Document and Entity Information
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 | 100,548 | ||
Document Type | 10-K | ||
Document Period End Date | Sep. 30, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
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
Consolidated Balance Sheets - USD ($) $ in Thousands | 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 | 0 | 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 (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | 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 Inco
Consolidated Statements of Income - USD ($) $ in Thousands | 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 Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 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) | 0 |
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 Com6
Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 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
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 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) | 0 | 0 |
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 | 0 | 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 Stoc
Consolidated Statements of Stockholder's Equity - USD ($) $ in Thousands | 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 | 0 | 0 | |||
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 | 12 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
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 Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Accounting Changes and Error Corrections [Abstract] | |
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 Liabiliti
Regulatory Assets and Liabilities and Regulatory Matters | 12 Months Ended |
Sep. 30, 2016 | |
Regulated Operations [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Inventory Disclosure [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Property, Plant and Equipment [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Series Preferred Stock [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
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 | 12 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
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 Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
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
Accumulated Other Comprehensive Income | 12 Months Ended |
Sep. 30, 2016 | |
Equity [Abstract] | |
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 ) — (3,482 ) AOCI - September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Reclassifications of benefit plans actuarial losses and net prior service credits 639 — 639 Reclassifications of net losses on IRPAs — 1,568 1,568 Net losses on IRPAs — (16,942 ) (16,942 ) Benefit plans, principally actuarial losses (3,197 ) — (3,197 ) AOCI - September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of net losses on IRPAs are reflected in interest expense on the Consolidated Statements of Income. |
Segment Information
Segment Information | 12 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | SEGMENT INFORMATION We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The PNG HVAC Business, prior to its sale in June 2015, did not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other” below. The accounting policies of our reportable segments are the same as those described in Note 2 . We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes. No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States. Financial information by business segment follows: Total Gas Utility Electric Utility Other 2016 Revenues $ 768,484 $ 677,387 $ 91,097 Cost of sales $ 289,786 $ 239,163 $ 50,623 Depreciation and amortization $ 67,303 $ 62,451 $ 4,852 Operating income $ 200,901 $ 189,412 $ 11,489 Interest expense $ 37,630 $ 35,786 $ 1,844 Income before income taxes $ 163,271 $ 153,626 $ 9,645 Total assets $ 2,743,091 $ 2,570,297 $ 172,794 Goodwill $ 182,145 $ 182,145 $ — Capital expenditures $ 262,503 $ 251,261 $ 11,242 2015 Revenues $ 1,041,581 $ 933,080 $ 107,577 $ 924 Cost of sales $ 510,784 $ 448,617 $ 62,167 $ — Depreciation and amortization $ 63,590 $ 58,974 $ 4,616 $ — Operating income $ 241,667 $ 226,485 $ 14,153 $ 1,029 Interest expense $ 41,128 $ 39,112 $ 2,016 $ — Income before income taxes $ 200,539 $ 187,373 $ 12,137 $ 1,029 Total assets $ 2,505,984 $ 2,360,156 $ 145,828 $ — Goodwill $ 182,145 $ 182,145 $ — $ — Capital expenditures $ 197,684 $ 189,671 $ 8,013 $ — 2014 Revenues $ 1,086,889 $ 977,333 $ 108,072 $ 1,484 Cost of sales $ 562,942 $ 496,762 $ 66,180 $ — Depreciation and amortization $ 59,219 $ 54,816 $ 4,403 $ — Operating income $ 246,400 $ 236,219 $ 9,668 $ 513 Interest expense $ 38,471 $ 36,602 $ 1,869 $ — Income before income taxes $ 207,929 $ 199,617 $ 7,799 $ 513 Total assets $ 2,352,143 $ 2,211,618 $ 140,525 $ — Goodwill $ 182,145 $ 182,145 $ — $ — Capital expenditures $ 164,180 $ 156,425 $ 7,755 $ — |
Other Operating (Expense) Incom
Other Operating (Expense) Income, Net | 12 Months Ended |
Sep. 30, 2016 | |
Component of Operating Income [Abstract] | |
Other Operating (Expense) Income, Net | OTHER OPERATING (EXPENSE) INCOME, NET Other operating (expense) income, net, comprises the following: 2016 2015 2014 Non-tariff service income $ 2,633 $ 4,760 $ 2,670 Environmental matters (2,918 ) 1,152 297 Construction service income — 2,175 — Sale of HVAC Business — 1,065 — PGC interest on over (under) collection (1,740 ) (606 ) 1,388 Other, net 25 323 4 Total other operating (expense) income, net $ (2,000 ) $ 8,869 $ 4,359 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Sep. 30, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material. From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years . At September 30, 2016 , UGI Utilities was a party to one SCAA with Energy Services, and, during the periods covered by the financial statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , these payments were not material. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $12,739 , $16,849 and $38,299 in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in other current liabilities on the Consolidated Balance Sheets, were $8,100 and $10,700 at September 30, 2016 and 2015 , respectively. UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption inventories. The carrying values of these gas storage inventories at September 30, 2016 and 2015 , comprising approximately 4.6 bcf and 5.0 bcf of natural gas, were $11,148 and $12,889 , respectively. UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 totaled $63,331 , $47,794 and $35,810 , respectively. From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , revenues associated with sales to Energy Services totaled $30,743 , $79,182 and $109,913 , respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one -year agreements. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , such purchases totaled $35,067 , $85,383 and $128,076 , respectively. |
Quarterly Data (unaudited)
Quarterly Data (unaudited) | 12 Months Ended |
Sep. 30, 2016 | |
Quarterly Financial Data [Abstract] | |
Quarterly Data (unaudited) | QUARTERLY DATA (unaudited) The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses. December 31, March 31, June 30, September 30, 2015 2014 2016 2015 2016 2015 2016 2015 Revenues $ 197,982 $ 287,306 $ 322,047 $ 500,573 $ 140,283 $ 143,490 $ 108,172 $ 110,212 Operating income $ 48,296 $ 75,640 $ 114,481 $ 142,699 $ 29,815 $ 20,184 $ 8,309 $ 3,144 Net income (loss) $ 23,351 $ 38,839 $ 63,294 $ 79,589 $ 12,603 $ 7,307 $ (1,875 ) $ (4,680 ) |
Valuation and Qualifying Accoun
Valuation and Qualifying Accounts | 12 Months Ended |
Sep. 30, 2016 | |
Valuation and Qualifying Accounts [Abstract] | |
Valuation and Qualifying Accounts | SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (Thousands of dollars) Balance at beginning of year Charged to costs and expenses Other Balance at end of year September 30, 2016 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 5,599 $ 7,760 $ (9,413 ) (1) $ 3,946 September 30, 2015 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 6,992 $ 13,498 $ (14,891 ) (1) $ 5,599 September 30, 2014 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 5,519 $ 13,149 $ (11,676 ) (1) $ 6,992 (1) Uncollectible accounts written off, net of recoveries |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | 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 | 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 | 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 | 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 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 | 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 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 | 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 | 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 Restricted cash represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. |
Inventories | 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 | 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. |
Goodwill | 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. |
Impairment of Long-Lived Assets | 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. |
Employee Retirement Plans | 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 | 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 | 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 | 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 Liabili30
Regulatory Assets and Liabilities and Regulatory Matters (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility | 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. |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Inventory Disclosure [Abstract] | |
Schedule of 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 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule of 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 (Tables)
Debt (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Composition of Long Term 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 ). |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Provisions for 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 |
Reconciliation from US Federal Statutory Tax Rate to Effective Tax Rate | 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 % |
Deferred Tax Liabilities (Assets) | 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 |
Reconciliation of Unrecognized Tax Benefits | 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 (Tabl
Employee Retirement Plans (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Change in Pension Benefits and Other Postretirement Benefit Obligations, Plan Assets, and Funded Status | 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 ) |
Actuarial Assumptions for Domestic Plans | 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 % |
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs | 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 |
Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits | 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 |
Schedule of Effect of One-percentage-point Change in Assumed Health Care Cost Trend Rates | 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 |
Allocation of Pension Plan and VEBA Trust Assets | 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 % |
Fair Value of Pension Plan and VEBA Trust Assets | 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 |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
UGI Unit Award Activity | 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 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following table presents, on a gross basis, our derivative assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as 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 ) |
Derivative Instruments and He38
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Assets and Liabilities Including Offsetting Amounts | 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 ) |
Effects of Derivative Instruments on Consolidated Statements of Income and Changes in AOCI | 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 |
Accumulated Other Comprehensi39
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive 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 ) — (3,482 ) AOCI - September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Reclassifications of benefit plans actuarial losses and net prior service credits 639 — 639 Reclassifications of net losses on IRPAs — 1,568 1,568 Net losses on IRPAs — (16,942 ) (16,942 ) Benefit plans, principally actuarial losses (3,197 ) — (3,197 ) AOCI - September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Financial information by business segment follows: Total Gas Utility Electric Utility Other 2016 Revenues $ 768,484 $ 677,387 $ 91,097 Cost of sales $ 289,786 $ 239,163 $ 50,623 Depreciation and amortization $ 67,303 $ 62,451 $ 4,852 Operating income $ 200,901 $ 189,412 $ 11,489 Interest expense $ 37,630 $ 35,786 $ 1,844 Income before income taxes $ 163,271 $ 153,626 $ 9,645 Total assets $ 2,743,091 $ 2,570,297 $ 172,794 Goodwill $ 182,145 $ 182,145 $ — Capital expenditures $ 262,503 $ 251,261 $ 11,242 2015 Revenues $ 1,041,581 $ 933,080 $ 107,577 $ 924 Cost of sales $ 510,784 $ 448,617 $ 62,167 $ — Depreciation and amortization $ 63,590 $ 58,974 $ 4,616 $ — Operating income $ 241,667 $ 226,485 $ 14,153 $ 1,029 Interest expense $ 41,128 $ 39,112 $ 2,016 $ — Income before income taxes $ 200,539 $ 187,373 $ 12,137 $ 1,029 Total assets $ 2,505,984 $ 2,360,156 $ 145,828 $ — Goodwill $ 182,145 $ 182,145 $ — $ — Capital expenditures $ 197,684 $ 189,671 $ 8,013 $ — 2014 Revenues $ 1,086,889 $ 977,333 $ 108,072 $ 1,484 Cost of sales $ 562,942 $ 496,762 $ 66,180 $ — Depreciation and amortization $ 59,219 $ 54,816 $ 4,403 $ — Operating income $ 246,400 $ 236,219 $ 9,668 $ 513 Interest expense $ 38,471 $ 36,602 $ 1,869 $ — Income before income taxes $ 207,929 $ 199,617 $ 7,799 $ 513 Total assets $ 2,352,143 $ 2,211,618 $ 140,525 $ — Goodwill $ 182,145 $ 182,145 $ — $ — Capital expenditures $ 164,180 $ 156,425 $ 7,755 $ — |
Other Operating (Expense) Inc41
Other Operating (Expense) Income, Net (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Component of Operating Income [Abstract] | |
Schedule of Other Operating (Expense) Income, Net | Other operating (expense) income, net, comprises the following: 2016 2015 2014 Non-tariff service income $ 2,633 $ 4,760 $ 2,670 Environmental matters (2,918 ) 1,152 297 Construction service income — 2,175 — Sale of HVAC Business — 1,065 — PGC interest on over (under) collection (1,740 ) (606 ) 1,388 Other, net 25 323 4 Total other operating (expense) income, net $ (2,000 ) $ 8,869 $ 4,359 |
Quarterly Data (unaudited) (Tab
Quarterly Data (unaudited) (Tables) | 12 Months Ended |
Sep. 30, 2016 | |
Quarterly Financial Data [Abstract] | |
Schedule of Quarterly Financial Information | The following quarterly information includes all adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses. December 31, March 31, June 30, September 30, 2015 2014 2016 2015 2016 2015 2016 2015 Revenues $ 197,982 $ 287,306 $ 322,047 $ 500,573 $ 140,283 $ 143,490 $ 108,172 $ 110,212 Operating income $ 48,296 $ 75,640 $ 114,481 $ 142,699 $ 29,815 $ 20,184 $ 8,309 $ 3,144 Net income (loss) $ 23,351 $ 38,839 $ 63,294 $ 79,589 $ 12,603 $ 7,307 $ (1,875 ) $ (4,680 ) |
Nature of Operations Nature of
Nature of Operations Nature of Operations (Details) | 12 Months Ended |
Sep. 30, 2016county | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of counties | 1 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies (Details) - USD ($) | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Property, Plant and Equipment | |||
Goodwill impairments | $ 0 | $ 0 | $ 0 |
Impairment of long-lived assets | 0 | $ 0 | $ 0 |
Operating Expense | |||
Property, Plant and Equipment | |||
Depreciation expense | $ 0 | ||
Maximum | |||
Property, Plant and Equipment | |||
Maximum useful life of computer software | 15 years | ||
Gas Utility | |||
Property, Plant and Equipment | |||
Depreciation expense as percentage of related average depreciable base | 2.20% | 2.20% | 2.30% |
Electric Utility | |||
Property, Plant and Equipment | |||
Depreciation expense as percentage of related average depreciable base | 2.50% | 2.50% | 2.50% |
Removal Costs | |||
Property, Plant and Equipment | |||
Period to recover costs related to regulatory assets | 5 years |
Accounting Changes (Details)
Accounting Changes (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Debt issuance costs | [1] | $ 3,559 | $ 2,194 |
Long-term Debt, Including Current Maturities | Accounting Standards Update 2015-03 | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Debt issuance costs | $ 3,559 | $ 2,194 | |
[1] | Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 3). |
Regulatory Assets and Liabili46
Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 | |
Regulatory Assets and Liabilities | |||
Regulatory assets | $ 395,141 | $ 304,208 | |
Regulatory liabilities | [1] | 55,569 | 71,004 |
Postretirement Benefits Overcollections | |||
Regulatory Assets and Liabilities | |||
Regulatory liabilities | [1] | 17,519 | 19,975 |
Deferred Fuel and Power Refunds | |||
Regulatory Assets and Liabilities | |||
Regulatory liabilities | [1] | 22,299 | 36,638 |
State Income Tax Benefits — Distribution System Repairs | |||
Regulatory Assets and Liabilities | |||
Regulatory liabilities | [1] | 15,086 | 13,266 |
Other | |||
Regulatory Assets and Liabilities | |||
Regulatory liabilities | [1] | 665 | 1,125 |
Income Taxes Recoverable | |||
Regulatory Assets and Liabilities | |||
Regulatory assets | 115,643 | 115,946 | |
Underfunded Pension and Postretirement Plans | |||
Regulatory Assets and Liabilities | |||
Regulatory assets | 183,129 | 140,762 | |
Environmental Costs | |||
Regulatory Assets and Liabilities | |||
Regulatory assets | [2] | 59,397 | 19,983 |
Removal Costs, Net | |||
Regulatory Assets and Liabilities | |||
Regulatory assets | 27,956 | 21,223 | |
Other | |||
Regulatory Assets and Liabilities | |||
Regulatory assets | $ 9,016 | $ 6,294 | |
[1] | Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Consolidated Balance Sheets. | ||
[2] | )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 |
Regulatory Assets and Liabili47
Regulatory Assets and Liabilities and Regulatory Matters (Details) - USD ($) $ in Thousands | Oct. 19, 2016 | Oct. 14, 2016 | Jun. 30, 2016 | Apr. 01, 2016 | Jan. 19, 2016 | Apr. 01, 2015 | Mar. 31, 2016 | Mar. 31, 2016 | Sep. 30, 2016 | Sep. 30, 2014 | Sep. 30, 2015 |
Regulatory Assets | |||||||||||
Unrealized gains (losses) on derivative financial instruments contracts | $ 4,263 | $ (3,262) | |||||||||
Capitalized project costs | $ 5,830 | $ 5,830 | |||||||||
Project costs expensed in prior periods | 5,375 | ||||||||||
Pennsylvania Public Utility Commission | |||||||||||
Regulatory Assets | |||||||||||
Requested operating revenue increase | $ 58,600 | ||||||||||
Operating revenue increase | $ 27,000 | ||||||||||
Maximum period post petition to file general rate filing | 5 years | ||||||||||
Technology Equipment | |||||||||||
Regulatory Assets | |||||||||||
Associated increases to utility property, plant and equipment | 2,755 | 2,755 | |||||||||
Removal Costs | |||||||||||
Regulatory Assets | |||||||||||
Period to recover costs related to regulatory assets | 5 years | ||||||||||
Deferred Project Costs | |||||||||||
Regulatory Assets | |||||||||||
Associated increases to utility regulatory assets | $ 3,075 | $ 3,075 | |||||||||
Subsequent Event | Pennsylvania Public Utility Commission | |||||||||||
Regulatory Assets | |||||||||||
Approved operating revenue increase | $ 27,000 | ||||||||||
Minimum | |||||||||||
Regulatory Assets | |||||||||||
Average remaining depreciable lives of the associated property | 1 year | ||||||||||
Minimum | Other Regulatory Assets | |||||||||||
Regulatory Assets | |||||||||||
Period to recover costs related to regulatory assets | 1 year | ||||||||||
Maximum | |||||||||||
Regulatory Assets | |||||||||||
Average remaining depreciable lives of the associated property | 65 years | ||||||||||
Maximum | Pennsylvania Public Utility Commission | |||||||||||
Regulatory Assets | |||||||||||
Distribution system improvement charge, percent of amount billed to customers | 5.00% | 5.00% | 0.00% | ||||||||
Maximum | Pennsylvania Public Utility Commission | PNG | |||||||||||
Regulatory Assets | |||||||||||
Distribution system improvement charge, percent of amount billed to customers | 0.00% | 10.00% | |||||||||
Maximum | Pennsylvania Public Utility Commission | CPG | |||||||||||
Regulatory Assets | |||||||||||
Distribution system improvement charge, percent of amount billed to customers | 0.00% | 10.00% | |||||||||
Maximum | Other Regulatory Assets | |||||||||||
Regulatory Assets | |||||||||||
Period to recover costs related to regulatory assets | 20 years | ||||||||||
Maximum | Subsequent Event | Postretirement Benefits Overcollections | |||||||||||
Regulatory Assets | |||||||||||
Regulatory liability, period over which overcollections will be refunded to customers | 10 years |
Inventories - Schedule of Inven
Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Public Utilities, Inventory | ||
Total inventories | $ 42,340 | $ 51,716 |
Gas Utility Natural Gas | ||
Public Utilities, Inventory | ||
Total inventories | 29,223 | 37,510 |
Materials, Supplies and Other | ||
Public Utilities, Inventory | ||
Total inventories | $ 13,117 | $ 14,206 |
Inventories (Details)
Inventories (Details) $ in Thousands | 12 Months Ended | |
Sep. 30, 2016USD ($)agreementBcf | Sep. 30, 2015USD ($)Bcf | |
Public Utilities, Inventory | ||
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf | 8.1 | 9 |
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $ | $ 18,773 | $ 22,694 |
SCAAs | ||
Public Utilities, Inventory | ||
Number of storage agreements | 3 | |
SCAAs | Other Current Liabilities | ||
Public Utilities, Inventory | ||
Security deposit liability | $ | $ 19,100 | $ 17,700 |
SCAAs | UGI Energy Services, Inc | ||
Public Utilities, Inventory | ||
Number of Storage Agreements with Energy Services | 1 | |
SCAAs | Third Party | ||
Public Utilities, Inventory | ||
Number of Storage Agreements with Non-Affiliates | 2 | |
SCAAs | Maximum | UGI Energy Services, Inc | ||
Public Utilities, Inventory | ||
Storage agreement, term (in years) | 3 years |
Property, Plant and Equipment -
Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Property, Plant and Equipment | ||
Property, plant and equipment | $ 2,998,915 | $ 2,753,499 |
Distribution | ||
Property, Plant and Equipment | ||
Property, plant and equipment | 2,634,191 | 2,458,080 |
Transmission | ||
Property, Plant and Equipment | ||
Property, plant and equipment | 93,454 | 90,036 |
General and Other, Including Contruction in Process | ||
Property, Plant and Equipment | ||
Property, plant and equipment | $ 271,270 | $ 205,383 |
Debt - Composition of Long Term
Debt - Composition of Long Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Jun. 30, 2016 | Sep. 30, 2015 | |
Debt Instrument | ||||
Total long-term debt | $ 675,000 | $ 622,000 | ||
Less: unamortized debt issuance costs | [1] | (3,559) | (2,194) | |
Less: current maturities | (19,986) | (246,893) | ||
Total long-term debt due after one year | $ 651,455 | 372,913 | ||
Senior Notes | 4.12%, due September 2046 | ||||
Debt Instrument | ||||
Interest rate | 4.12% | |||
Total long-term debt | $ 200,000 | $ 0 | ||
Senior Notes | 5.75%, due September 2016 | ||||
Debt Instrument | ||||
Interest rate | 5.75% | |||
Total long-term debt | $ 0 | $ 175,000 | ||
Senior Notes | 4.98%, due March 2044 | ||||
Debt Instrument | ||||
Interest rate | 4.98% | 4.98% | ||
Total long-term debt | $ 175,000 | $ 175,000 | ||
Senior Notes | 2.95%, due June 2026 | ||||
Debt Instrument | ||||
Interest rate | 2.95% | 2.95% | ||
Total long-term debt | $ 100,000 | $ 0 | ||
Senior Notes | 6.21%, due September 2036 | ||||
Debt Instrument | ||||
Interest rate | 6.21% | 6.21% | ||
Total long-term debt | $ 100,000 | $ 100,000 | ||
Medium-Term Notes | 7.37%, due October 2015 | ||||
Debt Instrument | ||||
Interest rate | 7.37% | |||
Total long-term debt | 0 | $ 22,000 | ||
Medium-Term Notes | 5.64%, due December 2015 | ||||
Debt Instrument | ||||
Interest rate | 5.64% | |||
Total long-term debt | $ 0 | $ 50,000 | ||
Medium-Term Notes | 6.17%, due June 2017 | ||||
Debt Instrument | ||||
Interest rate | 6.17% | 6.17% | ||
Total long-term debt | $ 20,000 | $ 20,000 | ||
Medium-Term Notes | 7.25%, due November 2017 | ||||
Debt Instrument | ||||
Interest rate | 7.25% | 7.25% | ||
Total long-term debt | $ 20,000 | $ 20,000 | ||
Medium-Term Notes | 5.67%, due January 2018 | ||||
Debt Instrument | ||||
Interest rate | 5.67% | 5.67% | ||
Total long-term debt | $ 20,000 | $ 20,000 | ||
Medium-Term Notes | 6.50%, due August 2033 | ||||
Debt Instrument | ||||
Interest rate | 6.50% | 6.50% | ||
Total long-term debt | $ 20,000 | $ 20,000 | ||
Medium-Term Notes | 6.13%, due October 2034 | ||||
Debt Instrument | ||||
Interest rate | 6.13% | 6.13% | ||
Total long-term debt | $ 20,000 | $ 20,000 | ||
[1] | Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 3). |
Debt (Details)
Debt (Details) | 12 Months Ended | |||
Sep. 30, 2016USD ($) | Oct. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Sep. 30, 2015USD ($) | |
Debt Instrument | ||||
Due in Fiscal 2017 | $ 20,000,000 | |||
Due in Fiscal 2018 | 40,000,000 | |||
Due in Fiscal 2019 | 0 | |||
Due in Fiscal 2020 | 0 | |||
Due in Fiscal 2021 | 0 | |||
Short-term borrowings | $ 112,500,000 | $ 71,700,000 | ||
Senior Notes | ||||
Debt Instrument | ||||
Debt to capital ratio | 0.65 | |||
2.95% Senior Notes, due June 2026 | Senior Notes | ||||
Debt Instrument | ||||
Face amount | $ 100,000,000 | |||
Interest rate | 2.95% | 2.95% | ||
4.12% Senior Notes, due September 2046 | Senior Notes | ||||
Debt Instrument | ||||
Face amount | $ 200,000,000 | |||
Interest rate | 4.12% | |||
4.12% Senior Notes, due October 2046 | Senior Notes | Subsequent Event | ||||
Debt Instrument | ||||
Face amount | $ 100,000,000 | |||
Interest rate | 4.12% | |||
UGI Utilities 2015 Credit Agreement | ||||
Debt Instrument | ||||
Short-term borrowings | $ 112,500,000 | $ 71,700,000 | ||
Weighted average interest rate at period end | 1.42% | 1.07% | ||
UGI Utilities 2015 Credit Agreement | Line of Credit | ||||
Debt Instrument | ||||
Credit agreement | $ 300,000,000 | |||
Issued and outstanding letters of credit | 2,009,000 | $ 2,000,000 | ||
UGI Utilities 2015 Credit Agreement | Letter of Credit | ||||
Debt Instrument | ||||
Credit agreement | $ 100,000,000 | |||
UGI Utilities 2015 Credit Agreement | Minimum | Line of Credit | ||||
Debt Instrument | ||||
Margin on term loan base rate borrowings | 0.00% | |||
UGI Utilities 2015 Credit Agreement | Maximum | Line of Credit | ||||
Debt Instrument | ||||
Margin on term loan base rate borrowings | 1.75% | |||
5.75%, due September 2016 | Senior Notes | ||||
Debt Instrument | ||||
Interest rate | 5.75% | |||
7.37%, due October 2015 | Medium-Term Notes | ||||
Debt Instrument | ||||
Interest rate | 7.37% | |||
5.64%, due December 2015 | Medium-Term Notes | ||||
Debt Instrument | ||||
Interest rate | 5.64% |
Income Taxes - Provisions for I
Income Taxes - Provisions for Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 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 |
Income Taxes - Reconciliation f
Income Taxes - Reconciliation from US Federal Statutory Tax Rate to Effective Tax Rate (Details) | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Income Tax Disclosure [Abstract] | |||
U.S. federal statutory tax rate | 35.00% | 35.00% | 35.00% |
Difference in tax rate due to: | |||
State income taxes, net of federal | 5.20% | 5.10% | 5.10% |
Other, net | 0.20% | (0.50%) | 0.20% |
Effective tax rate | 40.40% | 39.60% | 40.30% |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2013 | |
Income Taxes | ||||
Interest expense | $ 204 | $ 0 | $ 39 | |
Unrecognized tax benefits | 2,055 | 0 | 0 | $ 1,087 |
Accrued interest | 204 | |||
Unrecognized tax benefits if recognized would impact the reported effective tax rate | 711 | |||
State and Local Jurisdiction | ||||
Income Taxes | ||||
Decrease in income tax expense due to state tax flow through of accelerated depreciation | $ 1,344 | $ 1,539 | $ 1,976 |
Income Taxes - Deferred Tax Lia
Income Taxes - Deferred Tax Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Income Tax Disclosure [Abstract] | ||
Excess book basis over tax basis of property, plant and equipment | $ 491,038 | $ 431,480 |
Goodwill | 45,070 | 40,552 |
Derivative financial instruments | 948 | 0 |
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 | 0 | (3,501) |
Other | (17,473) | (6,367) |
Gross deferred tax assets | (139,397) | (104,223) |
Net deferred tax liabilities | $ 550,229 | $ 487,802 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Reconciliation of Unrecognized Tax Benefits | |||
Unrecognized tax benefits - beginning of year | $ 0 | $ 0 | $ 1,087 |
Additions for tax positions of prior years | 2,055 | 0 | 0 |
Additions for tax positions of the current year | |||
Settlements with tax authorities | 0 | 0 | (1,087) |
Unrecognized tax benefits - end of year | $ 2,055 | $ 0 | $ 0 |
Employee Retirement Plans - Cha
Employee Retirement Plans - Change in Pension Benefits and Other Postretirement Benefit Obligations, Plan Assets, and Funded Status (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Assets (liabilities) recorded in the balance sheet: | |||
Unfunded liabilities — included in other noncurrent liabilities | $ (184,516) | $ (135,003) | |
Pension Benefits | |||
Change in benefit obligations: | |||
Benefit obligations — beginning of year | 563,621 | 539,725 | |
Service cost | 7,772 | 7,863 | |
Interest cost | 25,733 | 24,656 | |
Actuarial loss (gain) | 72,418 | 14,667 | |
Benefits paid | (24,100) | (23,290) | |
Benefit obligations — end of year | 645,444 | 563,621 | $ 539,725 |
Change in plan assets: | |||
Fair value of plan assets — beginning of year | 430,789 | 442,465 | |
Actual gain (loss) on assets | 46,874 | 483 | |
Employer contributions | 9,869 | 11,131 | 19,227 |
Benefits paid | (24,100) | (23,290) | |
Fair value of plan assets — end of year | 463,432 | 430,789 | 442,465 |
Funded status of the plans — end of year | (182,012) | (132,832) | |
Assets (liabilities) recorded in the balance sheet: | |||
Assets in excess of liabilities — included in other noncurrent assets | 0 | 0 | |
Unfunded liabilities — included in other noncurrent liabilities | (182,012) | (132,832) | |
Net amount recognized | (182,012) | (132,832) | |
Amounts recorded in stockholder’s equity (pre-tax): | |||
Prior service cost (credit) | 138 | 178 | |
Net actuarial loss (gain) | 19,866 | 15,757 | |
Total | 20,004 | 15,935 | |
Amounts recorded in regulatory assets and liabilities (pre-tax): | |||
Prior service cost (credit) | 1,262 | 1,570 | |
Net actuarial loss | 180,964 | 138,440 | |
Total | 182,226 | 140,010 | |
Other Postretirement Benefits | |||
Change in benefit obligations: | |||
Benefit obligations — beginning of year | 10,676 | 11,136 | |
Service cost | 198 | 220 | |
Interest cost | 483 | 511 | |
Actuarial loss (gain) | 1,117 | (835) | |
Benefits paid | (399) | (356) | |
Benefit obligations — end of year | 12,075 | 10,676 | 11,136 |
Change in plan assets: | |||
Fair value of plan assets — beginning of year | 12,523 | 12,848 | |
Actual gain (loss) on assets | 1,347 | (95) | |
Employer contributions | 98 | 126 | |
Benefits paid | (253) | (356) | |
Fair value of plan assets — end of year | 13,715 | 12,523 | $ 12,848 |
Funded status of the plans — end of year | 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 | (2,499) | (2,164) | |
Net amount recognized | 1,640 | 1,847 | |
Amounts recorded in stockholder’s equity (pre-tax): | |||
Prior service cost (credit) | (35) | (48) | |
Net actuarial loss (gain) | (1) | (158) | |
Total | (36) | (206) | |
Amounts recorded in regulatory assets and liabilities (pre-tax): | |||
Prior service cost (credit) | (2,247) | (2,890) | |
Net actuarial loss | 2,425 | 2,289 | |
Total | $ 178 | $ (601) |
Employee Retirement Plans (Deta
Employee Retirement Plans (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Defined Benefit Plan Disclosure | |||
Estimated amortization of net actuarial losses for Fiscal 2017 | $ 16,500 | ||
Amortization of net prior service costs (credits) | $ (500) | ||
Percentage point change in assumed health care cost trend rates | 1.00% | ||
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans | $ 3,628 | $ 2,835 | |
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans | $ 353 | $ 445 | $ 372 |
The aggregate holdings of all qualifying employer securities not to exceed the fair value of trust assets at the time of purchase | 10.00% | ||
Percentage of UGI Common Stock represented Pension Plan Assets | 8.00% | 10.10% | |
Cost of benefits under Utilities Savings Plan | $ 2,409 | $ 2,162 | 1,916 |
Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
ABO for the Pension Plans | 601,255 | 523,704 | |
Benefit obligations | 645,444 | 563,621 | 539,725 |
Employer contributions | 9,869 | 11,131 | 19,227 |
Pension Benefits | Employees of UGI and Certain of its Other Subsidiaries | |||
Defined Benefit Plan Disclosure | |||
Benefit obligations | 63,847 | 57,595 | |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure | |||
Benefit obligations | 12,075 | 10,676 | $ 11,136 |
Employer contributions | 98 | 126 | |
Other Postretirement Benefits | Employees of UGI and Certain of its Other Subsidiaries | |||
Defined Benefit Plan Disclosure | |||
ABO for the Pension Plans | $ 951 | $ 863 |
Employee Retirement Plans - Act
Employee Retirement Plans - Actuarial Assumptions for Domestic Plans (Details) | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension Benefits | |||
Weighted-average assumptions: | |||
Discount rate - benefit obligations | 3.80% | 4.60% | 4.60% |
Discount rate - benefit cost | 4.60% | 4.60% | 5.20% |
Expected return on plan assets | 7.55% | 7.75% | 7.75% |
Rate of increase in salary levels | 3.25% | 3.25% | 3.25% |
Other Postretirement Benefits | |||
Weighted-average assumptions: | |||
Discount rate - benefit obligations | 3.80% | 4.70% | 4.60% |
Discount rate - benefit cost | 4.70% | 4.60% | |
Expected return on plan assets | 5.00% | 5.00% | 5.00% |
Rate of increase in salary levels | 3.25% | 3.25% | 3.25% |
Minimum | Other Postretirement Benefits | |||
Weighted-average assumptions: | |||
Discount rate - benefit cost | 5.10% | ||
Maximum | Other Postretirement Benefits | |||
Weighted-average assumptions: | |||
Discount rate - benefit cost | 5.40% |
Employee Retirement Plans - Com
Employee Retirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
Service cost | $ 7,772 | $ 7,863 | |
Interest cost | 25,733 | 24,656 | |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure | |||
Service cost | 198 | 220 | |
Interest cost | 483 | 511 | |
UGI Utilities Employees | Pension Benefits | |||
Defined Benefit Plan Disclosure | |||
Service cost | 6,927 | 6,962 | $ 6,492 |
Interest cost | 23,270 | 22,511 | 22,885 |
Expected return on assets | (28,668) | (28,898) | (26,599) |
Amortization of: | |||
Prior service cost (benefit) | 348 | 348 | 348 |
Actuarial loss | 9,571 | 8,793 | 6,642 |
Net benefit cost (income) | 11,448 | 9,716 | 9,768 |
Change in associated regulatory liabilities | 0 | 0 | 0 |
Net benefit cost after change in regulatory liabilities | 11,448 | 9,716 | 9,768 |
UGI Utilities Employees | Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure | |||
Service cost | 183 | 202 | 162 |
Interest cost | 465 | 479 | 488 |
Expected return on assets | (596) | (612) | (557) |
Amortization of: | |||
Prior service cost (benefit) | (641) | (641) | (641) |
Actuarial loss | 98 | 122 | 116 |
Net benefit cost (income) | (491) | (450) | (432) |
Change in associated regulatory liabilities | 971 | 3,740 | 3,704 |
Net benefit cost after change in regulatory liabilities | $ 480 | $ 3,290 | $ 3,272 |
Employee Retirement Plans - Exp
Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) $ in Thousands | Sep. 30, 2016USD ($) |
Pension Benefits | |
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract] | |
Fiscal 2,017 | $ 25,980 |
Fiscal 2,018 | 27,254 |
Fiscal 2,019 | 28,555 |
Fiscal 2,020 | 29,902 |
Fiscal 2,021 | 31,168 |
Fiscal 2021 - 2025 | 174,070 |
Other Postretirement Benefits | |
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract] | |
Fiscal 2,017 | 588 |
Fiscal 2,018 | 577 |
Fiscal 2,019 | 575 |
Fiscal 2,020 | 561 |
Fiscal 2,021 | 545 |
Fiscal 2021 - 2025 | $ 2,719 |
Employee Retirement Plans - Sch
Employee Retirement Plans - Schedule of Effect of One-percentage-point Change in Assumed Health Care Cost Trend Rates (Details) | 12 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | ||
Health care cost trend rate assumed for next year | 7.25% | 7.50% |
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | 5.00% | 5.00% |
Fiscal year that the rate reaches the ultimate trend rate | 2,026 | 2,026 |
Employee Retirement Plans - All
Employee Retirement Plans - Allocation of Pension Plan and VEBA Trust Assets (Details) | 12 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Pension Benefits | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 100.00% | 100.00% |
Target asset allocation | 100.00% | |
Pension Benefits | Equity Investments | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 64.30% | 66.40% |
Target asset allocation | 65.00% | |
Permitted range - minimum | 60.00% | |
Permitted range - maximum | 70.00% | |
Pension Benefits | Domestic | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 54.10% | 56.20% |
Target asset allocation | 52.50% | |
Permitted range - minimum | 40.00% | |
Permitted range - maximum | 65.00% | |
Pension Benefits | International | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 10.20% | 10.20% |
Target asset allocation | 12.50% | |
Permitted range - minimum | 7.50% | |
Permitted range - maximum | 17.50% | |
Pension Benefits | Fixed Income Funds and Cash Equivalents | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 35.70% | 33.60% |
Target asset allocation | 35.00% | |
Permitted range - minimum | 30.00% | |
Permitted range - maximum | 40.00% | |
VEBA Trust | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 100.00% | 100.00% |
Target asset allocation | 100.00% | |
VEBA Trust | Domestic | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 69.90% | 67.40% |
Target asset allocation | 65.00% | |
Permitted range - minimum | 60.00% | |
Permitted range - maximum | 70.00% | |
VEBA Trust | Fixed Income Funds and Cash Equivalents | ||
Defined Benefit Plan Disclosure | ||
Actual pension plan | 30.10% | 32.60% |
Target asset allocation | 35.00% | |
Permitted range - minimum | 30.00% | |
Permitted range - maximum | 40.00% |
Employee Retirement Plans - Fai
Employee Retirement Plans - Fair Value of Pension Plan and VEBA Trust Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 |
Pension Benefits | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | $ 463,432 | $ 430,789 | $ 442,465 |
Pension Benefits | Domestic Equity Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 250,503 | 242,037 | |
Pension Benefits | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 158,906 | 147,266 | |
Pension Benefits | Small and Midcap Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 43,170 | 40,625 | |
Pension Benefits | Smallcap Common Stocks | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 11,414 | 10,727 | |
Pension Benefits | UGI Corporation Common Stock | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 37,013 | 43,419 | |
Pension Benefits | International Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 47,324 | 43,906 | |
Pension Benefits | Fixed Income Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 165,605 | 144,846 | |
Pension Benefits | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 147,794 | 140,776 | |
Pension Benefits | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 17,811 | 4,070 | |
Pension Benefits | Level 1 | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 445,621 | 426,719 | |
Pension Benefits | Level 1 | Domestic Equity Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 250,503 | 242,037 | |
Pension Benefits | Level 1 | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 158,906 | 147,266 | |
Pension Benefits | Level 1 | Small and Midcap Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 43,170 | 40,625 | |
Pension Benefits | Level 1 | Smallcap Common Stocks | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 11,414 | 10,727 | |
Pension Benefits | Level 1 | UGI Corporation Common Stock | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 37,013 | 43,419 | |
Pension Benefits | Level 1 | International Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 47,324 | 43,906 | |
Pension Benefits | Level 1 | Fixed Income Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 147,794 | 140,776 | |
Pension Benefits | Level 1 | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 147,794 | 140,776 | |
Pension Benefits | Level 1 | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 17,811 | 4,070 | |
Pension Benefits | Level 2 | Domestic Equity Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | Small and Midcap Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | Smallcap Common Stocks | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | UGI Corporation Common Stock | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | International Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | Fixed Income Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 17,811 | 4,070 | |
Pension Benefits | Level 2 | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 2 | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 17,811 | 4,070 | |
Pension Benefits | Level 3 | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | Domestic Equity Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | Small and Midcap Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | Smallcap Common Stocks | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | UGI Corporation Common Stock | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | International Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | Fixed Income Investments | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Benefits | Level 3 | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 13,715 | 12,523 | |
VEBA Trust | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 9,583 | 8,434 | |
VEBA Trust | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 4,019 | 3,832 | |
VEBA Trust | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 113 | 257 | |
VEBA Trust | Level 1 | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 13,602 | 12,266 | |
VEBA Trust | Level 1 | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 9,583 | 8,434 | |
VEBA Trust | Level 1 | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 4,019 | 3,832 | |
VEBA Trust | Level 1 | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | Level 2 | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 113 | 257 | |
VEBA Trust | Level 2 | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | Level 2 | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | Level 2 | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 113 | 257 | |
VEBA Trust | Level 3 | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | Level 3 | S&P 500 Index Equity Mutual Funds | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | Level 3 | Bond Index Mutual Fund | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | 0 | 0 | |
VEBA Trust | Level 3 | Cash Equivalents | |||
Fair Value of Pension Plan Assets | |||
Fair Value of Plan Assets | $ 0 | $ 0 |
Series Preferred Stock (Details
Series Preferred Stock (Details) - shares | Sep. 30, 2016 | Sep. 30, 2015 |
Series Preferred Stock [Abstract] | ||
Preferred stock, authorized (in shares) | 2,000,000 | |
Preferred stock, shares outstanding (in shares) | 0 | 0 |
Equity-Based Compensation (Deta
Equity-Based Compensation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award | |||
Number of equity-based units for unrecognized compensation expense (in units) | 57,783 | 60,583 | |
Share Based Compensation Types, Excluding Stock Options | UGI Omnibus Equity Compensation Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Award vesting period (in years) | 3 years | ||
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Exercise period after grant date - no more than (in years) | 10 years | ||
Performance Unit | UGI Units and UGI Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Allocated share-based compensation expense | $ 1,924 | $ 1,847 | $ 1,912 |
Allocated share-based compensation expense, after-tax | $ 1,126 | 1,081 | $ 1,119 |
Performance Unit | UGI Units and UGI Stock Options | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Percent of target award paid to grantee | 0.00% | ||
Performance Unit | UGI Units and UGI Stock Options | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Percent of target award paid to grantee | 200.00% | ||
Performance Unit | UGI Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Nonvested awards, total compensation cost not yet recognized | $ 862 | ||
Nonvested awards, total compensation cost not yet recognized, period for recognition | 1 year 11 months | ||
Performance Unit | UGI Units | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Nonvested awards, total compensation cost not yet recognized | $ 1,104 | ||
Nonvested awards, total compensation cost not yet recognized, period for recognition | 1 year 9 months 1 day | ||
Number of equity-based units for unrecognized compensation expense (in units) | 57,783 | ||
Performance Unit | UGI Units | Other Current Liabilities | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Deferred compensation arrangements, liability, current | $ 1,304 | ||
Performance Unit | UGI Units | Other Noncurrent Liabilities | |||
Share-based Compensation Arrangement by Share-based Payment Award | |||
Deferred compensation arrangements, liability, noncurrent | $ 1,182 |
Equity-Based Compensation - UGI
Equity-Based Compensation - UGI Unit Award Activity (Details) | 12 Months Ended |
Sep. 30, 2016$ / sharesshares | |
Number of UGI Units | |
Beginning balance (in units) | shares | 60,583 |
Granted (in units) | shares | 21,900 |
Vested (in units) | shares | 0 |
Forfeitures & transfers (in units) | shares | (2,851) |
Unit awards paid (in units) | shares | (21,849) |
Ending balance (in units) | shares | 57,783 |
Weighted Average Grant Date Fair Value (per Unit) | |
Beginning balance (in usd per share) | $ / shares | $ 32.01 |
Granted (in usd per share) | $ / shares | 33.30 |
Vested (in usd per share) | $ / shares | 0 |
Forfeitures & transfers (in usd per share) | $ / shares | 36.53 |
Unit awards paid (in usd per share) | $ / shares | 25.51 |
Ending balance (in usd per share) | $ / shares | $ 34.66 |
Vested | |
Number of UGI Units | |
Beginning balance (in units) | shares | 15,358 |
Granted (in units) | shares | 1,083 |
Vested (in units) | shares | 15,724 |
Forfeitures & transfers (in units) | shares | 0 |
Unit awards paid (in units) | shares | (21,849) |
Ending balance (in units) | shares | 10,316 |
Weighted Average Grant Date Fair Value (per Unit) | |
Beginning balance (in usd per share) | $ / shares | $ 29.46 |
Granted (in usd per share) | $ / shares | 32.97 |
Vested (in usd per share) | $ / shares | 26.92 |
Forfeitures & transfers (in usd per share) | $ / shares | 0 |
Unit awards paid (in usd per share) | $ / shares | 25.51 |
Ending balance (in usd per share) | $ / shares | $ 34.31 |
Non-Vested | |
Number of UGI Units | |
Beginning balance (in units) | shares | 45,225 |
Granted (in units) | shares | 20,817 |
Vested (in units) | shares | 15,724 |
Forfeitures & transfers (in units) | shares | (2,851) |
Unit awards paid (in units) | shares | 0 |
Ending balance (in units) | shares | 47,467 |
Weighted Average Grant Date Fair Value (per Unit) | |
Beginning balance (in usd per share) | $ / shares | $ 32.88 |
Granted (in usd per share) | $ / shares | 33.32 |
Vested (in usd per share) | $ / shares | 26.92 |
Forfeitures & transfers (in usd per share) | $ / shares | 36.53 |
Unit awards paid (in usd per share) | $ / shares | 0 |
Ending balance (in usd per share) | $ / shares | $ 34.74 |
Commitments and Contingencies (
Commitments and Contingencies (Details) | 12 Months Ended | ||
Sep. 30, 2016USD ($)subsidiary | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | |
Contingencies | |||
Rental expense | $ 7,669,000 | $ 7,956,000 | $ 6,803,000 |
Minimum future payments under operating leases | |||
2,017 | 5,984,000 | ||
2,018 | 5,016,000 | ||
2,019 | 3,048,000 | ||
2,020 | 1,314,000 | ||
2,021 | 560,000 | ||
After 2,021 | 209,000 | ||
Contractual obligations under suplly, storage and service agreements | |||
2,017 | 205,548,000 | ||
2,018 | 142,208,000 | ||
2,019 | 120,142,000 | ||
2,020 | 80,443,000 | ||
2,021 | 54,430,000 | ||
After 2,021 | $ 134,978,000 | ||
PNG and CPG | |||
Contingencies | |||
Number of subsidiaries acquired with similar histories | subsidiary | 2 | ||
UGI Gas-COA | |||
Contingencies | |||
Accrued liabilities for environmental investigation and remediation costs | $ 43,737,000 | ||
Environmental Issue | UGI Gas MGP Properties | |||
Contingencies | |||
Expected environmental expenditures cap during year | $ 2,500,000 | ||
Gas Utility | |||
Contingencies | |||
Duration of supply agreements - not more than (in months) | 16 months | ||
CPG-COA and PNG-COA | |||
Contingencies | |||
Accrued liabilities for environmental investigation and remediation costs | $ 11,326,000 | $ 13,758,000 | |
CPG MGP | |||
Contingencies | |||
Environmental expenditures cap during year | 1,800,000 | ||
PNG MGP | |||
Contingencies | |||
Environmental expenditures cap during year | $ 1,100,000 | ||
Option to termination agreement by either party effective at end of any two-year period | 2 years |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - Fair Value - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Commodity Contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative assets, gross | $ 4,510 | $ 1,307 |
Fair value of derivative liabilities, gross | (557) | (5,948) |
Commodity Contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative assets, gross | 4,506 | 934 |
Fair value of derivative liabilities, gross | (263) | (4,560) |
Commodity Contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative assets, gross | 4 | 373 |
Fair value of derivative liabilities, gross | (294) | (1,388) |
Commodity Contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative assets, gross | 0 | 0 |
Fair value of derivative liabilities, gross | $ 0 | 0 |
Interest Rate Contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative liabilities, gross | (7,016) | |
Interest Rate Contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative liabilities, gross | 0 | |
Interest Rate Contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative liabilities, gross | (7,016) | |
Interest Rate Contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ||
Fair value of derivative liabilities, gross | $ 0 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Fair Value Disclosures [Abstract] | ||
Carrying amount of long-term debt | $ 675,000 | $ 622,000 |
Estimated fair value of long-term debt | $ 770,781 | $ 681,415 |
Derivative Instruments and He72
Derivative Instruments and Hedging Activities (Details) kWh in Millions, MMBTU in Millions | Mar. 31, 2016USD ($) | Sep. 30, 2016USD ($)MMBTUkWh | Sep. 30, 2015USD ($)MMBTUkWh | Sep. 30, 2014USD ($) |
Derivative | ||||
Settlement of interest rate agreements | $ 35,975,000 | $ 0 | $ 0 | |
Interest rate cash flow hedge loss to be reclassified during next 12 months, net | 3,426,000 | |||
Restricted cash in brokerage accounts | 583,000 | 6,602,000 | ||
Interest Rate Protection Agreements | ||||
Derivative | ||||
Settlement of interest rate agreements | $ 35,975,000 | |||
Underlying variable rate debt | $ 0 | $ 250,000,000 | ||
Gas Utility | ||||
Derivative | ||||
Notional amount (in units) | MMBTU | 18.4 | 18.9 | ||
Maximum length of time hedged in price risk cash flow hedges (in months) | 12 months | |||
Electric Utility | Electric Utility Electric Transmission Congestion | ||||
Derivative | ||||
Notional amount (in units) | kWh | 58.3 | 277.1 | ||
Maximum length of time hedged in price risk cash flow hedges (in months) | 8 months |
Derivative Instruments and He73
Derivative Instruments and Hedging Activities - Derivative Assets and Liabilities Including Offsetting Amounts (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Derivative Instruments, Assets | ||
Derivative assets: | ||
Fair value of derivative assets, gross | $ 4,510 | $ 1,307 |
Gross amounts offset in the balance sheet | (247) | (373) |
Total derivative assets - net | 4,263 | 934 |
Derivative Instruments, Assets | Commodity Contract Subject to PGC and DS Mechanisms | ||
Derivative assets: | ||
Fair value of derivative assets, gross | 4,472 | 1,307 |
Derivative Instruments, Assets | Commodity Contract Not Subject to PGC and DS Mechanisms | ||
Derivative assets: | ||
Fair value of derivative assets, gross | 38 | 0 |
Derivative Instruments, Liabilities | ||
Derivative liabilities: | ||
Fair value of derivative liabilities, gross | (557) | (12,964) |
Gross amounts offset in the balance sheet | 247 | 373 |
Total derivative liabilities - net | (310) | (12,591) |
Derivative Instruments, Liabilities | Commodity Contract Subject to PGC and DS Mechanisms | ||
Derivative liabilities: | ||
Fair value of derivative liabilities, gross | (499) | (5,584) |
Derivative Instruments, Liabilities | Commodity Contract Not Subject to PGC and DS Mechanisms | ||
Derivative liabilities: | ||
Fair value of derivative liabilities, gross | (58) | (364) |
Derivative Instruments, Liabilities | Designated as Hedging Instrument | Interest Rate Contracts | ||
Derivative liabilities: | ||
Fair value of derivative liabilities, gross | $ 0 | $ (7,016) |
Derivative Instruments and He74
Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on Consolidated Statements of Income and Changes in AOCI (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Gasoline Contracts Not Subject to PGC and DS Mechanisms | Operating and Administrative Expenses/Other Operating Income, Net | |||
Derivative Instruments, Gain (Loss) | |||
Loss Recognized in Income | $ (88) | $ (761) | $ 0 |
Designated as Hedging Instrument | Cash Flow Hedging | Interest Rate Contracts | |||
Derivative Instruments, Gain (Loss) | |||
Loss Recognized in AOCI | (28,958) | (7,016) | 0 |
Designated as Hedging Instrument | Cash Flow Hedging | Interest Rate Contracts | Interest Expense | |||
Derivative Instruments, Gain (Loss) | |||
Loss Reclassified from AOCI into Income | $ (2,680) | $ (2,674) | $ (2,679) |
Accumulated Other Comprehensi75
Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of year | $ 890,620 | $ 839,837 | |
Reclassifications, net of tax | 639 | 517 | $ 385 |
Net losses on derivative instruments | (16,942) | (4,105) | 0 |
Benefit plans, principally actuarial losses | (3,197) | (3,482) | (1,413) |
Balance, end of year | 924,737 | 890,620 | 839,837 |
Postretirement Benefit Plans | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of year | (9,276) | (6,311) | (5,283) |
Reclassifications, net of tax | 639 | 517 | 385 |
Net losses on derivative instruments | 0 | 0 | |
Benefit plans, principally actuarial losses | (3,197) | (3,482) | (1,413) |
Balance, end of year | (11,834) | (9,276) | (6,311) |
Derivative Instrument Net Losses | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of year | (4,410) | (1,870) | (3,437) |
Reclassifications, net of tax | 0 | 0 | 0 |
Net losses on derivative instruments | (16,942) | (4,105) | |
Benefit plans, principally actuarial losses | 0 | 0 | 0 |
Balance, end of year | (19,784) | (4,410) | (1,870) |
AOCI Attributable to Parent | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Balance, beginning of year | (13,686) | (8,181) | (8,720) |
Net losses on derivative instruments | (16,942) | (4,105) | 0 |
Balance, end of year | (31,618) | (13,686) | (8,181) |
Interest Rate Protection Agreements | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Reclassifications, net of tax | 1,568 | 1,565 | 1,567 |
Interest Rate Protection Agreements | Postretirement Benefit Plans | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Reclassifications, net of tax | 0 | 0 | 0 |
Interest Rate Protection Agreements | Derivative Instrument Net Losses | |||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | |||
Reclassifications, net of tax | $ 1,568 | $ 1,565 | $ 1,567 |
Segment Information (Details)
Segment Information (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2016USD ($)countySegmentcustomer | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | |
Measurement Disclosures | |||||||||||
Number of reportable segments (in segments) | Segment | 2 | ||||||||||
Number of counties | county | 1 | ||||||||||
Revenues | $ 108,172 | $ 140,283 | $ 322,047 | $ 197,982 | $ 110,212 | $ 143,490 | $ 500,573 | $ 287,306 | $ 768,484 | $ 1,041,581 | $ 1,086,889 |
Cost of sales | 289,786 | 510,784 | 562,942 | ||||||||
Depreciation and amortization | 67,303 | 63,590 | 59,219 | ||||||||
Operating income | 8,309 | $ 29,815 | $ 114,481 | $ 48,296 | 3,144 | $ 20,184 | $ 142,699 | $ 75,640 | 200,901 | 241,667 | 246,400 |
Interest expense | 37,630 | 41,128 | 38,471 | ||||||||
Income before income taxes | 163,271 | 200,539 | 207,929 | ||||||||
Total assets | 2,743,091 | 2,505,984 | 2,743,091 | 2,505,984 | 2,352,143 | ||||||
Goodwill | 182,145 | 182,145 | 182,145 | 182,145 | 182,145 | ||||||
Capital expenditures | $ 262,503 | 197,684 | 164,180 | ||||||||
Electric Utility | |||||||||||
Measurement Disclosures | |||||||||||
Number of counties | county | 2 | ||||||||||
Operating Segments | Gas Utility | |||||||||||
Measurement Disclosures | |||||||||||
Revenues | $ 677,387 | 933,080 | 977,333 | ||||||||
Cost of sales | 239,163 | 448,617 | 496,762 | ||||||||
Depreciation and amortization | 62,451 | 58,974 | 54,816 | ||||||||
Operating income | 189,412 | 226,485 | 236,219 | ||||||||
Interest expense | 35,786 | 39,112 | 36,602 | ||||||||
Income before income taxes | 153,626 | 187,373 | 199,617 | ||||||||
Total assets | 2,570,297 | 2,360,156 | 2,570,297 | 2,360,156 | 2,211,618 | ||||||
Goodwill | 182,145 | 182,145 | 182,145 | 182,145 | 182,145 | ||||||
Capital expenditures | 251,261 | 189,671 | 156,425 | ||||||||
Operating Segments | Electric Utility | |||||||||||
Measurement Disclosures | |||||||||||
Revenues | 91,097 | 107,577 | 108,072 | ||||||||
Cost of sales | 50,623 | 62,167 | 66,180 | ||||||||
Depreciation and amortization | 4,852 | 4,616 | 4,403 | ||||||||
Operating income | 11,489 | 14,153 | 9,668 | ||||||||
Interest expense | 1,844 | 2,016 | 1,869 | ||||||||
Income before income taxes | 9,645 | 12,137 | 7,799 | ||||||||
Total assets | 172,794 | 145,828 | 172,794 | 145,828 | 140,525 | ||||||
Goodwill | $ 0 | 0 | 0 | 0 | 0 | ||||||
Capital expenditures | $ 11,242 | 8,013 | 7,755 | ||||||||
Other | |||||||||||
Measurement Disclosures | |||||||||||
Revenues | 924 | 1,484 | |||||||||
Cost of sales | 0 | 0 | |||||||||
Depreciation and amortization | 0 | 0 | |||||||||
Operating income | 1,029 | 513 | |||||||||
Interest expense | 0 | 0 | |||||||||
Income before income taxes | 1,029 | 513 | |||||||||
Total assets | 0 | 0 | 0 | ||||||||
Goodwill | $ 0 | 0 | 0 | ||||||||
Capital expenditures | $ 0 | $ 0 | |||||||||
Customer Concentration Risk | Revenue, Consolidated | |||||||||||
Measurement Disclosures | |||||||||||
Number of customers | customer | 0 |
Other Operating (Expense) Inc77
Other Operating (Expense) Income, Net - Schedule of Other Income, Net (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Component of Operating Income [Abstract] | |||
Non-tariff service income | $ 2,633 | $ 4,760 | $ 2,670 |
Environmental matters | (2,918) | 1,152 | 297 |
Construction service income | 0 | 2,175 | 0 |
Sale of HVAC Business | 0 | 1,065 | 0 |
PGC interest on over (under) collection | (1,740) | (606) | 1,388 |
Other, net | 25 | 323 | 4 |
Total other operating (expense) income, net | $ (2,000) | $ 8,869 | $ 4,359 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2016USD ($)agreementBcf | Sep. 30, 2015USD ($)Bcf | Sep. 30, 2014USD ($) | |
Related Party Transaction | |||
Related party costs incurred | $ 11,863 | $ 11,956 | $ 10,671 |
UGI Energy Services, Inc | |||
Related Party Transaction | |||
Agreement term (in years) | 1 year | ||
Revenue from related parties | $ 30,743 | 79,182 | 109,913 |
Purchases from related party | $ 35,067 | 85,383 | 128,076 |
UGI Energy Services, Inc | SCAAs | |||
Related Party Transaction | |||
Agreement term (in years) | 3 years | ||
Number of storage agreements | agreement | 1 | ||
Related party costs incurred | $ 12,739 | 16,849 | 38,299 |
UGI Energy Services, Inc | Exclusive of Transactions Pursuant SCAAs | |||
Related Party Transaction | |||
Related party costs incurred | 63,331 | 47,794 | $ 35,810 |
UGI Energy Services, Inc | Other Current Liabilities | SCAAs | |||
Related Party Transaction | |||
Related party security deposits | $ 8,100 | $ 10,700 | |
UGI Energy Services, Inc | Inventories | |||
Related Party Transaction | |||
Volume of gas storage inventory (in bcf of natural gas) | Bcf | 4.6 | 5 | |
Natural gas storage inventory, related parties, current | $ 11,148 | $ 12,889 |
Quarterly Data (unaudited) - Sc
Quarterly Data (unaudited) - Schedule of Quarterly Financial Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $ 108,172 | $ 140,283 | $ 322,047 | $ 197,982 | $ 110,212 | $ 143,490 | $ 500,573 | $ 287,306 | $ 768,484 | $ 1,041,581 | $ 1,086,889 |
Operating income | 8,309 | 29,815 | 114,481 | 48,296 | 3,144 | 20,184 | 142,699 | 75,640 | 200,901 | 241,667 | 246,400 |
Net income (loss) | $ (1,875) | $ 12,603 | $ 63,294 | $ 23,351 | $ (4,680) | $ 7,307 | $ 79,589 | $ 38,839 | $ 97,373 | $ 121,055 | $ 124,106 |
Valuation and Qualifying Acco80
Valuation and Qualifying Accounts (Details) - Allowance for Doubtful Accounts - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Movement in Valuation Allowances and Reserves | ||||
Balance at beginning of year | $ 5,599 | $ 6,992 | $ 5,519 | |
Charged to costs and expenses | 7,760 | 13,498 | 13,149 | |
Other | [1] | (9,413) | (14,891) | (11,676) |
Balance at end of year | $ 3,946 | $ 5,599 | $ 6,992 | |
[1] | Uncollectible accounts written off, net of recoveries |