UGI UTILITIES INC, 10-K filed on 22 Nov 16
Document and Entity Information (USD $)
12 Months Ended
Sep. 30, 2016
Nov. 15, 2016
Mar. 31, 2016
Document and Entity Information [Abstract]
 
 
 
Entity Registrant Name
UGI UTILITIES INC 
 
 
Entity Central Index Key
0000100548 
 
 
Document Type
10-K 
 
 
Document Period End Date
Sep. 30, 2016 
 
 
Amendment Flag
false 
 
 
Document Fiscal Year Focus
2016 
 
 
Document Fiscal Period Focus
FY 
 
 
Current Fiscal Year End Date
--09-30 
 
 
Entity Well-known Seasoned Issuer
No 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Filer Category
Non-accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
26,781,785 
 
Entity Public Float
 
 
$ 0 
Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Sep. 30, 2016
Sep. 30, 2015
Current assets:
 
 
Cash and cash equivalents
$ 2,819 
$ 3,099 
Restricted cash
583 
6,602 
Accounts receivable (less allowances for doubtful accounts of $3,946 and $5,599, respectively)
44,692 
55,659 
Accounts receivable — related parties
398 
1,271 
Accrued utility revenues
12,753 
12,051 
Inventories
42,340 
51,716 
Deferred income taxes
24,694 
Prepaid income taxes
1,956 
10,026 
Regulatory assets
3,208 
4,105 
Derivative instruments
4,263 
934 
Prepaid expenses
10,499 
9,701 
Other current assets
11,510 
14,202 
Total current assets
135,021 
194,060 
Property, plant and equipment
2,998,915 
2,753,499 
Less accumulated depreciation and amortization
(975,374)
(929,130)
Net property, plant and equipment
2,023,541 
1,824,369 
Goodwill
182,145 
182,145 
Regulatory assets
391,933 
300,103 
Other assets
10,451 
5,307 
Total assets
2,743,091 
2,505,984 
Current liabilities:
 
 
Current maturities of long-term debt
19,986 
246,893 
Short-term borrowings
112,500 
71,700 
Accounts payable — trade
65,180 
58,135 
Accounts payable — related parties
3,995 
4,430 
Employee compensation and benefits accrued
16,323 
14,286 
Interest accrued
7,605 
8,553 
Customer deposits and advances
41,391 
41,646 
Derivative instruments
310 
12,591 
Regulatory liability - deferred fuel and power refunds
22,299 
36,638 
Other current liabilities
44,321 
38,780 
Total current liabilities
333,910 
533,652 
Long-term debt
651,455 
372,913 
Deferred income taxes
550,229 
512,497 
Deferred investment tax credits
3,268 
3,597 
Pension and other postretirement benefit obligations
184,516 
135,003 
Other noncurrent liabilities
94,976 
57,702 
Total liabilities
1,818,354 
1,615,364 
Commitments and contingencies (Note 12)
   
   
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 
Additional paid-in capital
473,580 
471,904 
Retained earnings
422,516 
372,143 
Accumulated other comprehensive loss
(31,618)
(13,686)
Total common stockholder’s equity
924,737 
890,620 
Total liabilities and stockholder’s equity
$ 2,743,091 
$ 2,505,984 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Sep. 30, 2016
Sep. 30, 2015
Current assets:
 
 
Allowance for doubtful accounts
$ 3,946 
$ 5,599 
Common stockholder’s equity:
 
 
Common stock, par value (in usd per share)
$ 2.25 
$ 2.25 
Common stock, shares authorized (in shares)
40,000,000 
40,000,000 
Common stock, shares issued (in shares)
26,781,785 
26,781,785 
Common stock, shares outstanding (in shares)
26,781,785 
26,781,785 
Consolidated Statements of Income (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
Income Statement [Abstract]
 
 
 
Revenues
$ 768,484 
$ 1,041,581 
$ 1,086,889 
Costs and expenses:
 
 
 
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below)
289,786 
510,784 
562,942 
Operating and administrative expenses
180,842 
206,319 
195,408 
Operating and administrative expenses — related parties
11,863 
11,956 
10,671 
Taxes other than income taxes
15,789 
16,134 
16,608 
Depreciation
64,260 
59,841 
55,776 
Amortization
3,043 
3,749 
3,443 
Other expense (income), net
2,000 
(8,869)
(4,359)
Costs and expenses
567,583 
799,914 
840,489 
Operating income
200,901 
241,667 
246,400 
Interest expense
37,630 
41,128 
38,471 
Income before income taxes
163,271 
200,539 
207,929 
Income taxes
65,898 
79,484 
83,823 
Net income
$ 97,373 
$ 121,055 
$ 124,106 
Consolidated Statements of Comprehensive Income (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
 
 
 
Net income
$ 97,373 
$ 121,055 
$ 124,106 
Net losses on derivative instruments (net of tax of $12,016, $2,911 and $0, respectively)
(16,942)
(4,105)
Reclassifications of net losses on derivative instruments (net of tax of $(1,112), $(1,109) and $(1,112), respectively)
1,568 
1,565 
1,567 
Benefit plans, principally actuarial losses (net of tax of $2,267, $2,469 and $1,002, respectively)
(3,197)
(3,482)
(1,413)
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(454), $(367) and $(274), respectively)
639 
517 
385 
Other comprehensive (loss) income
(17,932)
(5,505)
539 
Comprehensive income
$ 79,441 
$ 115,550 
$ 124,645 
Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
 
 
 
Tax on (loss) gain on derivative instruments
$ 12,016 
$ 2,911 
$ 0 
Tax on reclassifications of net losses (gains) on derivative instruments
(1,112)
(1,109)
(1,112)
Tax on benefit plans
2,267 
2,469 
1,002 
Tax on reclassification of benefits plans actuarial losses and prior service cost
$ (454)
$ (367)
$ (274)
Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Sep. 30, 2016
Sep. 30, 2015
Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$ 97,373 
$ 121,055 
$ 124,106 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
67,303 
63,590 
59,219 
Deferred income taxes, net
76,938 
29,356 
33,588 
Pension contributions, net of pension expense
1,580 
(1,415)
(9,459)
Settlement of interest rate protection agreements
(35,975)
Provision for uncollectible accounts
7,760 
13,498 
13,149 
Other, net
(10,112)
3,228 
3,998 
Net change in:
 
 
 
Accounts receivable and accrued utility revenues
1,120 
7,297 
(19,718)
Inventories
9,376 
43,503 
(5,558)
Deferred fuel costs, net of changes in unsettled derivatives
(22,740)
51,778 
(17,632)
Accounts payable
(3,053)
(7,649)
5,757 
Other current assets
(70)
(9,723)
362 
Other current liabilities
15,870 
(7,808)
864 
Net cash provided by operating activities
205,370 
306,710 
188,676 
CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Expenditures for property, plant and equipment
(250,584)
(203,192)
(164,180)
Net costs of property, plant and equipment disposals
(7,940)
(10,443)
(8,214)
Decrease (increase) in restricted cash
6,019 
(3,010)
(411)
Net cash used by investing activities
(252,505)
(216,645)
(172,805)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Payment of dividends
(47,000)
(65,600)
(77,395)
Increase (decrease) in short-term borrowings
40,800 
(14,600)
68,800 
Issuances of long-term debt, net of issuance costs
298,379 
174,445 
Repayments of long-term debt
(247,000)
(20,000)
(175,000)
Excess tax benefits from equity-based payment arrangements
1,676 
833 
973 
Net cash provided (used) by financing activities
46,855 
(99,367)
(8,177)
Cash and cash equivalents (decrease) increase
(280)
(9,302)
7,694 
CASH AND CASH EQUIVALENTS:
 
 
 
End of year
2,819 
3,099 
12,401 
Beginning of year
3,099 
12,401 
4,707 
(Decrease) increase
(280)
(9,302)
7,694 
Cash paid (received) for:
 
 
 
Interest
36,155 
38,405 
34,781 
Income taxes
$ (19,758)
$ 54,427 
$ 54,293 
Consolidated Statements of Stockholder's Equity (USD $)
In Thousands, unless otherwise specified
Total
Common stock, without par value
Retained earnings
Additional paid-in capital
Accumulated other comprehensive income (loss)
Balance, beginning of year at Sep. 30, 2013
 
$ 60,259 
$ 269,977 
$ 470,098 
$ (8,720)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
Net income
124,106 
 
124,106 
 
 
Cash dividends — Common Stock
 
 
(77,395)
 
 
Excess tax benefits on equity-based compensation
 
 
 
973 
 
Net losses on derivative instruments
 
 
 
Reclassifications of net losses on derivative instruments
1,567 
 
 
 
1,567 
Benefit plans, principally actuarial losses
 
 
 
 
(1,413)
Reclassifications of benefit plans actuarial losses and net prior service credits
385 
 
 
 
385 
Balance, end of year at Sep. 30, 2014
839,837 
60,259 
316,688 
471,071 
(8,181)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
Net income
121,055 
 
121,055 
 
 
Cash dividends — Common Stock
 
 
(65,600)
 
 
Excess tax benefits on equity-based compensation
 
 
 
833 
 
Net losses on derivative instruments
(4,105)
 
 
 
(4,105)
Reclassifications of net losses on derivative instruments
1,565 
 
 
 
1,565 
Benefit plans, principally actuarial losses
 
 
 
 
(3,482)
Reclassifications of benefit plans actuarial losses and net prior service credits
517 
 
 
 
517 
Balance, end of year at Sep. 30, 2015
890,620 
60,259 
372,143 
471,904 
(13,686)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
Net income
97,373 
 
97,373 
 
 
Cash dividends — Common Stock
 
 
(47,000)
 
 
Excess tax benefits on equity-based compensation
 
 
 
1,676 
 
Net losses on derivative instruments
(16,942)
 
 
 
(16,942)
Reclassifications of net losses on derivative instruments
1,568 
 
 
 
1,568 
Benefit plans, principally actuarial losses
 
 
 
 
(3,197)
Reclassifications of benefit plans actuarial losses and net prior service credits
639 
 
 
 
639 
Balance, end of year at Sep. 30, 2016
$ 924,737 
$ 60,259 
$ 422,516 
$ 473,580 
$ (31,618)
Nature of Operations
Nature of Operations
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.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business which operated principally in the PNG service territory (“PNG HVAC Business”). The assets of the PNG HVAC Business principally comprising customer contracts were sold on June 1, 2015.
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
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
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.
Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation
Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or “the Company”). We eliminate intercompany accounts when we consolidate.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 4.
Fair Value Measurements
The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, also on a nonrecurring basis. Fair value measurements performed on a recurring basis principally relate to derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means.

Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.
Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments
Derivative instruments are reported in the 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 14.
Revenue Recognition
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.
We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.
Accounts Receivable
Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
Income Taxes
We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities’ plant additions over the service lives of the related property. Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is consistent with income taxes calculated on a separate return basis. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash
Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
Inventories
Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for substantially all of our inventory.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.
We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. The composite annual rate for depreciable property at our Gas Utility was 2.2% in Fiscal 2016, 2.2% in Fiscal 2015 and 2.3% in Fiscal 2014. The composite annual rate for depreciable property at our Electric Utility was 2.5% in Fiscal 2016, 2.5% in Fiscal 2015 and 2.5% in Fiscal 2014. When Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over 5 years, consistent with the recovery period approved by the PUC.
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill
Our goodwill is the result of Gas Utility business acquisitions. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below the operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2016, the Company changed the measurement date for performing its annual goodwill impairment test from September 30 to July 31. This voluntary change in accounting principle, applied prospectively, is preferable as it aligns the annual goodwill impairment test date more closely with the Company’s internal budgeting process and did not delay, accelerate or avoid an impairment of the Company’s goodwill. 
We are required to recognize an impairment charge under GAAP if the carrying amount of a reporting unit exceeds its fair value and the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill. From time to time, we may assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. From time to time, we may bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine the fair value of our Gas Utility generally based on a weighting of income and market approaches. For purposes of the income approach, fair value is determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for the reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting unit. The market approach requires judgment to determine the appropriate valuation multiple. Under certain circumstances, the Company may perform a qualitative approach to determine if it is more likely than not that the carrying value of a reporting unit is greater than its fair value. No provisions for goodwill impairments were recorded during Fiscal 2016, Fiscal 2015 or Fiscal 2014.
Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2016, Fiscal 2015 or Fiscal 2014.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 9).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options and grants of UGI stock-based equity instruments (“Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, equity-based compensation costs are measured based upon the fair value of the award on the date of grant or the fair value of the award as of the end of each reporting period. We expect to adopt new accounting guidance that simplifies and clarifies certain aspects of the accounting for and presentation of share-based payments during the first quarter of Fiscal 2017 (see Note 3).
For additional information on our equity-based compensation plans and related disclosures, see Note 11.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites.  This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 12.
Accounting Changes
Accounting Changes
ACCOUNTING CHANGES

Adoption of New Accounting Standard

Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. As required, we applied this guidance prospectively and, accordingly, balance sheets prior to Fiscal 2016 have not been reclassified.

Debt Issuance Costs. During the fourth quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of debt issuance costs. This new guidance amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. As required by the new guidance, prior period amounts have been reclassified. As of September 30, 2016 and 2015, the Company has reflected $3,559 and $2,194 of such costs as a reduction to long-term debt, including current maturities, on the Consolidated Balance Sheets.

Accounting Standards Not Yet Adopted

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

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

Employee Share-Based Payments. In March 2016, the FASB issued ASU No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the 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 share-based awards will be recognized as income tax benefit or expense in the income statement and the tax effects of exercised or vested awards will be treated as discrete items in the reporting period in which they occur. The Company expects to adopt the new guidance in the first quarter of Fiscal 2017. The amendment most likely to impact the Company, principally those requiring recognition of excess tax benefits and tax deficiencies in the income statement, will be applied prospectively. Based upon the number of share-based payment awards currently outstanding, we do not believe that the adoption of the new guidance will have a material impact on our net income.

Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements.
Regulatory Assets and Liabilities and Regulatory Matters
Regulatory Assets and Liabilities and Regulatory Matters
REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS
The following regulatory assets and liabilities associated with Utilities are included in our accompanying Consolidated Balance Sheets at September 30:
 
 
2016
 
2015
Regulatory assets:
 
 
 
 
Income taxes recoverable
 
$
115,643

 
$
115,946

Underfunded pension and postretirement plans
 
183,129

 
140,762

Environmental costs (a)
 
59,397

 
19,983

Removal costs, net
 
27,956

 
21,223

Other
 
9,016

 
6,294

Total regulatory assets
 
$
395,141

 
$
304,208

Regulatory liabilities (b):
 
 
 
 
Postretirement benefits overcollections
 
$
17,519

 
$
19,975

Deferred fuel and power refunds
 
22,299

 
36,638

State income tax benefits — distribution system repairs
 
15,086

 
13,266

Other
 
665

 
1,125

Total regulatory liabilities
 
$
55,569

 
$
71,004


(a)
Balance at September 30, 2016, includes amounts associated with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 12).
(b)
Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets.
Other than removal costs, UGI Utilities does not recover a rate of return on the regulatory assets included in the table above.
Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years.
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of net actuarial losses and prior service cost associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.
Environmental costs. Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at Manufactured Gas Plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection. Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2016, the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 12.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over 5 years.
Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, these overcollections will be refunded to customers over a ten-year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “UGI Gas Base Rate Filing” below). With respect to Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers.
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 September 30, 2016 and 2015, were $4,263 and $(3,262), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2016 and 2015, substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 14).

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 September 30, 2016 and 2015, were not material.
State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.
Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses. At September 30, 2016, UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years.
Other Regulatory Matters

Preliminary Stage Information Technology Costs. During the second quarter of Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the second quarter of Fiscal 2016, we capitalized $5,830 of such project costs ($5,375 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ($2,755) and regulatory assets ($3,075). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities.

UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58,600. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27,000 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27,000 base distribution rate increase. The increase became effective on October 19, 2016.

Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount 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 April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on either of these petitions. The Company cannot predict the timing or outcome of these petitions. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenue collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an administrative law judge. To commence recovery of revenue under the mechanism, UGI Gas must first place into service a threshold level of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is not likely to occur prior to September 30, 2017.
Inventories
Inventories
INVENTORIES
Inventories comprise the following at September 30:
 
2016
 
2015
Gas Utility natural gas
$
29,223

 
$
37,510

Materials, supplies and other
13,117

 
14,206

Total inventories
$
42,340

 
$
51,716


At September 30, 2016, UGI Utilities was a party to three principal storage contract administrative agreements (“SCAAs”) having terms of three years. One of the SCAAs was with Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 18), and two of the SCAAs were 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 value of gas storage inventories released under the SCAAs at September 30, 2016 and 2015, comprising 8.1 billion cubic feet (“bcf”) and 9.0 bcf of natural gas, were $18,773 and $22,694, respectively. At September 30, 2016 and 2015, UGI Utilities held a total of $19,100 and $17,700, respectively, of security deposits received from its SCAA counterparties. These amounts are included in other current liabilities on the Consolidated Balance Sheets.
For additional information related to the SCAAs with Energy Services, see Note 18.
Property, Plant and Equipment
Property, Plant and Equipment
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment comprise the following categories at September 30:
 
2016
 
2015
Distribution
$
2,634,191

 
$
2,458,080

Transmission
93,454

 
90,036

General and other, including construction in process
271,270

 
205,383

Total property, plant and equipment
$
2,998,915

 
$
2,753,499

Debt
Debt
DEBT
Long-term debt comprises the following at September 30:
 
2016
 
2015
Senior Notes:
 
 
 
4.12%, due September 2046
$
200,000

 
$

5.75%, due September 2016

 
175,000

4.98%, due March 2044
175,000

 
175,000

2.95%, due June 2026
100,000

 

6.21%, due September 2036
100,000

 
100,000

Medium-Term Notes:
 
 
 
7.37%, due October 2015

 
22,000

5.64%, due December 2015

 
50,000

6.17%, due June 2017
20,000

 
20,000

7.25%, due November 2017
20,000

 
20,000

5.67%, due January 2018
20,000

 
20,000

6.50%, due August 2033
20,000

 
20,000

6.13%, due October 2034
20,000

 
20,000

Total long-term debt
675,000

 
622,000

Less: unamortized debt issuance costs (a)
(3,559
)
 
(2,194
)
Less: current maturities
(19,986
)
 
(246,893
)
Total long-term debt due after one year
$
651,455

 
$
372,913


(a)
Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 3).
Principal payments on long-term debt during the next five fiscal years is as follows: $20,000 is due in Fiscal 2017; $40,000 is due in Fiscal 2018; $0 is due in Fiscal 2019; $0 is due in Fiscal 2020; and $0 is due in Fiscal 2021.
In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100,000 aggregate principal amount of 2.95% Senior Notes due June 2026 and $200,000 aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September 2016, respectively. In October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due in October 2046 pursuant to the 2016 Note Purchase Agreement. The net proceeds of the issuance of these senior notes were used 1) to repay UGI Utilities’ maturing 5.75% Senior Notes, 7.37% Medium-term notes and 5.64% Medium-term notes; 2) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and the information technology initiatives; and 3) for general corporate purposes. The Utilities Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.
UGI Utilities has an unsecured credit agreement (the “Credit Agreement”) with a group of banks providing for borrowings of up to $300,000 (including a $100,000 sublimit for letters of credit) which expires in March 2020. Under the Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities had borrowings outstanding under the credit agreements, which we classify as short-term borrowings on the Consolidated Balance Sheets, totaling $112,500 and $71,700 at September 30, 2016 and 2015, respectively. The weighted-average interest rates on the credit agreement borrowings at September 30, 2016 and 2015 were 1.42% and 1.07%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the credit agreements, totaled $2,009 and $2,000 at September 30, 2016 and 2015, respectively.

Restrictive Covenants. Certain of UGI Utilities Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. These Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

The UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.
Income Taxes
Income Taxes
INCOME TAXES
The provisions for income taxes consist of the following:
 
2016
 
2015
 
2014
Current expense (benefit):
 
 
 
 
 
Federal
$
(17,845
)
 
$
34,990

 
$
38,786

State
6,805

 
15,138

 
11,449

Total current (benefit) expense
(11,040
)
 
50,128

 
50,235

Deferred expense (benefit):
 
 
 
 
 
Federal
71,005

 
28,877

 
29,208

State
6,262

 
815

 
4,717

Investment tax credit amortization
(329
)
 
(336
)
 
(337
)
Total income tax expense
$
65,898

 
$
79,484

 
$
83,823


A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
 
2016
 
2015
 
2014
U.S. federal statutory tax rate
35.0
%
 
35.0
 %
 
35.0
%
Difference in tax rate due to:
 
 
 
 
 
State income taxes, net of federal
5.2

 
5.1

 
5.1

Other, net
0.2

 
(0.5
)
 
0.2

Effective tax rate
40.4
%
 
39.6
 %
 
40.3
%


Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2016, Fiscal 2015 and Fiscal 2014, the beneficial effects of state tax flow through of accelerated depreciation reduced tax expense by $1,344, $1,539 and $1,976, respectively.
Deferred tax liabilities (assets) comprise the following at September 30:
 
2016
 
2015
Excess book basis over tax basis of property, plant and equipment
$
491,038

 
$
431,480

Goodwill
45,070

 
40,552

Derivative financial instruments
948

 

Regulatory assets
149,660

 
117,420

Other
2,910

 
2,573

Gross deferred tax liabilities
689,626

 
592,025

Pension plan liabilities
(74,129
)
 
(54,444
)
Allowance for doubtful accounts
(1,637
)
 
(2,809
)
Deferred investment tax credits
(1,356
)
 
(1,493
)
Employee-related expenses
(5,247
)
 
(5,637
)
Regulatory liabilities
(16,798
)
 
(23,958
)
Environmental liabilities
(22,757
)
 
(6,014
)
Derivative financial instruments

 
(3,501
)
Other
(17,473
)
 
(6,367
)
Gross deferred tax assets
(139,397
)
 
(104,223
)
Net deferred tax liabilities
$
550,229

 
$
487,802


We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. UGI’s federal income tax returns are settled through the tax year 2012.
We file separate company income tax returns in various other states but are subject to state income tax principally in Pennsylvania. Pennsylvania income tax returns are generally subject to examination for a period of three years after the filing of the respective returns.
During Fiscal 2016, Fiscal 2015 and Fiscal 2014, interest expense of $204, $0 and $39, respectively, was recognized in income taxes in the Consolidated Statements of Income.
As of September 30, 2016, we have unrecognized income tax benefits totaling $2,055 including related accrued interest of $204. If these unrecognized tax benefits were subsequently recognized, $711 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
 
2016
 
2015
 
2014
Unrecognized tax benefits - beginning of year
$

 
$

 
$
1,087

Additions for tax positions of prior years
2,055

 

 

Additions for tax positions of the current year

 


 


Settlements with tax authorities

 

 
(1,087
)
Unrecognized tax benefits - end of year
$
2,055

 
$

 
$

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plan, the accumulated benefit obligations (“ABOs”) of the Other Postretirement Plans, plan assets and the funded status of the Pension Plan and Other Postretirement Plans as of September 30, 2016 and 2015. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect future compensation.
 
Pension
Benefits
 
Other Postretirement
Benefits
 
2016
 
2015
 
2016
 
2015
Change in benefit obligations:
 
 
 
 
 
 
 
Benefit obligations — beginning of year
$
563,621

 
$
539,725

 
$
10,676

 
$
11,136

Service cost
7,772

 
7,863

 
198

 
220

Interest cost
25,733

 
24,656

 
483

 
511

Actuarial loss (gain)
72,418

 
14,667

 
1,117

 
(835
)
Benefits paid
(24,100
)
 
(23,290
)
 
(399
)
 
(356
)
Benefit obligations — end of year
$
645,444

 
$
563,621

 
$
12,075

 
$
10,676

Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets — beginning of year
$
430,789

 
$
442,465

 
$
12,523

 
$
12,848

Actual gain (loss) on assets
46,874

 
483

 
1,347

 
(95
)
Employer contributions
9,869

 
11,131

 
98

 
126

Benefits paid
(24,100
)
 
(23,290
)
 
(253
)
 
(356
)
Fair value of plan assets — end of year
$
463,432

 
$
430,789

 
$
13,715

 
$
12,523

Funded status of the plans — end of year
$
(182,012
)
 
$
(132,832
)
 
$
1,640

 
$
1,847

Assets (liabilities) recorded in the balance sheet:
 
 
 
 
 
 
 
Assets in excess of liabilities — included in other noncurrent assets
$

 
$

 
$
4,139

 
$
4,011

Unfunded liabilities — included in other noncurrent liabilities
(182,012
)
 
(132,832
)
 
(2,499
)
 
(2,164
)
Net amount recognized
$
(182,012
)
 
$
(132,832
)
 
$
1,640

 
$
1,847

Amounts recorded in stockholder’s equity (pre-tax):
 
 
 
 
 
 
 
Prior service cost (credit)
$
138

 
$
178

 
$
(35
)
 
$
(48
)
Net actuarial loss (gain)
19,866

 
15,757

 
(1
)
 
(158
)
Total
$
20,004

 
$
15,935

 
$
(36
)
 
$
(206
)
Amounts recorded in regulatory assets and liabilities (pre-tax):
 
 
 
 
 
 
 
Prior service cost (credit)
$
1,262

 
$
1,570

 
$
(2,247
)
 
$
(2,890
)
Net actuarial loss
180,964

 
138,440

 
2,425

 
2,289

Total
$
182,226

 
$
140,010

 
$
178

 
$
(601
)

In Fiscal 2017, we estimate that we will amortize approximately $16,500 of net actuarial losses, primarily associated with Pension Plan, and $500 of prior service credits from stockholder’s equity and regulatory assets.
Actuarial assumptions are described below. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the Company’s postretirement plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets as further described below.
 
Pension Benefits
 
 
 
Other Postretirement Benefits
 
Weighted-average assumptions:
2016
 
2015
 
2014
 
 
 
2016
 
2015
 
2014
 
Discount rate - benefit obligations
3.80
%
 
4.60
%
 
4.60
%
 
 
 
3.80
%
 
4.70
%
 
4.60
%
 
Discount rate - benefit cost
4.60
%
 
4.60
%
 
5.20
%
 
 
 
4.70
%
 
4.60
%
 
5.10% - 5.40%

 
Expected return on plan assets
7.55
%
 
7.75
%
 
7.75
%
 
 
 
5.00
%
 
5.00
%
 
5.00
%
 
Rate of increase in salary levels
3.25
%
 
3.25
%
 
3.25
%
 
 
 
3.25
%
 
3.25
%
 
3.25
%
 
The ABOs for the Pension Plan were $601,255 and $523,704 as of September 30, 2016 and 2015, respectively. Included in the end of year Pension Plan PBOs above are $63,847 at September 30, 2016, and $57,595 at September 30, 2015, relating to employees of UGI and certain of its other subsidiaries. Included in the end of year Other Postretirement Plans ABOs above are $951 at September 30, 2016, and $863 at September 30, 2015, relating to employees of UGI and certain of its other subsidiaries.
Net periodic pension and other postretirement benefit costs relating to the Company’s employees include the following components:
 
Pension Benefits
 
Other Postretirement Benefits
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
Service cost
$
6,927

 
$
6,962

 
$
6,492

 
$
183

 
$
202

 
$
162

Interest cost
23,270

 
22,511

 
22,885

 
465

 
479

 
488

Expected return on assets
(28,668
)
 
(28,898
)
 
(26,599
)
 
(596
)
 
(612
)
 
(557
)
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
348

 
348

 
348

 
(641
)
 
(641
)
 
(641
)
Actuarial loss
9,571

 
8,793

 
6,642

 
98

 
122

 
116

Net benefit cost (income)
11,448

 
9,716

 
9,768

 
(491
)
 
(450
)
 
(432
)
Change in associated regulatory liabilities

 

 

 
971

 
3,740

 
3,704

Net benefit cost after change in regulatory liabilities
$
11,448

 
$
9,716

 
$
9,768

 
$
480

 
$
3,290

 
$
3,272


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 Fiscal 2016, Fiscal 2015 and Fiscal 2014, we made contributions to the Pension Plan of $9,869, $11,131 and $19,227, respectively. The minimum required contributions in Fiscal 2017 are not expected to be material.
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. The required contributions to the VEBA during Fiscal 2017, if any, are not expected to be material.
Expected payments for pension and other postretirement welfare benefits are as follows:
 
Pension
Benefits
 
Other
Postretirement
Benefits
Fiscal 2017
$
25,980

 
$
588

Fiscal 2018
27,254

 
577

Fiscal 2019
28,555

 
575

Fiscal 2020
29,902

 
561

Fiscal 2021
31,168

 
545

Fiscal 2021 - 2025
174,070

 
2,719


The assumed health care cost trend rates at September 30 are as follows:
 
2016
 
2015
Health care cost trend rate assumed for next year
7.25
%
 
7.5
%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
5.0
%
 
5.0
%
Fiscal year that the rate reaches the ultimate trend rate
2026

 
2026


A one percentage point change in these assumed health care cost trend rates would not have had a material impact on Fiscal 2016 other postretirement benefit cost or the September 30, 2016, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement income plans. At September 30, 2016 and 2015, the PBOs of these plans were $3,628 and $2,835, respectively. We recorded expense for these plans of $353 in Fiscal 2016, $445 in Fiscal 2015 and $372 in Fiscal 2014.
Pension Plan and VEBA Assets. The assets of the Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock.
The targets, target ranges and actual allocations for the Pension Plan and VEBA trust assets at September 30 are as follows:
 
 
 
 
 
 
Target
 
 
 
 
Actual
 
Asset
 
Permitted
Pension Plan:
 
2016
 
2015
 
Allocation
 
Range
Equity investments:
 
 
 
 
 
 
 
 
Domestic
 
54.1
%
 
56.2
%
 
52.5
%
 
40.0% - 65.0%
International
 
10.2
%
 
10.2
%
 
12.5
%
 
7.5% - 17.5%
Total
 
64.3
%
 
66.4
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
 
35.7
%
 
33.6
%
 
35.0
%
 
30.0% - 40.0%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
 
 
 
 
 
 
 
Target
 
 
 
 
Actual
 
Asset
 
Permitted
VEBA:
 
2016
 
2015
 
Allocation
 
Range
Domestic equity investments
 
69.9
%
 
67.4
%
 
65.0
%
 
60.0% - 70.0%
Fixed income funds & cash equivalents
 
30.1
%
 
32.6
%
 
35.0
%
 
30.0% - 40.0%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
 

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8% and 10.1% of Pension Plan assets at September 30, 2016 and 2015, respectively.
The fair values of the Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2, as of September 30, 2016 and 2015 are as follows:
 
Pension Plan
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2016:
 
 
 
 
 
 
 
Domestic equity investments:
 
 
 
 
 
 
 
S&P 500 Index equity mutual funds
$
158,906

 
$

 
$

 
$
158,906

Small and midcap equity mutual funds
43,170

 

 

 
43,170

Smallcap common stocks
11,414

 

 

 
11,414

   UGI Corporation Common Stock
37,013

 

 

 
37,013

     Total domestic equity investments
250,503

 

 

 
250,503

International index equity mutual funds
47,324

 

 

 
47,324

Fixed income investments:
 
 
 
 
 
 


   Bond index mutual funds
147,794

 

 

 
147,794

   Cash equivalents

 
17,811

 

 
17,811

      Total fixed income investments
147,794

 
17,811

 

 
165,605

Total
$
445,621

 
$
17,811

 
$

 
$
463,432

September 30, 2015:
 
 
 
 
 
 
 
Equity investments:
 
 
 
 
 
 
 
S&P 500 Index equity mutual funds
$
147,266

 
$

 
$

 
$
147,266

Small and midcap equity mutual funds
40,625

 

 

 
40,625

Smallcap common stocks
10,727

 

 

 
10,727

   UGI Corporation Common Stock
43,419

 

 

 
43,419

     Total domestic equity investments
242,037

 

 

 
242,037

International index equity mutual funds
43,906

 

 

 
43,906

Fixed income investments:
 
 
 
 
 
 
 
   Bond index mutual funds
140,776

 

 

 
140,776

   Cash equivalents

 
4,070

 

 
4,070

      Total fixed income investments
140,776

 
4,070

 

 
144,846

Total
$
426,719

 
$
4,070

 
$

 
$
430,789


 
VEBA
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2016:
 
 
 
 
 
 
 
S&P 500 Index equity mutual fund
$
9,583

 
$

 
$

 
$
9,583

Bond index mutual fund
4,019

 

 

 
4,019

Cash equivalents

 
113

 

 
113

Total
$
13,602

 
$
113

 
$

 
$
13,715

September 30, 2015:
 
 
 
 
 
 
 
S&P 500 Index equity mutual fund
$
8,434

 
$

 
$

 
$
8,434

Bond index mutual fund
3,832

 

 

 
3,832

Cash equivalents

 
257

 

 
257

Total
$
12,266

 
$
257

 
$

 
$
12,523


The expected long-term rates of return on Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.
Defined Contribution Plan. We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. The Utilities Savings Plan provides for employer matching contributions. Those employees hired after December 31, 2008, who are not eligible to participate in the Pension Plan, receive employer matching contributions at a higher rate. The cost of benefits under the Utilities Savings Plan totaled $2,409 in Fiscal 2016, $2,162 in Fiscal 2015 and $1,916 in Fiscal 2014. We also sponsor a nonqualified supplemental defined contribution executive retirement plan. This plan generally provides supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. Costs associated with this plan were not material in Fiscal 2016, Fiscal 2015 or Fiscal 2014.
Series Preferred Stock
Series Preferred Stock
SERIES PREFERRED STOCK
We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of Series Preferred Stock outstanding at September 30, 2016 or 2015.
Equity-Based Compensation
Equity-Based Compensation
EQUITY-BASED COMPENSATION

Under UGI Corporation’s 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”) and prior UGI equity compensation plans, certain key employees of UGI Utilities may be granted stock options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards. The exercise price for UGI stock options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP and the prior plans may vest immediately or ratably over a period of years (generally three-year periods), and stock options for UGI Common Stock can be exercised no later than ten years from the grant date. In addition, the 2013 OICP and the prior UGI equity compensation plans provide that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.
UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. With respect to Performance Units awards, the actual number of UGI shares actually issued (or their cash equivalent) at the end of the performance period and the actual amount of dividend equivalents paid, may range from 0% to 200% of the target award based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding telecommunication companies (“UGI comparator group”). Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of UGI Performance Unit awards. We recorded total net pre-tax equity-based compensation expense associated with both UGI Units and UGI stock options of $1,924 ($1,126 after-tax) during Fiscal 2016; $1,847 ($1,081 after-tax) during Fiscal 2015; and $1,912 ($1,119 after-tax) during Fiscal 2014.
As of September 30, 2016, there was $862 of unrecognized compensation cost related to non-vested UGI stock options that is expected to be recognized over a weighted-average period of 1.9 years. As of September 30, 2016, there was a total of $1,104 of unrecognized compensation expense associated with 57,783 UGI Unit awards that is expected to be recognized over a weighted average period of 1.8 years. At September 30, 2016 and 2015, total liabilities of $1,304 and $1,182, respectively, associated with UGI Unit awards are reflected in other current liabilities and other noncurrent liabilities on the Consolidated Balance Sheets.
The following table summarizes UGI Unit award activity for Fiscal 2016:
 
Total
 
Vested
 
Non-Vested
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
 
Number of
UGI
Units
 
Weighted
Average
Grant Date
Fair Value
(per Unit)
September 30, 2015
60,583

 
$
32.01

 
15,358

 
$
29.46

 
45,225

 
$
32.88

Granted
21,900

 
$
33.30

 
1,083

 
$
32.97

 
20,817

 
$
33.32

Vested

 
$

 
15,724

 
$
26.92

 
(15,724
)
 
$
26.92

Forfeitures & transfers
(2,851
)
 
$
36.53

 

 
$

 
(2,851
)
 
$
36.53

Unit awards paid
(21,849
)
 
$
25.51

 
(21,849
)
 
$
25.51

 

 
$

September 30, 2016
57,783

 
$
34.66

 
10,316

 
$
34.31

 
47,467

 
$
34.74

Commitments and Contingencies
Commitments and Contingencies
COMMITMENTS AND CONTINGENCIES
Commitments
We lease various buildings and vehicles, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $7,669 in Fiscal 2016, $7,956 in Fiscal 2015 and $6,803 in Fiscal 2014.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2017$5,984; 2018$5,016; 2019$3,048; 2020$1,314; 2021$560; after 2021$209.
Gas Utility has gas supply agreements with producers and marketers with terms not exceeding 16 months. Gas Utility also has agreements for firm pipeline transportation, natural gas storage and peaking service which Gas Utility may terminate at various dates through Fiscal 2030. Gas Utility’s costs associated with transportation and storage service agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices.
Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2017.
Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2016, for fiscal years ending September 30 are as follows: 2017$205,548; 2018$142,208; 2019$120,142; 2020$80,443; 2021$54,430; after 2021$134,978.
Contingencies
Environmental Matters
From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of 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) which have similar histories of owning, and in some cases operating, MGPs in Pennsylvania.

UGI Utilities and its subsidiaries have entered into agreements with the DEP to address the remediation of former MGPs in Pennsylvania. CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG 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 operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, required environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100, respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, 2016 and 2015, our accrued liabilities for estimated environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11,326 and $13,758, respectively. CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.
In May 2016, UGI Gas executed a Consent Order and Agreement (“UGI Gas-COA”) with the DEP with an effective date of October 1, 2016. The UGI Gas-COA will terminate in September 2031 if not extended by the parties. The UGI Gas-COA requires UGI Gas 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 operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties are capped at $2,500 in any calendar year. At September 30, 2016, our accrued liabilities for estimated environmental investigation and remediation costs related to the UGI Gas-COA totaled $43,737. UGI Gas has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (See Note 4).
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas, CPG and PNG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites.  This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 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.
There are pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.
Fair Value Measurements
Fair Value Measurements
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 described in Note 2, as of September 30, 2016 and 2015:
 
Asset (Liability)
 
Level 1
 
Level 2
 
Level 3
 
Total
September 30, 2016
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
4,506

 
$
4

 
$

 
$
4,510

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

 
$
(557
)
September 30, 2015
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity contracts
$
934

 
$
373

 
$

 
$
1,307

Liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
(4,560
)
 
$
(1,388
)
 
$

 
$
(5,948
)
Interest rate contracts
$

 
$
(7,016
)
 
$

 
$
(7,016
)

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. The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2016, were $675,000 and $770,781, respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at September 30, 2015, were $622,000 and $681,415, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2).
Derivative Instruments and Hedging Activities
Derivative Instruments and Hedging Activities
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We are exposed to certain market risks associated with 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. For more information on the accounting for our derivative instruments, see Note 2.
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 September 30, 2016 and 2015, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.4 million dekatherms and 18.9 million dekatherms, respectively. At September 30, 2016, 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 any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the 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 4).

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 September 30, 2016 and 2015, a majority of such contracts were subject to the NPNS exception under GAAP.

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 in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to customers through the DS mechanism (see Note 4). At September 30, 2016 and 2015, the total volumes associated with FTRs totaled 58.3 million kilowatt hours and 277.1 million kilowatt hours, respectively. At September 30, 2016, the maximum period over which we are economically hedging electricity congestion is 8 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 September 30, 2016 and 2015, the gasoline volumes 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. On March 31, 2016, concurrent with the pricing of the Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $35,975. Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs has been recorded in AOCI and will be recognized in interest expense as the associated future interest expense impacts earnings. See Note 7 for additional information on the 2016 Note Purchase Agreement. At September 30, 2016, we had no unsettled IRPAs. At September 30, 2015, the total notional amount of our debt associated with unsettled IRPA contracts was $250,000.

At September 30, 2016, the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,426.
Derivative Instrument Credit Risk
Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2016 and 2015, restricted cash in brokerage accounts totaled $583 and $6,602, respectively.
Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on our 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 our 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 September 30, 2016 and 2015:
 
2016
 
2015
Derivative assets:
 
 
 
Derivatives subject to PGC and DS mechanisms:
 
 
 
Commodity contracts
$
4,472

 
$
1,307

Derivatives not subject to PGC and DS mechanisms:
 
 
 
Commodity contracts
38

 

Total derivative assets - gross
4,510

 
1,307

Gross amounts offset in the balance sheet
(247
)
 
(373
)
Total derivative assets - net
$
4,263

 
$
934

 
 
 
 
Derivative liabilities:
 
 
 
Derivatives designated as hedging instruments:
 
 
 
Interest rate contracts
$

 
$
(7,016
)
Derivatives subject to PGC and DS mechanisms:
 
 
 
Commodity contracts
(499
)
 
(5,584
)
Derivatives not subject to PGC and DS mechanisms:
 
 
 
Commodity contracts
(58
)
 
(364
)
Total derivative liabilities - gross
(557
)
 
(12,964
)
Gross amounts offset in the balance sheet
247

 
373

Total derivative liabilities - net
$
(310
)
 
$
(12,591
)

Effect of Derivative Instruments
The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Consolidated Statements of Income and changes in AOCI for Fiscal 2016, Fiscal 2015 and Fiscal 2014:
 
Loss Recognized in AOCI
 
Loss Reclassified from AOCI into Income
 
Location of
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
 
Loss Reclassified from AOCI into Income
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest rate contracts
$
(28,958
)
 
$
(7,016
)
 
$

 
$
(2,680
)
 
$
(2,674
)
 
$
(2,679
)
 
Interest expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Recognized in Income
 
 
 
 
 
 
 
Location of Loss
 
2016
 
2015
 
2014
 
 
 
 
 
 
 
Recognized in Income
Derivatives Not Subject to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PGC and DS Mechanisms:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline contracts
$
(88
)
 
$
(761
)
 
$

 
 
 
 
 
 
 
Operating and administrative expenses/other operating income, net


The amounts of derivative gains and losses on cash flow hedges representing ineffectiveness were not material for all periods presented.

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.
Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income
ACCUMULATED OTHER COMPREHENSIVE INCOME
Other comprehensive income (loss) principally reflects losses on IRPAs qualifying as cash flow hedges and actuarial gains and losses on postretirement benefit plans, net of reclassifications to net income.
Changes in AOCI, net of tax, during Fiscal 2016, Fiscal 2015 and Fiscal 2014 are as follows:
 
Postretirement
Benefit Plans
 
Derivative
Instruments
Net Losses
 
Total
AOCI - September 30, 2013
$
(5,283
)
 
$
(3,437
)
 
$
(8,720
)
Reclassifications of benefit plans actuarial losses and net prior service credits
385

 

 
385

Reclassifications of net losses on IRPAs

 
1,567

 
1,567

Benefit plans, principally actuarial losses
(1,413
)
 

 
(1,413
)
AOCI - September 30, 2014
$
(6,311
)
 
$
(1,870
)
 
$
(8,181
)
Reclassifications of benefit plans actuarial losses and net prior service credits
517

 

 
517

Reclassifications of net losses on IRPAs

 
1,565

 
1,565

Net losses on IRPAs

 
(4,105
)
 
(4,105
)
Benefit plans, principally actuarial losses
(3,482
)