatory liability has been increased, and a federal deferred income tax asset has been recorded, in the amount of $87,803 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. For further information on this regulatory liability, see Note 6 to condensed consolidated financial statements.
For the three months ended December 31, 2017, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rate. We are subject to a blended federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21% on January 1, 2018. As a result, the U.S. federal income tax rate included in our estimated annual effective tax rate is based on this 24.5% blended rate for Fiscal 2018. The PUC has not issued any orders with respect to the lower income tax rate. Our estimated annual effective tax rate for Fiscal 2018 does not reflect the impact of any regulatory action that may be taken by the PUC with respect to the TCJA.
Regulatory Assets and Liabilities and Regulatory Matters
Regulatory Assets and Liabilities and Regulatory Matters
Note 6 — 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 2017 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 UGI Utilities are included in the accompanying condensed consolidated balance sheets:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
126,509

 
$
121,421

 
$
117,777

Underfunded pension and postretirement plans
138,287

 
141,310

 
179,364

Environmental costs
60,760

 
61,566

 
61,437

Deferred fuel and power costs
108

 
7,685

 

Removal costs, net
31,426

 
30,996

 
27,062

Other
5,752

 
5,951

 
7,224

Total regulatory assets
$
362,842

 
$
368,929

 
$
392,864

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
17,315

 
$
17,493

 
$
17,259

Deferred fuel and power refunds
12,658

 
10,621

 
23,809

State tax benefits — distribution system repairs
19,101

 
18,430

 
15,579

Excess federal deferred income taxes (a)
303,901

 

 

Other
4,507

 
2,686

 
2,021

Total regulatory liabilities
$
357,482

 
$
49,230

 
$
58,668


(a)
Balance at December 31, 2017, comprises excess federal deferred income taxes resulting from the enactment of the TCJA (see below and Note 5).

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 (losses) gains on such contracts at December 31, 2017, September 30, 2017, and December 31, 2016, were $(1,720), $146 and $6,927, respectively.

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, 2017, September 30, 2017, and December 31, 2016, were not material.

Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 5). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that these excess federal deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability will be amortized and credited to tax expense.
Other Regulatory Matters

Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9,200. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Electric Utility requested that the new electric rates become effective March 27, 2018, although the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last up to nine months; however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

On August 31, 2017, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11,250 annual base distribution rate increase for PNG. The increase became effective on October 20, 2017.

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. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more-timely cost recovery of qualifying capital expenditures between base rate cases.

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 May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. PNG’s DSIC has been reset to zero as a result of its most recent rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its recent base rate case.

In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case.
Debt
Debt
Note 7 — Debt

On October 31, 2017, UGI Utilities entered into a $125,000 unsecured variable-rate term loan agreement (the “Term Loan”) with a group of banks which initially matures on October 30, 2018.  Such maturity will be automatically extended to October 30, 2022, after UGI Utilities receives a securities certificate from the PUC authorizing issuance of the security and upon delivery of such certificate to the agent.  Proceeds from the Term Loan were used to repay revolving credit balances and for general corporate purposes. The outstanding principal amount of the Term Loan is payable in equal quarterly installments of $1,563 with the balance of the principal being due and payable in full on the maturity date.  Under the Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin.  The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities.  The Term Loan requires UGI Utilities to not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. Because UGI Utilities has not yet received a securities certificate from the PUC authorizing the extension of the maturity date to October 30, 2022, the Term Loan has been reflected in “Current maturities of long-term debt” on the December 31, 2017, Condensed Consolidated Balance Sheet.
Commitments and Contingencies
Commitments and Contingencies
Note 8 — 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 a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2,500, $1,750, and $1,100, for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At December 31, 2017, September 30, 2017 and December 31, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $53,409, $54,250, and $55,300, respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 6).

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 Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles 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 a former subsidiary. 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 a former subsidiary 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, 2017, September 30, 2017 and December 31, 2016, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material.

Other Matters

Manor Township, Pennsylvania Natural Gas Explosion. On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of a Company employee, significant injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The National Transportation Safety Board (“NTSB”), the Occupational Safety and Health Administration (“OSHA”) and the PUC are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the PUC, the local fire department and the Pipeline and Hazardous Materials Safety Administration and the Company is cooperating with the investigation. The Company continues to provide information requested by the investigating parties.
While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and may become involved in lawsuits relative to the incident. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are expected to be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements.
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 statements.
Defined Benefit Pension and Other Postretirement Plans
Defined Benefit Pension and Other Postretirement Plans
Note 9 — 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 (“Other Postretirement Plans”).

Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended December 31,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
1,881

 
$
2,023

 
$
67

 
$
61

Interest cost
 
5,767

 
5,539

 
112

 
108

Expected return on assets
 
(7,777
)
 
(7,497
)
 
(177
)
 
(164
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
63

 
81

 
(110
)
 
(160
)
Actuarial loss
 
2,984

 
3,707

 
24

 
28

Net benefit cost (benefit)
 
2,918

 
3,853

 
(84
)
 
(127
)
Change in associated regulatory liabilities
 

 

 
(123
)
 
(122
)
Net benefit cost (benefit) after change in regulatory liabilities
 
$
2,918

 
$
3,853

 
$
(207
)
 
$
(249
)


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, 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, 2017 and 2016, the Company made contributions to the Pension Plan of $3,359 and $2,849, respectively. The Company expects to make additional discretionary cash contributions of approximately $10,077 to the Pension Plan during the remainder of Fiscal 2018.

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. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, 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, 2017 and 2016.

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 10 — 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, 2017, September 30, 2017 and December 31, 2016:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
December 31, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
678

 
$
19

 
$

 
$
697

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(2,151
)
 
$
(112
)
 
$

 
$
(2,263
)
September 30, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,735

 
$
72

 
$

 
$
1,807

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(1,447
)
 
$
(73
)
 
$

 
$
(1,520
)
December 31, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
7,077

 
$

 
$

 
$
7,077

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$

 
$
(295
)
 
$

 
$
(295
)


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, 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. 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). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at December 31, 2017, September 30, 2017 and December 31, 2016 were as follows:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Carrying amount
$
860,000

 
$
755,000

 
$
775,000

Estimated fair value
$
909,283

 
$
791,378

 
$
800,504

Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities
Note 11 — 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, 2017, September 30, 2017 and December 31, 2016, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.4 million dekatherms, 14.8 million dekatherms and 11.7 million dekatherms, respectively. At December 31, 2017, 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 6).

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, 2017, September 30, 2017 and December 31, 2016, 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 6). At December 31, 2017, September 30, 2017 and December 31, 2016, the total volumes associated with FTRs totaled 63.1 million kilowatt hours, 101.2 million kilowatt hours and 36.2 million kilowatt hours, respectively. At December 31, 2017, 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, 2017, September 30, 2017 and December 31, 2016, 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, 2017, September 30, 2017 and December 31, 2016, we had no unsettled IRPAs. At December 31, 2017, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,485.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2017 and September 30, 2017, restricted cash in brokerage accounts totaled $3,665 and $3,046, respectively. At December 31, 2016, there were no such amounts.

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, 2017, September 30, 2017 and December 31, 2016:
 
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Derivative assets:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
$
450

 
$
1,665

 
$
6,926

Derivatives not subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
247

 
142

 
151

Total derivative assets — gross
 
697

 
1,807

 
7,077

Gross amounts offset in the balance sheet
 
(19
)
 
(450
)
 

Total derivative assets — net (a)
 
$
678

 
$
1,357

 
$
7,077

 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
$
(2,263
)
 
$
(1,520
)
 
$
(295
)
Total derivative liabilities — gross
 
(2,263
)
 
(1,520
)
 
(295
)
Gross amounts offset in the balance sheet
 
19

 
450

 

Total derivative liabilities — net (a)
 
$
(2,244
)
 
$
(1,070
)
 
$
(295
)

(a)
Derivative assets and liabilities with maturities greater than one year are recorded in “Other assets” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

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, 2017 and 2016:
 
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended December 31,
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
Interest rate contracts
 
$
(871
)
 
$
(846
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
Gain Recognized in Income
 
Location of Gain Recognized in Income
Three Months Ended December 31,
 
2017
 
2016
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
149

 
$
130

 
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 NPNS exception accounting 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 12 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2017 and 2016:
 
 
 
 
 
 
 

Three Months Ended December 31, 2017
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — September 30, 2017
 
$
(8,995
)
 
$
(17,796
)
 
$
(26,791
)
Reclassifications of benefit plans actuarial losses and net prior service credits
 
220

 

 
220

Reclassifications of net losses on IRPAs
 

 
592

 
592

AOCI — December 31, 2017
 
$
(8,775
)
 
$
(17,204
)
 
$
(25,979
)
 
 
 
 
 
 
 
Three Months Ended December 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — September 30, 2016
 
$
(11,834
)
 
$
(19,784
)
 
$
(31,618
)
Reclassifications of benefit plans actuarial losses and net prior service credits
 
239

 

 
239

Reclassifications of net losses on IRPAs
 

 
495

 
495

AOCI — December 31, 2016
 
$
(11,595
)
 
$
(19,289
)
 
$
(30,884
)
Related Party Transactions
Related Party Transactions
Note 13 — 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 totaled $1,046 and $1,169 during the three months ended December 31, 2017 and 2016, respectively.

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. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $3,101 and $2,294 during the three months ended December 31, 2017 and 2016, respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. These payments totaled $718 and $564 during the three months ended December 31, 2017 and 2016, 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, at December 31, 2017, September 30, 2017 and December 31, 2016, were $11,040, $11,040, and $11,000, respectively.

UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) in “Inventories” on the Condensed Consolidated Balance Sheets. The carrying values of these gas storage inventories at December 31, 2017, September 30, 2017 and December 31, 2016, comprising approximately 6.1 bcf, 6.8 bcf and 5.9 bcf of natural gas, were $17,043, $19,323 and $12,851, 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, 2017 and 2016 totaled $34,588 and $30,510, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three months ended December 31, 2017 and 2016, revenues associated with such sales to Energy Services totaled $21,147 and $10,972, respectively. Also from time to time, UGI Utilities 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, 2017 and 2016, such purchases totaled $37,597 and $22,023, respectively.
Segment Information
Segment Information
Note 14 — 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 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 2017 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:
 
 
 
 
Reportable Segments
Three Months Ended December 31, 2017
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
323,105

 
$
299,965

 
$
23,140

Cost of sales — gas, fuel and purchased power
 
$
151,774

 
$
138,858

 
$
12,916

Depreciation and amortization
 
$
20,354

 
$
19,000

 
$
1,354

Operating income
 
$
96,295

 
$
93,681

 
$
2,614

Interest expense
 
$
10,939

 
$
10,526

 
$
413

Income before income taxes
 
$
85,356

 
$
83,155

 
$
2,201

Capital expenditures (including the effects of accruals)
 
$
71,699

 
$
68,842

 
$
2,857

 
 
 
 
 
 
 
As of December 31, 2017
 
 
 
 
 
 
Total assets
 
$
3,174,693

 
$
3,038,250

 
$
136,443

Goodwill
 
$
182,145

 
$
182,145

 
$

 
 
 
 
Reportable Segments
Three Months Ended December 31, 2016
 
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
 
$
2,898,523

 
$
2,736,908

 
$
161,615

Goodwill
 
$
182,145

 
$
182,145

 
$

Summary of Significant Accounting Policies (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.
Derivative Instruments
Derivative instruments are reported on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. 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. From time to time we enter into derivative instruments that are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair values 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 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. We do not currently have derivative instruments that are designated and qualify as cash flow hedges. 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 11.
Use of Estimates. The preparation of financial statements 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 Standards Not Yet Adopted

Pension and Other Postretirement Benefit Costs. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). The amendments in the ASU should generally 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.

Restricted Cash. 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 are required to 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 and determining the period in which the new guidance will be adopted.

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 and determining the period in which the new guidance will be adopted 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” (“ASU 2014-09”). The guidance provided under ASU 2014-09, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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.

The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue.

The Company currently anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018. The ultimate decision with respect to the transition method that it will use will depend upon the completion of the Company’s analysis including confirming its preliminary conclusion that the adoption of the new guidance will not have a material impact on its consolidated financial statements.
Inventories (Tables)
Schedule of Inventories
Inventories comprise the following:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Gas Utility natural gas
$
34,587

 
$
39,486

 
$
25,777

Materials, supplies and other
15,130

 
13,823

 
13,916

Total inventories
$
49,717

 
$
53,309

 
$
39,693

Regulatory Assets and Liabilities and Regulatory Matters (Tables)
The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying condensed consolidated balance sheets:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
126,509

 
$
121,421

 
$
117,777

Underfunded pension and postretirement plans
138,287

 
141,310

 
179,364

Environmental costs
60,760

 
61,566

 
61,437

Deferred fuel and power costs
108

 
7,685

 

Removal costs, net
31,426

 
30,996

 
27,062

Other
5,752

 
5,951

 
7,224

Total regulatory assets
$
362,842

 
$
368,929

 
$
392,864

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
17,315

 
$
17,493

 
$
17,259

Deferred fuel and power refunds
12,658

 
10,621

 
23,809

State tax benefits — distribution system repairs
19,101

 
18,430

 
15,579

Excess federal deferred income taxes (a)
303,901

 

 

Other
4,507

 
2,686

 
2,021

Total regulatory liabilities
$
357,482

 
$
49,230

 
$
58,668

The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying condensed consolidated balance sheets:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
126,509

 
$
121,421

 
$
117,777

Underfunded pension and postretirement plans
138,287

 
141,310

 
179,364

Environmental costs
60,760

 
61,566

 
61,437

Deferred fuel and power costs
108

 
7,685

 

Removal costs, net
31,426

 
30,996

 
27,062

Other
5,752

 
5,951

 
7,224

Total regulatory assets
$
362,842

 
$
368,929

 
$
392,864

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
17,315

 
$
17,493

 
$
17,259

Deferred fuel and power refunds
12,658

 
10,621

 
23,809

State tax benefits — distribution system repairs
19,101

 
18,430

 
15,579

Excess federal deferred income taxes (a)
303,901

 

 

Other
4,507

 
2,686

 
2,021

Total regulatory liabilities
$
357,482

 
$
49,230

 
$
58,668

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,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
1,881

 
$
2,023

 
$
67

 
$
61

Interest cost
 
5,767

 
5,539

 
112

 
108

Expected return on assets
 
(7,777
)
 
(7,497
)
 
(177
)
 
(164
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
63

 
81

 
(110
)
 
(160
)
Actuarial loss
 
2,984

 
3,707

 
24

 
28

Net benefit cost (benefit)
 
2,918

 
3,853

 
(84
)
 
(127
)
Change in associated regulatory liabilities
 

 

 
(123
)
 
(122
)
Net benefit cost (benefit) after change in regulatory liabilities
 
$
2,918

 
$
3,853

 
$
(207
)
 
$
(249
)
Fair Value Measurements (Tables)
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, 2017, September 30, 2017 and December 31, 2016:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
December 31, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
678

 
$
19

 
$

 
$
697

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(2,151
)
 
$
(112
)
 
$

 
$
(2,263
)
September 30, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,735

 
$
72

 
$

 
$
1,807

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(1,447
)
 
$
(73
)
 
$

 
$
(1,520
)
December 31, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
7,077

 
$

 
$

 
$
7,077

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$

 
$
(295
)
 
$

 
$
(295
)


The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at December 31, 2017, September 30, 2017 and December 31, 2016 were as follows:
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Carrying amount
$
860,000

 
$
755,000

 
$
775,000

Estimated fair value
$
909,283

 
$
791,378

 
$
800,504

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, 2017, September 30, 2017 and December 31, 2016:
 
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
Derivative assets:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
$
450

 
$
1,665

 
$
6,926

Derivatives not subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
247

 
142

 
151

Total derivative assets — gross
 
697

 
1,807

 
7,077

Gross amounts offset in the balance sheet
 
(19
)
 
(450
)
 

Total derivative assets — net (a)
 
$
678

 
$
1,357

 
$
7,077

 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
$
(2,263
)
 
$
(1,520
)
 
$
(295
)
Total derivative liabilities — gross
 
(2,263
)
 
(1,520
)
 
(295
)
Gross amounts offset in the balance sheet
 
19

 
450

 

Total derivative liabilities — net (a)
 
$
(2,244
)
 
$
(1,070
)
 
$
(295
)
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, 2017 and 2016:
 
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended December 31,
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
Interest rate contracts
 
$
(871
)
 
$
(846
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
Gain Recognized in Income
 
Location of Gain Recognized in Income
Three Months Ended December 31,
 
2017
 
2016
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
149

 
$
130

 
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, 2017 and 2016:
 
 
 
 
 
 
 

Three Months Ended December 31, 2017
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — September 30, 2017
 
$
(8,995
)
 
$
(17,796
)
 
$
(26,791
)
Reclassifications of benefit plans actuarial losses and net prior service credits
 
220

 

 
220

Reclassifications of net losses on IRPAs
 

 
592

 
592

AOCI — December 31, 2017
 
$
(8,775
)
 
$
(17,204
)
 
$
(25,979
)
 
 
 
 
 
 
 
Three Months Ended December 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — September 30, 2016
 
$
(11,834
)
 
$
(19,784
)
 
$
(31,618
)
Reclassifications of benefit plans actuarial losses and net prior service credits
 
239

 

 
239

Reclassifications of net losses on IRPAs
 

 
495

 
495

AOCI — December 31, 2016
 
$
(11,595
)
 
$
(19,289
)
 
$
(30,884
)
Segment Information (Tables)
Schedule of Segment Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial information by business segment follows:
 
 
 
 
Reportable Segments
Three Months Ended December 31, 2017
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
323,105

 
$
299,965

 
$
23,140

Cost of sales — gas, fuel and purchased power
 
$
151,774

 
$
138,858

 
$
12,916

Depreciation and amortization
 
$
20,354

 
$
19,000

 
$
1,354

Operating income
 
$
96,295

 
$
93,681

 
$
2,614

Interest expense
 
$
10,939

 
$
10,526

 
$
413

Income before income taxes
 
$
85,356

 
$
83,155

 
$
2,201

Capital expenditures (including the effects of accruals)
 
$
71,699

 
$
68,842

 
$
2,857

 
 
 
 
 
 
 
As of December 31, 2017
 
 
 
 
 
 
Total assets
 
$
3,174,693

 
$
3,038,250

 
$
136,443

Goodwill
 
$
182,145

 
$
182,145

 
$

 
 
 
 
Reportable Segments
Three Months Ended December 31, 2016
 
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
 
$
2,898,523

 
$
2,736,908

 
$
161,615

Goodwill
 
$
182,145

 
$
182,145

 
$

Nature of Operations (Details)
3 Months Ended
Dec. 31, 2017
county
Organization, Consolidation and Presentation of Financial Statements [Abstract]
 
Number of counties of operation
Inventories - Schedule of Inventories (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2017
Sep. 30, 2017
Dec. 31, 2016
Public Utilities, Inventory
 
 
 
Total inventories
$ 49,717 
$ 53,309 
$ 39,693 
Gas Utility natural gas
 
 
 
Public Utilities, Inventory
 
 
 
Total inventories
34,587 
39,486 
25,777 
Materials, supplies and other
 
 
 
Public Utilities, Inventory
 
 
 
Total inventories
$ 15,130 
$ 13,823 
$ 13,916 
Inventories - Narrative (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended
Dec. 31, 2017
Bcf
agreement
Sep. 30, 2017
Bcf
Dec. 31, 2016
Bcf
Dec. 31, 2017
Maximum
Public Utilities, Inventory
 
 
 
 
Number of storage agreements
 
 
 
Term of agreements (in years)
 
 
 
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 
9.1 
7.8 
 
Carrying value of gas storage inventories released under SCAAs with non-affiliates
$ 22,191 
$ 26,064 
$ 17,700 
 
Security deposit liability
$ 13,840 
$ 15,040 
$ 15,000 
 
Income Taxes (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2017
Sep. 30, 2018
Scenario, Forecast
Operating Loss Carryforwards [Line Items]
 
 
Federal statutory income tax rate
 
24.50% 
Tax Cuts and Jobs Act of 2017, reduction of net deferred income tax liabilities
$ 223,660 
 
Tax Cuts and Jobs Act of 2017, reduction of income tax expense
8,122 
 
Tax Cuts and Jobs Act of 2017, change in tax rate, provisional unrecognized deferred tax liability
216,098 
 
Increase in regulatory liabilities, excess deferred income taxes
$ 87,803 
 
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
0 Months Ended
Dec. 31, 2017
Sep. 30, 2017
Dec. 31, 2016
Dec. 31, 2017
Postretirement benefits
Sep. 30, 2017
Postretirement benefits
Dec. 31, 2016
Postretirement benefits
Dec. 31, 2017
Deferred fuel and power refunds
Sep. 30, 2017
Deferred fuel and power refunds
Dec. 31, 2016
Deferred fuel and power refunds
Dec. 31, 2017
State tax benefits — distribution system repairs
Sep. 30, 2017
State tax benefits — distribution system repairs
Dec. 31, 2016
State tax benefits — distribution system repairs
Dec. 31, 2017
Excess federal deferred income taxes (a)
Sep. 30, 2017
Excess federal deferred income taxes (a)
Dec. 31, 2016
Excess federal deferred income taxes (a)
Dec. 31, 2017
Other
Sep. 30, 2017
Other
Dec. 31, 2016
Other
Dec. 31, 2017
Income taxes recoverable
Sep. 30, 2017
Income taxes recoverable
Dec. 31, 2016
Income taxes recoverable
Dec. 31, 2017
Underfunded pension and postretirement plans
Sep. 30, 2017
Underfunded pension and postretirement plans
Dec. 31, 2016
Underfunded pension and postretirement plans
Dec. 31, 2017
Environmental costs
Sep. 30, 2017
Environmental costs
Dec. 31, 2016
Environmental costs
Dec. 31, 2017
Deferred fuel and power costs
Sep. 30, 2017
Deferred fuel and power costs
Dec. 31, 2016
Deferred fuel and power costs
Dec. 31, 2017
Removal costs, net
Sep. 30, 2017
Removal costs, net
Dec. 31, 2016
Removal costs, net
Dec. 31, 2017
Other
Sep. 30, 2017
Other
Dec. 31, 2016
Other
Jan. 26, 2018
Scenario, Forecast
Subsequent Event
Pennsylvania Public Utilities Commission
Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Requested operating revenue increase
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 9,200 
Regulatory assets
362,842 
368,929 
392,864 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
126,509 
121,421 
117,777 
138,287 
141,310 
179,364 
60,760 
61,566 
61,437 
108 
7,685 
31,426 
30,996 
27,062 
5,752 
5,951 
7,224 
 
Regulatory Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities
357,482 
49,230 
58,668 
17,315 
17,493 
17,259 
12,658 
10,621 
23,809 
19,101 
18,430 
15,579 
303,901 
4,507 
2,686 
2,021 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and postretirement benefit obligations
$ 140,224 
$ 143,674 
$ 181,809 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended
Dec. 31, 2017
Minimum
Dec. 31, 2017
Maximum
Dec. 31, 2017
Pennsylvania PUC
Sep. 30, 2014
Pennsylvania PUC
Maximum
Oct. 20, 2017
Pennsylvania PUC
PNG
Jul. 1, 2017
Pennsylvania PUC
PNG
Apr. 1, 2015
Pennsylvania PUC
PNG
Maximum
Oct. 14, 2016
Pennsylvania PUC
UGI Gas
Jul. 1, 2017
Pennsylvania PUC
CPG
Apr. 1, 2016
Pennsylvania PUC
CPG
Maximum
Mar. 31, 2016
Pennsylvania PUC
CPG
Maximum
Dec. 31, 2017
Gas Utility
Sep. 30, 2017
Gas Utility
Dec. 31, 2016
Gas Utility
Regulatory Assets