Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Jun. 30, 2015 | Jul. 31, 2015 | |
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, 2015 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,015 | |
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, 2015 | Sep. 30, 2014 | Jun. 30, 2014 |
Current assets: | |||
Cash and cash equivalents | $ 16,522 | $ 12,401 | $ 28,480 |
Restricted cash | 3,683 | 3,592 | 1,109 |
Accounts receivable (less allowances for doubtful accounts of $12,534, $6,992 and $13,517, respectively) | 89,340 | 65,080 | 97,144 |
Accounts receivable — related parties | 2,039 | 2,865 | 3,484 |
Accrued utility revenues | 7,716 | 14,330 | 7,950 |
Inventories | 33,376 | 95,219 | 58,750 |
Deferred income taxes | 29,904 | 1,492 | 11,908 |
Regulatory assets | 2,763 | 13,159 | 9,354 |
Derivative instruments | 1,285 | 1,028 | 1,703 |
Prepaid expenses & other current assets | 13,551 | 18,535 | 11,057 |
Total current assets | 200,179 | 227,701 | 230,939 |
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $918,311, $886,268 and $888,279, respectively) | 1,781,668 | 1,682,284 | 1,635,867 |
Goodwill | 182,145 | 182,145 | 182,145 |
Regulatory assets | 251,479 | 255,007 | 233,272 |
Derivative instruments | 111 | 0 | 0 |
Other assets | 7,623 | 7,506 | 7,618 |
Total assets | 2,423,205 | 2,354,643 | 2,289,841 |
Current liabilities: | |||
Current maturities of long-term debt | 72,000 | 20,000 | 20,000 |
Short-term borrowings | 2,700 | 86,300 | 0 |
Accounts payable | 44,687 | 58,453 | 47,396 |
Accounts payable — related parties | 5,477 | 11,761 | 21,131 |
Deferred fuel refunds | 45,564 | 306 | 0 |
Derivative instruments | 4,412 | 1,632 | 31 |
Other current liabilities | 151,760 | 99,030 | 140,404 |
Total current liabilities | 326,600 | 277,482 | 228,962 |
Long-term debt | 550,000 | 622,000 | 622,000 |
Deferred income taxes | 478,108 | 461,461 | 454,871 |
Deferred investment tax credits | 3,681 | 3,933 | 4,017 |
Pension and postretirement benefit obligations | 91,804 | 98,363 | 61,991 |
Other noncurrent liabilities | 50,752 | 51,567 | 53,439 |
Total liabilities | $ 1,500,945 | $ 1,514,806 | $ 1,425,280 |
Commitments and contingencies | |||
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 | 471,796 | 471,071 | 470,844 |
Retained earnings | 396,823 | 316,688 | 340,714 |
Accumulated other comprehensive loss | (6,618) | (8,181) | (7,256) |
Total common stockholder’s equity | 922,260 | 839,837 | 864,561 |
Total liabilities and stockholder’s equity | $ 2,423,205 | $ 2,354,643 | $ 2,289,841 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Jun. 30, 2015 | Sep. 30, 2014 | Jun. 30, 2014 |
Statement of Financial Position [Abstract] | |||
Allowance for doubtful accounts | $ 12,534 | $ 6,992 | $ 13,517 |
Accumulated depreciation and amortization | $ 918,311 | $ 886,268 | $ 888,279 |
Common stock, par value | $ 2.25 | $ 2.25 | $ 2.25 |
Common stock, shares authorized | 40,000,000 | 40,000,000 | 40,000,000 |
Common stock, shares issued | 26,781,785 | 26,781,785 | 26,781,785 |
Common stock, shares outstanding | 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, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Statement [Abstract] | ||||
Revenues | $ 143,490 | $ 152,694 | $ 931,369 | $ 965,549 |
Costs and expenses: | ||||
Cost of sales — gas, fuel and purchased power (excluding depreciation shown below) | 53,691 | 63,323 | 475,079 | 515,612 |
Operating and administrative expenses | 51,393 | 49,862 | 156,858 | 145,313 |
Operating and administrative expenses — related parties | 2,647 | 2,385 | 9,567 | 7,997 |
Taxes other than income taxes | 3,706 | 3,768 | 12,613 | 12,748 |
Depreciation | 14,985 | 14,048 | 44,300 | 41,485 |
Amortization | 928 | 844 | 2,682 | 2,500 |
Other operating income, net | (4,044) | (1,256) | (8,253) | (3,623) |
Total costs and expenses | 123,306 | 132,974 | 692,846 | 722,032 |
Operating income | 20,184 | 19,720 | 238,523 | 243,517 |
Interest expense | 9,985 | 10,433 | 31,245 | 28,036 |
Income before income taxes | 10,199 | 9,287 | 207,278 | 215,481 |
Income taxes | 2,892 | 2,397 | 81,543 | 87,195 |
Net income | $ 7,307 | $ 6,890 | $ 125,735 | $ 128,286 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 7,307 | $ 6,890 | $ 125,735 | $ 128,286 |
Other comprehensive income: | ||||
Reclassifications of net losses on derivative instruments (net of tax of $(277), $(278), $(833) and $(834), respectively) | 392 | 393 | 1,175 | 1,176 |
Benefit plans reclassifications of actuarial losses and prior service costs (net of tax of $(92), $(67), $(275) and $(206), respectively) | 128 | 95 | 388 | 288 |
Other comprehensive income | 520 | 488 | 1,563 | 1,464 |
Comprehensive income | $ 7,827 | $ 7,378 | $ 127,298 | $ 129,750 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Statement of Comprehensive Income [Abstract] | ||||
Reclassifications of net losses on derivative instruments | $ (277) | $ (278) | $ (833) | $ (834) |
Benefit plans reclassifications of actuarial losses and prior service costs | $ (92) | $ (67) | $ (275) | $ (206) |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net income | $ 125,735 | $ 128,286 |
Adjustments to reconcile net income to net cash from operating activities: | ||
Depreciation and amortization | 46,982 | 43,985 |
Deferred income taxes, net | (10,417) | 18,747 |
Provision for uncollectible accounts | 10,997 | 11,657 |
Other, net | 526 | (2,809) |
Net change in: | ||
Accounts receivable and accrued utility revenues | (27,817) | (44,530) |
Inventories | 61,843 | 30,911 |
Deferred fuel and power costs, net of changes in unsettled derivatives | 59,397 | (17,611) |
Accounts payable | (14,884) | 4,070 |
Other current assets | 631 | 4,690 |
Other current liabilities | 47,939 | 27,947 |
Net cash provided by operating activities | 300,932 | 205,343 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Expenditures for property, plant and equipment | (141,884) | (104,117) |
Net costs of property, plant and equipment disposals | (6,358) | (5,222) |
(Increase) decrease in restricted cash | (91) | 2,072 |
Net cash used by investing activities | (148,333) | (107,267) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Payment of dividends | (45,600) | (57,549) |
Issuances of long-term debt | 0 | 175,000 |
Repayments of long-term debt | (20,000) | (175,000) |
Decrease in short-term borrowings | (83,600) | (17,500) |
Other | 722 | 746 |
Net cash used by financing activities | (148,478) | (74,303) |
Cash and cash equivalents increase | 4,121 | 23,773 |
CASH AND CASH EQUIVALENTS: | ||
End of period | 16,522 | 28,480 |
Beginning of period | $ 12,401 | $ 4,707 |
Nature of Operations
Nature of Operations | 9 Months Ended |
Jun. 30, 2015 | |
Nature of Operations [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.” Prior to June 1, 2015, PNG also had a heating, ventilation and air-conditioning service business (“UGI Penn HVAC Services, Inc.”) which operated principally in the PNG service territory (“HVAC Business”). The assets of the HVAC business principally comprising customer contracts were sold on June 1, 2015. The sale did not have a material impact on the condensed consolidated financial statements. 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, 2015 | |
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, 2014 , 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, 2014 (“the Company’s 2014 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. 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. |
Accounting Changes
Accounting Changes | 9 Months Ended |
Jun. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Changes | Note 3 — Accounting Changes Accounting Standards Not Yet Adopted Measurement of Inventory. In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-11, "Simplifying the Measurement of Inventory." This ASU amends existing guidance to require inventory to be measured at the lower of cost or net realizable value. Entities will continue to apply their existing impairment models to inventories that are accounted for using “last-in, first-out” and the “retail inventory” methods. The amendments in this ASU are effective for annual periods beginning after December 15, 2016 (Fiscal 2018) including interim periods within those fiscal years. Early adoption is permitted. Entities will apply the new guidance prospectively after the date of adoption. The adoption is not expected to have a material impact on the Company’s financial statements. Debt Issuance Costs. In April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 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 company expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On July 9, 2015, the FASB voted to delay the effective date by one year. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements. |
Inventories
Inventories | 9 Months Ended |
Jun. 30, 2015 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 4 — Inventories Inventories comprise the following: June 30, 2015 September 30, 2014 June 30, 2014 Gas Utility natural gas $ 19,205 $ 82,664 $ 45,701 Materials, supplies and other 14,171 12,555 13,049 Total inventories $ 33,376 $ 95,219 $ 58,750 At June 30, 2015 , UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) having terms of three years. Two of the SCAAs are with 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 value of gas storage inventories released under the SCAAs at June 30, 2015 , September 30, 2014 and June 30, 2014 , comprising 4.5 billion cubic feet (“bcf”), 11.6 bcf and 6.1 bcf of natural gas, was $11,337 , $49,897 and $28,299 , respectively. At June 30, 2015 , September 30, 2014 and June 30, 2014 , UGI Utilities held a total of $17,700 , $17,600 and $17,600 , respectively, of security deposits from its SCAA counterparties. These amounts are included in other current liabilities on the Condensed Consolidated Balance Sheets. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities and Regulatory Matters | 9 Months Ended |
Jun. 30, 2015 | |
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 2014 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: June 30, 2015 September 30, 2014 June 30, 2014 Regulatory assets: Income taxes recoverable $ 111,807 $ 110,709 $ 107,166 Underfunded pension and postretirement plans 103,250 110,116 89,236 Environmental costs 14,441 14,616 14,581 Deferred fuel and power costs — 11,732 9,354 Removal costs, net 19,635 16,790 15,620 Other 5,109 4,203 6,669 Total regulatory assets $ 254,242 $ 268,166 $ 242,626 Regulatory liabilities: Postretirement benefits $ 19,687 $ 18,594 $ 17,545 Environmental overcollections — 349 1,631 Deferred fuel and power refunds 45,564 306 — State tax benefits — distribution system repairs 10,894 10,076 9,271 Other 1,377 3,172 1,862 Total regulatory liabilities (a) $ 77,522 $ 32,497 $ 30,309 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. Deferred fuel and power — costs and refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at June 30, 2015 , September 30, 2014 , and June 30, 2014 , were $(729) , $(1,363) and $680 , respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Previous to March 1, 2015, we did not designate these purchase contracts as an NPNS election under GAAP. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At June 30, 2015 , September 30, 2014 , and June 30, 2014 , the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(1,428) , $345 and $760 , respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet (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, 2015 , September 30, 2014 , and June 30, 2014 , were not material. Distribution System Improvement Charge. On April 14, 2012, legislation enabling gas and electric utilities in Pennsylvania to seek to charge recovery of eligible capital investment in distribution system infrastructure improvement projects became effective. 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, for up to five percent of distribution rates. 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. PNG and CPG began seeking permission to include a DSIC in their tariffs in 2014, while UGI Gas has not had a general rate filing within the required time period to be eligible. Beginning on April 1, 2015, PNG was able to include a DSIC charge in its tariff rate in accordance with a PUC order. The impact of the DSIC charge at PNG did not have a material effect on Gas Utility results of operations. |
Debt
Debt | 9 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Debt | Note 6 — Debt On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300,000 (including a $100,000 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300,000 revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0 . The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company receives approval for the UGI Utilities 2015 Credit Agreement by the PUC. The Company filed to obtain such approval on June 30, 2015. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 7 — Commitments and Contingencies Contingencies Environmental Matters CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100 , respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two -year period beginning with the original effective date in March 2004. At June 30, 2015 and 2014 , our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $9,595 and $11,381 , respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable. From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, 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 does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five -year average of such prudently incurred remediation costs, and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2015 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material for UGI Utilities. 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. There are pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows. |
Defined Benefit Pension and Oth
Defined Benefit Pension and Other Postretirement Plans | 9 Months Ended |
Jun. 30, 2015 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [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 relating to the Company’s employees include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, 2015 2014 2015 2014 Service cost $ 1,741 $ 1,623 $ 48 $ 41 Interest cost 5,628 5,721 119 127 Expected return on assets (7,225 ) (6,649 ) (153 ) (139 ) Amortization of: Prior service cost (benefit) 87 87 (160 ) (160 ) Actuarial loss 2,199 1,660 32 37 Net benefit cost (income) 2,430 2,442 (114 ) (94 ) Change in associated regulatory liabilities — — 938 918 Net benefit cost after change in regulatory liabilities $ 2,430 $ 2,442 $ 824 $ 824 Pension Benefits Other Postretirement Benefits Nine Months Ended June 30, 2015 2014 2015 2014 Service cost $ 5,222 $ 4,869 $ 145 $ 123 Interest cost 16,883 17,163 356 381 Expected return on assets (21,674 ) (19,949 ) (459 ) (417 ) Amortization of: Prior service cost (benefit) 261 261 (480 ) (480 ) Actuarial loss 6,595 4,982 95 111 Net benefit cost (income) 7,287 7,326 (343 ) (282 ) Change in associated regulatory liabilities — — 2,813 2,754 Net benefit cost after change in regulatory liabilities $ 7,287 $ 7,326 $ 2,470 $ 2,472 Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution required by ERISA. During the nine months ended June 30, 2015 and 2014 , the Company made contributions to the Pension Plan of $8,348 and $10,975 , respectively. The Company expects to make additional discretionary cash contributions of approximately $2,800 to the Pension Plan during the remainder of Fiscal 2015 . 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 calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the nine months ended June 30, 2015 and 2014 . 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, 2015 | |
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, 2015 , September 30, 2014 and June 30, 2014 : Asset (Liability) Level 1 Level 2 Level 3 Total June 30, 2015: Assets: Commodity contracts $ 1,510 $ 469 $ — $ 1,979 Liabilities: Commodity contracts $ (2,390 ) $ (2,605 ) $ — $ (4,995 ) September 30, 2014: Assets: Commodity contracts $ 679 $ 1,018 $ — $ 1,697 Liabilities: Commodity contracts $ (2,095 ) $ (206 ) $ — $ (2,301 ) June 30, 2014 (a): Assets: Commodity contracts $ 1,500 $ 1,016 $ — $ 2,516 Liabilities: Commodity contracts $ (693 ) $ (151 ) $ — $ (844 ) (a) Certain immaterial amounts have been revised to correct the classification of derivatives. The fair values of our Level 1 exchange-traded commodity futures and option derivative contracts and certain non exchange-traded electricity forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The fair values of the remainder of our derivative financial instruments and electricity forward contracts, which are designated as Level 2, are generally based upon recent market transactions and related market indicators. There were no transfers between Level 1 and Level 2 during the periods presented. Other Financial Instruments The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt (including current maturities) at June 30, 2015 , were $622,000 and $683,521 , respectively. The carrying amount and estimated fair value of our long-term debt (including current maturities) at June 30, 2014 , were $642,000 and $708,916 , respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar types of debt (Level 2). |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 9 Months Ended |
Jun. 30, 2015 | |
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. For more information on the accounting for our derivative instruments, see Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2014 Annual Report. 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, 2015 and 2014 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 13.1 million dekatherms and 10.9 million dekatherms, respectively. At June 30, 2015 , 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 any gains on 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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5 ). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At June 30, 2015 and 2014 , the volumes of Electric Utility’s forward electricity purchase contracts were 494.5 million kilowatt hours and 315.8 million kilowatt hours, respectively. At June 30, 2015 , the maximum period over which these contracts extend is 11 months . In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 5 ). At June 30, 2015 and 2014 , the total volumes associated with FTRs totaled 381.6 million kilowatt hours and 319.7 million kilowatt hours, respectively. At June 30, 2015 , 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 and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. 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, 2015 and 2014 , we had no unsettled IRPAs. At June 30, 2015 , the amount of net losses associated with IRPAs expected to be reclassified into earnings during the next twelve months is $2,550 . Derivative Instrument Credit Risk Our natural gas exchange-traded futures contracts generally require cash deposits in margin accounts. At June 30, 2015 , restricted cash in brokerage accounts totaled $3,683 . At June 30, 2014 , there was $1,109 restricted cash in brokerage accounts. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities on a gross basis as of June 30, 2015 and 2014 : June 30, 2015 June 30, 2014 (a) Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 1,943 $ 2,450 Derivatives not subject to PGC and DS mechanisms: Commodity contracts 36 66 Total derivative assets $ 1,979 $ 2,516 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (4,807 ) $ (844 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts (188 ) — Total derivative liabilities $ (4,995 ) $ (844 ) (a) Certain immaterial amounts have been revised to correct the classification of derivatives. Offsetting Derivative Assets and Liabilities Derivative assets and liabilities are presented net by counterparty on our 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 our 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. The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of June 30, 2015 and 2014 : Gross Amounts Recognized Gross Amounts Offset in Balance Sheet Net Amounts Recognized Cash Collateral (Received) Pledged Net Amounts Recognized in Balance Sheet June 30, 2015 Derivative assets $ 1,979 $ (583 ) $ 1,396 $ — $ 1,396 Derivative liabilities $ (4,995 ) $ 583 $ (4,412 ) $ — $ (4,412 ) June 30, 2014 Derivative assets $ 2,516 $ (813 ) $ 1,703 $ — $ 1,703 Derivative liabilities $ (844 ) $ 813 $ (31 ) $ — $ (31 ) Effect of Derivative Instruments The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30, 2015 and 2014 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain (Loss) Reclassified from AOCI into Income Three Months Ended June 30, 2015 2014 2015 2014 Cash Flow Hedges: Interest rate contracts $ — $ — $ (669 ) $ (671 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Three Months Ended June 30, 2015 2014 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ 111 $ 49 Operating expenses/other operating income, net Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain Nine Months Ended June 30, 2015 2014 2015 2014 Cash Flow Hedges: Interest rate contracts $ — $ — $ (2,008 ) $ (2,010 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Nine Months Ended June 30, 2015 2014 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (415 ) $ 128 Operating expenses/other operating income, net We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchase and normal sale exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 9 Months Ended |
Jun. 30, 2015 | |
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, 2015 and 2014 : Postretirement Benefit Plans Derivative Instruments Total Three Months Ended June 30, 2015 AOCI - March 31, 2015 $ (6,051 ) $ (1,087 ) $ (7,138 ) Reclassifications of benefit plan actuarial losses and prior service cost 128 — 128 Reclassifications of net losses on interest rate protection agreements — 392 392 AOCI - June 30, 2015 $ (5,923 ) $ (695 ) $ (6,618 ) Three Months Ended June 30, 2014 AOCI - March 31, 2014 $ (5,090 ) $ (2,654 ) $ (7,744 ) Reclassifications of benefit plan actuarial losses and prior service cost 95 — 95 Reclassifications of net losses on interest rate protection agreements — 393 393 AOCI - June 30, 2014 $ (4,995 ) $ (2,261 ) $ (7,256 ) Postretirement Benefit Plans Derivative Instruments Total Nine Months Ended June 30, 2015 AOCI - September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 ) Reclassifications of benefit plan actuarial losses and prior service cost 388 — 388 Reclassifications of net losses on interest rate protection agreements — 1,175 1,175 AOCI - June 30, 2015 $ (5,923 ) $ (695 ) $ (6,618 ) Nine Months Ended June 30, 2014 AOCI - September 30, 2013 $ (5,283 ) $ (3,437 ) $ (8,720 ) Reclassifications of benefit plan actuarial losses and prior service cost 288 — 288 Reclassifications of net losses on interest rate protection agreements — 1,176 1,176 AOCI - June 30, 2014 $ (4,995 ) $ (2,261 ) $ (7,256 ) |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Jun. 30, 2015 | |
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 in the Condensed Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries under PUC approved affiliated interest agreements. Amounts billed to these entities by UGI Utilities for all periods presented were not material. UGI Utilities is a party to two SCAAs with Energy Services which have terms of three years. Under the SCAAs, UGI Utilities has, among other things, and subject to recall for operational purposes, released certain storage and transportation contracts to Energy Services for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities incurred costs associated with Energy Services’ SCAAs totaling $5,691 and $10,898 during the three and nine months ended June 30, 2015 , respectively, and $16,894 and $23,590 during the three and nine months ended June 30, 2014 , respectively. In conjunction with the SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such security deposits, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, was $10,700 , $10,600 , and $10,600 as of June 30, 2015 , September 30, 2014 and June 30, 2014 , respectively. UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption inventories. The carrying value of these gas storage inventories at June 30, 2015 , September 30, 2014 and June 30, 2014 , comprising 2.6 bcf, 7.7 bcf and 4.0 bcf of natural gas, was $6,809 , $33,057 and $19,410 , 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 principally during the heating season months of November through March. The capacity charges for these transactions (exclusive of transactions pursuant to the SCAAs) during the three and nine months ended June 30, 2015 totaled $2,380 and $45,413 , respectively. During the three and nine months ended June 30, 2014 , such transactions totaled $1,551 and $34,259 , respectively, and are reflected in cost of sales. From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During the three and nine months ended June 30, 2015 , revenues associated with such sales to Energy Services totaled $9,129 and $71,546 , respectively. During the three and nine months ended June 30, 2014 , revenues associated with such sales to Energy Services totaled $9,869 and $102,118 , respectively. Also from time to time, the Company purchases natural gas, pipeline capacity and electricity from Energy Services (in addition to those transactions already described above) and purchases a firm storage service from UGI Storage Company, a subsidiary of Energy Services, under one -year agreements. During the three and nine months ended June 30, 2015 , such purchases totaled $8,431 and $79,956 , respectively. During the three and nine months ended June 30, 2014 , such purchases totaled $22,114 and $114,811 , respectively. |
Segment Information
Segment Information | 9 Months Ended |
Jun. 30, 2015 | |
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 HVAC Business, prior to its sale in June 2015, did not meet the quantitative thresholds for separate segment reporting under GAAP relating to business segment reporting and has been included in “Other” below. The accounting policies of our reportable segments are the same as those described in Note 2 of the Company’s 2014 Annual Report. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes. No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States. Financial information by business segment follows: Three Months Ended June 30, 2015 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 143,490 $ 119,412 $ 23,875 $ 203 Cost of sales $ 53,691 $ 41,352 $ 12,339 $ — Depreciation and amortization $ 15,913 $ 14,786 $ 1,127 $ — Operating income $ 20,184 $ 15,099 $ 4,071 $ 1,014 Interest expense $ 9,985 $ 9,483 $ 502 $ — Income before income taxes $ 10,199 $ 5,616 $ 3,569 $ 1,014 Capital expenditures $ 43,315 $ 41,324 $ 1,991 $ — Three Months Ended June 30, 2014 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 152,694 $ 128,264 $ 23,954 $ 476 Cost of sales $ 63,323 $ 49,257 $ 14,066 $ — Depreciation and amortization $ 14,892 $ 13,774 $ 1,118 $ — Operating income $ 19,720 $ 17,115 $ 2,304 $ 301 Interest expense $ 10,433 $ 9,904 $ 529 $ — Income before income taxes $ 9,287 $ 7,211 $ 1,775 $ 301 Capital expenditures $ 38,215 $ 35,955 $ 2,260 $ — Nine Months Ended June 30, 2015 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 931,369 $ 847,890 $ 82,621 $ 858 Cost of sales $ 475,079 $ 426,715 $ 48,364 $ — Depreciation and amortization $ 46,982 $ 43,555 $ 3,427 $ — Operating income $ 238,523 $ 226,248 $ 11,300 $ 975 Interest expense $ 31,245 $ 29,717 $ 1,528 $ — Income before income taxes $ 207,278 $ 196,531 $ 9,772 $ 975 Capital expenditures $ 139,624 $ 134,018 $ 5,606 $ — As of June 30, 2015 Total assets (at period end) $ 2,423,205 $ 2,278,975 $ 144,230 $ — Goodwill (at period end) $ 182,145 $ 182,145 $ — $ — Nine Months Ended June 30, 2014 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 965,549 $ 879,989 $ 84,467 $ 1,093 Cost of sales $ 515,612 $ 463,492 $ 52,120 $ — Depreciation and amortization $ 43,985 $ 40,733 $ 3,252 $ — Operating income $ 243,517 $ 233,728 $ 9,485 $ 304 Interest expense $ 28,036 $ 26,652 $ 1,384 $ — Income before income taxes $ 215,481 $ 207,076 $ 8,101 $ 304 Capital expenditures $ 104,117 $ 98,806 $ 5,311 $ — As of June 30, 2014 Total assets (at period end) $ 2,289,841 $ 2,147,407 $ 142,434 $ — Goodwill (at period end) $ 182,145 $ 182,145 $ — $ — |
Summary of Significant Accoun21
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
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. |
Accounting Standards Not Yet Adopted | Accounting Standards Not Yet Adopted Measurement of Inventory. In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-11, "Simplifying the Measurement of Inventory." This ASU amends existing guidance to require inventory to be measured at the lower of cost or net realizable value. Entities will continue to apply their existing impairment models to inventories that are accounted for using “last-in, first-out” and the “retail inventory” methods. The amendments in this ASU are effective for annual periods beginning after December 15, 2016 (Fiscal 2018) including interim periods within those fiscal years. Early adoption is permitted. Entities will apply the new guidance prospectively after the date of adoption. The adoption is not expected to have a material impact on the Company’s financial statements. Debt Issuance Costs. In April 2015, the FASB issued ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 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 company expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On July 9, 2015, the FASB voted to delay the effective date by one year. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our consolidated financial statements. |
Inventories (Tables)
Inventories (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventories | Inventories comprise the following: June 30, 2015 September 30, 2014 June 30, 2014 Gas Utility natural gas $ 19,205 $ 82,664 $ 45,701 Materials, supplies and other 14,171 12,555 13,049 Total inventories $ 33,376 $ 95,219 $ 58,750 |
Regulatory Assets and Liabili23
Regulatory Assets and Liabilities and Regulatory Matters (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility | The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: June 30, 2015 September 30, 2014 June 30, 2014 Regulatory assets: Income taxes recoverable $ 111,807 $ 110,709 $ 107,166 Underfunded pension and postretirement plans 103,250 110,116 89,236 Environmental costs 14,441 14,616 14,581 Deferred fuel and power costs — 11,732 9,354 Removal costs, net 19,635 16,790 15,620 Other 5,109 4,203 6,669 Total regulatory assets $ 254,242 $ 268,166 $ 242,626 Regulatory liabilities: Postretirement benefits $ 19,687 $ 18,594 $ 17,545 Environmental overcollections — 349 1,631 Deferred fuel and power refunds 45,564 306 — State tax benefits — distribution system repairs 10,894 10,076 9,271 Other 1,377 3,172 1,862 Total regulatory liabilities (a) $ 77,522 $ 32,497 $ 30,309 (a) Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. |
Defined Benefit Pension and O24
Defined Benefit Pension and Other Postretirement Plans (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Schedule of Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs | Net periodic pension expense and other postretirement benefit costs relating to the Company’s employees include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, 2015 2014 2015 2014 Service cost $ 1,741 $ 1,623 $ 48 $ 41 Interest cost 5,628 5,721 119 127 Expected return on assets (7,225 ) (6,649 ) (153 ) (139 ) Amortization of: Prior service cost (benefit) 87 87 (160 ) (160 ) Actuarial loss 2,199 1,660 32 37 Net benefit cost (income) 2,430 2,442 (114 ) (94 ) Change in associated regulatory liabilities — — 938 918 Net benefit cost after change in regulatory liabilities $ 2,430 $ 2,442 $ 824 $ 824 Pension Benefits Other Postretirement Benefits Nine Months Ended June 30, 2015 2014 2015 2014 Service cost $ 5,222 $ 4,869 $ 145 $ 123 Interest cost 16,883 17,163 356 381 Expected return on assets (21,674 ) (19,949 ) (459 ) (417 ) Amortization of: Prior service cost (benefit) 261 261 (480 ) (480 ) Actuarial loss 6,595 4,982 95 111 Net benefit cost (income) 7,287 7,326 (343 ) (282 ) Change in associated regulatory liabilities — — 2,813 2,754 Net benefit cost after change in regulatory liabilities $ 7,287 $ 7,326 $ 2,470 $ 2,472 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
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, 2015 , September 30, 2014 and June 30, 2014 : Asset (Liability) Level 1 Level 2 Level 3 Total June 30, 2015: Assets: Commodity contracts $ 1,510 $ 469 $ — $ 1,979 Liabilities: Commodity contracts $ (2,390 ) $ (2,605 ) $ — $ (4,995 ) September 30, 2014: Assets: Commodity contracts $ 679 $ 1,018 $ — $ 1,697 Liabilities: Commodity contracts $ (2,095 ) $ (206 ) $ — $ (2,301 ) June 30, 2014 (a): Assets: Commodity contracts $ 1,500 $ 1,016 $ — $ 2,516 Liabilities: Commodity contracts $ (693 ) $ (151 ) $ — $ (844 ) (a) Certain immaterial amounts have been revised to correct the classification of derivatives. |
Derivative Instruments and He26
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
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 on a gross basis as of June 30, 2015 and 2014 : June 30, 2015 June 30, 2014 (a) Derivative assets: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ 1,943 $ 2,450 Derivatives not subject to PGC and DS mechanisms: Commodity contracts 36 66 Total derivative assets $ 1,979 $ 2,516 Derivative liabilities: Derivatives subject to PGC and DS mechanisms: Commodity contracts $ (4,807 ) $ (844 ) Derivatives not subject to PGC and DS mechanisms: Commodity contracts (188 ) — Total derivative liabilities $ (4,995 ) $ (844 ) (a) Certain immaterial amounts have been revised to correct the classification of derivatives. |
Derivative Assets and Liabilities and the Effects of Offsetting | The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of June 30, 2015 and 2014 : Gross Amounts Recognized Gross Amounts Offset in Balance Sheet Net Amounts Recognized Cash Collateral (Received) Pledged Net Amounts Recognized in Balance Sheet June 30, 2015 Derivative assets $ 1,979 $ (583 ) $ 1,396 $ — $ 1,396 Derivative liabilities $ (4,995 ) $ 583 $ (4,412 ) $ — $ (4,412 ) June 30, 2014 Derivative assets $ 2,516 $ (813 ) $ 1,703 $ — $ 1,703 Derivative liabilities $ (844 ) $ 813 $ (31 ) $ — $ (31 ) |
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 on the Condensed Consolidated Statements of Income and changes in AOCI for the three and nine months ended June 30, 2015 and 2014 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain (Loss) Reclassified from AOCI into Income Three Months Ended June 30, 2015 2014 2015 2014 Cash Flow Hedges: Interest rate contracts $ — $ — $ (669 ) $ (671 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Three Months Ended June 30, 2015 2014 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ 111 $ 49 Operating expenses/other operating income, net Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain Nine Months Ended June 30, 2015 2014 2015 2014 Cash Flow Hedges: Interest rate contracts $ — $ — $ (2,008 ) $ (2,010 ) Interest expense Gain (Loss) Recognized in Income Location of Gain (Loss) Recognized in Income Nine Months Ended June 30, 2015 2014 Derivatives Not Subject to PGC and DS Mechanisms: Gasoline contracts $ (415 ) $ 128 Operating expenses/other operating income, net |
Accumulated Other Comprehensi27
Accumulated Other Comprehensive Income (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
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, 2015 and 2014 : Postretirement Benefit Plans Derivative Instruments Total Three Months Ended June 30, 2015 AOCI - March 31, 2015 $ (6,051 ) $ (1,087 ) $ (7,138 ) Reclassifications of benefit plan actuarial losses and prior service cost 128 — 128 Reclassifications of net losses on interest rate protection agreements — 392 392 AOCI - June 30, 2015 $ (5,923 ) $ (695 ) $ (6,618 ) Three Months Ended June 30, 2014 AOCI - March 31, 2014 $ (5,090 ) $ (2,654 ) $ (7,744 ) Reclassifications of benefit plan actuarial losses and prior service cost 95 — 95 Reclassifications of net losses on interest rate protection agreements — 393 393 AOCI - June 30, 2014 $ (4,995 ) $ (2,261 ) $ (7,256 ) Postretirement Benefit Plans Derivative Instruments Total Nine Months Ended June 30, 2015 AOCI - September 30, 2014 $ (6,311 ) $ (1,870 ) $ (8,181 ) Reclassifications of benefit plan actuarial losses and prior service cost 388 — 388 Reclassifications of net losses on interest rate protection agreements — 1,175 1,175 AOCI - June 30, 2015 $ (5,923 ) $ (695 ) $ (6,618 ) Nine Months Ended June 30, 2014 AOCI - September 30, 2013 $ (5,283 ) $ (3,437 ) $ (8,720 ) Reclassifications of benefit plan actuarial losses and prior service cost 288 — 288 Reclassifications of net losses on interest rate protection agreements — 1,176 1,176 AOCI - June 30, 2014 $ (4,995 ) $ (2,261 ) $ (7,256 ) |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Jun. 30, 2015 | |
Segment Reporting [Abstract] | |
Schedule of Segment Information | Financial information by business segment follows: Three Months Ended June 30, 2015 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 143,490 $ 119,412 $ 23,875 $ 203 Cost of sales $ 53,691 $ 41,352 $ 12,339 $ — Depreciation and amortization $ 15,913 $ 14,786 $ 1,127 $ — Operating income $ 20,184 $ 15,099 $ 4,071 $ 1,014 Interest expense $ 9,985 $ 9,483 $ 502 $ — Income before income taxes $ 10,199 $ 5,616 $ 3,569 $ 1,014 Capital expenditures $ 43,315 $ 41,324 $ 1,991 $ — Three Months Ended June 30, 2014 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 152,694 $ 128,264 $ 23,954 $ 476 Cost of sales $ 63,323 $ 49,257 $ 14,066 $ — Depreciation and amortization $ 14,892 $ 13,774 $ 1,118 $ — Operating income $ 19,720 $ 17,115 $ 2,304 $ 301 Interest expense $ 10,433 $ 9,904 $ 529 $ — Income before income taxes $ 9,287 $ 7,211 $ 1,775 $ 301 Capital expenditures $ 38,215 $ 35,955 $ 2,260 $ — Nine Months Ended June 30, 2015 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 931,369 $ 847,890 $ 82,621 $ 858 Cost of sales $ 475,079 $ 426,715 $ 48,364 $ — Depreciation and amortization $ 46,982 $ 43,555 $ 3,427 $ — Operating income $ 238,523 $ 226,248 $ 11,300 $ 975 Interest expense $ 31,245 $ 29,717 $ 1,528 $ — Income before income taxes $ 207,278 $ 196,531 $ 9,772 $ 975 Capital expenditures $ 139,624 $ 134,018 $ 5,606 $ — As of June 30, 2015 Total assets (at period end) $ 2,423,205 $ 2,278,975 $ 144,230 $ — Goodwill (at period end) $ 182,145 $ 182,145 $ — $ — Nine Months Ended June 30, 2014 : Reportable Segments Total Gas Utility Electric Utility Other Revenues $ 965,549 $ 879,989 $ 84,467 $ 1,093 Cost of sales $ 515,612 $ 463,492 $ 52,120 $ — Depreciation and amortization $ 43,985 $ 40,733 $ 3,252 $ — Operating income $ 243,517 $ 233,728 $ 9,485 $ 304 Interest expense $ 28,036 $ 26,652 $ 1,384 $ — Income before income taxes $ 215,481 $ 207,076 $ 8,101 $ 304 Capital expenditures $ 104,117 $ 98,806 $ 5,311 $ — As of June 30, 2014 Total assets (at period end) $ 2,289,841 $ 2,147,407 $ 142,434 $ — Goodwill (at period end) $ 182,145 $ 182,145 $ — $ — |
Inventories (Details)
Inventories (Details) $ in Thousands | 9 Months Ended | ||
Jun. 30, 2015USD ($)agreementBcf | Sep. 30, 2014USD ($)Bcf | Jun. 30, 2014USD ($)Bcf | |
Public Utilities, Inventory | |||
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet) | Bcf | 4.5 | 11.6 | 6.1 |
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $ | $ 11,337 | $ 49,897 | $ 28,299 |
SCAAs | |||
Public Utilities, Inventory | |||
Number of storage agreements (in storage agreements) | 3 | ||
Term of agreements | 3 years | ||
Number of storage agreements with Energy Services | 2 | ||
Number of storage agreements with non-affiliates | 1 | ||
SCAAs | Other Current Liabilities | |||
Public Utilities, Inventory | |||
Security deposit liability | $ | $ 17,700 | $ 17,600 | $ 17,600 |
Inventories - Schedule of Inven
Inventories - Schedule of Inventories (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Sep. 30, 2014 | Jun. 30, 2014 |
Public Utilities, Inventory | |||
Total inventories | $ 33,376 | $ 95,219 | $ 58,750 |
Gas Utility Natural Gas | |||
Public Utilities, Inventory | |||
Total inventories | 19,205 | 82,664 | 45,701 |
Materials, Supplies and Other | |||
Public Utilities, Inventory | |||
Total inventories | $ 14,171 | $ 12,555 | $ 13,049 |
Regulatory Assets and Liabili31
Regulatory Assets and Liabilities and Regulatory Matters (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Sep. 30, 2014 | Jun. 30, 2014 |
Gas Utility | |||
Regulatory Assets | |||
Fair value of unrealized gains (losses) | $ (729) | $ (1,363) | $ 680 |
Electric Utility | |||
Regulatory Assets | |||
Fair value of unrealized gains (losses) | $ (1,428) | $ 345 | $ 760 |
Regulatory Assets and Liabili32
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, 2015 | Sep. 30, 2014 | Jun. 30, 2014 | |
Regulatory Assets and Liabilities | ||||
Regulatory Assets | $ 254,242 | $ 268,166 | $ 242,626 | |
Regulatory Liabilities | [1] | 77,522 | 32,497 | 30,309 |
Postretirement Benefits | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Liabilities | 19,687 | 18,594 | 17,545 | |
Environmental Overcollections | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Liabilities | 0 | 349 | 1,631 | |
Deferred Fuel and Power Refunds | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Liabilities | 45,564 | 306 | 0 | |
State Tax Benefits -- Distribution System Repairs | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Liabilities | 10,894 | 10,076 | 9,271 | |
Other | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Liabilities | 1,377 | 3,172 | 1,862 | |
Income Taxes Recoverable | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Assets | 111,807 | 110,709 | 107,166 | |
Underfunded Pension and Postretirement Plans | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Assets | 103,250 | 110,116 | 89,236 | |
Environmental Costs | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Assets | 14,441 | 14,616 | 14,581 | |
Deferred Fuel and Power Costs | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Assets | 0 | 11,732 | 9,354 | |
Removal Costs, Net | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Assets | 19,635 | 16,790 | 15,620 | |
Other | ||||
Regulatory Assets and Liabilities | ||||
Regulatory Assets | $ 5,109 | $ 4,203 | $ 6,669 | |
[1] | Regulatory liabilities, other than deferred fuel and power refunds, are recorded in other current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. |
Debt (Details)
Debt (Details) | 9 Months Ended | ||
Jun. 30, 2015 | Mar. 27, 2015USD ($) | May. 25, 2011USD ($) | |
UGI Utilities 2015 Credit Agreement | |||
Line of Credit Facility | |||
Maximum borrowing capacity | $ 300,000,000 | ||
Sublimit for letters of credit | $ 100,000,000 | ||
UGI Utilities 2015 Credit Agreement | Minimum | |||
Line of Credit Facility | |||
Basis spread on variable rate | 0.00% | ||
UGI Utilities 2015 Credit Agreement | Maximum | |||
Line of Credit Facility | |||
Basis spread on variable rate | 1.75% | ||
Ratio of consolidated debt to consolidated capital | 0.65 | ||
UGI Utilities 2011 Credit Agreement | |||
Line of Credit Facility | |||
Maximum borrowing capacity | $ 300,000,000 |
Commitments and Contingencies (
Commitments and Contingencies (Details) - USD ($) | 9 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
CPG and PNG COAs | ||
Commitments and Contingencies | ||
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 | |
Accrual for environmental loss contingencies | $ 9,595,000 | $ 11,381,000 |
Environmental Issue | ||
Commitments and Contingencies | ||
Base year for determination of investigation and remediation cost (in years) | 5 years | |
CPG MGP | ||
Commitments and Contingencies | ||
Environmental remediation expense | $ 1,800,000 | |
PNG MGP | ||
Commitments and Contingencies | ||
Environmental remediation expense | $ 1,100,000 |
Defined Benefit Pension and O35
Defined Benefit Pension and Other Postretirement Plans (Details) - USD ($) | 9 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Pension Benefits | ||
Defined Benefit Plan Disclosure | ||
Contribution made to Pension Plan | $ 8,348,000 | $ 10,975,000 |
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 |
Defined Benefit Pension and O36
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, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Pension Benefits | ||||
Defined Benefit Plan Disclosure | ||||
Service cost | $ 1,741 | $ 1,623 | $ 5,222 | $ 4,869 |
Interest cost | 5,628 | 5,721 | 16,883 | 17,163 |
Expected return on assets | (7,225) | (6,649) | (21,674) | (19,949) |
Amortization of: | ||||
Prior service cost (benefit) | 87 | 87 | 261 | 261 |
Actuarial loss | 2,199 | 1,660 | 6,595 | 4,982 |
Net benefit cost (income) | 2,430 | 2,442 | 7,287 | 7,326 |
Change in associated regulatory liabilities | 0 | 0 | 0 | 0 |
Net benefit cost after change in regulatory liabilities | 2,430 | 2,442 | 7,287 | 7,326 |
VEBA | ||||
Defined Benefit Plan Disclosure | ||||
Service cost | 48 | 41 | 145 | 123 |
Interest cost | 119 | 127 | 356 | 381 |
Expected return on assets | (153) | (139) | (459) | (417) |
Amortization of: | ||||
Prior service cost (benefit) | (160) | (160) | (480) | (480) |
Actuarial loss | 32 | 37 | 95 | 111 |
Net benefit cost (income) | (114) | (94) | (343) | (282) |
Change in associated regulatory liabilities | 938 | 918 | 2,813 | 2,754 |
Net benefit cost after change in regulatory liabilities | $ 824 | $ 824 | $ 2,470 | $ 2,472 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Jun. 30, 2014 |
Fair Value Disclosures [Abstract] | ||
Carrying amount of long-term debt | $ 622,000 | $ 642,000 |
Estimated fair value of long-term debt | $ 683,521 | $ 708,916 |
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, 2015 | Sep. 30, 2014 | Jun. 30, 2014 | [1] |
Assets: | ||||
Derivative assets | $ 1,979 | $ 1,697 | $ 2,516 | |
Liabilities: | ||||
Derivative liabilities | (4,995) | (2,301) | (844) | |
Level 1 | ||||
Assets: | ||||
Derivative assets | 1,510 | 679 | 1,500 | |
Liabilities: | ||||
Derivative liabilities | (2,390) | (2,095) | (693) | |
Level 2 | ||||
Assets: | ||||
Derivative assets | 469 | 1,018 | 1,016 | |
Liabilities: | ||||
Derivative liabilities | (2,605) | (206) | (151) | |
Level 3 | ||||
Assets: | ||||
Derivative assets | 0 | 0 | 0 | |
Liabilities: | ||||
Derivative liabilities | $ 0 | $ 0 | $ 0 | |
[1] | Certain immaterial amounts have been revised to correct the classification of derivatives. |
Derivative Instruments and He39
Derivative Instruments and Hedging Activities (Details) kWh in Millions, MMBTU in Millions | 9 Months Ended | ||
Jun. 30, 2015USD ($)kWhMMBTU | Jun. 30, 2014USD ($)kWhMMBTU | Sep. 30, 2014USD ($) | |
Derivative | |||
Restricted cash in brokerage accounts | $ 3,683,000 | $ 1,109,000 | $ 3,592,000 |
Gas Utility | |||
Derivative | |||
Notional amount (energy measure) | MMBTU | 13.1 | 10.9 | |
Maximum length of time hedged in price risk cash flow hedges (in months) | 15 months | ||
Electric Utility | |||
Derivative | |||
Notional amount (energy measure) | kWh | 494.5 | 315.8 | |
Maximum length of time hedged in price risk cash flow hedges (in months) | 11 months | ||
Electric Utility | Electric Utility Electric Transmission Congestion | |||
Derivative | |||
Notional amount (energy measure) | kWh | 381.6 | 319.7 | |
Maximum length of time hedged in price risk cash flow hedges (in months) | 11 months | ||
Interest Rate Protection Agreements | |||
Derivative | |||
Notional Amount | $ 0 | $ 0 | |
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months | $ 2,550,000 |
Derivative Instruments and He40
Derivative Instruments and Hedging Activities - Balance Sheet Location and Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Jun. 30, 2014 | [1] |
Derivative assets: | |||
Derivative assets | $ 1,979 | $ 2,516 | |
Derivative liabilities: | |||
Derivative liabilities | (4,995) | (844) | |
Commodity Contracts | Derivatives Subject to PGC and DS Mechanisms | |||
Derivative assets: | |||
Derivative assets | 1,943 | 2,450 | |
Derivative liabilities: | |||
Derivative liabilities | (4,807) | (844) | |
Commodity Contracts | Derivatives Not Subject To PGC And DS Mechanisms | |||
Derivative assets: | |||
Derivative assets | 36 | 66 | |
Derivative liabilities: | |||
Derivative liabilities | $ (188) | $ 0 | |
[1] | Certain immaterial amounts have been revised to correct the classification of derivatives. |
Derivative Instruments and He41
Derivative Instruments and Hedging Activities - Derivative Assets and Liabilities and the Effects of Offsetting (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Jun. 30, 2014 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Derivative asset, gross | $ 1,979 | $ 2,516 | [1] |
Derivative asset, gross liability | (583) | (813) | |
Derivative asset, net | 1,396 | 1,703 | |
Cash collateral (received) pledged | 0 | 0 | |
Derivative asset, net amount recognized in balance sheet | 1,396 | 1,703 | |
Derivative liability, gross | (4,995) | (844) | [1] |
Derivative liability, gross asset | 583 | 813 | |
Derivative liability, net | (4,412) | (31) | |
Cash collateral (received) pledged | 0 | 0 | |
Derivative liability, net amount recognized in balance sheet | $ (4,412) | $ (31) | |
[1] | Certain immaterial amounts have been revised to correct the classification of derivatives. |
Derivative Instruments and He42
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, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Derivatives Not Subject To PGC And DS Mechanisms | Gasoline Contracts | ||||
Derivative Instruments, Gain (Loss) | ||||
Gain (loss) recognized in income | $ 111 | $ 49 | $ (415) | $ 128 |
Cash Flow Hedges | Interest Rate Contracts | ||||
Derivative Instruments, Gain (Loss) | ||||
Gain (loss) recognized in AOCI | 0 | 0 | 0 | 0 |
Cash Flow Hedges | Interest Rate Contracts | Interest Expense | ||||
Derivative Instruments, Gain (Loss) | ||||
Gain (loss) reclassified from AOCI into income | $ (669) | $ (671) | $ (2,008) | $ (2,010) |
Accumulated Other Comprehensi43
Accumulated Other Comprehensive Income - Schedule of Changes in Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | $ (7,138) | $ (7,744) | $ (8,181) | $ (8,720) |
AOCI, net of tax - ending balance | (6,618) | (7,256) | (6,618) | (7,256) |
Postretirement Benefit Plans | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | (6,051) | (5,090) | (6,311) | (5,283) |
Reclassifications, net of tax | 128 | 95 | 388 | 288 |
AOCI, net of tax - ending balance | (5,923) | (4,995) | (5,923) | (4,995) |
Derivative Instruments | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
AOCI, net of tax - beginning balance | (1,087) | (2,654) | (1,870) | (3,437) |
AOCI, net of tax - ending balance | (695) | (2,261) | (695) | (2,261) |
Derivative Instruments | Interest Rate Protection Agreements | ||||
Accumulated Other Comprehensive Income (Loss) | ||||
Reclassifications, net of tax | $ 392 | $ 393 | $ 1,175 | $ 1,176 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Jun. 30, 2015USD ($)Bcf | Jun. 30, 2014USD ($)Bcf | Jun. 30, 2015USD ($)Bcf | Jun. 30, 2014USD ($)Bcf | Sep. 30, 2014USD ($)Bcf | |
Related Party Transaction | |||||
Related party costs incurred | $ 2,647 | $ 2,385 | $ 9,567 | $ 7,997 | |
Energy Services | |||||
Related Party Transaction | |||||
Revenue from related parties | 9,129 | 9,869 | $ 71,546 | 102,118 | |
Term of agreements | 1 year | ||||
Purchases from related party | $ 8,431 | $ 22,114 | $ 79,956 | $ 114,811 | |
Inventories | Energy Services | |||||
Related Party Transaction | |||||
Volume of gas storage inventory (in bcf of natural gas) | Bcf | 2.6 | 4 | 2.6 | 4 | 7.7 |
Natural gas storage inventory, related parties, current | $ 6,809 | $ 19,410 | $ 6,809 | $ 19,410 | $ 33,057 |
SCAAs | Energy Services | |||||
Related Party Transaction | |||||
SCAA contract term (in years) | 3 years | ||||
Related party costs incurred | 5,691 | 16,894 | $ 10,898 | 23,590 | |
SCAAs | Other Current Liabilities | Energy Services | |||||
Related Party Transaction | |||||
Related party security deposits | 10,700 | 10,600 | 10,700 | 10,600 | $ 10,600 |
Exclusive of Transactions Pursuant SCAAs | Energy Services | |||||
Related Party Transaction | |||||
Related party costs incurred | $ 2,380 | $ 1,551 | $ 45,413 | $ 34,259 |
Segment Information (Details)
Segment Information (Details) - 9 months ended Jun. 30, 2015 | segmentcountycustomer |
Segment Reporting Information | |
Number of reportable segments (in segments) | segment | 2 |
Counties of operation, number | 1 |
Customer Concentration Risk | Revenue | |
Segment Reporting Information | |
Number of customers exceeding threshold | customer | 0 |
Electric Utility | |
Segment Reporting Information | |
Counties of operation, number | 2 |
Segment Information - Schedule
Segment Information - Schedule of Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Sep. 30, 2014 | |
Segment Reporting Information | |||||
Revenues | $ 143,490 | $ 152,694 | $ 931,369 | $ 965,549 | |
Cost of sales | 53,691 | 63,323 | 475,079 | 515,612 | |
Depreciation and amortization | 15,913 | 14,892 | 46,982 | 43,985 | |
Operating income | 20,184 | 19,720 | 238,523 | 243,517 | |
Interest expense | 9,985 | 10,433 | 31,245 | 28,036 | |
Income before income taxes | 10,199 | 9,287 | 207,278 | 215,481 | |
Capital expenditures | 43,315 | 38,215 | 139,624 | 104,117 | |
Total assets (at period end) | 2,423,205 | 2,289,841 | 2,423,205 | 2,289,841 | $ 2,354,643 |
Goodwill (at period end) | 182,145 | 182,145 | 182,145 | 182,145 | $ 182,145 |
Reportable Segments | Gas Utility | |||||
Segment Reporting Information | |||||
Revenues | 119,412 | 128,264 | 847,890 | 879,989 | |
Cost of sales | 41,352 | 49,257 | 426,715 | 463,492 | |
Depreciation and amortization | 14,786 | 13,774 | 43,555 | 40,733 | |
Operating income | 15,099 | 17,115 | 226,248 | 233,728 | |
Interest expense | 9,483 | 9,904 | 29,717 | 26,652 | |
Income before income taxes | 5,616 | 7,211 | 196,531 | 207,076 | |
Capital expenditures | 41,324 | 35,955 | 134,018 | 98,806 | |
Total assets (at period end) | 2,278,975 | 2,147,407 | 2,278,975 | 2,147,407 | |
Goodwill (at period end) | 182,145 | 182,145 | 182,145 | 182,145 | |
Reportable Segments | Electric Utility | |||||
Segment Reporting Information | |||||
Revenues | 23,875 | 23,954 | 82,621 | 84,467 | |
Cost of sales | 12,339 | 14,066 | 48,364 | 52,120 | |
Depreciation and amortization | 1,127 | 1,118 | 3,427 | 3,252 | |
Operating income | 4,071 | 2,304 | 11,300 | 9,485 | |
Interest expense | 502 | 529 | 1,528 | 1,384 | |
Income before income taxes | 3,569 | 1,775 | 9,772 | 8,101 | |
Capital expenditures | 1,991 | 2,260 | 5,606 | 5,311 | |
Total assets (at period end) | 144,230 | 142,434 | 144,230 | 142,434 | |
Goodwill (at period end) | 0 | 0 | 0 | 0 | |
Other | |||||
Segment Reporting Information | |||||
Revenues | 203 | 476 | 858 | 1,093 | |
Cost of sales | 0 | 0 | 0 | 0 | |
Depreciation and amortization | 0 | 0 | 0 | 0 | |
Operating income | 1,014 | 301 | 975 | 304 | |
Interest expense | 0 | 0 | 0 | 0 | |
Income before income taxes | 1,014 | 301 | 975 | 304 | |
Capital expenditures | 0 | 0 | 0 | 0 | |
Total assets (at period end) | 0 | 0 | 0 | 0 | |
Goodwill (at period end) | $ 0 | $ 0 | $ 0 | $ 0 |