Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Jun. 30, 2017 | Jul. 31, 2017 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | UGI UTILITIES INC | |
Entity Central Index Key | 100,548 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2017 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | --09-30 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 26,781,785 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Current assets: | |||
Cash and cash equivalents | $ 4,828 | $ 2,819 | $ 82,449 |
Restricted cash | 2,524 | 583 | 212 |
Accounts receivable (less allowances for doubtful accounts of $10,050, $3,946 and $7,921, respectively) | 69,246 | 44,692 | 59,301 |
Accounts receivable — related parties | 718 | 398 | 638 |
Accrued utility revenues | 5,924 | 12,753 | 10,099 |
Inventories | 37,129 | 42,340 | 27,009 |
Prepaid income taxes | 428 | 1,956 | 0 |
Regulatory assets | 7,759 | 3,208 | 3,263 |
Derivative instruments | 942 | 4,263 | 5,384 |
Prepaid expenses & other current assets | 12,995 | 22,009 | 33,724 |
Total current assets | 142,493 | 135,021 | 222,079 |
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,008,121, $975,374 and $961,006, respectively) | 2,174,609 | 2,023,541 | 1,945,539 |
Goodwill | 182,145 | 182,145 | 182,145 |
Regulatory assets | 390,988 | 391,933 | 342,037 |
Other assets | 14,297 | 10,451 | 5,501 |
Total assets | 2,904,532 | 2,743,091 | 2,697,301 |
Current liabilities: | |||
Current maturities of long-term debt | 39,990 | 19,986 | 19,981 |
Short-term borrowings | 50,000 | 112,500 | 130,000 |
Accounts payable | 56,866 | 65,180 | 50,665 |
Accounts payable — related parties | 7,625 | 3,995 | 5,838 |
Regulatory liability — deferred fuel and power refunds | 12,587 | 22,299 | 34,432 |
Derivative instruments | 1,056 | 310 | 507 |
Other current liabilities | 129,325 | 109,640 | 113,011 |
Total current liabilities | 297,449 | 333,910 | 354,434 |
Long-term debt | 711,116 | 651,455 | 627,422 |
Deferred income taxes | 614,419 | 550,229 | 545,614 |
Deferred investment tax credits | 3,029 | 3,268 | 3,348 |
Pension and postretirement benefit obligations | 176,393 | 184,516 | 128,932 |
Other noncurrent liabilities | 95,108 | 94,976 | 98,652 |
Total liabilities | 1,897,514 | 1,818,354 | 1,758,402 |
Commitments and contingencies (Note 7) | |||
Common stockholder’s equity: | |||
Common Stock, $2.25 par value (authorized — 40,000,000 shares; issued and outstanding — 26,781,785 shares) | 60,259 | 60,259 | 60,259 |
Additional paid-in capital | 473,580 | 473,580 | 473,295 |
Retained earnings | 502,603 | 422,516 | 434,391 |
Accumulated other comprehensive loss | (29,424) | (31,618) | (29,046) |
Total common stockholder’s equity | 1,007,018 | 924,737 | 938,899 |
Total liabilities and stockholder’s equity | $ 2,904,532 | $ 2,743,091 | $ 2,697,301 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Statement of Financial Position [Abstract] | |||
Allowance for doubtful accounts | $ 10,050 | $ 3,946 | $ 7,921 |
Accumulated depreciation and amortization | $ 1,008,121 | $ 975,374 | $ 961,006 |
Common stock, par value (in usd per share) | $ 2.25 | $ 2.25 | $ 2.25 |
Common stock, shares authorized (in shares) | 40,000,000 | 40,000,000 | 40,000,000 |
Common stock, shares issued (in shares) | 26,781,785 | 26,781,785 | 26,781,785 |
Common stock, shares outstanding (in shares) | 26,781,785 | 26,781,785 | 26,781,785 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Income Statement [Abstract] | ||||
Revenues | $ 146,692 | $ 140,283 | $ 768,045 | $ 660,312 |
Costs and expenses: | ||||
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below) | 51,979 | 44,415 | 325,991 | 257,288 |
Operating and administrative expenses | 49,031 | 43,254 | 148,132 | 136,406 |
Operating and administrative expenses — related parties | 2,961 | 2,811 | 10,059 | 8,789 |
Taxes other than income taxes | 3,706 | 3,970 | 12,342 | 12,187 |
Depreciation | 17,364 | 15,877 | 51,351 | 47,850 |
Amortization | 548 | 673 | 1,651 | 2,431 |
Other operating (income) expense, net | (6,568) | (532) | (7,796) | 2,769 |
Total costs and expenses | 119,021 | 110,468 | 541,730 | 467,720 |
Operating income | 27,671 | 29,815 | 226,315 | 192,592 |
Interest expense | 10,128 | 9,158 | 30,478 | 27,922 |
Income before income taxes | 17,543 | 20,657 | 195,837 | 164,670 |
Income taxes | 6,846 | 8,054 | 75,750 | 65,422 |
Net income | $ 10,697 | $ 12,603 | $ 120,087 | $ 99,248 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 10,697 | $ 12,603 | $ 120,087 | $ 99,248 |
Other comprehensive income (loss): | ||||
Net losses on derivative instruments (net of tax of $0, $0, $0, and $12,016, respectively) | 0 | 0 | 0 | (16,943) |
Reclassifications of net losses on derivative instruments (net of tax of $(355), $(253), $(1,047), and $(782), respectively) | 501 | 357 | 1,477 | 1,103 |
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(169), $(113), $(507), and $(340), respectively) | 239 | 160 | 717 | 480 |
Other comprehensive income (loss) | 740 | 517 | 2,194 | (15,360) |
Comprehensive income | $ 11,437 | $ 13,120 | $ 122,281 | $ 83,888 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | ||||
Net losses on derivative instruments, tax | $ 0 | $ 0 | $ 0 | $ 12,016 |
Reclassifications of net losses on derivative instruments, tax | (355) | (253) | (1,047) | (782) |
Benefit plans reclassifications of actuarial losses and prior service costs, tax | $ (169) | $ (113) | $ (507) | $ (340) |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income | $ 120,087 | $ 99,248 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 53,002 | 50,281 |
Deferred income tax expense | 56,285 | 66,136 |
Provision for uncollectible accounts | 8,184 | 6,716 |
Settlement of interest rate protection agreements | 0 | (35,975) |
Other, net | 4,358 | 954 |
Net change in: | ||
Accounts receivable and accrued utility revenues | (31,471) | (9,864) |
Inventories | 5,211 | 24,707 |
Deferred fuel and power costs, net of changes in unsettled derivatives | (12,571) | (11,587) |
Accounts payable | 2,775 | (6,062) |
Other current assets | 9,014 | (7,833) |
Other current liabilities | 21,727 | 17,763 |
Net cash provided by operating activities | 236,601 | 194,484 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Expenditures for property, plant and equipment | (201,916) | (163,967) |
Net costs of property, plant and equipment disposals | (7,734) | (7,664) |
(Increase) decrease in restricted cash | (1,941) | 6,390 |
Net cash used by investing activities | (211,591) | (165,241) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Payments of dividends | (40,000) | (37,000) |
Issuances of long-term debt, net of issuance costs | 99,499 | 99,415 |
Repayments of long-term debt | (20,000) | (72,000) |
(Decrease) increase in short-term borrowings | (62,500) | 58,300 |
Other | 0 | 1,392 |
Net cash (used) provided by financing activities | (23,001) | 50,107 |
Cash and cash equivalents increase | 2,009 | 79,350 |
CASH AND CASH EQUIVALENTS | ||
End of period | 4,828 | 82,449 |
Beginning of period | 2,819 | 3,099 |
Increase | $ 2,009 | $ 79,350 |
Nature of Operations
Nature of Operations | 9 Months Ended |
Jun. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature of Operations | Note 1 — Nature of Operations UGI Utilities, Inc. (“UGI Utilities”), a wholly owned subsidiary of UGI Corporation (“UGI”), and UGI Utilities’ wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”), own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.” The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 2 — Summary of Significant Accounting Policies Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or the “Company”). We eliminate intercompany accounts when we consolidate. The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2016 , condensed consolidated balance sheet data was derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2016 (“the Company’s 2016 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year. Derivative Instruments Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP and such exception has been elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting. Gains and losses on substantially all of the derivative instruments used by UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 10 . Deferred Debt Issuance Costs. During the fourth quarter of Fiscal 2016, we adopted new accounting guidance regarding the classification of deferred debt issuance costs. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with line of credit facilities continue to be classified as “ Other assets ” on the Condensed Consolidated Balance Sheets. As a result of the retrospective application of new accounting guidance adopted, the Company has reflected $2,597 of such costs as a reduction to long-term debt, including current maturities, on the June 30, 2016 , Condensed Consolidated Balance Sheet. Previously, these costs were presented within “ Other assets .” Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Reclassifications. Certain prior period amounts have been reclassified to conform to the current-period presentation. |
Accounting Changes
Accounting Changes | 9 Months Ended |
Jun. 30, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Changes | Note 3 — Accounting Changes Adoption of New Accounting Standard Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements. Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Goodwill Impairment. In January 2017, the FASB issued ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment.” Under the new accounting guidance, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Instead, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. In addition, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment, if applicable. The provisions of the new accounting guidance are required to be applied prospectively. The new accounting guidance is effective for the Company for goodwill impairment tests performed in fiscal years beginning after December 15, 2019 (Fiscal 2021). Early adoption is permitted for goodwill impairment tests performed after January 1, 2017. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2017. Cash Flow Classification. In August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company has not yet selected a transition method and is in the process of assessing the impact on its financial statements from the adoption of the new guidance. |
Inventories
Inventories | 9 Months Ended |
Jun. 30, 2017 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 4 — Inventories Inventories comprise the following: June 30, 2017 September 30, 2016 June 30, 2016 Gas Utility natural gas $ 21,826 $ 29,223 $ 13,561 Materials, supplies and other 15,303 13,117 13,448 Total inventories $ 37,129 $ 42,340 $ 27,009 At June 30, 2017 , UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Four of the SCAAs were with UGI Energy Services, LLC (“Energy Services”), a second-tier, wholly owned subsidiary of UGI (see Note 12 ) and one of the SCAAs is with a non-affiliate. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. The carrying values of gas storage inventories released under the SCAAs at June 30, 2017 , September 30, 2016 and June 30, 2016 , comprising 4.8 billion cubic feet (“bcf”), 8.1 bcf and 4.6 bcf of natural gas, were $14,146 , $18,773 and $8,390 , respectively. At June 30, 2017 , September 30, 2016 and June 30, 2016 , UGI Utilities held a total of $15,040 , $19,100 and $15,100 , respectively, of security deposits received from its SCAA counterparties. These amounts are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets. For additional information related to the SCAAs with Energy Services, see Note 12 . |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities and Regulatory Matters | 9 Months Ended |
Jun. 30, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities and Regulatory Matters | Note 5 — Regulatory Assets and Liabilities and Regulatory Matters For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 4 in the Company’s 2016 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying Condensed Consolidated Balance Sheets: June 30, 2017 September 30, 2016 June 30, 2016 Regulatory assets: Income taxes recoverable $ 122,733 $ 115,643 $ 119,604 Underfunded pension and postretirement plans 171,833 183,129 133,356 Environmental costs 61,616 59,397 60,716 Deferred fuel and power costs 7,024 151 — Removal costs, net 29,405 27,956 22,444 Other 6,136 8,865 9,180 Total regulatory assets $ 398,747 $ 395,141 $ 345,300 Regulatory liabilities: Postretirement benefits $ 16,715 $ 17,519 $ 19,671 Deferred fuel and power refunds 12,587 22,299 34,432 State tax benefits — distribution system repairs 16,662 15,086 14,604 Other 2,706 665 1,149 Total regulatory liabilities (a) $ 48,670 $ 55,569 $ 69,856 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized (losses) gains on such contracts at June 30, 2017 , September 30, 2016 , and June 30, 2016 , were $(73) , $4,263 and $5,483 , respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At June 30, 2017 , September 30, 2016 , and June 30, 2016 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 10 ). In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at June 30, 2017 , September 30, 2016 , and June 30, 2016 , were not material. Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s base operating revenues for residential, commercial and industrial customers by $21,700 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. PNG requested that the new gas rates become effective March 20, 2017. The PUC entered an Order dated February 9, 2017, suspending the effective date for the rate increase to allow for investigation and public hearings. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PUC. Under the terms of the Joint Petition, UGI Utilities will be permitted, effective October 20, 2017, to increase PNG’s annual base distribution rates by $11,250 . On July 25, 2017, the PUC administrative law judge recommended that the settlement be adopted without modification. Although the Company expects to receive the final order from the PUC approving the settlement by October 2017, the Company cannot predict the timing or the ultimate outcome of the rate case review process. On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27,000 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016. Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at 5% of distribution charges billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions seeking approval to increase the maximum allowable DSIC from 5% to 10% of billed distribution revenues. On May 10, 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at the Company’s Long-term Infrastructure Improvement Plan filing in 2018. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. Revenue collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an administrative law judge. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is not likely to occur prior to September 30, 2017. |
Debt
Debt | 9 Months Ended |
Jun. 30, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Note 6 — Debt Pursuant to a Note Purchase Agreement, in October 2016, UGI Utilities issued $100,000 aggregate principal amount of 4.12% Senior Notes due October 2046 (the “ 4.12% Senior Notes”). The net proceeds of the issuance of the 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives and (2) for general corporate purposes. The 4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 7 — Commitments and Contingencies Contingencies From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into an agreement with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania (each, a “COA”). The COAs require UGI Gas, CPG and PNG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP-related facilities were previously operated (“MGP Properties”) and, in the case of CPG, to plug a minimum number of non-producing natural gas wells per year. Under these agreements, in any calendar year, required environmental expenditures relating to the MGP Properties and, with respect to CPG, the natural gas wells, are capped at $2,500 , $1,800 , and $1,100 , for UGI Gas, CPG and PNG, respectively. The COAs for UGI Gas, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively, but each COA may be terminated by either party at the end of any two -year period beginning with the original effective date of such COA. At June 30, 2017 , September 30, 2016 and June 30, 2016 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Gas, CPG and PNG totaled $55,185 , $55,063 , and $56,006 , respectively. UGI Gas, CPG, and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 5). UGI Utilities does not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law, UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At June 30, 2017 , September 30, 2016 and June 30, 2016 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material. Other Matters Manor Township, Pennsylvania Natural Gas Explosion. On July 2, 2017, an explosion occurred in Manor Township, Pennsylvania which resulted in the death of a Company employee, significant injuries to two other Company employees and an employee of the local sewer authority, and significant property damage. The National Transportation Safety Board (“NTSB”), the Occupational Safety and Health Administration (“OSHA”) and the PUC are investigating the Manor Township incident. The NTSB investigative team includes representatives from the Company, the PUC, the local Fire Department and the Pipeline and Hazardous Materials Safety Administration and the Company is cooperating with the investigation. Other parties may be invited to participate by the NTSB. While the investigation into this incident is still underway and the cause of the explosion has not been determined, the Company has received claims as a result of the explosion and may become involved in lawsuits relative to the incident. The Company maintains workers’ compensation insurance and liability insurance for personal injury, property and casualty damages and believes that third-party claims associated with the explosion, in excess of the Company’s deductible, are expected to be recovered through the Company’s insurance. Although the Company cannot predict the result of these pending or future claims, we believe that claims and expenses associated with the explosion will not have a material impact on our consolidated financial statements. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial statements. |
Defined Benefit Pension and Oth
Defined Benefit Pension and Other Postretirement Plans | 9 Months Ended |
Jun. 30, 2017 | |
Defined Benefit Plan [Abstract] | |
Defined Benefit Pension and Other Postretirement Plans | Note 8 — Defined Benefit Pension and Other Postretirement Plans We sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all active and retired employees. Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 Service cost $ 2,023 $ 1,731 $ 62 $ 46 Interest cost 5,540 5,818 108 116 Expected return on assets (7,497 ) (7,167 ) (164 ) (149 ) Amortization of: Prior service cost (benefit) 81 87 (160 ) (160 ) Actuarial loss 3,706 2,393 28 24 Net benefit cost (income) 3,853 2,862 (126 ) (123 ) Change in associated regulatory liabilities — — (123 ) 878 Net benefit cost (income) after change in regulatory liabilities $ 3,853 $ 2,862 $ (249 ) $ 755 Pension Benefits Other Postretirement Benefits Nine Months Ended June 30, 2017 2016 2017 2016 Service cost $ 6,068 $ 5,195 $ 184 $ 137 Interest cost 16,618 17,453 323 349 Expected return on assets (22,490 ) (21,502 ) (492 ) (447 ) Amortization of: Prior service cost (benefit) 244 261 (480 ) (480 ) Actuarial loss 11,119 7,179 85 73 Net benefit cost (income) 11,559 8,586 (380 ) (368 ) Change in associated regulatory liabilities — — (368 ) 2,632 Net benefit cost (income) after change in regulatory liabilities $ 11,559 $ 8,586 $ (748 ) $ 2,264 Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Corporation Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. From time to time we may, at our discretion, contribute additional amounts. During the nine months ended June 30, 2017 and 2016 , the Company made contributions to the Pension Plan of $8,546 and $7,402 , respectively. The Company expects to make additional discretionary cash contributions of approximately $2,800 to the Pension Plan during the remainder of Fiscal 2017 . UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and the amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the nine months ended June 30, 2017 and 2016 . We also participate in an unfunded and non-qualified defined benefit supplemental executive retirement plan. Net benefit costs associated with this plan for all periods presented were not material. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Jun. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 9 — Fair Value Measurements Derivative Instruments The following table presents on a gross basis our derivative assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of June 30, 2017 , September 30, 2016 and June 30, 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total June 30, 2017: Assets: Commodity contracts $ 1,062 $ 101 $ — $ 1,163 Liabilities: Commodity contracts $ (1,157 ) $ (68 ) $ — $ (1,225 ) September 30, 2016: Assets: Commodity contracts $ 4,506 $ 4 $ — $ 4,510 Liabilities: Commodity contracts $ (263 ) $ (294 ) $ — $ (557 ) June 30, 2016: Assets: Commodity contracts $ 5,715 $ 3 $ — $ 5,718 Liabilities: Commodity contracts $ (341 ) $ (391 ) $ — $ (732 ) The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. There were no transfers between Level 1 and Level 2 during the periods presented. Other Financial Instruments The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at June 30, 2017 , September 30, 2016 and June 30, 2016 were as follows: June 30, 2017 September 30, 2016 June 30, 2016 Carrying amount $ 755,000 $ 675,000 $ 650,000 Estimated fair value $ 788,472 $ 770,781 $ 747,588 |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 9 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 10 — Derivative Instruments and Hedging Activities We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk and (2) interest rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our commodity derivative instruments are generally subject to regulatory ratemaking mechanisms, we have limited commodity price risk associated with our Gas Utility or Electric Utility operations. Commodity Price Risk Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At June 30, 2017 , September 30, 2016 and June 30, 2016 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 12.7 million dekatherms, 18.4 million dekatherms and 13.4 million dekatherms, respectively. At June 30, 2017 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 15 months . Gains and losses on natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 5 ). Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At June 30, 2017 , September 30, 2016 and June 30, 2016 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5 ). At June 30, 2017 , September 30, 2016 and June 30, 2016 , the total volumes associated with FTRs totaled 139.4 million kilowatt hours, 58.3 million kilowatt hours and 80.6 million kilowatt hours, respectively. At June 30, 2017 , the maximum period over which we are economically hedging electricity congestion is 11 months . In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. At June 30, 2017 , September 30, 2016 and June 30, 2016 , the total volumes associated with gasoline futures contracts were not material. Interest Rate Risk Our long-term debt typically is issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for IRPAs as cash flow hedges. As of June 30, 2017 , September 30, 2016 and June 30, 2016 , we had no unsettled IRPAs. At June 30, 2017 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $3,485 . Derivative Instrument Credit Risk Our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2017 , September 30, 2016 and June 30, 2016 , restricted cash in brokerage accounts totaled $2,524 , $583 and $212 , respectively. Offsetting Derivative Assets and Liabilities Derivative assets and liabilities are presented net by counterparty on the Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions. In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of June 30, 2017 , September 30, 2016 and June 30, 2016 : June 30, 2017 September 30, 2016 June 30, 2016 Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 1,163 $ 4,472 $ 5,718 Derivatives not subject to PGC and DS mechanisms: Commodity contracts — 38 — Total derivative assets — gross 1,163 4,510 5,718 Gross amounts offset in the balance sheet (159 ) (247 ) (225 ) Total derivative assets — net (a) $ 1,004 $ 4,263 $ 5,493 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (1,204 ) $ (499 ) $ (593 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts (21 ) (58 ) (139 ) Total derivative liabilities — gross (1,225 ) (557 ) (732 ) Gross amounts offset in the balance sheet 159 247 225 Total derivative liabilities — net (a) $ (1,066 ) $ (310 ) $ (507 ) (a) Derivative assets and liabilities with maturities greater than one year are recorded in “Other assets” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Effect of Derivative Instruments The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30, 2017 and 2016 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended June 30, 2017 2016 2017 2016 Cash Flow Hedges: Interest rate contracts $ — $ — $ (856 ) $ (610 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Three Months Ended June 30, 2017 2016 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (57 ) $ 27 Operating and administrative expenses Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Nine Months Ended June 30, 2017 2016 2017 2016 Cash Flow Hedges: Interest rate contracts $ — $ (28,959 ) $ (2,524 ) $ (1,885 ) Interest expense Loss Recognized in Income Location of Loss Recognized in Income Nine Months Ended June 30, 2017 2016 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (25 ) $ (93 ) Operating and administrative expenses We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 9 Months Ended |
Jun. 30, 2017 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income | Note 11 — Accumulated Other Comprehensive Income The tables below present changes in AOCI, net of tax, during the three and nine months ended June 30, 2017 and 2016 : Three Months Ended June 30, 2017 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2017 $ (11,356 ) $ (18,808 ) $ (30,164 ) Reclassifications of benefit plan actuarial losses and prior service costs 239 — 239 Reclassifications of net losses on IRPAs — 501 501 AOCI — June 30, 2017 $ (11,117 ) $ (18,307 ) $ (29,424 ) Three Months Ended June 30, 2016 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2016 $ (8,956 ) $ (20,607 ) $ (29,563 ) Reclassifications of benefit plan actuarial losses and prior service costs 160 — 160 Reclassifications of net losses on IRPAs — 357 357 AOCI — June 30, 2016 $ (8,796 ) $ (20,250 ) $ (29,046 ) Nine Months Ended June 30, 2017 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of benefit plans actuarial losses and prior service costs 717 — 717 Reclassifications of net losses on IRPAs — 1,477 1,477 AOCI — June 30, 2017 $ (11,117 ) $ (18,307 ) $ (29,424 ) Nine Months Ended June 30, 2016 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Net losses on IRPAs — (16,943 ) (16,943 ) Reclassifications of benefit plans actuarial losses and prior service costs 480 — 480 Reclassifications of net losses on IRPAs — 1,103 1,103 AOCI — June 30, 2016 $ (8,796 ) $ (20,250 ) $ (29,046 ) |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Jun. 30, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 12 — Related Party Transactions UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an allocated share of indirect corporate expenses incurred or paid with respect to services provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a weighted, three-component formula comprising revenues, operating expenses and net assets employed and considers UGI Utilities’ relative percentage of such items to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to UGI Utilities and this allocation method has been accepted by the PUC in past rate case proceedings and management audits as a reasonable method of allocating such expenses. These billed expenses are classified as “Operating and administrative expenses — related parties” on the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC affiliated interest agreements. Amounts billed to these entities by UGI Utilities totaled $562 and $3,420 during the three and nine months ended June 30, 2017 , respectively, and $1,752 and $3,904 during the three and nine months ended June 30, 2016 , respectively. From time to time, UGI Utilities is a party to SCAAs with Energy Services which have terms of up to three years. Under the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts (subject to recall for operational purposes) to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $9,777 and $12,272 during the three and nine months ended June 30, 2017 , respectively, and $4,358 and $6,387 during the three and nine months ended June 30, 2016 , respectively. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. These payments totaled $729 and $2,027 during the three and nine months ended June 30, 2017 , respectively, and $493 and $1,510 during the three and nine months ended June 30, 2016 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amounts of such security deposits, which are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets, were $11,040 at June 30, 2017 and $8,100 as of September 30, 2016 and June 30, 2016 . UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) in “Inventories” on the Condensed Consolidated Balance Sheets. The carrying values of these gas storage inventories at June 30, 2017 , September 30, 2016 and June 30, 2016 , comprising approximately 3.6 bcf, 4.6 bcf and 2.7 bcf of natural gas, were $10,662 , $11,148 and $5,100 , respectively. UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility primarily during the heating-season months of November through March. The aggregate amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the three and nine months ended June 30, 2017 totaled $2,137 and $73,872 , respectively. During the three and nine months ended June 30, 2016 , such purchases totaled $2,138 and $61,193 , respectively. From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2017 , revenues associated with such sales to Energy Services totaled $10,554 and $43,836 , respectively. During the three and nine months ended June 30, 2016 , revenues associated with such sales to Energy Services totaled $4,514 and $26,134 , respectively. Also from time to time, UGI Utilities purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one -year agreements. During the three and nine months ended June 30, 2017 , such purchases totaled $14,675 and $75,783 , respectively. During the three and nine months ended June 30, 2016 , such purchases totaled $6,928 and $30,032 , respectively. |
Segment Information
Segment Information | 9 Months Ended |
Jun. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Note 13 — Segment Information We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties. The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2016 Annual Report. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes. Financial information by business segment follows: Reportable Segments Three Months Ended June 30, 2017 Total Gas Utility Electric Utility Revenues $ 146,692 $ 127,849 $ 18,843 Cost of sales — gas, fuel and purchased power $ 51,979 $ 42,180 $ 9,799 Depreciation and amortization $ 17,912 $ 16,845 $ 1,067 Operating income $ 27,671 $ 25,628 $ 2,043 Interest expense $ 10,128 $ 9,601 $ 527 Income before income taxes $ 17,543 $ 16,027 $ 1,516 Capital expenditures (including the effects of accruals) $ 79,088 $ 75,836 $ 3,252 Reportable Segments Three Months Ended June 30, 2016 Total Gas Utility Electric Utility Revenues $ 140,283 $ 119,995 $ 20,288 Cost of sales — gas, fuel and purchased power $ 44,415 $ 33,715 $ 10,700 Depreciation and amortization $ 16,550 $ 15,339 $ 1,211 Operating income $ 29,815 $ 27,116 $ 2,699 Interest expense $ 9,158 $ 8,670 $ 488 Income before income taxes $ 20,657 $ 18,446 $ 2,211 Capital expenditures (including the effects of accruals) $ 56,481 $ 53,199 $ 3,282 Reportable Segments Nine Months Ended June 30, 2017 Total Gas Utility Electric Utility Revenues $ 768,045 $ 700,813 $ 67,232 Cost of sales — gas, fuel and purchased power $ 325,991 $ 288,610 $ 37,381 Depreciation and amortization $ 53,002 $ 49,378 $ 3,624 Operating income $ 226,315 $ 219,700 $ 6,615 Interest expense $ 30,478 $ 29,017 $ 1,461 Income before income taxes $ 195,837 $ 190,683 $ 5,154 Capital expenditures (including the effects of accruals) $ 199,701 $ 191,715 $ 7,986 As of June 30, 2017 Total assets $ 2,904,532 $ 2,743,035 $ 161,497 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Nine Months Ended June 30, 2016 Total Gas Utility Electric Utility Revenues $ 660,312 $ 595,025 $ 65,287 Cost of sales — gas, fuel and purchased power $ 257,288 $ 221,646 $ 35,642 Depreciation and amortization $ 50,281 $ 46,665 $ 3,616 Operating income $ 192,592 $ 183,940 $ 8,652 Interest expense $ 27,922 $ 26,583 $ 1,339 Income before income taxes $ 164,670 $ 157,357 $ 7,313 Capital expenditures (including the effects of accruals) $ 166,058 $ 158,472 $ 7,586 As of June 30, 2016 Total assets $ 2,697,301 $ 2,531,573 $ 165,728 Goodwill $ 182,145 $ 182,145 $ — |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation. Our condensed consolidated financial statements include the accounts of UGI Utilities and its subsidiaries (collectively, “we” or the “Company”). We eliminate intercompany accounts when we consolidate. The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. |
Derivative Instruments | Derivative Instruments Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP and such exception has been elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or is designated and qualifies for hedge accounting. Gains and losses on substantially all of the derivative instruments used by UGI Utilities (for which NPNS has not been elected) to hedge commodity prices are included in regulatory assets and liabilities in accordance with GAAP regarding accounting for rate-regulated entities. Certain of our derivative instruments are designated and qualify as cash flow hedges. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Certain other commodity derivative financial instruments, although generally effective as hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments are included in cash flows from operating activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 10 . |
Deferred Debt Issuance Costs | Deferred Debt Issuance Costs. During the fourth quarter of Fiscal 2016, we adopted new accounting guidance regarding the classification of deferred debt issuance costs. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with line of credit facilities continue to be classified as “ Other assets ” on the Condensed Consolidated Balance Sheets. |
Use of Estimates | Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. |
Reclassifications | Reclassifications. Certain prior period amounts have been reclassified to conform to the current-period presentation. |
Adoption of New Accounting Standard and Accounting Standards Not Yet Adopted | Adoption of New Accounting Standard Employee Share-based Payments. Effective October 1, 2016, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense and treated as discrete items in the reporting period in which they occur. The adoption of the new accounting guidance did not have a material impact on our financial statements. Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs. In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of operating income. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Goodwill Impairment. In January 2017, the FASB issued ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment.” Under the new accounting guidance, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Instead, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. In addition, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment, if applicable. The provisions of the new accounting guidance are required to be applied prospectively. The new accounting guidance is effective for the Company for goodwill impairment tests performed in fiscal years beginning after December 15, 2019 (Fiscal 2021). Early adoption is permitted for goodwill impairment tests performed after January 1, 2017. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2017. Cash Flow Classification. In August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU are required to be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company has not yet selected a transition method and is in the process of assessing the impact on its financial statements from the adoption of the new guidance. |
Inventories (Tables)
Inventories (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventories | Inventories comprise the following: June 30, 2017 September 30, 2016 June 30, 2016 Gas Utility natural gas $ 21,826 $ 29,223 $ 13,561 Materials, supplies and other 15,303 13,117 13,448 Total inventories $ 37,129 $ 42,340 $ 27,009 |
Regulatory Assets and Liabili23
Regulatory Assets and Liabilities and Regulatory Matters (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets Associated with Gas Utility and Electric Utility | The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying Condensed Consolidated Balance Sheets: June 30, 2017 September 30, 2016 June 30, 2016 Regulatory assets: Income taxes recoverable $ 122,733 $ 115,643 $ 119,604 Underfunded pension and postretirement plans 171,833 183,129 133,356 Environmental costs 61,616 59,397 60,716 Deferred fuel and power costs 7,024 151 — Removal costs, net 29,405 27,956 22,444 Other 6,136 8,865 9,180 Total regulatory assets $ 398,747 $ 395,141 $ 345,300 Regulatory liabilities: Postretirement benefits $ 16,715 $ 17,519 $ 19,671 Deferred fuel and power refunds 12,587 22,299 34,432 State tax benefits — distribution system repairs 16,662 15,086 14,604 Other 2,706 665 1,149 Total regulatory liabilities (a) $ 48,670 $ 55,569 $ 69,856 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. |
Schedule of Regulatory Liabilities Associated with Gas Utility and Electric Utility | The following regulatory assets and liabilities associated with UGI Utilities are included in the accompanying Condensed Consolidated Balance Sheets: June 30, 2017 September 30, 2016 June 30, 2016 Regulatory assets: Income taxes recoverable $ 122,733 $ 115,643 $ 119,604 Underfunded pension and postretirement plans 171,833 183,129 133,356 Environmental costs 61,616 59,397 60,716 Deferred fuel and power costs 7,024 151 — Removal costs, net 29,405 27,956 22,444 Other 6,136 8,865 9,180 Total regulatory assets $ 398,747 $ 395,141 $ 345,300 Regulatory liabilities: Postretirement benefits $ 16,715 $ 17,519 $ 19,671 Deferred fuel and power refunds 12,587 22,299 34,432 State tax benefits — distribution system repairs 16,662 15,086 14,604 Other 2,706 665 1,149 Total regulatory liabilities (a) $ 48,670 $ 55,569 $ 69,856 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. |
Defined Benefit Pension and O24
Defined Benefit Pension and Other Postretirement Plans (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Defined Benefit Plan [Abstract] | |
Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs | Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, 2017 2016 2017 2016 Service cost $ 2,023 $ 1,731 $ 62 $ 46 Interest cost 5,540 5,818 108 116 Expected return on assets (7,497 ) (7,167 ) (164 ) (149 ) Amortization of: Prior service cost (benefit) 81 87 (160 ) (160 ) Actuarial loss 3,706 2,393 28 24 Net benefit cost (income) 3,853 2,862 (126 ) (123 ) Change in associated regulatory liabilities — — (123 ) 878 Net benefit cost (income) after change in regulatory liabilities $ 3,853 $ 2,862 $ (249 ) $ 755 Pension Benefits Other Postretirement Benefits Nine Months Ended June 30, 2017 2016 2017 2016 Service cost $ 6,068 $ 5,195 $ 184 $ 137 Interest cost 16,618 17,453 323 349 Expected return on assets (22,490 ) (21,502 ) (492 ) (447 ) Amortization of: Prior service cost (benefit) 244 261 (480 ) (480 ) Actuarial loss 11,119 7,179 85 73 Net benefit cost (income) 11,559 8,586 (380 ) (368 ) Change in associated regulatory liabilities — — (368 ) 2,632 Net benefit cost (income) after change in regulatory liabilities $ 11,559 $ 8,586 $ (748 ) $ 2,264 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Financial Assets and Financial Liabilities that are 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 of June 30, 2017 , September 30, 2016 and June 30, 2016 : Asset (Liability) Level 1 Level 2 Level 3 Total June 30, 2017: Assets: Commodity contracts $ 1,062 $ 101 $ — $ 1,163 Liabilities: Commodity contracts $ (1,157 ) $ (68 ) $ — $ (1,225 ) September 30, 2016: Assets: Commodity contracts $ 4,506 $ 4 $ — $ 4,510 Liabilities: Commodity contracts $ (263 ) $ (294 ) $ — $ (557 ) June 30, 2016: Assets: Commodity contracts $ 5,715 $ 3 $ — $ 5,718 Liabilities: Commodity contracts $ (341 ) $ (391 ) $ — $ (732 ) |
Schedule of Carrying Amount and Estimated Fair Value of Long-term Debt | The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at June 30, 2017 , September 30, 2016 and June 30, 2016 were as follows: June 30, 2017 September 30, 2016 June 30, 2016 Carrying amount $ 755,000 $ 675,000 $ 650,000 Estimated fair value $ 788,472 $ 770,781 $ 747,588 |
Derivative Instruments and He26
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Balance Sheet Location and Fair Value of Derivative Assets and Liabilities | The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of June 30, 2017 , September 30, 2016 and June 30, 2016 : June 30, 2017 September 30, 2016 June 30, 2016 Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 1,163 $ 4,472 $ 5,718 Derivatives not subject to PGC and DS mechanisms: Commodity contracts — 38 — Total derivative assets — gross 1,163 4,510 5,718 Gross amounts offset in the balance sheet (159 ) (247 ) (225 ) Total derivative assets — net (a) $ 1,004 $ 4,263 $ 5,493 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (1,204 ) $ (499 ) $ (593 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts (21 ) (58 ) (139 ) Total derivative liabilities — gross (1,225 ) (557 ) (732 ) Gross amounts offset in the balance sheet 159 247 225 Total derivative liabilities — net (a) $ (1,066 ) $ (310 ) $ (507 ) |
Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest | The following table provides information on the effects of derivative instruments not subject to ratemaking mechanisms on the Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30, 2017 and 2016 : Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Three Months Ended June 30, 2017 2016 2017 2016 Cash Flow Hedges: Interest rate contracts $ — $ — $ (856 ) $ (610 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Three Months Ended June 30, 2017 2016 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (57 ) $ 27 Operating and administrative expenses Loss Recognized in AOCI Loss Reclassified from AOCI into Income Location of Loss Reclassified from AOCI into Income Nine Months Ended June 30, 2017 2016 2017 2016 Cash Flow Hedges: Interest rate contracts $ — $ (28,959 ) $ (2,524 ) $ (1,885 ) Interest expense Loss Recognized in Income Location of Loss Recognized in Income Nine Months Ended June 30, 2017 2016 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (25 ) $ (93 ) Operating and administrative expenses |
Accumulated Other Comprehensi27
Accumulated Other Comprehensive Income (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Equity [Abstract] | |
Schedule of Changes in Accumulated Other Comprehensive Income | The tables below present changes in AOCI, net of tax, during the three and nine months ended June 30, 2017 and 2016 : Three Months Ended June 30, 2017 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2017 $ (11,356 ) $ (18,808 ) $ (30,164 ) Reclassifications of benefit plan actuarial losses and prior service costs 239 — 239 Reclassifications of net losses on IRPAs — 501 501 AOCI — June 30, 2017 $ (11,117 ) $ (18,307 ) $ (29,424 ) Three Months Ended June 30, 2016 Postretirement Benefit Plans Derivative Instruments Total AOCI — March 31, 2016 $ (8,956 ) $ (20,607 ) $ (29,563 ) Reclassifications of benefit plan actuarial losses and prior service costs 160 — 160 Reclassifications of net losses on IRPAs — 357 357 AOCI — June 30, 2016 $ (8,796 ) $ (20,250 ) $ (29,046 ) Nine Months Ended June 30, 2017 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2016 $ (11,834 ) $ (19,784 ) $ (31,618 ) Reclassifications of benefit plans actuarial losses and prior service costs 717 — 717 Reclassifications of net losses on IRPAs — 1,477 1,477 AOCI — June 30, 2017 $ (11,117 ) $ (18,307 ) $ (29,424 ) Nine Months Ended June 30, 2016 Postretirement Benefit Plans Derivative Instruments Total AOCI — September 30, 2015 $ (9,276 ) $ (4,410 ) $ (13,686 ) Net losses on IRPAs — (16,943 ) (16,943 ) Reclassifications of benefit plans actuarial losses and prior service costs 480 — 480 Reclassifications of net losses on IRPAs — 1,103 1,103 AOCI — June 30, 2016 $ (8,796 ) $ (20,250 ) $ (29,046 ) |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Jun. 30, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Segment Information | Financial information by business segment follows: Reportable Segments Three Months Ended June 30, 2017 Total Gas Utility Electric Utility Revenues $ 146,692 $ 127,849 $ 18,843 Cost of sales — gas, fuel and purchased power $ 51,979 $ 42,180 $ 9,799 Depreciation and amortization $ 17,912 $ 16,845 $ 1,067 Operating income $ 27,671 $ 25,628 $ 2,043 Interest expense $ 10,128 $ 9,601 $ 527 Income before income taxes $ 17,543 $ 16,027 $ 1,516 Capital expenditures (including the effects of accruals) $ 79,088 $ 75,836 $ 3,252 Reportable Segments Three Months Ended June 30, 2016 Total Gas Utility Electric Utility Revenues $ 140,283 $ 119,995 $ 20,288 Cost of sales — gas, fuel and purchased power $ 44,415 $ 33,715 $ 10,700 Depreciation and amortization $ 16,550 $ 15,339 $ 1,211 Operating income $ 29,815 $ 27,116 $ 2,699 Interest expense $ 9,158 $ 8,670 $ 488 Income before income taxes $ 20,657 $ 18,446 $ 2,211 Capital expenditures (including the effects of accruals) $ 56,481 $ 53,199 $ 3,282 Reportable Segments Nine Months Ended June 30, 2017 Total Gas Utility Electric Utility Revenues $ 768,045 $ 700,813 $ 67,232 Cost of sales — gas, fuel and purchased power $ 325,991 $ 288,610 $ 37,381 Depreciation and amortization $ 53,002 $ 49,378 $ 3,624 Operating income $ 226,315 $ 219,700 $ 6,615 Interest expense $ 30,478 $ 29,017 $ 1,461 Income before income taxes $ 195,837 $ 190,683 $ 5,154 Capital expenditures (including the effects of accruals) $ 199,701 $ 191,715 $ 7,986 As of June 30, 2017 Total assets $ 2,904,532 $ 2,743,035 $ 161,497 Goodwill $ 182,145 $ 182,145 $ — Reportable Segments Nine Months Ended June 30, 2016 Total Gas Utility Electric Utility Revenues $ 660,312 $ 595,025 $ 65,287 Cost of sales — gas, fuel and purchased power $ 257,288 $ 221,646 $ 35,642 Depreciation and amortization $ 50,281 $ 46,665 $ 3,616 Operating income $ 192,592 $ 183,940 $ 8,652 Interest expense $ 27,922 $ 26,583 $ 1,339 Income before income taxes $ 164,670 $ 157,357 $ 7,313 Capital expenditures (including the effects of accruals) $ 166,058 $ 158,472 $ 7,586 As of June 30, 2016 Total assets $ 2,697,301 $ 2,531,573 $ 165,728 Goodwill $ 182,145 $ 182,145 $ — |
Nature of Operations (Details)
Nature of Operations (Details) | 9 Months Ended |
Jun. 30, 2017county | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of counties of operation | 1 |
Summary of Significant Accoun30
Summary of Significant Accounting Policies (Details) $ in Thousands | Jun. 30, 2016USD ($) |
Accounting Policies [Abstract] | |
Debt issuance costs | $ 2,597 |
Inventories - Schedule of Inven
Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Public Utilities, Inventory | |||
Total inventories | $ 37,129 | $ 42,340 | $ 27,009 |
Gas Utility natural gas | |||
Public Utilities, Inventory | |||
Total inventories | 21,826 | 29,223 | 13,561 |
Materials, supplies and other | |||
Public Utilities, Inventory | |||
Total inventories | $ 15,303 | $ 13,117 | $ 13,448 |
Inventories - Narrative (Detail
Inventories - Narrative (Details) $ in Thousands | 9 Months Ended | ||
Jun. 30, 2017USD ($)agreementBcf | Sep. 30, 2016USD ($)Bcf | Jun. 30, 2016USD ($)Bcf | |
Public Utilities, Inventory | |||
Number of storage agreements | 5 | ||
Number of storage agreements with Energy Services | 4 | ||
Number of storage agreements with non-affiliates | 1 | ||
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf | 4.8 | 8.1 | 4.6 |
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $ | $ 14,146 | $ 18,773 | $ 8,390 |
Security deposit liability | $ | $ 15,040 | $ 19,100 | $ 15,100 |
Minimum | |||
Public Utilities, Inventory | |||
Term of agreements (in years) | 1 year | ||
Maximum | |||
Public Utilities, Inventory | |||
Term of agreements (in years) | 3 years |
Regulatory Assets and Liabili33
Regulatory Assets and Liabilities and Regulatory Matters - Schedule of Regulatory Assets and Liabilities Associated With Gas Utility and Electric Utility (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Regulatory Assets | |||
Regulatory assets | $ 398,747 | $ 395,141 | $ 345,300 |
Regulatory Liabilities | |||
Regulatory liabilities | 48,670 | 55,569 | 69,856 |
Postretirement benefits | |||
Regulatory Liabilities | |||
Regulatory liabilities | 16,715 | 17,519 | 19,671 |
Deferred fuel and power refunds | |||
Regulatory Liabilities | |||
Regulatory liabilities | 12,587 | 22,299 | 34,432 |
State tax benefits — distribution system repairs | |||
Regulatory Liabilities | |||
Regulatory liabilities | 16,662 | 15,086 | 14,604 |
Other | |||
Regulatory Liabilities | |||
Regulatory liabilities | 2,706 | 665 | 1,149 |
Income taxes recoverable | |||
Regulatory Assets | |||
Regulatory assets | 122,733 | 115,643 | 119,604 |
Underfunded pension and postretirement plans | |||
Regulatory Assets | |||
Regulatory assets | 171,833 | 183,129 | 133,356 |
Environmental costs | |||
Regulatory Assets | |||
Regulatory assets | 61,616 | 59,397 | 60,716 |
Deferred fuel and power costs | |||
Regulatory Assets | |||
Regulatory assets | 7,024 | 151 | 0 |
Removal costs, net | |||
Regulatory Assets | |||
Regulatory assets | 29,405 | 27,956 | 22,444 |
Other | |||
Regulatory Assets | |||
Regulatory assets | $ 6,136 | $ 8,865 | $ 9,180 |
Regulatory Assets and Liabili34
Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Thousands | Oct. 20, 2017 | Jul. 01, 2017 | Jan. 19, 2017 | Jan. 01, 2017 | Oct. 14, 2016 | Apr. 01, 2016 | Apr. 01, 2015 | Mar. 31, 2016 | Jun. 30, 2017 | Sep. 30, 2014 | Sep. 30, 2016 | Jun. 30, 2016 |
Pennsylvania PUC | ||||||||||||
Regulatory Assets | ||||||||||||
Maximum period post petition to file general rate filing (in years) | 5 years | |||||||||||
Pennsylvania PUC | Maximum | ||||||||||||
Regulatory Assets | ||||||||||||
Distribution system improvement charge, percent of amount billed to customers | 5.00% | 5.00% | 0.00% | |||||||||
Pennsylvania PUC | PNG | ||||||||||||
Regulatory Assets | ||||||||||||
Requested operating revenue increase | $ 21,700 | |||||||||||
Pennsylvania PUC | PNG | Subsequent Event | ||||||||||||
Regulatory Assets | ||||||||||||
Distribution system improvement charge, percent of amount billed to customers | 7.50% | |||||||||||
Pennsylvania PUC | PNG | Maximum | ||||||||||||
Regulatory Assets | ||||||||||||
Distribution system improvement charge, percent of amount billed to customers | 0.00% | 10.00% | ||||||||||
Pennsylvania PUC | PNG | Forecast | ||||||||||||
Regulatory Assets | ||||||||||||
Increase in annual base distribution rate | $ 11,250 | |||||||||||
Pennsylvania PUC | UGI Gas | ||||||||||||
Regulatory Assets | ||||||||||||
Increase in annual base distribution rate | $ 27,000 | |||||||||||
Pennsylvania PUC | CPG | Subsequent Event | ||||||||||||
Regulatory Assets | ||||||||||||
Distribution system improvement charge, percent of amount billed to customers | 7.50% | |||||||||||
Pennsylvania PUC | CPG | Maximum | ||||||||||||
Regulatory Assets | ||||||||||||
Distribution system improvement charge, percent of amount billed to customers | 0.00% | 10.00% | ||||||||||
Gas Utility | ||||||||||||
Regulatory Assets | ||||||||||||
Fair value of unrealized gains (losses) | $ (73) | $ 4,263 | $ 5,483 |
Debt (Details)
Debt (Details) - Senior Notes - Senior Notes due October 2046 | Oct. 31, 2016USD ($) |
Debt Instrument [Line Items] | |
Aggregate principal amount | $ 100,000,000 |
Stated interest rate | 4.12% |
Commitments and Contingencies (
Commitments and Contingencies (Details) | 9 Months Ended | ||
Jun. 30, 2017USD ($)subsidiary | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | |
UGI Gas | Environmental Issue | |||
Loss Contingencies [Line Items] | |||
Environmental expenditures cap during year | $ 2,500,000 | ||
CPG MGP | Environmental Issue | |||
Loss Contingencies [Line Items] | |||
Environmental expenditures cap during year | 1,800,000 | ||
PNG MGP | Environmental Issue | |||
Loss Contingencies [Line Items] | |||
Environmental expenditures cap during year | $ 1,100,000 | ||
PNG-COA | |||
Loss Contingencies [Line Items] | |||
Option to termination agreement by either party effective at end of any two-year period beginning with the original effective date in March 2004 (in years) | 2 years | ||
CPG, PNG and UGI Gas COAs | |||
Loss Contingencies [Line Items] | |||
Accrual for environmental loss contingencies | $ 55,185,000 | $ 55,063,000 | $ 56,006,000 |
PNG and CPG | |||
Loss Contingencies [Line Items] | |||
Number of subsidiaries acquired with similar histories | subsidiary | 2 |
Defined Benefit Pension and O37
Defined Benefit Pension and Other Postretirement Plans - Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Pension Benefits | ||||
Defined Benefit Plan Disclosure | ||||
Service cost | $ 2,023 | $ 1,731 | $ 6,068 | $ 5,195 |
Interest cost | 5,540 | 5,818 | 16,618 | 17,453 |
Expected return on assets | (7,497) | (7,167) | (22,490) | (21,502) |
Amortization of: | ||||
Prior service cost (benefit) | 81 | 87 | 244 | 261 |
Actuarial loss | 3,706 | 2,393 | 11,119 | 7,179 |
Net benefit cost (income) | 3,853 | 2,862 | 11,559 | 8,586 |
Change in associated regulatory liabilities | 0 | 0 | 0 | 0 |
Net benefit cost (income) after change in regulatory liabilities | 3,853 | 2,862 | 11,559 | 8,586 |
Other Postretirement Benefits | ||||
Defined Benefit Plan Disclosure | ||||
Service cost | 62 | 46 | 184 | 137 |
Interest cost | 108 | 116 | 323 | 349 |
Expected return on assets | (164) | (149) | (492) | (447) |
Amortization of: | ||||
Prior service cost (benefit) | (160) | (160) | (480) | (480) |
Actuarial loss | 28 | 24 | 85 | 73 |
Net benefit cost (income) | (126) | (123) | (380) | (368) |
Change in associated regulatory liabilities | (123) | 878 | (368) | 2,632 |
Net benefit cost (income) after change in regulatory liabilities | $ (249) | $ 755 | $ (748) | $ 2,264 |
Defined Benefit Pension and O38
Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($) | 9 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Pension Benefits | ||
Defined Benefit Plan Disclosure | ||
Contribution made to Pension Plan | $ 8,546,000 | $ 7,402,000 |
Expected contribution to pensions plans in the remainder of current fiscal year | 2,800,000 | |
VEBA | ||
Defined Benefit Plan Disclosure | ||
Contribution made to Pension Plan | $ 0 | $ 0 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Assets and Financial Liabilities That are Measured at Fair Value on a Recurring Basis (Details) - Fair Value, Measurements, Recurring - Commodity contracts - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Assets: | |||
Derivative assets | $ 1,163 | $ 4,510 | $ 5,718 |
Liabilities: | |||
Derivative liabilities | (1,225) | (557) | (732) |
Level 1 | |||
Assets: | |||
Derivative assets | 1,062 | 4,506 | 5,715 |
Liabilities: | |||
Derivative liabilities | (1,157) | (263) | (341) |
Level 2 | |||
Assets: | |||
Derivative assets | 101 | 4 | 3 |
Liabilities: | |||
Derivative liabilities | (68) | (294) | (391) |
Level 3 | |||
Assets: | |||
Derivative assets | 0 | 0 | 0 |
Liabilities: | |||
Derivative liabilities | $ 0 | $ 0 | $ 0 |
Fair Value Measurements - Long-
Fair Value Measurements - Long-term Debt (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Carrying amount | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term debt | $ 755,000 | $ 675,000 | $ 650,000 |
Estimated fair value | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term debt | $ 788,472 | $ 770,781 | $ 747,588 |
Derivative Instruments and He41
Derivative Instruments and Hedging Activities - Narrative (Details) kWh in Millions, MMBTU in Millions | 9 Months Ended | ||
Jun. 30, 2017USD ($)kWhMMBTU | Sep. 30, 2016USD ($)kWhMMBTU | Jun. 30, 2016USD ($)kWhMMBTU | |
Derivative | |||
Restricted cash in brokerage accounts | $ 2,524,000 | $ 583,000 | $ 212,000 |
IRPAs | |||
Derivative | |||
Notional amount of unsettled IRPA contracts | 0 | $ 0 | $ 0 |
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months | $ (3,485,000) | ||
Gas Utility | |||
Derivative | |||
Notional amount (energy measure) (in mmbtu) | MMBTU | 12.7 | 18.4 | 13.4 |
Maximum length of time hedged in price risk cash flow hedges (in months) | 15 months | ||
Electric Utility | Electric Utility Electric Transmission Congestion | |||
Derivative | |||
Notional amount (energy measure) (in mmbtu) | kWh | 139.4 | 58.3 | 80.6 |
Maximum length of time hedged in price risk cash flow hedges (in months) | 11 months |
Derivative Instruments and He42
Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2017 | Sep. 30, 2016 | Jun. 30, 2016 |
Derivative assets | |||
Derivative assets: | |||
Derivative assets | $ 1,163 | $ 4,510 | $ 5,718 |
Gross amounts offset in the balance sheet | (159) | (247) | (225) |
Total derivative assets — net (a) | 1,004 | 4,263 | 5,493 |
Derivative assets | Derivatives subject to PGC and DS mechanisms | Commodity contracts | |||
Derivative assets: | |||
Derivative assets | 1,163 | 4,472 | 5,718 |
Derivative assets | Derivatives not subject to PGC and DS mechanisms | Commodity contracts | |||
Derivative assets: | |||
Derivative assets | 0 | 38 | 0 |
Derivative liabilities | |||
Derivative liabilities: | |||
Derivative liabilities | (1,225) | (557) | (732) |
Gross amounts offset in the balance sheet | 159 | 247 | 225 |
Total derivative liabilities — net (a) | (1,066) | (310) | (507) |
Derivative liabilities | Derivatives subject to PGC and DS mechanisms | Commodity contracts | |||
Derivative liabilities: | |||
Derivative liabilities | (1,204) | (499) | (593) |
Derivative liabilities | Derivatives not subject to PGC and DS mechanisms | Commodity contracts | |||
Derivative liabilities: | |||
Derivative liabilities | $ (21) | $ (58) | $ (139) |
Derivative Instruments and He43
Derivative Instruments and Hedging Activities - Effects of Derivatives on Statements of Income and AOCI (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Derivatives Not Subject To PGC And DS Mechanisms | Gasoline contracts | Operating and administrative expenses | ||||
Derivative Instruments, Gain (Loss) | ||||
Loss Recognized in Income | $ (57) | $ 27 | $ (25) | $ (93) |
Cash Flow Hedges | Interest rate contracts | ||||
Derivative Instruments, Gain (Loss) | ||||
Loss Recognized in AOCI | 0 | 0 | 0 | (28,959) |
Cash Flow Hedges | Interest rate contracts | Interest expense | ||||
Derivative Instruments, Gain (Loss) | ||||
Loss Reclassified from AOCI into Income | $ (856) | $ (610) | $ (2,524) | $ (1,885) |
Accumulated Other Comprehensi44
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | $ 924,737 | |||
Reclassifications, net of tax | $ 239 | $ 160 | 717 | $ 480 |
AOCI, net of tax - end balance | 1,007,018 | 938,899 | 1,007,018 | 938,899 |
IRPAs | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
Net losses on IRPAs | (16,943) | |||
Reclassifications, net of tax | 501 | 357 | 1,477 | 1,103 |
Postretirement Benefit Plans | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | (11,356) | (8,956) | (11,834) | (9,276) |
Reclassifications, net of tax | 239 | 160 | 717 | 480 |
AOCI, net of tax - end balance | (11,117) | (8,796) | (11,117) | (8,796) |
Postretirement Benefit Plans | IRPAs | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
Net losses on IRPAs | 0 | |||
Reclassifications, net of tax | 0 | 0 | 0 | 0 |
Derivative Instruments | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | (18,808) | (20,607) | (19,784) | (4,410) |
Reclassifications, net of tax | 0 | 0 | 0 | 0 |
AOCI, net of tax - end balance | (18,307) | (20,250) | (18,307) | (20,250) |
Derivative Instruments | IRPAs | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
Net losses on IRPAs | (16,943) | |||
Reclassifications, net of tax | 501 | 357 | 1,477 | 1,103 |
Total | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | (30,164) | (29,563) | (31,618) | (13,686) |
AOCI, net of tax - end balance | $ (29,424) | $ (29,046) | $ (29,424) | $ (29,046) |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Jun. 30, 2017USD ($)Bcf | Jun. 30, 2016USD ($)Bcf | Jun. 30, 2017USD ($)Bcf | Jun. 30, 2016USD ($)Bcf | Sep. 30, 2016USD ($)Bcf | |
Related Party Transaction | |||||
Related party costs incurred | $ 2,961 | $ 2,811 | $ 10,059 | $ 8,789 | |
UGI and Subsidiaries | Administrative Services | |||||
Related Party Transaction | |||||
Amount of related party transaction | $ 562 | $ 1,752 | $ 3,420 | $ 3,904 | |
Energy Services | |||||
Related Party Transaction | |||||
Volume of gas storage inventory (in bcf of natural gas) | Bcf | 3.6 | 2.7 | 3.6 | 2.7 | 4.6 |
Natural gas storage inventory, related parties, current | $ 10,662 | $ 5,100 | $ 10,662 | $ 5,100 | $ 11,148 |
Revenue from related parties | 10,554 | 4,514 | $ 43,836 | 26,134 | |
Term of agreements (in years) | 1 year | ||||
Purchases from related party | 14,675 | 6,928 | $ 75,783 | 30,032 | |
Energy Services | SCAAs | |||||
Related Party Transaction | |||||
Amount of related party transaction | 729 | 493 | $ 2,027 | 1,510 | |
SCAA contract term (in years) | 3 years | ||||
Related party costs incurred | 9,777 | 4,358 | $ 12,272 | 6,387 | |
Related party security deposits | 11,040 | 8,100 | 11,040 | 8,100 | $ 8,100 |
Energy Services | Exclusive of Transactions Pursuant SCAAs | |||||
Related Party Transaction | |||||
Related party costs incurred | $ 2,137 | $ 2,138 | $ 73,872 | $ 61,193 |
Segment Information - Narrative
Segment Information - Narrative (Details) | 9 Months Ended |
Jun. 30, 2017segmentcounty | |
Segment Reporting [Abstract] | |
Number of reportable segments | segment | 2 |
Segment Reporting Information | |
Number of counties of operation | 1 |
Electric Utility | |
Segment Reporting Information | |
Number of counties of operation | 2 |
Segment Information - Schedule
Segment Information - Schedule of Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Sep. 30, 2016 | |
Segment Reporting Information | |||||
Revenues | $ 146,692 | $ 140,283 | $ 768,045 | $ 660,312 | |
Cost of sales — gas, fuel and purchased power | 51,979 | 44,415 | 325,991 | 257,288 | |
Depreciation and amortization | 17,912 | 16,550 | 53,002 | 50,281 | |
Operating income | 27,671 | 29,815 | 226,315 | 192,592 | |
Interest expense | 10,128 | 9,158 | 30,478 | 27,922 | |
Income before income taxes | 17,543 | 20,657 | 195,837 | 164,670 | |
Capital expenditures (including the effects of accruals) | 79,088 | 56,481 | 199,701 | 166,058 | |
Total assets | 2,904,532 | 2,697,301 | 2,904,532 | 2,697,301 | $ 2,743,091 |
Goodwill | 182,145 | 182,145 | 182,145 | 182,145 | $ 182,145 |
Gas Utility | |||||
Segment Reporting Information | |||||
Revenues | 127,849 | 119,995 | 700,813 | 595,025 | |
Cost of sales — gas, fuel and purchased power | 42,180 | 33,715 | 288,610 | 221,646 | |
Depreciation and amortization | 16,845 | 15,339 | 49,378 | 46,665 | |
Operating income | 25,628 | 27,116 | 219,700 | 183,940 | |
Interest expense | 9,601 | 8,670 | 29,017 | 26,583 | |
Income before income taxes | 16,027 | 18,446 | 190,683 | 157,357 | |
Capital expenditures (including the effects of accruals) | 75,836 | 53,199 | 191,715 | 158,472 | |
Total assets | 2,743,035 | 2,531,573 | 2,743,035 | 2,531,573 | |
Goodwill | 182,145 | 182,145 | 182,145 | 182,145 | |
Electric Utility | |||||
Segment Reporting Information | |||||
Revenues | 18,843 | 20,288 | 67,232 | 65,287 | |
Cost of sales — gas, fuel and purchased power | 9,799 | 10,700 | 37,381 | 35,642 | |
Depreciation and amortization | 1,067 | 1,211 | 3,624 | 3,616 | |
Operating income | 2,043 | 2,699 | 6,615 | 8,652 | |
Interest expense | 527 | 488 | 1,461 | 1,339 | |
Income before income taxes | 1,516 | 2,211 | 5,154 | 7,313 | |
Capital expenditures (including the effects of accruals) | 3,252 | 3,282 | 7,986 | 7,586 | |
Total assets | 161,497 | 165,728 | 161,497 | 165,728 | |
Goodwill | $ 0 | $ 0 | $ 0 | $ 0 |