UGI UTILITIES INC, 10-Q filed on 05 May 17
Document and Entity Information
6 Months Ended
Mar. 31, 2017
Apr. 30, 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
Mar. 31, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q2 
 
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
Mar. 31, 2017
Sep. 30, 2016
Mar. 31, 2016
Current assets:
 
 
 
Cash and cash equivalents
$ 4,566 
$ 2,819 
$ 26,406 
Restricted cash
347 
583 
3,909 
Accounts receivable (less allowances for doubtful accounts of $9,401, $3,946 and $8,232, respectively)
123,285 
44,692 
102,125 
Accounts receivable — related parties
1,739 
398 
1,271 
Accrued utility revenues
36,665 
12,753 
24,052 
Inventories
17,174 
42,340 
16,685 
Prepaid income taxes
301 
1,956 
Regulatory assets
2,309 
3,208 
3,229 
Derivative instruments
2,024 
4,263 
881 
Prepaid expenses & other current assets
22,957 
22,009 
27,632 
Total current assets
211,367 
135,021 
206,190 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $997,591, $975,374 and $952,478, respectively)
2,112,013 
2,023,541 
1,900,806 
Goodwill
182,145 
182,145 
182,145 
Regulatory assets
392,408 
391,933 
344,983 
Other assets
11,792 
10,451 
5,395 
Total assets
2,909,725 
2,743,091 
2,639,519 
Current liabilities:
 
 
 
Current maturities of long-term debt
59,980 
19,986 
Short-term borrowings
48,500 
112,500 
155,000 
Accounts payable
58,095 
65,180 
42,681 
Accounts payable — related parties
11,339 
3,995 
6,710 
Regulatory liability — deferred fuel and power refunds
13,791 
22,299 
30,838 
Derivative instruments
19 
310 
3,370 
Other current liabilities
126,342 
109,640 
152,479 
Total current liabilities
318,066 
333,910 
391,078 
Long-term debt
711,066 
651,455 
547,932 
Deferred income taxes
590,964 
550,229 
526,937 
Deferred investment tax credits
3,109 
3,268 
3,429 
Pension and postretirement benefit obligations
179,101 
184,516 
130,915 
Other noncurrent liabilities
96,838 
94,976 
99,029 
Total liabilities
1,899,144 
1,818,354 
1,699,320 
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 
472,715 
Retained earnings
506,906 
422,516 
436,788 
Accumulated other comprehensive loss
(30,164)
(31,618)
(29,563)
Total common stockholder’s equity
1,010,581 
924,737 
940,199 
Total liabilities and stockholder’s equity
$ 2,909,725 
$ 2,743,091 
$ 2,639,519 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Mar. 31, 2017
Sep. 30, 2016
Mar. 31, 2016
Statement of Financial Position [Abstract]
 
 
 
Allowance for doubtful accounts
$ 9,401 
$ 3,946 
$ 8,232 
Accumulated depreciation and amortization
$ 997,591 
$ 975,374 
$ 952,478 
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 6 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Mar. 31, 2017
Mar. 31, 2016
Income Statement [Abstract]
 
 
 
 
Revenues
$ 359,940 
$ 322,047 
$ 621,353 
$ 520,029 
Costs and expenses:
 
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
164,541 
137,434 
274,012 
212,873 
Operating and administrative expenses
53,064 
45,125 
99,101 
93,152 
Operating and administrative expenses — related parties
4,534 
3,798 
7,098 
5,978 
Taxes other than income taxes
4,957 
4,448 
8,636 
8,217 
Depreciation
17,125 
16,146 
33,987 
31,973 
Amortization
574 
884 
1,103 
1,758 
Other operating (income) expense, net
(1,263)
(269)
(1,228)
3,301 
Total costs and expenses
243,532 
207,566 
422,709 
357,252 
Operating income
116,408 
114,481 
198,644 
162,777 
Interest expense
10,322 
9,270 
20,350 
18,764 
Income before income taxes
106,086 
105,211 
178,294 
144,013 
Income taxes
40,961 
41,917 
68,904 
57,368 
Net income
$ 65,125 
$ 63,294 
$ 109,390 
$ 86,645 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Mar. 31, 2017
Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income
$ 65,125 
$ 63,294 
$ 109,390 
$ 86,645 
Other comprehensive income (loss):
 
 
 
 
Net losses on derivative instruments (net of tax of $0, $13,348, $0, and $12,016, respectively)
(18,820)
(16,943)
Reclassifications of net losses on derivative instruments (net of tax of $(341), $(253), $(692), and $(529), respectively)
481 
356 
976 
746 
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(169), $(114), $(338), and $(227), respectively)
239 
160 
478 
320 
Other comprehensive income (loss)
720 
(18,304)
1,454 
(15,877)
Comprehensive income
$ 65,845 
$ 44,990 
$ 110,844 
$ 70,768 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Mar. 31, 2017
Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net losses on derivative instruments, tax
$ 0 
$ 13,348 
$ 0 
$ 12,016 
Reclassifications of net losses on derivative instruments, tax
(341)
(253)
(692)
(529)
Benefit plans reclassifications of actuarial losses and prior service costs, tax
$ (169)
$ (114)
$ (338)
$ (227)
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Thousands, unless otherwise specified
6 Months Ended
Mar. 31, 2017
Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 109,390 
$ 86,645 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
35,090 
33,731 
Deferred income tax expense
35,992 
48,905 
Provision for uncollectible accounts
6,265 
5,572 
Other, net
6,292 
2,138 
Net change in:
 
 
Accounts receivable and accrued utility revenues
(110,111)
(66,130)
Inventories
25,166 
35,031 
Deferred fuel and power costs, net of changes in unsettled derivatives
(7,601)
(7,789)
Accounts payable
14,722 
(3,882)
Other current assets
(948)
(2,529)
Other current liabilities
17,591 
20,691 
Net cash provided by operating activities
131,848 
152,383 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(135,075)
(116,778)
Net costs of property, plant and equipment disposals
(5,753)
(5,101)
Decrease in restricted cash
236 
2,693 
Net cash used by investing activities
(140,592)
(119,186)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Payments of dividends
(25,000)
(22,000)
Issuances of long-term debt, net of issuance costs
99,491 
Repayments of long-term debt
(72,000)
(Decrease) increase in short-term borrowings
(64,000)
83,300 
Other
810 
Net cash provided (used) by financing activities
10,491 
(9,890)
Cash and cash equivalents increase
1,747 
23,307 
CASH AND CASH EQUIVALENTS
 
 
End of period
4,566 
26,406 
Beginning of period
2,819 
3,099 
Increase
$ 1,747 
$ 23,307 
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 on 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 $2,068 of such costs as a reduction to long-term debt, including current maturities, on the accompanying March 31, 2016, 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. Effective October 1, 2016, 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

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). Early adoption is permitted. 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 and determining the period in which the new guidance will be adopted.

Goodwill Impairment. In January 2017, the FASB issued 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 guidance and determining the period in which the new guidance will be adopted.

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 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 and determining the period in which the new guidance will be adopted.

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 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.” 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. The Company has not yet selected a transition method and is in the process of assessing the impact on its financial statements from the adoption of the new guidance.
Inventories
Inventories
Note 4 — Inventories
Inventories comprise the following:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Gas Utility natural gas
$
2,394

 
$
29,223

 
$
3,786

Materials, supplies and other
14,780

 
13,117

 
12,899

Total inventories
$
17,174

 
$
42,340

 
$
16,685



At March 31, 2017, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from one 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 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 March 31, 2017, September 30, 2016 and March 31, 2016, comprising 0.8 billion cubic feet (“bcf”), 8.1 bcf and 1.1 bcf of natural gas, were $1,964, $18,773 and $2,593, respectively. At March 31, 2017, September 30, 2016 and March 31, 2016, UGI Utilities held a total of $15,040, $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 UGI Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
120,255

 
$
115,643

 
$
118,160

Underfunded pension and postretirement plans
175,598

 
183,129

 
135,825

Environmental costs
62,209

 
59,397

 
60,494

Deferred fuel and power costs
1,262

 
151

 

Removal costs, net
28,840

 
27,956

 
25,030

Other
6,553

 
8,865

 
8,703

Total regulatory assets
$
394,717

 
$
395,141

 
$
348,212

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
16,974

 
$
17,519

 
$
19,307

Deferred fuel and power refunds
13,791

 
22,299

 
30,838

State tax benefits — distribution system repairs
16,145

 
15,086

 
14,158

Other
3,548

 
665

 
2,500

Total regulatory liabilities (a)
$
50,458

 
$
55,569

 
$
66,803


(a)
Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on 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 March 31, 2017, September 30, 2016, and March 31, 2016, were $1,973, $4,263 and $(1,900), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At March 31, 2017, September 30, 2016, and March 31, 2016, 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 March 31, 2017, September 30, 2016, and March 31, 2016, were not material.

Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s base operating revenues for residential, commercial and industrial customers by $21,700 annually. 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. The PUC entered an Order dated February 9, 2017, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing; however, 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 5% 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 5% to 10% of billed distribution revenues. On April 20, 2017, the PUC voted 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 the issuance of a final order of the PUC.

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. 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. 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 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 March 31, 2017, September 30, 2016 and March 31, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Gas, CPG and PNG totaled $55,659, $55,063, and $55,533, 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 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 its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At March 31, 2017, September 30, 2016 and March 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.

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 8 — Defined Benefit Pension and Other Postretirement Plans

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

Net periodic pension expense and other postretirement benefit costs include the following components:
 
 
Pension Benefits
 
Other Postretirement Benefits
Three Months Ended March 31,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
2,022

 
$
1,732

 
$
61

 
$
45

Interest cost
 
5,539

 
5,818

 
107

 
117

Expected return on assets
 
(7,496
)
 
(7,168
)
 
(164
)
 
(149
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
82

 
87

 
(160
)
 
(160
)
Actuarial loss
 
3,706

 
2,393

 
29

 
25

Net benefit cost (income)
 
3,853

 
2,862

 
(127
)
 
(122
)
Change in associated regulatory liabilities
 

 

 
(123
)
 
876

Net benefit cost (income) after change in regulatory liabilities
 
$
3,853

 
$
2,862

 
$
(250
)
 
$
754

 
 
 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
4,045

 
$
3,464

 
$
122

 
$
91

Interest cost
 
11,078

 
11,635

 
215

 
233

Expected return on assets
 
(14,993
)
 
(14,335
)
 
(328
)
 
(298
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
163

 
174

 
(320
)
 
(320
)
Actuarial loss
 
7,413

 
4,786

 
57

 
49

Net benefit cost (income)
 
7,706

 
5,724

 
(254
)
 
(245
)
Change in associated regulatory liabilities
 

 

 
(245
)
 
1,754

Net benefit cost (income) after change in regulatory liabilities
 
$
7,706

 
$
5,724

 
$
(499
)
 
$
1,509



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 six months ended March 31, 2017 and 2016, the Company made contributions to the Pension Plan of $5,698 and $4,934, respectively. The Company expects to make additional discretionary cash contributions of approximately $5,500 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 six months ended March 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 9 — Fair Value Measurements

Derivative Instruments

The following table presents on a gross basis our derivative assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2017, September 30, 2016 and March 31, 2016:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
2,157

 
$

 
$

 
$
2,157

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(133
)
 
$
(19
)
 
$

 
$
(152
)
September 30, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
4,506

 
$
4

 
$

 
$
4,510

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(263
)
 
$
(294
)
 
$

 
$
(557
)
March 31, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,179

 
$

 
$

 
$
1,179

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

 
$
(3,668
)


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. 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 type 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 March 31, 2017, September 30, 2016 and March 31, 2016 were as follows:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Carrying amount
$
775,000

 
$
675,000

 
$
550,000

Estimated fair value
$
801,675

 
$
770,781

 
$
637,016

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 March 31, 2017, September 30, 2016 and March 31, 2016, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.0 million dekatherms, 18.4 million dekatherms and 10.0 million dekatherms, respectively. At March 31, 2017, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 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 March 31, 2017, September 30, 2016 and March 31, 2016, 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 March 31, 2017, September 30, 2016 and March 31, 2016, the total volumes associated with FTRs totaled 14.6 million kilowatt hours, 58.3 million kilowatt hours and 69.2 million kilowatt hours, respectively. At March 31, 2017, the maximum period over which we are economically hedging electricity congestion is 2 months.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At March 31, 2017, September 30, 2016 and March 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 March 31, 2017, September 30, 2016 and March 31, 2016, we had no unsettled IRPAs. At March 31, 2017, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,470.

Derivative Instrument Credit Risk

Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2017, September 30, 2016 and March 31, 2016, restricted cash in brokerage accounts totaled $347, $583 and $3,909, 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 March 31, 2017, September 30, 2016 and March 31, 2016:
 
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Derivative assets:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
$
2,104

 
$
4,472

 
$
1,179

Derivatives not subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
53

 
38

 

Total derivative assets — gross
 
2,157

 
4,510

 
1,179

Gross amounts offset in the balance sheet
 
(133
)
 
(247
)
 
(298
)
Total derivative assets — net
 
$
2,024

 
$
4,263

 
$
881

 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
$
(150
)
 
$
(499
)
 
$
(3,466
)
Derivatives not subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
(2
)
 
(58
)
 
(202
)
Total derivative liabilities — gross
 
(152
)
 
(557
)
 
(3,668
)
Gross amounts offset in the balance sheet
 
133

 
247

 
298

Total derivative liabilities — net
 
$
(19
)
 
$
(310
)
 
$
(3,370
)


Effect of Derivative Instruments

The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three and six months ended March 31, 2017 and 2016:
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended March 31,
 
2017
 
2016
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$
(32,168
)
 
$
(822
)
 
$
(609
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in Income
 
Location of Loss Recognized in Income
 
 
 
 
Three Months Ended March 31,
 
2017
 
2016
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(98
)
 
$
(55
)
 
Operating and administrative expenses
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Six Months Ended March 31,
 
2017
 
2016
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$
(28,959
)
 
$
(1,668
)
 
$
(1,275
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Six Months Ended March 31,
 
2017
 
2016
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
32

 
$
(120
)
 
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 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 and six months ended March 31, 2017 and 2016:
Three Months Ended March 31, 2017
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — December 31, 2016
 
$
(11,595
)
 
$
(19,289
)
 
$
(30,884
)
Reclassifications of benefit plan actuarial losses and prior service costs
 
239

 

 
239

Reclassifications of net losses on IRPAs
 

 
481

 
481

AOCI — March 31, 2017
 
$
(11,356
)
 
$
(18,808
)
 
$
(30,164
)
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — December 31, 2015
 
$
(9,116
)
 
$
(2,143
)
 
$
(11,259
)
Net losses on IRPAs
 

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

 

 
160

Reclassifications of net losses on IRPAs
 

 
356

 
356

AOCI — March 31, 2016
 
$
(8,956
)
 
$
(20,607
)
 
$
(29,563
)

Six Months Ended March 31, 2017
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — September 30, 2016
 
$
(11,834
)
 
$
(19,784
)
 
$
(31,618
)
Reclassifications of benefit plans actuarial losses and prior service costs
 
478

 

 
478

Reclassifications of net losses on IRPAs
 

 
976

 
976

AOCI — March 31, 2017
 
$
(11,356
)
 
$
(18,808
)
 
$
(30,164
)
 
 
 
 
 
 
 
Six Months Ended March 31, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — September 30, 2015
 
$
(9,276
)
 
$
(4,410
)
 
$
(13,686
)
Net losses on IRPAs
 

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

 

 
320

Reclassifications of net losses on IRPAs
 

 
746

 
746

AOCI — March 31, 2016
 
$
(8,956
)
 
$
(20,607
)
 
$
(29,563
)
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” on the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material.

From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories 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 $201 and $2,495 during the three and six months ended March 31, 2017, respectively, and $159 and $2,029 during the three and six months ended March 31, 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. During the three and six months ended March 31, 2017 and 2016, these payments were not material. 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 $11,040 at March 31, 2017 and $8,100 as of September 30, 2016 and March 31, 2016.

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 March 31, 2017, September 30, 2016 and March 31, 2016, comprising approximately 0.8 bcf, 4.6 bcf and 0.9 bcf of natural gas, were $1,964, $11,148 and $2,074, respectively.

UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and six months ended March 31, 2017 totaled $41,225 and $71,735, respectively. During the three and six months ended March 31, 2016, such purchases totaled $31,691 and $59,055, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three and six months ended March 31, 2017, revenues associated with such sales to Energy Services totaled $22,310 and $33,282, respectively. During the three and six months ended March 31, 2016, revenues associated with such sales to Energy Services totaled $12,854 and $21,620, respectively. 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 and six months ended March 31, 2017, such purchases totaled $39,085 and $61,108, respectively. During the three and six months ended March 31, 2016, such purchases totaled $14,912 and $23,104, 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:
 
 
 
 
Reportable Segments
Three Months Ended March 31, 2017
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
359,940

 
$
335,864

 
$
24,076

Cost of sales — gas, fuel and purchased power
 
$
164,541

 
$
150,863

 
$
13,678

Depreciation and amortization
 
$
17,699

 
$
16,378

 
$
1,321

Operating income
 
$
116,408

 
$
115,105

 
$
1,303

Interest expense
 
$
10,322

 
$
9,833

 
$
489

Income before income taxes
 
$
106,086

 
$
105,272

 
$
814

Capital expenditures (including the effects of accruals)
 
$
56,517

 
$
54,137

 
$
2,380

 
 
 
 
Reportable Segments
Three Months Ended March 31, 2016
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
322,047

 
$
298,088

 
$
23,959

Cost of sales — gas, fuel and purchased power
 
$
137,434

 
$
123,702

 
$
13,732

Depreciation and amortization
 
$
17,030

 
$
15,822

 
$
1,208

Operating income
 
$
114,481

 
$
111,004

 
$
3,477

Interest expense
 
$
9,270

 
$
8,847

 
$
423

Income before income taxes
 
$
105,211

 
$
102,157

 
$
3,054

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

 
$
46,003

 
$
2,110

 
 
 
 
Reportable Segments
Six Months Ended March 31, 2017
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
621,353

 
$
572,964

 
$
48,389

Cost of sales — gas, fuel and purchased power
 
$
274,012

 
$
246,430

 
$
27,582

Depreciation and amortization
 
$
35,090

 
$
32,533

 
$
2,557

Operating income
 
$
198,644

 
$
194,072

 
$
4,572

Interest expense
 
$
20,350

 
$
19,416

 
$
934

Income before income taxes
 
$
178,294

 
$
174,656

 
$
3,638

Capital expenditures (including the effects of accruals)
 
$
120,613

 
$
115,879

 
$
4,734

 
 
 
 
 
 
 
As of March 31, 2017
 
 
 
 
 
 
Total assets
 
$
2,909,725

 
$
2,746,144

 
$
163,581

Goodwill
 
$
182,145

 
$
182,145

 
$

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

 
$
475,030

 
$
44,999

Cost of sales — gas, fuel and purchased power
 
$
212,873

 
$
187,931

 
$
24,942

Depreciation and amortization
 
$
33,731

 
$
31,326

 
$
2,405

Operating income
 
$
162,777

 
$
156,824

 
$
5,953

Interest expense
 
$
18,764

 
$
17,913

 
$
851

Income before income taxes
 
$
144,013

 
$
138,911

 
$
5,102

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

 
$
105,273

 
$
4,304

 
 
 
 
 
 
 
As of March 31, 2016
 
 
 
 
 
 
Total assets
 
$
2,639,519

 
$
2,486,225

 
$
153,294

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.
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 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. Effective October 1, 2016, 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

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). Early adoption is permitted. 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 and determining the period in which the new guidance will be adopted.

Goodwill Impairment. In January 2017, the FASB issued 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 guidance and determining the period in which the new guidance will be adopted.

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 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 and determining the period in which the new guidance will be adopted.

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 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.” 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. The Company has not yet selected a transition method and is in the process of assessing the impact on its financial statements from the adoption of the new guidance.
Inventories (Tables)
Schedule of Inventories
Inventories comprise the following:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Gas Utility natural gas
$
2,394

 
$
29,223

 
$
3,786

Materials, supplies and other
14,780

 
13,117

 
12,899

Total inventories
$
17,174

 
$
42,340

 
$
16,685

Regulatory Assets and Liabilities and Regulatory Matters (Tables)
The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
120,255

 
$
115,643

 
$
118,160

Underfunded pension and postretirement plans
175,598

 
183,129

 
135,825

Environmental costs
62,209

 
59,397

 
60,494

Deferred fuel and power costs
1,262

 
151

 

Removal costs, net
28,840

 
27,956

 
25,030

Other
6,553

 
8,865

 
8,703

Total regulatory assets
$
394,717

 
$
395,141

 
$
348,212

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
16,974

 
$
17,519

 
$
19,307

Deferred fuel and power refunds
13,791

 
22,299

 
30,838

State tax benefits — distribution system repairs
16,145

 
15,086

 
14,158

Other
3,548

 
665

 
2,500

Total regulatory liabilities (a)
$
50,458

 
$
55,569

 
$
66,803


(a)
Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.
The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
120,255

 
$
115,643

 
$
118,160

Underfunded pension and postretirement plans
175,598

 
183,129

 
135,825

Environmental costs
62,209

 
59,397

 
60,494

Deferred fuel and power costs
1,262

 
151

 

Removal costs, net
28,840

 
27,956

 
25,030

Other
6,553

 
8,865

 
8,703

Total regulatory assets
$
394,717

 
$
395,141

 
$
348,212

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
16,974

 
$
17,519

 
$
19,307

Deferred fuel and power refunds
13,791

 
22,299

 
30,838

State tax benefits — distribution system repairs
16,145

 
15,086

 
14,158

Other
3,548

 
665

 
2,500

Total regulatory liabilities (a)
$
50,458

 
$
55,569

 
$
66,803


(a)
Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on 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 March 31,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
2,022

 
$
1,732

 
$
61

 
$
45

Interest cost
 
5,539

 
5,818

 
107

 
117

Expected return on assets
 
(7,496
)
 
(7,168
)
 
(164
)
 
(149
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
82

 
87

 
(160
)
 
(160
)
Actuarial loss
 
3,706

 
2,393

 
29

 
25

Net benefit cost (income)
 
3,853

 
2,862

 
(127
)
 
(122
)
Change in associated regulatory liabilities
 

 

 
(123
)
 
876

Net benefit cost (income) after change in regulatory liabilities
 
$
3,853

 
$
2,862

 
$
(250
)
 
$
754

 
 
 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Six Months Ended March 31,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
4,045

 
$
3,464

 
$
122

 
$
91

Interest cost
 
11,078

 
11,635

 
215

 
233

Expected return on assets
 
(14,993
)
 
(14,335
)
 
(328
)
 
(298
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
163

 
174

 
(320
)
 
(320
)
Actuarial loss
 
7,413

 
4,786

 
57

 
49

Net benefit cost (income)
 
7,706

 
5,724

 
(254
)
 
(245
)
Change in associated regulatory liabilities
 

 

 
(245
)
 
1,754

Net benefit cost (income) after change in regulatory liabilities
 
$
7,706

 
$
5,724

 
$
(499
)
 
$
1,509

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 March 31, 2017, September 30, 2016 and March 31, 2016:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
March 31, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
2,157

 
$

 
$

 
$
2,157

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(133
)
 
$
(19
)
 
$

 
$
(152
)
September 30, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
4,506

 
$
4

 
$

 
$
4,510

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(263
)
 
$
(294
)
 
$

 
$
(557
)
March 31, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,179

 
$

 
$

 
$
1,179

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

 
$
(3,668
)


The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at March 31, 2017, September 30, 2016 and March 31, 2016 were as follows:
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Carrying amount
$
775,000

 
$
675,000

 
$
550,000

Estimated fair value
$
801,675

 
$
770,781

 
$
637,016

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 March 31, 2017, September 30, 2016 and March 31, 2016:
 
 
March 31, 2017
 
September 30, 2016
 
March 31, 2016
Derivative assets:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
$
2,104

 
$
4,472

 
$
1,179

Derivatives not subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
53

 
38

 

Total derivative assets — gross
 
2,157

 
4,510

 
1,179

Gross amounts offset in the balance sheet
 
(133
)
 
(247
)
 
(298
)
Total derivative assets — net
 
$
2,024

 
$
4,263

 
$
881

 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
$
(150
)
 
$
(499
)
 
$
(3,466
)
Derivatives not subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
(2
)
 
(58
)
 
(202
)
Total derivative liabilities — gross
 
(152
)
 
(557
)
 
(3,668
)
Gross amounts offset in the balance sheet
 
133

 
247

 
298

Total derivative liabilities — net
 
$
(19
)
 
$
(310
)
 
$
(3,370
)


The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three and six months ended March 31, 2017 and 2016:
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended March 31,
 
2017
 
2016
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$
(32,168
)
 
$
(822
)
 
$
(609
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in Income
 
Location of Loss Recognized in Income
 
 
 
 
Three Months Ended March 31,
 
2017
 
2016
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(98
)
 
$
(55
)
 
Operating and administrative expenses
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Six Months Ended March 31,
 
2017
 
2016
 
2017