UGI UTILITIES INC, 10-Q filed on 04 Aug 17
Document and Entity Information
9 Months Ended
Jun. 30, 2017
Jul. 31, 2017
Document and Entity Information [Abstract]
 
 
Entity Registrant Name
UGI UTILITIES INC 
 
Entity Central Index Key
0000100548 
 
Document Type
10-Q 
 
Document Period End Date
Jun. 30, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
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
Jun. 30, 2017
Sep. 30, 2016
Jun. 30, 2016
Current assets:
 
 
 
Cash and cash equivalents
$ 4,828 
$ 2,819 
$ 82,449 
Restricted cash
2,524 
583 
212 
Accounts receivable (less allowances for doubtful accounts of $10,050, $3,946 and $7,921, respectively)
69,246 
44,692 
59,301 
Accounts receivable — related parties
718 
398 
638 
Accrued utility revenues
5,924 
12,753 
10,099 
Inventories
37,129 
42,340 
27,009 
Prepaid income taxes
428 
1,956 
Regulatory assets
7,759 
3,208 
3,263 
Derivative instruments
942 
4,263 
5,384 
Prepaid expenses & other current assets
12,995 
22,009 
33,724 
Total current assets
142,493 
135,021 
222,079 
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,008,121, $975,374 and $961,006, respectively)
2,174,609 
2,023,541 
1,945,539 
Goodwill
182,145 
182,145 
182,145 
Regulatory assets
390,988 
391,933 
342,037 
Other assets
14,297 
10,451 
5,501 
Total assets
2,904,532 
2,743,091 
2,697,301 
Current liabilities:
 
 
 
Current maturities of long-term debt
39,990 
19,986 
19,981 
Short-term borrowings
50,000 
112,500 
130,000 
Accounts payable
56,866 
65,180 
50,665 
Accounts payable — related parties
7,625 
3,995 
5,838 
Regulatory liability — deferred fuel and power refunds
12,587 
22,299 
34,432 
Derivative instruments
1,056 
310 
507 
Other current liabilities
129,325 
109,640 
113,011 
Total current liabilities
297,449 
333,910 
354,434 
Long-term debt
711,116 
651,455 
627,422 
Deferred income taxes
614,419 
550,229 
545,614 
Deferred investment tax credits
3,029 
3,268 
3,348 
Pension and postretirement benefit obligations
176,393 
184,516 
128,932 
Other noncurrent liabilities
95,108 
94,976 
98,652 
Total liabilities
1,897,514 
1,818,354 
1,758,402 
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 
473,295 
Retained earnings
502,603 
422,516 
434,391 
Accumulated other comprehensive loss
(29,424)
(31,618)
(29,046)
Total common stockholder’s equity
1,007,018 
924,737 
938,899 
Total liabilities and stockholder’s equity
$ 2,904,532 
$ 2,743,091 
$ 2,697,301 
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Jun. 30, 2017
Sep. 30, 2016
Jun. 30, 2016
Statement of Financial Position [Abstract]
 
 
 
Allowance for doubtful accounts
$ 10,050 
$ 3,946 
$ 7,921 
Accumulated depreciation and amortization
$ 1,008,121 
$ 975,374 
$ 961,006 
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 9 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Income Statement [Abstract]
 
 
 
 
Revenues
$ 146,692 
$ 140,283 
$ 768,045 
$ 660,312 
Costs and expenses:
 
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
51,979 
44,415 
325,991 
257,288 
Operating and administrative expenses
49,031 
43,254 
148,132 
136,406 
Operating and administrative expenses — related parties
2,961 
2,811 
10,059 
8,789 
Taxes other than income taxes
3,706 
3,970 
12,342 
12,187 
Depreciation
17,364 
15,877 
51,351 
47,850 
Amortization
548 
673 
1,651 
2,431 
Other operating (income) expense, net
(6,568)
(532)
(7,796)
2,769 
Total costs and expenses
119,021 
110,468 
541,730 
467,720 
Operating income
27,671 
29,815 
226,315 
192,592 
Interest expense
10,128 
9,158 
30,478 
27,922 
Income before income taxes
17,543 
20,657 
195,837 
164,670 
Income taxes
6,846 
8,054 
75,750 
65,422 
Net income
$ 10,697 
$ 12,603 
$ 120,087 
$ 99,248 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income
$ 10,697 
$ 12,603 
$ 120,087 
$ 99,248 
Other comprehensive income (loss):
 
 
 
 
Net losses on derivative instruments (net of tax of $0, $0, $0, and $12,016, respectively)
(16,943)
Reclassifications of net losses on derivative instruments (net of tax of $(355), $(253), $(1,047), and $(782), respectively)
501 
357 
1,477 
1,103 
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(169), $(113), $(507), and $(340), respectively)
239 
160 
717 
480 
Other comprehensive income (loss)
740 
517 
2,194 
(15,360)
Comprehensive income
$ 11,437 
$ 13,120 
$ 122,281 
$ 83,888 
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Jun. 30, 2017
Jun. 30, 2016
Jun. 30, 2017
Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net losses on derivative instruments, tax
$ 0 
$ 0 
$ 0 
$ 12,016 
Reclassifications of net losses on derivative instruments, tax
(355)
(253)
(1,047)
(782)
Benefit plans reclassifications of actuarial losses and prior service costs, tax
$ (169)
$ (113)
$ (507)
$ (340)
Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Jun. 30, 2017
Jun. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
Net income
$ 120,087 
$ 99,248 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
53,002 
50,281 
Deferred income tax expense
56,285 
66,136 
Provision for uncollectible accounts
8,184 
6,716 
Settlement of interest rate protection agreements
(35,975)
Other, net
4,358 
954 
Net change in:
 
 
Accounts receivable and accrued utility revenues
(31,471)
(9,864)
Inventories
5,211 
24,707 
Deferred fuel and power costs, net of changes in unsettled derivatives
(12,571)
(11,587)
Accounts payable
2,775 
(6,062)
Other current assets
9,014 
(7,833)
Other current liabilities
21,727 
17,763 
Net cash provided by operating activities
236,601 
194,484 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
Expenditures for property, plant and equipment
(201,916)
(163,967)
Net costs of property, plant and equipment disposals
(7,734)
(7,664)
(Increase) decrease in restricted cash
(1,941)
6,390 
Net cash used by investing activities
(211,591)
(165,241)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
Payments of dividends
(40,000)
(37,000)
Issuances of long-term debt, net of issuance costs
99,499 
99,415 
Repayments of long-term debt
(20,000)
(72,000)
(Decrease) increase in short-term borrowings
(62,500)
58,300 
Other
1,392 
Net cash (used) provided by financing activities
(23,001)
50,107 
Cash and cash equivalents increase
2,009 
79,350 
CASH AND CASH EQUIVALENTS
 
 
End of period
4,828 
82,449 
Beginning of period
2,819 
3,099 
Increase
$ 2,009 
$ 79,350 
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 the Condensed Consolidated Balance Sheets. As a result of the retrospective application of new accounting guidance adopted, the Company has reflected $2,597 of such costs as a reduction to long-term debt, including current maturities, on the June 30, 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 expects to adopt the new guidance in the fourth quarter of Fiscal 2017.

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 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.” 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:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Gas Utility natural gas
$
21,826

 
$
29,223

 
$
13,561

Materials, supplies and other
15,303

 
13,117

 
13,448

Total inventories
$
37,129

 
$
42,340

 
$
27,009



At June 30, 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 June 30, 2017, September 30, 2016 and June 30, 2016, comprising 4.8 billion cubic feet (“bcf”), 8.1 bcf and 4.6 bcf of natural gas, were $14,146, $18,773 and $8,390, respectively. At June 30, 2017, September 30, 2016 and June 30, 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 the accompanying Condensed Consolidated Balance Sheets:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
122,733

 
$
115,643

 
$
119,604

Underfunded pension and postretirement plans
171,833

 
183,129

 
133,356

Environmental costs
61,616

 
59,397

 
60,716

Deferred fuel and power costs
7,024

 
151

 

Removal costs, net
29,405

 
27,956

 
22,444

Other
6,136

 
8,865

 
9,180

Total regulatory assets
$
398,747

 
$
395,141

 
$
345,300

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
16,715

 
$
17,519

 
$
19,671

Deferred fuel and power refunds
12,587

 
22,299

 
34,432

State tax benefits — distribution system repairs
16,662

 
15,086

 
14,604

Other
2,706

 
665

 
1,149

Total regulatory liabilities (a)
$
48,670

 
$
55,569

 
$
69,856


(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 (losses) gains on such contracts at June 30, 2017, September 30, 2016, and June 30, 2016, were $(73), $4,263 and $5,483, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At June 30, 2017, September 30, 2016, and June 30, 2016, 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 June 30, 2017, September 30, 2016, and June 30, 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. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC. Under the terms of the Joint Petition, UGI Utilities will be permitted, effective October 20, 2017, to increase PNG’s annual base distribution rates by $11,250. On July 25, 2017, the PUC administrative law judge recommended that the settlement be adopted without modification. Although the Company expects to receive the final order from the PUC approving the settlement by October 2017, 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 May 10, 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 the Company’s Long-term Infrastructure Improvement Plan filing in 2018.

On November 9, 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. 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 at the end of any two-year period beginning with the original effective date of such COA. At June 30, 2017, September 30, 2016 and June 30, 2016, our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Gas, CPG and PNG totaled $55,185, $55,063, and $56,006, 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 June 30, 2017, September 30, 2016 and June 30, 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. Other parties may be invited to participate by the NTSB.
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 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 June 30,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
2,023

 
$
1,731

 
$
62

 
$
46

Interest cost
 
5,540

 
5,818

 
108

 
116

Expected return on assets
 
(7,497
)
 
(7,167
)
 
(164
)
 
(149
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
81

 
87

 
(160
)
 
(160
)
Actuarial loss
 
3,706

 
2,393

 
28

 
24

Net benefit cost (income)
 
3,853

 
2,862

 
(126
)
 
(123
)
Change in associated regulatory liabilities
 

 

 
(123
)
 
878

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

 
$
2,862

 
$
(249
)
 
$
755

 
 
 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Nine Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
6,068

 
$
5,195

 
$
184

 
$
137

Interest cost
 
16,618

 
17,453

 
323

 
349

Expected return on assets
 
(22,490
)
 
(21,502
)
 
(492
)
 
(447
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
244

 
261

 
(480
)
 
(480
)
Actuarial loss
 
11,119

 
7,179

 
85

 
73

Net benefit cost (income)
 
11,559

 
8,586

 
(380
)
 
(368
)
Change in associated regulatory liabilities
 

 

 
(368
)
 
2,632

Net benefit cost (income) after change in regulatory liabilities
 
$
11,559

 
$
8,586

 
$
(748
)
 
$
2,264



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 nine months ended June 30, 2017 and 2016, the Company made contributions to the Pension Plan of $8,546 and $7,402, respectively. The Company expects to make additional discretionary cash contributions of approximately $2,800 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, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the nine months ended June 30, 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 June 30, 2017, September 30, 2016 and June 30, 2016:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
June 30, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,062

 
$
101

 
$

 
$
1,163

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(1,157
)
 
$
(68
)
 
$

 
$
(1,225
)
September 30, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
4,506

 
$
4

 
$

 
$
4,510

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

 
$
(557
)
June 30, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
5,715

 
$
3

 
$

 
$
5,718

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(341
)
 
$
(391
)
 
$

 
$
(732
)


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 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 June 30, 2017, September 30, 2016 and June 30, 2016 were as follows:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Carrying amount
$
755,000

 
$
675,000

 
$
650,000

Estimated fair value
$
788,472

 
$
770,781

 
$
747,588

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 June 30, 2017, September 30, 2016 and June 30, 2016, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 12.7 million dekatherms, 18.4 million dekatherms and 13.4 million dekatherms, respectively. At June 30, 2017, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 15 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 June 30, 2017, September 30, 2016 and June 30, 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 5). At June 30, 2017, September 30, 2016 and June 30, 2016, the total volumes associated with FTRs totaled 139.4 million kilowatt hours, 58.3 million kilowatt hours and 80.6 million kilowatt hours, respectively. At June 30, 2017, the maximum period over which we are economically hedging electricity congestion is 11 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 June 30, 2017, September 30, 2016 and June 30, 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 June 30, 2017, September 30, 2016 and June 30, 2016, we had no unsettled IRPAs. At June 30, 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 June 30, 2017, September 30, 2016 and June 30, 2016, restricted cash in brokerage accounts totaled $2,524, $583 and $212, 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 June 30, 2017, September 30, 2016 and June 30, 2016:
 
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Derivative assets:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
$
1,163

 
$
4,472

 
$
5,718

Derivatives not subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 

 
38

 

Total derivative assets — gross
 
1,163

 
4,510

 
5,718

Gross amounts offset in the balance sheet
 
(159
)
 
(247
)
 
(225
)
Total derivative assets — net (a)
 
$
1,004

 
$
4,263

 
$
5,493

 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
$
(1,204
)
 
$
(499
)
 
$
(593
)
Derivatives not subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
(21
)
 
(58
)
 
(139
)
Total derivative liabilities — gross
 
(1,225
)
 
(557
)
 
(732
)
Gross amounts offset in the balance sheet
 
159

 
247

 
225

Total derivative liabilities — net (a)
 
$
(1,066
)
 
$
(310
)
 
$
(507
)


(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 and nine months ended June 30, 2017 and 2016:
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$

 
$
(856
)
 
$
(610
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Three Months Ended June 30,
 
2017
 
2016
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(57
)
 
$
27

 
Operating and administrative expenses
 

 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Nine Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$
(28,959
)
 
$
(2,524
)
 
$
(1,885
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in Income
 
Location of Loss Recognized in Income
 
 
 
 
Nine Months Ended June 30,
 
2017
 
2016
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(25
)
 
$
(93
)
 
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 nine months ended June 30, 2017 and 2016:
Three Months Ended June 30, 2017
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — March 31, 2017
 
$
(11,356
)
 
$
(18,808
)
 
$
(30,164
)
Reclassifications of benefit plan actuarial losses and prior service costs
 
239

 

 
239

Reclassifications of net losses on IRPAs
 

 
501

 
501

AOCI — June 30, 2017
 
$
(11,117
)
 
$
(18,307
)
 
$
(29,424
)
 
 
 
 
 
 
 
Three Months Ended June 30, 2016
 
Postretirement Benefit Plans
 
Derivative Instruments
 
Total
AOCI — March 31, 2016
 
$
(8,956
)
 
$
(20,607
)
 
$
(29,563
)
Reclassifications of benefit plan actuarial losses and prior service costs
 
160

 

 
160

Reclassifications of net losses on IRPAs
 

 
357

 
357

AOCI — June 30, 2016
 
$
(8,796
)
 
$
(20,250
)
 
$
(29,046
)

Nine Months Ended June 30, 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
 
717

 

 
717

Reclassifications of net losses on IRPAs
 

 
1,477

 
1,477

AOCI — June 30, 2017
 
$
(11,117
)
 
$
(18,307
)
 
$
(29,424
)
 
 
 
 
 
 
 
Nine Months Ended June 30, 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
 
480

 

 
480

Reclassifications of net losses on IRPAs
 

 
1,103

 
1,103

AOCI — June 30, 2016
 
$
(8,796
)
 
$
(20,250
)
 
$
(29,046
)
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 totaled $562 and $3,420 during the three and nine months ended June 30, 2017, respectively, and $1,752 and $3,904 during the three and nine months ended June 30, 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 $9,777 and $12,272 during the three and nine months ended June 30, 2017, respectively, and $4,358 and $6,387 during the three and nine months ended June 30, 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 $729 and $2,027 during the three and nine months ended June 30, 2017, respectively, and $493 and $1,510 during the three and nine months ended June 30, 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, were $11,040 at June 30, 2017 and $8,100 as of September 30, 2016 and June 30, 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 June 30, 2017, September 30, 2016 and June 30, 2016, comprising approximately 3.6 bcf, 4.6 bcf and 2.7 bcf of natural gas, were $10,662, $11,148 and $5,100, 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 nine months ended June 30, 2017 totaled $2,137 and $73,872, respectively. During the three and nine months ended June 30, 2016, such purchases totaled $2,138 and $61,193, respectively.

From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2017, revenues associated with such sales to Energy Services totaled $10,554 and $43,836, respectively. During the three and nine months ended June 30, 2016, revenues associated with such sales to Energy Services totaled $4,514 and $26,134, 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 nine months ended June 30, 2017, such purchases totaled $14,675 and $75,783, respectively. During the three and nine months ended June 30, 2016, such purchases totaled $6,928 and $30,032, 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 June 30, 2017
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
146,692

 
$
127,849

 
$
18,843

Cost of sales — gas, fuel and purchased power
 
$
51,979

 
$
42,180

 
$
9,799

Depreciation and amortization
 
$
17,912

 
$
16,845

 
$
1,067

Operating income
 
$
27,671

 
$
25,628

 
$
2,043

Interest expense
 
$
10,128

 
$
9,601

 
$
527

Income before income taxes
 
$
17,543

 
$
16,027

 
$
1,516

Capital expenditures (including the effects of accruals)
 
$
79,088

 
$
75,836

 
$
3,252

 
 
 
 
Reportable Segments
Three Months Ended June 30, 2016
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
140,283

 
$
119,995

 
$
20,288

Cost of sales — gas, fuel and purchased power
 
$
44,415

 
$
33,715

 
$
10,700

Depreciation and amortization
 
$
16,550

 
$
15,339

 
$
1,211

Operating income
 
$
29,815

 
$
27,116

 
$
2,699

Interest expense
 
$
9,158

 
$
8,670

 
$
488

Income before income taxes
 
$
20,657

 
$
18,446

 
$
2,211

Capital expenditures (including the effects of accruals)
 
$
56,481

 
$
53,199

 
$
3,282

 
 
 
 
Reportable Segments
Nine Months Ended June 30, 2017
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
768,045

 
$
700,813

 
$
67,232

Cost of sales — gas, fuel and purchased power
 
$
325,991

 
$
288,610

 
$
37,381

Depreciation and amortization
 
$
53,002

 
$
49,378

 
$
3,624

Operating income
 
$
226,315

 
$
219,700

 
$
6,615

Interest expense
 
$
30,478

 
$
29,017

 
$
1,461

Income before income taxes
 
$
195,837

 
$
190,683

 
$
5,154

Capital expenditures (including the effects of accruals)
 
$
199,701

 
$
191,715

 
$
7,986

 
 
 
 
 
 
 
As of June 30, 2017
 
 
 
 
 
 
Total assets
 
$
2,904,532

 
$
2,743,035

 
$
161,497

Goodwill
 
$
182,145

 
$
182,145

 
$

 
 
 
 
Reportable Segments
Nine Months Ended June 30, 2016
 
Total
 
Gas Utility
 
Electric Utility
Revenues
 
$
660,312

 
$
595,025

 
$
65,287

Cost of sales — gas, fuel and purchased power
 
$
257,288

 
$
221,646

 
$
35,642

Depreciation and amortization
 
$
50,281

 
$
46,665

 
$
3,616

Operating income
 
$
192,592

 
$
183,940

 
$
8,652

Interest expense
 
$
27,922

 
$
26,583

 
$
1,339

Income before income taxes
 
$
164,670

 
$
157,357

 
$
7,313

Capital expenditures (including the effects of accruals)
 
$
166,058

 
$
158,472

 
$
7,586

 
 
 
 
 
 
 
As of June 30, 2016
 
 
 
 
 
 
Total assets
 
$
2,697,301

 
$
2,531,573

 
$
165,728

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 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 the 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 expects to adopt the new guidance in the fourth quarter of Fiscal 2017.

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 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.” 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:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Gas Utility natural gas
$
21,826

 
$
29,223

 
$
13,561

Materials, supplies and other
15,303

 
13,117

 
13,448

Total inventories
$
37,129

 
$
42,340

 
$
27,009

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:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
122,733

 
$
115,643

 
$
119,604

Underfunded pension and postretirement plans
171,833

 
183,129

 
133,356

Environmental costs
61,616

 
59,397

 
60,716

Deferred fuel and power costs
7,024

 
151

 

Removal costs, net
29,405

 
27,956

 
22,444

Other
6,136

 
8,865

 
9,180

Total regulatory assets
$
398,747

 
$
395,141

 
$
345,300

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
16,715

 
$
17,519

 
$
19,671

Deferred fuel and power refunds
12,587

 
22,299

 
34,432

State tax benefits — distribution system repairs
16,662

 
15,086

 
14,604

Other
2,706

 
665

 
1,149

Total regulatory liabilities (a)
$
48,670

 
$
55,569

 
$
69,856


(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 the accompanying Condensed Consolidated Balance Sheets:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Regulatory assets:
 
 
 
 
 
Income taxes recoverable
$
122,733

 
$
115,643

 
$
119,604

Underfunded pension and postretirement plans
171,833

 
183,129

 
133,356

Environmental costs
61,616

 
59,397

 
60,716

Deferred fuel and power costs
7,024

 
151

 

Removal costs, net
29,405

 
27,956

 
22,444

Other
6,136

 
8,865

 
9,180

Total regulatory assets
$
398,747

 
$
395,141

 
$
345,300

Regulatory liabilities:
 
 
 
 
 
Postretirement benefits
$
16,715

 
$
17,519

 
$
19,671

Deferred fuel and power refunds
12,587

 
22,299

 
34,432

State tax benefits — distribution system repairs
16,662

 
15,086

 
14,604

Other
2,706

 
665

 
1,149

Total regulatory liabilities (a)
$
48,670

 
$
55,569

 
$
69,856


(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 June 30,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
2,023

 
$
1,731

 
$
62

 
$
46

Interest cost
 
5,540

 
5,818

 
108

 
116

Expected return on assets
 
(7,497
)
 
(7,167
)
 
(164
)
 
(149
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
81

 
87

 
(160
)
 
(160
)
Actuarial loss
 
3,706

 
2,393

 
28

 
24

Net benefit cost (income)
 
3,853

 
2,862

 
(126
)
 
(123
)
Change in associated regulatory liabilities
 

 

 
(123
)
 
878

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

 
$
2,862

 
$
(249
)
 
$
755

 
 
 
 
 
 
 
 
 
 
 
Pension Benefits
 
Other Postretirement Benefits
Nine Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
Service cost
 
$
6,068

 
$
5,195

 
$
184

 
$
137

Interest cost
 
16,618

 
17,453

 
323

 
349

Expected return on assets
 
(22,490
)
 
(21,502
)
 
(492
)
 
(447
)
Amortization of:
 
 
 
 
 
 
 
 
Prior service cost (benefit)
 
244

 
261

 
(480
)
 
(480
)
Actuarial loss
 
11,119

 
7,179

 
85

 
73

Net benefit cost (income)
 
11,559

 
8,586

 
(380
)
 
(368
)
Change in associated regulatory liabilities
 

 

 
(368
)
 
2,632

Net benefit cost (income) after change in regulatory liabilities
 
$
11,559

 
$
8,586

 
$
(748
)
 
$
2,264

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 June 30, 2017, September 30, 2016 and June 30, 2016:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
June 30, 2017:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
1,062

 
$
101

 
$

 
$
1,163

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(1,157
)
 
$
(68
)
 
$

 
$
(1,225
)
September 30, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
4,506

 
$
4

 
$

 
$
4,510

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

 
$
(557
)
June 30, 2016:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
5,715

 
$
3

 
$

 
$
5,718

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(341
)
 
$
(391
)
 
$

 
$
(732
)


The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at June 30, 2017, September 30, 2016 and June 30, 2016 were as follows:
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Carrying amount
$
755,000

 
$
675,000

 
$
650,000

Estimated fair value
$
788,472

 
$
770,781

 
$
747,588

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 June 30, 2017, September 30, 2016 and June 30, 2016:
 
 
June 30, 2017
 
September 30, 2016
 
June 30, 2016
Derivative assets:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 
$
1,163

 
$
4,472

 
$
5,718

Derivatives not subject to PGC and DS mechanisms:
 
 
 
 
 
 
Commodity contracts
 

 
38

 

Total derivative assets — gross
 
1,163

 
4,510

 
5,718

Gross amounts offset in the balance sheet
 
(159
)
 
(247
)
 
(225
)
Total derivative assets — net (a)
 
$
1,004

 
$
4,263

 
$
5,493

 
 
 
 
 
 
 
Derivative liabilities:
 
 
 
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
$
(1,204
)
 
$
(499
)
 
$
(593
)
Derivatives not subject to PGC and DS mechanisms:
 
 

 
 
 
 

Commodity contracts
 
(21
)
 
(58
)
 
(139
)
Total derivative liabilities — gross
 
(1,225
)
 
(557
)
 
(732
)
Gross amounts offset in the balance sheet
 
159

 
247

 
225

Total derivative liabilities — net (a)
 
$
(1,066
)
 
$
(310
)
 
$
(507
)


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 nine months ended June 30, 2017 and 2016:
 
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of Loss Reclassified from AOCI into Income
Three Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
 
$

 
$

 
$
(856
)
 
$
(610
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain (Loss) Recognized in Income
 
Location of Gain (Loss) Recognized in Income
 
 
 
 
Three Months Ended June 30,
 
2017
 
2016
 
 
 
 
 
 
 
 
Derivatives Not Subject to PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
 
$
(57
)
 
$
27

 
Operating and administrative expenses