Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 28, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | VECTREN UTILITY HOLDINGS INC | ||
Entity Central Index Key | 1,129,542 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 10 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 0 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash & cash equivalents | $ 9.8 | $ 9.4 |
Accounts receivable - less reserves of $3.9 & $4.1, respectively | 109.5 | 102.6 |
Accrued unbilled revenues | 123.7 | 112 |
Inventories | 117.5 | 119 |
Recoverable fuel & natural gas costs | 19.2 | 29.9 |
Prepayments & other current assets | 32.7 | 38.6 |
Total current assets | 412.4 | 411.5 |
Utility Plant | ||
Original cost | 7,015.4 | 6,545.4 |
Less: accumulated depreciation & amortization | 2,738.7 | 2,562.5 |
Net utility plant | 4,276.7 | 3,982.9 |
Investments in unconsolidated affiliates | 0.2 | 0.2 |
Other investments | 26.7 | 21.3 |
Nonutility plant - net | 198.6 | 164.8 |
Goodwill | 205 | 205 |
Regulatory assets | 314 | 206.2 |
Other assets | 64.2 | 49 |
TOTAL ASSETS | 5,497.8 | 5,040.9 |
Current Liabilities | ||
Accounts payable | 221.8 | 205.4 |
Payables to other Vectren companies | 33.3 | 25.4 |
Accrued liabilities | 154 | 140.1 |
Short-term borrowings | 179.5 | 194.4 |
Current maturities of long-term debt | 100 | 49.1 |
Total current liabilities | 688.6 | 614.4 |
Long-Term Debt - Net of Current Maturities | 1,479.5 | 1,331 |
Deferred Credits & Other Liabilities | ||
Deferred income taxes | 457.5 | 854.5 |
Regulatory liabilities | 937.2 | 453.7 |
Deferred credits & other liabilities | 212.2 | 163.3 |
Total deferred credits & other liabilities | 1,606.9 | 1,471.5 |
Commitments & Contingencies (Notes 8-11) | ||
Common Shareholder's Equity | ||
Common stock (no par value) | 877.5 | 831.2 |
Retained earnings | 845.3 | 792.8 |
Total common shareholder's equity | 1,722.8 | 1,624 |
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ 5,497.8 | $ 5,040.9 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Reserves | $ 3.9 | $ 4.1 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
OPERATING REVENUES | |||||||||||
Gas utility | $ 812.7 | $ 771.7 | $ 792.6 | ||||||||
Electric utility | 569.6 | 605.8 | 601.6 | ||||||||
Other | 0.3 | 0.3 | 0.3 | ||||||||
Total operating revenues | $ 392.1 | $ 279.7 | $ 285.9 | $ 425 | $ 383.5 | $ 291.3 | $ 279.8 | $ 423.4 | 1,382.6 | 1,377.8 | 1,394.5 |
OPERATING EXPENSES | |||||||||||
Cost of gas sold | 271.5 | 266.7 | 305.4 | ||||||||
Cost of fuel & purchased power | 171.8 | 183.6 | 187.5 | ||||||||
Other operating | 370.4 | 333.6 | 339.1 | ||||||||
Depreciation & amortization | 234.5 | 219.1 | 208.8 | ||||||||
Taxes other than income taxes | 55.9 | 58.3 | 57.1 | ||||||||
Total operating expenses | 1,104.1 | 1,061.3 | 1,097.9 | ||||||||
OPERATING INCOME | 57.5 | 58 | 49.7 | 113.5 | 93.5 | 64 | 52.2 | 106.8 | 278.5 | 316.5 | 296.6 |
Other income - net | 30.6 | 26.3 | 18.7 | ||||||||
Interest expense | 72.6 | 69.7 | 66.3 | ||||||||
INCOME BEFORE INCOME TAXES | 236.5 | 273.1 | 249 | ||||||||
Income taxes | 60.7 | 99.5 | 88.1 | ||||||||
NET INCOME | $ 53.6 | $ 30.8 | $ 25.5 | $ 65.9 | $ 51.3 | $ 34.9 | $ 26.3 | $ 61.1 | $ 175.8 | $ 173.6 | $ 160.9 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income | $ 175.8 | $ 173.6 | $ 160.9 |
Adjustments to reconcile net income to cash from operating activities: | |||
Depreciation & amortization | 234.5 | 219.1 | 208.8 |
Deferred income taxes & investment tax credits | 45.9 | 96.7 | 85.8 |
Provision for uncollectible accounts | 5.7 | 6.6 | 6.9 |
Expense portion of pension & postretirement benefit cost | 3.5 | 4 | 4.8 |
Other non-cash items - net | 2 | 3.5 | 7 |
Changes in working capital accounts: | |||
Accounts receivable, including to Vectren companies & accrued unbilled revenues | (27) | (48.8) | 50.5 |
Inventories | 1.5 | 6.3 | (12.1) |
Recoverable/refundable fuel & natural gas costs | 10.7 | (37.8) | 15.2 |
Prepayments & other current assets | 5.1 | 5 | 30 |
Accounts payable, including to Vectren companies & affiliated companies | 26.2 | 23.9 | (15.2) |
Accrued Liabilities | 13.9 | 18.7 | 0.7 |
Cash to fund pension and postretirement plans | 0 | (15) | (19.6) |
Changes in noncurrent assets | (66) | (46.5) | (23.7) |
Changes in noncurrent liabilities | 15 | (11.9) | (7.1) |
Net cash from operating activities | 446.8 | 397.4 | 492.9 |
Proceeds from: | |||
Long-term debt, net of issuance costs | 198.5 | 0 | 236.3 |
Additional capital contribution | 46.3 | 31.3 | 6.2 |
Requirements for: | |||
Dividends to parent | (123.3) | (116.1) | (110.4) |
Retirement of long-term debt | 0 | (13) | (95) |
Net change in short-term borrowings | (14.9) | 179.9 | (141.9) |
Net cash from financing activities | 106.6 | 82.1 | (104.8) |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Proceeds from other investing activities | 2.7 | 15.3 | 3.9 |
Requirements for: | |||
Capital expenditures, excluding AFUDC equity | (554.2) | (496.6) | (399.2) |
Other costs | (2.4) | 0 | 0 |
Changes in restricted cash | 0.9 | 5 | (5.9) |
Net cash from investing activities | (553) | (476.3) | (401.2) |
Net change in cash & cash equivalents | 0.4 | 3.2 | (13.1) |
Cash & cash equivalents at beginning of period | 9.4 | 6.2 | 19.3 |
Cash & cash equivalents at end of period | $ 9.8 | $ 9.4 | $ 6.2 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Millions | Total | Common Stock | Retained Earnings |
Balance at beginning of period at Dec. 31, 2014 | $ 1,478.5 | $ 793.7 | $ 684.8 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||
Net income | 160.9 | 160.9 | |
Common stock: | |||
Additional capital contribution | 6.2 | 6.2 | |
Dividends | (110.4) | (110.4) | |
Balance at end of period at Dec. 31, 2015 | 1,535.2 | 799.9 | 735.3 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||
Net income | 173.6 | 173.6 | |
Common stock: | |||
Additional capital contribution | 31.3 | 31.3 | |
Dividends | (116.1) | (116.1) | |
Balance at end of period at Dec. 31, 2016 | 1,624 | 831.2 | 792.8 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||
Net income | 175.8 | 175.8 | |
Common stock: | |||
Additional capital contribution | 46.3 | 46.3 | |
Dividends | (123.3) | (123.3) | |
Balance at end of period at Dec. 31, 2017 | $ 1,722.8 | $ 877.5 | $ 845.3 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Organization and Nature of Operations Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren or the Company's parent) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren Energy Delivery of Indiana - North), Southern Indiana Gas and Electric Company (SIGECO or Vectren Energy Delivery of Indiana - South), and Vectren Energy Delivery of Ohio, Inc. (VEDO). Herein, 'the Company' may also refer to Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Inc. and/or Vectren Energy Delivery of Ohio, Inc. The Company also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and the Company are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Indiana Gas provides energy delivery services to approximately 592,400 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 145,200 electric customers and approximately 111,500 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to approximately 318,100 natural gas customers located near Dayton in west-central Ohio. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of utility and nonutility plant and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions. Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. Cash & Cash Equivalents Highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. Allowance for Uncollectible Accounts The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed. Inventories In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities is recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Property, Plant & Equipment Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. Utility Plant & Related Depreciation Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income . When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant , with an offsetting charge to Accumulated depreciation , resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. The Company’s portion of jointly owned Utility Plant , along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. Nonutility Plant & Related Depreciation The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. Impairment Reviews Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. Goodwill Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually and at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented. Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. Regulatory Assets & Liabilities Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. Asset Retirement Obligations A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral. Energy Contracts & Derivatives The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value depends on the intended use of the derivative and resulting designation. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempt from mark-to-market accounting. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. The offset to contracts affected by regulatory accounting treatment, which includes most of the Company's executed and financial contracts, are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources or from internal models. As of and for the periods presented, related derivative activity is not material to these financial statements. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of an accounting period in Accrued unbilled revenues . Substantially all revenue sources are subject to unbilled accruals. MISO Transactions With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues . On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms. Excise & Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $29.1 million in 2017 , $28.3 million in 2016 , and $29.4 million in 2015 . Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes . Operating Segments The Company's chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 5). |
Utility & Nonutility Plant
Utility & Nonutility Plant | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Utility & Nonutility Plant | Utility & Nonutility Plant The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At and For the Year Ended December 31, (In millions) 2017 2016 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,969.6 3.4 % $ 3,587.5 3.4 % Electric utility plant 2,833.5 3.3 % 2,752.0 3.3 % Common utility plant 59.0 3.2 % 56.3 3.2 % Construction work in progress 70.7 — 63.0 — Asset retirement obligations 82.6 — 86.6 — Total original cost $ 7,015.4 $ 6,545.4 SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of Alcoa, Inc. (Alcoa), own a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common. SIGECO's share of the cost of this unit at December 31, 2017 , is $191.0 million with accumulated depreciation totaling $119.7 million . AGC and SIGECO share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income . Nonutility Plant, net of accumulated depreciation and amortization follows: At December 31, (In millions) 2017 2016 Computer hardware & software $ 155.6 $ 120.5 Land & buildings 37.1 37.6 All other 5.9 6.7 Nonutility plant - net $ 198.6 $ 164.8 Nonutility plant is presented net of accumulated depreciation and amortization of $285.6 million and $264.7 million as of December 31, 2017 and 2016 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , the Company capitalized interest totaling $1.2 million , $1.0 million , and $0.4 million , respectively, on nonutility plant construction projects. |
Regulatory Assets & Liabilities
Regulatory Assets & Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets & Liabilities | Regulatory Assets & Liabilities Regulatory Assets Regulatory assets consist of the following: At December 31, (In millions) 2017 2016 Future amounts recoverable from ratepayers related to: Net deferred income taxes $ 6.2 $ (17.1 ) Asset retirement obligations & other 24.3 — 30.5 (17.1 ) Amounts deferred for future recovery related to: Cost recovery riders & other 142.4 91.6 142.4 91.6 Amounts currently recovered in customer rates related to: Indiana authorized trackers 75.9 64.2 Ohio authorized trackers 28.4 22.2 Loss on reacquired debt & hedging costs 22.7 24.1 Deferred coal costs 14.1 21.2 141.1 131.7 Total regulatory assets $ 314.0 $ 206.2 Of the $141 million currently being recovered in customer rates, no amounts are earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $23 million , is 20 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable. Regulatory assets for asset retirement obligations are a result of costs incurred for expected retirement activity for the Company's ash ponds beyond what has been recovered in rates. The Company believes the recovery of these assets are probable as the costs are currently being recovered in rates. Regulatory Liabilities At December 31, 2017 and 2016 , the Company had regulatory liabilities of approximately $937 million and $454 million , respectively , $477 million and $452 million of which related to cost of removal obligations, and at December 31, 2017, $459 million to deferred taxes. The deferred tax related regulatory liability is primarily the result of the $446 million revaluation of deferred taxes at December 31, 2017 at the reduced federal corporate tax rate. These regulatory liabilities are expected to be refunded to customers over time following state regulator approval. |
Transactions with Other Vectren
Transactions with Other Vectren Companies and Affiliates | 12 Months Ended |
Dec. 31, 2017 | |
Transactions with Other Vectren Companies and Affiliates [Abstract] | |
Transactions With Other Vectren Companies and Affiliates | Transactions with Other Vectren Companies and Affiliates Vectren Infrastructure Services Corporation (VISCO) VISCO, a wholly owned subsidiary of the Company's parent, provides underground pipeline construction and repair services. VISCO’s customers include the Company's utilities and fees incurred by the Company totaled $157.1 million in 2017 , $117.8 million in 2016 , and $109.5 million in 2015 . The increase in 2017 is due to a large pipeline project that VISCO was awarded in a competitive process. Amounts owed to VISCO at December 31, 2017 and 2016 are included in Payables to other Vectren companies. Support Services & Purchases The Company's parent provides corporate and general and administrative services to the Company and allocates certain costs to the Company. These costs are allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. The Company received corporate allocations totaling $64.1 million , $57.6 million , and $52.3 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Retirement Plans & Other Postretirement Benefits At December 31, 2017 , the Company's parent maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The pension and SERP plans are closed to new participants. The defined benefit pension plans and postretirement benefit plan, which cover the Company’s eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The Company's current and former employees comprise the vast majority of the participants and retirees covered by these plans. The Company's parent satisfies the future funding requirements for funded plans and the payment of benefits for unfunded plans from general corporate assets and, as necessary, relies on the Company to support the funding of these obligations. However, the Company has no contractual funding obligation. In 2016 , the Company contributed $15.0 million to Vectren's defined benefit pension plans. No contributions were made in 2017 . The combined funded status of Vectren's defined benefit pension plans was approximately 92 percent at December 31, 2017 and December 31, 2016 . The Company's parent allocates retirement plan and other postretirement benefit plan periodic cost calculated pursuant to US GAAP to its subsidiaries, which is also how the Company’s rate regulated utilities recover retirement plan periodic costs through base rates. Periodic cost is charged to the Company following a labor cost allocation methodology and results in retirement costs being allocated to both operating expense and capital projects. For the years ended December 31, 2017 , 2016 and 2015 , costs totaling $8.2 million , $6.1 million and $7.0 million , respectively, were charged to the Company. Any difference between funding requirements and allocated periodic costs is recognized by the Company as an asset or liability. Neither plan assets nor plan obligations calculated pursuant to US GAAP are allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As of December 31, 2017 and 2016 , the Company has $61.3 million , and $40.9 million , respectively, included in Other assets representing defined benefit funding by the Company that is yet to be reflected in costs. As of December 31, 2017 and 2016 , the Company has $47.0 million and $12.2 million , respectively, included in Deferred credits & other liabilities representing costs related to other postretirement benefits charged to the Company that is yet to be funded to the Company's parent. The Company's labor allocation methodology is used to compute the funding of the defined benefit retirement and other postretirement plans, which is consistent with the regulatory ratemaking processes of the Company's subsidiaries. Share-Based Incentive Plans & Deferred Compensation Plans The Company does not have share-based compensation plans separate from the Company's parent. The Company recognizes its allocated portion of costs related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to the Company. As of December 31, 2017 and 2016 , $55.7 million and $42.3 million , respectively, is included in Accrued liabilities and Deferred credits & other liabilities and represents obligations that are yet to be funded to the Company's parent. Income Taxes The Company does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. The Company's parent files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file income tax returns in various states. Pursuant to a tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of this consolidated tax group are recorded at the parent company level. Current taxes payable/receivable are settled with the Company's parent in cash quarterly and after filing the consolidated federal and state income tax returns. Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities . Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes. On December 22, 2017, the United States government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (“TCJA”). The TCJA makes broad and complex changes to the Internal Revenue Code (“IRC”), many of which are effective on January 1, 2018, including, but not limited to, (1) reducing the federal corporate income tax rate from 35 percent to 21 percent, (2) eliminating the use of bonus depreciation for regulated utilities, while permitting full expensing of qualified property for non-regulated entities, (3) eliminating the domestic production activities deduction previously allowable under Section 199 of the IRC, (4) creating a new limitation on the deductibility of interest expense for non-regulated businesses, (5) eliminating the corporate Alternative Minimum Tax (“AMT”) and changing how existing AMT credits can be realized, (6) limiting the deductibility of certain executive compensation, (7) restricting the deductibility of entertainment and lobbying-related expenses, (8) requiring regulated entities to employ the average rate assumption method (“ARAM”) to refund excess deferred taxes created by the rate change to their customers, and (9) changing the rules under Section 118 of the IRC regarding taxability of contributions made by government or civic groups. Consolidated results reflect a net tax benefit of $23.2 million for the period ending December 31, 2017 from the enactment of the TCJA. This benefit is associated with the impact of the corporate rate reduction on the Company’s deferred income tax balances related to assets which are not included in customer rates, such as goodwill associated with past acquisitions. In addition, the reduction in the federal corporate rate results in $333.4 million in excess federal deferred income taxes. The Company's gas and electric utilities currently recover corporate income tax expense in Commission approved rates charged to customers. The IURC and PUCO both issued orders which initiated proceedings to investigate the impact of the TCJA on utility companies and customers within each state. In addition, both Commissions have ordered each utility to establish regulatory assets and liabilities to record all estimated impacts of tax reform starting January 1, 2018. The Company is complying with both orders. In Indiana, the IURC held an initial conference of parties on February 6, 2018, and an order was issued by the Commission on February 16, 2018, outlining the process the utility companies are to follow. In accordance with the order, the Company expects to initiate proceedings to effect the timely reduction in customer bills due to the lower corporate federal income tax rate in the very near term. In Ohio, in response to the PUCO's request for comments from utilities, Vectren submitted its response indicating that the issues should be address in its base rate case, for which the pre-filing notice was filed February 21, 2018. The components of income tax expense and amortization of investment tax credits follow: Year Ended December 31, (In millions) 2017 2016 2015 Current: Federal $ 10.0 $ (1.4 ) $ (1.9 ) State 4.8 4.2 4.2 Total current taxes 14.8 2.8 2.3 Deferred: Federal 43.9 93.5 81.7 State 2.4 3.7 4.6 Total deferred taxes 46.3 97.2 86.3 Amortization of investment tax credits (0.4 ) (0.5 ) (0.5 ) Total income tax expense $ 60.7 $ 99.5 $ 88.1 A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, 2017 2016 2015 Statutory rate 35.0 % 35.0 % 35.0 % State and local taxes-net of federal benefit 2.8 2.6 2.8 Deferred tax revaluation-tax law change (9.8 ) — — Amortization of investment tax credit (0.2 ) (0.2 ) (0.2 ) Domestic production deduction (1.1 ) (0.5 ) (0.9 ) Research and development credit (0.3 ) (0.8 ) (2.0 ) All other - net (0.7 ) 0.3 0.7 Effective tax rate 25.7 % 36.4 % 35.4 % Significant components of the net deferred tax liability follow: At December 31, (In millions) 2017 2016 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 537.2 $ 821.6 Regulatory assets recoverable through future rates 7.9 17.6 Alternative minimum tax carryforward (12.2 ) (29.3 ) Employee benefit obligations (0.3 ) 10.2 U.S. federal charitable contributions carryforwards (6.2 ) — Regulatory liabilities to be settled through future rates (116.2 ) (15.9 ) Deferred fuel costs 16.2 25.9 Other – net 31.1 24.4 Net noncurrent deferred tax liability $ 457.5 $ 854.5 At December 31, 2017 and 2016 , investment tax credits totaling $1.2 million and $1.6 million , respectively, are included in Deferred credits & other liabilities . At December 31, 2017 , the Company has alternative minimum tax carryforwards of $12.2 million , which do not expire. The TCJA eliminated the alternative minimum tax after 2017. Pursuant to the TCJA, the Company will be able to recover its alternative minimum tax carryforwards created in 2017 and prior in future periods. Uncertain Tax Positions Unrecognized tax benefits for all periods presented were not material to the Company. The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest and penalties totaled $1.3 million and $1.1 million , respectively, at December 31, 2017 and 2016 . The Company's parent and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The Internal Revenue Service (IRS) has concluded examinations of Vectren's U.S. federal income tax returns for tax years through December 31, 2012. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2010. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2014 except to the extent of refunds claimed on amended tax returns. The statutes of limitations for assessment of the 2013 tax year related to the amended federal return will expire in 2020. The statutes of limitations for assessment of the 2009 and 2011 through 2014 tax years related to the amended Indiana income tax returns will expire in 2018 through 2020. On February 28, 2018, the Company was notified by the Indiana Department of Revenue that the Company's Parent and subsidiaries were selected for a routine compliance audit for the tax periods January 1, 2015 through December 31, 2017. Indiana Senate Bill 1 In March 2014, Indiana Senate Bill 1 was signed into law. This legislation phases in a 1.6 percent rate reduction to the Indiana Adjusted Gross Income Tax Rate for corporations over a six year period. Pursuant to this legislation, the tax rate will be lowered by 0.25 percent each year for the first five years and 0.35 percent in year six beginning on July 1, 2016 to the final rate of 4.9 percent effective July 1, 2021. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the first quarter of 2014, the period of enactment. The impact was not material to results of operations. |
Borrowing Arrangements
Borrowing Arrangements | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Borrowing Arrangements | Borrowing Arrangements Short-Term Borrowings On July 14, 2017, the Company closed on a renegotiated credit agreement with existing lenders. This credit agreement matures on July 14, 2022 and replaced a bank credit agreement that had an original maturity date of October 19, 2019. The Company's new credit facility totals $400 million with a $10 million swing line sublimit and $20 million letter of credit sublimit. The credit agreement commitment was increased by $50 million as compared to the prior credit agreement. The Company's credit agreement is jointly and severally guaranteed by its wholly owned subsidiaries Indiana Gas, SIGECO, and VEDO and is a backup facility for its commercial paper program. The commercial paper program is used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. As reduced by borrowings outstanding at December 31, 2017 , approximately $220 million was available. The Company has historically funded the short-term borrowing needs through the commercial paper market and expects to use the short-term borrowing facility in instances where the commercial paper market is not efficient. Following is certain information regarding the Company's short-term borrowing arrangement: (In millions) 2017 2016 2015 Year End Balance Outstanding $ 179.5 $ 194.4 $ 14.5 Weighted Average Interest Rate 1.92 % 1.05 % 0.55 % Annual Average Balance Outstanding $ 172.4 $ 59.8 $ 53.8 Weighted Average Interest Rate 1.30 % 0.71 % 0.38 % Maximum Month End Balance Outstanding $ 238.7 $ 194.4 $ 121.5 Long-Term Debt Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: At December 31, (In millions) 2017 2016 Utility Holdings Fixed Rate Senior Unsecured Notes 2018, 5.75% $ 100.0 $ 100.0 2020, 6.28% 100.0 100.0 2021, 4.67% 55.0 55.0 2023, 3.72% 150.0 150.0 2026, 5.02% 60.0 60.0 2028, 3.20% 45.0 45.0 2032, 3.26% 100.0 — 2035, 6.10% 75.0 75.0 2035, 3.90% 25.0 25.0 2041, 5.99% 35.0 35.0 2042, 5.00% 100.0 100.0 2043, 4.25% 80.0 80.0 2045, 4.36% 135.0 135.0 2047, 3.93% 100.0 — 2055, 4.51% 40.0 40.0 Total Utility Holdings 1,200.0 1,000.0 SIGECO First Mortgage Bonds 2022, 2013 Series C, current adjustable rate 1.565%, tax exempt 4.6 4.6 2024, 2013 Series D, current adjustable rate 1.565%, tax exempt 22.5 22.5 2025, 2014 Series B, current adjustable rate 1.565%, tax-exempt 41.3 41.3 2029, 1999 Series, 6.72% 80.0 80.0 2037, 2013 Series E, current adjustable rate 1.565%, tax exempt 22.0 22.0 2038, 2013 Series A, 4.00%, tax exempt 22.2 22.2 2043, 2013 Series B, 4.05%, tax exempt 39.6 39.6 2044, 2014 Series A, 4.00%, tax exempt 22.3 22.3 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt 23.0 23.0 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 15.2 Total SIGECO 292.7 292.7 Indiana Gas Fixed Rate Senior Unsecured Notes 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 1.0 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 Total Indiana Gas 96.0 96.0 Total long-term debt outstanding 1,588.7 1,388.7 Current maturities of long-term debt (100.0 ) (49.1 ) Debt issuance costs (8.6 ) (7.9 ) Unamortized debt premium & discount - net (0.6 ) (0.7 ) Total long-term debt-net $ 1,479.5 $ 1,331.0 Utility Holdings Long-Term Debt Issuance On July 14, 2017, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors agreed to purchase the following tranches of notes: (i) $100 million of 3.26 percent Guaranteed Senior Notes, Series A, due August 28, 2032, and (ii) $100 million of 3.93 percent Guaranteed Senior Notes, Series B, due November 29, 2047. The notes are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO, wholly owned subsidiaries of Utility Holdings. The Series A note proceeds were received on August 28, 2017 and the Series B proceeds were received on November 29, 2017. SIGECO Variable Rate Tax-Exempt Bonds On September 14, 2017, the Company, through SIGECO, executed a Bond Purchase and Covenants Agreement (Purchase and Covenants Agreement) providing SIGECO the ability to remarket and/or refinance approximately $152 million of tax-exempt bonds at a variable rate based on one month LIBOR through May 1, 2023 (except for one bond that matures on January 1, 2022). Bonds remarketed through the Bond Purchase and Covenants Agreement included three issuances that were mandatorily tendered to the Company on September 14, 2017. These were • 2013 Series C Notes with a principal of $4.6 million and a final maturity date of January 1, 2022; • 2013 Series D Notes with a principal of $22.5 million and a final maturity date of March 1, 2024; and • 2013 Series E Notes with a principal of $22.0 million and final maturity date of May 1, 2037. Through the Purchase and Covenants Agreement, on September 22, 2017, SIGECO also extended the mandatory tender date of its variable rate 2014 Series B Notes with a principal of $41.3 million and final maturity date of July 1, 2025 (the original tender date was September 24, 2019). The Purchase and Covenants Agreement provides the option, subject to satisfaction of customary conditions precedent, for the lenders to purchase from SIGECO and for SIGECO to convert to a variable rate other currently outstanding fixed rate, tax-exempt bonds that are callable at SIGECO's option in March 2018 (2013 Series A Notes totaling $22.2 million due March 1, 2038) and May 2018 (2013 Series B Notes totaling $39.6 million due by May 1, 2043). On March 1, 2018, SIGECO exercised its call option on the $22.2 million 2013 Series A Notes and refinanced those notes through the Purchase and Covenants agreement. The Company, through SIGECO, executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates on the 2013 Series A, B, and E Notes through final maturity dates. The swaps contain customary terms and conditions and generally provide offset for changes in the one month LIBOR rate. Other interest rate variability that may arise through the Purchase and Covenants Agreement, such as variability caused by changes in tax law or SIGECO’s credit rating, among others, may result in an actual interest rate above or below the anticipated fixed rate. Regulatory orders require SIGECO to include the impact of its interest rate risk management activities, such as gains and losses arising from these swaps, in its cost of capital utilized in rate cases and other periodic filings. SIGECO Bond Retirement On June 1, 2016, a $13 million SIGECO bond matured. The First Mortgage Bond, which was a portion of an original $25 million public issuance sold on June 1, 1986, carried a fixed interest rate of 8.875 percent. The repayment of debt was funded from the Company’s commercial paper program. Mandatory Tenders At December 31, 2017 , certain series of SIGECO bonds, aggregating $124.0 million are subject to mandatory tenders prior to the bonds' final maturities. $38.2 million will be tendered in 2020 and $85.8 million will be tendered in 2023. Call Options At December 31, 2017 , certain series of SIGECO bonds, aggregating $84.1 million may be called at SIGECO's option. $ 22.2 million was called on March 1, 2018 and $39.6 million is callable on May 1, 2018. $22.3 million is callable in 2019. Future Long-Term Debt Sinking Fund Requirements and Maturities The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO met the 2017 sinking fund requirement by this means and, expects to also meet this requirement in 2018 in this manner. Accordingly, the sinking fund requirement is excluded from Current liabilities in the Consolidated Balance Sheets . At December 31, 2017 , $1.5 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $3.4 billion at December 31, 2017 . Consolidated maturities of long-term debt during the years following 2017 (in millions) are $100.0 in 2018, $100.0 in 2020, $55.0 in 2021, $4.6 in 2022, and $1,319.9 thereafter. There are no maturities of long-term debt in 2019. Debt Guarantees The Company's currently outstanding long-term and short-term debt is jointly and severally guaranteed by SIGECO, Indiana Gas, and VEDO. The Company’s long-term debt and short-term debt outstanding at December 31, 2017 , totaled $1.2 billion and $180 million , respectively. Covenants Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent . As of December 31, 2017 , the Company was in compliance with all debt covenants. |
Common Shareholder's Equity
Common Shareholder's Equity | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Common Shareholder's Equity | Common Shareholder’s Equity During the years ended December 31, 2017 , 2016 , and 2015 , the Company has cumulatively received additional capital of $83.8 million from the Company's parent, of which $18.8 million was funded by new share issues from its dividend reinvestment plan and $65.0 million was received during 2016 and 2017 from the nonutility operations of the Company's parent to fund the Company's capital expenditure program. |
Commitments & Contingencies
Commitments & Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments & Contingencies | Commitments & Contingencies Commitments Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2017 and thereafter (in millions) are $1.1 in 2018 , $0.9 in 2019 , $0.6 in 2020 , $0.6 in 2021 , $0.5 in 2022 , and $1.4 thereafter. Total lease expense, for these types of commitments, (in millions) was $1.3 in 2017 , $1.1 in 2016 , and $0.8 in 2015 . The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights and certain contracts are firm commitments under five and twenty year arrangements. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Letters of Credit The Company, from time to time, through its subsidiaries, issues letters of credit that support consolidated operations. At December 31, 2017, letters of credit outstanding total $8.4 million . Legal and Regulatory Proceedings The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows. |
Gas Rate and Regulatory Matters
Gas Rate and Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Public Utilities, General Disclosures [Abstract] | |
Gas Rate and Regulatory Matters | Gas Rate and Regulatory Matters Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement The Company monitors and maintains its natural gas distribution system to ensure natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in programs to replace bare steel and cast iron infrastructure and other activities in both Indiana and Ohio to mitigate risk, improve the system, and comply with applicable regulations, many of which are the result of federal pipeline safety requirements. Laws passed in both Indiana and Ohio provide utilities the opportunity to timely recover costs of federally mandated projects and other infrastructure improvement projects outside of a base rate proceeding. Indiana Senate Bill 251 (Senate Bill 251) provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, based on the overall rate of return most recently approved by the IURC, through a base rate case or other proceeding, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs is deferred for future recovery in the utility's next general rate case. Indiana Senate Bill 560 (Senate Bill 560) supplements Senate Bill 251 described above, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for current recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on the investment that reflects the current capital structure and associated costs, with the exception of the rate of return on equity, which remains fixed at the rate determined in the Company's last rate case. Recoverable costs also include recovery of depreciation and other operating expenses. The remaining 20 percent of project costs are deferred for future recovery in the utility’s next general rate case, which must be filed before the expiration of the seven-year plan. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent. Ohio House Bill 95 (House Bill 95) permits a natural gas utility to apply for recovery of much of its capital expenditure program. This legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post-in-service carrying costs until recovery is approved by the PUCO. Indiana Recovery and Deferral Mechanisms The Company's Indiana natural gas utilities received Orders in 2008 and 2007 associated with the most recent base rate cases. These Orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The Orders provide for the deferral of depreciation and post-in-service carrying costs on qualifying projects totaling $20 million annually at Indiana Gas and $3 million annually at SIGECO. The debt-related post-in-service carrying costs are currently recognized in the Consolidated Statements of Income . The recording of post-in-service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at SIGECO and four years after being placed into service at Indiana Gas. At December 31, 2017 and December 31, 2016 , the Company has regulatory assets totaling $22.7 million and $21.9 million , respectively, associated with the deferral of depreciation and debt-related post-in-service carrying cost activities. Beginning in 2014, all bare steel and cast iron replacement activities are part of the Company’s seven -year capital investment plan discussed below. Requests for Recovery under Indiana Regulatory Mechanisms In August 2014, the IURC issued an Order approving the Company’s seven -year capital infrastructure replacement and improvement plan (the Plan), beginning in 2014, and the proposed accounting authority and recovery. Compliance projects and other infrastructure improvement projects were approved pursuant to Senate Bill 251 and 560, respectively. As provided in the two laws, the Order approved semi-annual filings for rate recovery of 100 percent of the costs, inclusive of return, related to these capital investments and operating expenses, with 80 percent of the costs, including a return, recovered currently via an approved tracking mechanism and 20 percent of the costs deferred and recovered in the Company’s next base rate proceeding. In addition, the Order established guidelines to annually update the seven year capital investment plan. Finally, the Order approved the Company’s proposal to recover eligible costs assigned to the residential customer class via a fixed monthly charge per residential customer. In March 2016, the IURC issued an Order re-approving approximately $890 million of the Company’s gas infrastructure modernization projects requested in the third update of the Plan, and approving the inclusion in rates of actual investments made through June 30, 2015. While most of the proposed capital spend has been approved as proposed, approximately $80 million of future projects were not approved for recovery through the mechanisms pursuant to these filings. Specifically, the Company proposed to add a new project to its Plan pursuant to Senate Bill 560 totaling approximately $65 million . The project, which is now complete, consists of a 20-mile transmission line and other related investments required to support industrial customer growth and ongoing system reliability in the Lafayette, Indiana area, as well as allows the Company to further diversify its gas supply portfolio via access to shale gas in the Marcellus and Utica reserves, was excluded for recovery under the Plan. The IURC stated because the project was not in the original plan filed in 2013, it does not qualify for cost recovery under Senate Bill 560. In the Order, the IURC did pre-approve the project for rate base inclusion upon the filing of the next base rate case. On April 27, 2017, the Indiana Court of Appeals affirmed the IURC Order. The Company does not expect similar issues related to updating future plan filings as the project inclusion process is now better understood by all parties. Subsequent to the March 2016 Order, the Company has received additional Orders approving plan investments. On January 24, 2018, the IURC issued an order (January 2018 order) approving the inclusion in rates of investments made from January 2017 to June 2017. Through the January 2018 Order, approximately $482 million of the approved capital investment has been incurred and included for recovery. The January 2018 Order also approved the Company's plan update, which now totals $995 million through 2020. The plan increase, totaling $105 million since inception, is for additional investments related to pipeline safety and compliance requirements under Senate Bill 251. In December 2016, PHMSA issued interim final rules related to integrity management for storage operations. Efforts are underway to implement the new requirements. Further, the Company reviewed the Underground Natural Gas Storage Safety Recommendations from a joint Department of Energy and PHMSA led task force. On August 3, 2017, the Company filed for authority to recover the associated costs using the mechanism allowed under Senate Bill 251. The request includes approximately $15 million of operating expenses and $17 million of capital investments over a four -year period beginning in 2018. The Company received the IURC Order approving the request for recovery on December 28, 2017. The Company does not have company-owned storage operations in Ohio. At December 31, 2017 and December 31, 2016 , the Company has regulatory assets related to the Plan totaling $78.0 million and $51.1 million , respectively. Ohio Recovery and Deferral Mechanisms The PUCO Order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines, as well as certain other infrastructure investments. This rider is updated annually for qualifying capital expenditures and allows for a return on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post-in-service carrying costs is also allowed until the related capital expenditures are included in the DRR. The Order also initially established a prospective bill impact evaluation on the annual deferrals. On February 19, 2014, the PUCO issued an Order approving a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR for the recovery of costs incurred through 2017 and expanded the types of investment covered by the DRR to include recovery of certain other infrastructure investments. The Order limits the resulting DRR fixed charge per month for residential and small general service customers to specific graduated levels through 2017. The capital expenditure plan is subject to the graduated caps on the fixed DRR monthly charge applicable to residential and small general service customers approved in the Order. In the event the Company exceeds these caps, amounts in excess can be deferred for future recovery. The Order also approved the Company's commitment that the DRR can only be further extended as part of a base rate case. In total, the Company has made capital investments on projects that are now in-service under the DRR totaling $321.1 million as of December 31, 2017 , of which $261.1 million has been approved for recovery under the DRR through December 31, 2016 . Regulatory assets associated with post-in-service carrying costs and depreciation deferrals were $31.2 million and $24.4 million at December 31, 2017 and December 31, 2016 , respectively. In August 2017, the Company received approval to adjust the DRR rates, effective December 31, 2017, for recovery of costs incurred through December 31, 2016. The PUCO has also issued Orders approving the Company's filings under House Bill 95. These Orders approve deferral of the Company’s Ohio capital expenditure program for items not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. House Bill 95 Orders also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. At December 31, 2017 and December 31, 2016 , the Company has regulatory assets totaling $66.1 million and $41.9 million , respectively, associated with the deferral of depreciation, post-in-service carrying costs, and property taxes. As of December 31, 2017 , the Company's deferrals have not reached this bill impact cap. On May 1, 2017, the Company submitted its most recent annual report required under its House Bill 95 Order. This report covers the Company's capital expenditure program through calendar year 2017. Vectren Ohio Gas Rate Case On February 21, 2018, the Company submitted a pre-filing notice with the PUCO indicating it plans to request an increase in its base rate charges for VEDO’s distribution business in its 17 county service area in west-central Ohio. The filing is necessary to recover the costs of capital investments made over the past ten years, much of which has been deferred as part of the Company’s capital expenditure program under House Bill 95. Also in the filing, the Company seeks approval for the continuation of the DRR mechanism. The Company will file the case-in-chief at the end of March 2018, and expects an order by early 2019. Pipeline and Hazardous Materials Safety Administration (PHMSA) In March 2016, PHMSA published a notice of proposed rulemaking (NOPR) on the safety of gas transmission and gathering lines. The proposed rule addresses many of the remaining requirements of the 2011 Pipeline Safety Act, with a particular focus on extending integrity management rules to address a much larger portion of the natural gas infrastructure and adds requirements to address broader threats to the integrity of a pipeline system. The Company continues to evaluate the impact these proposed rules will have on its integrity management programs and transmission and distribution systems. Progress on finalizing the rule continues to work through the administrative process. The rule is expected to be finalized in 2019 and the Company believes the costs to comply with the new rules would be considered federally mandated and therefore should be recoverable under Senate Bill 251 in Indiana and eligible for deferral under House Bill 95 in Ohio. |
Electric Rate and Regulatory Ma
Electric Rate and Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Public Utilities, General Disclosures [Abstract] | |
Electric Rate and Regulatory Matters | Electric Rate and Regulatory Matters Electric Requests for Recovery under Senate Bill 560 The provisions of Senate Bill 560, as described in the Gas Rate & Regulatory Matters footnote for gas projects, are the same for qualifying electric projects. On February 23, 2017, the Company filed for authority to recover costs related to its electric system modernization plan, using the mechanism allowed under Senate Bill 560. The electric system modernization plan includes investments to upgrade portions of the Company’s network of substations, transmission and distribution systems, to enhance reliability and allow the grid to accept advanced technology to improve the information and service provided to customers. The filing requested the recovery of associated capital expenditures estimated to be approximately $500 million over the seven -year period beginning in 2017. On September 20, 2017, the IURC issued an Order approving the settlement agreement reached between the Company, the OUCC and a coalition of industrial customers on May 18, 2017. The settlement agreement reduced the plan spend to $446 million , with defined annual caps on recoverable capital investments. The majority of the reduction relating to the removal of advanced metering infrastructure (AMI or digital meters) from the plan. However, deferral of the costs for AMI was agreed upon in the settlement whereby the company can move forward with deployment in the near-term. In removing it from the plan, the request for cost recovery for the AMI project will not occur until the next base rate review proceeding, which would be expected to be filed by the end of 2023. The settlement agreement also addresses how the eligible costs would be recoverable in rates, with a cap on the residential and small general service fixed monthly charge per customer in each semi-annual filing. The remaining costs to residential and small general service customers would be recovered via a volumetric energy charge. The settlement agreement also addresses that semi-annual filings are to be made August 1, based on capital investments and expenses through the period ended April 30, and February 1, based on capital investments and expenses through October 31. The parties agreed in the settlement that the Company would make its first semi-annual filing on August 1, 2017, with additional time allotted subsequent to the plan case order for intervening parties to review the filing and to address any changes to the settlement agreement. On August 1, 2017, the Company filed with the IURC its initial request for approval of the revenue requirement associated with a capital investment of $7.1 million through April 30, 2017. On December 20, 2017, the IURC issued an Order approving the initial rates necessary to begin cash recovery of 80 percent of the revenue requirement, inclusive of return, with the remaining 20 percent deferred for recovery in the utility's next general rate case. On February 1, 2018, the Company submitted its second semi-annual filing, seeking approval of the recovery in rates of investments made of approximately $31 million through October 31, 2017. As of December 31, 2017 , the Company has regulatory assets related to the Electric TDSIC plan totaling $4.3 million . Renewable Generation Resources On August 30, 2017, the IURC issued an Order approving the Company’s request to recover costs related to the construction of three solar projects, using the mechanism allowed under Senate Bill 29, which allows for timely recovery of costs and expenses incurred during the construction and operation of clean energy projects. These investments, presented as part of the Company’s Integrated Resource Plan (IRP) submitted in December 2016, allow the Company to add approximately 4 MW of universal solar generation, rooftop solar generation, and 1 MW of battery storage resources to its portfolio. See more information on the IRP below in Environmental & Sustainability Matters. The approved cost of the projects cannot exceed the approximate $16 million estimate submitted by the Company, without seeking further Commission approval. SIGECO Electric Environmental Compliance Filing On January 28, 2015, the IURC issued an Order approving the Company’s request for approval of capital investments in its coal-fired generation units to comply with new EPA mandates related to mercury and air toxic standards (MATS) effective in 2015 and to address an outstanding Notice of Violation (NOV) from the EPA pertaining to its A.B. Brown generating station sulfur trioxide emissions. The MATS rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. As of December 31, 2017 , $30 million has been spent on equipment to control mercury in both air and water emissions, and $40 million to address the issues raised in the NOV. The Order approved the Company’s request for deferred accounting treatment, as supported by provisions under Indiana Senate Bill 29 and Senate Bill 251. The accounting treatment includes the deferral of depreciation and property tax expense related to these investments, accrual of post-in-service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. These costs will be included for recovery no later than the next rate case. The initial phase of the projects went into service in 2014, with the remaining investment going into service in 2016. As of December 31, 2017 , the Company has approximately $12.8 million deferred related to depreciation and operating expenses, and $4.7 million deferred related to post-in-service carrying costs. MATS compliance was required beginning April 16, 2015 and the Company continues to operate in full compliance with the MATS rule. In June 2015, Joint Appellants’ Citizens Action Coalition of Indiana, Inc., Sierra Club, Inc., and Valley Watch, Inc. (the appellants) challenged the IURC's January 2015 Order. On October 29, 2015, the Indiana Court of Appeals issued an opinion that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules but remanded the case to the IURC to determine whether a certificate of public convenience and necessity (CPCN) should be issued for the equipment required by the NOV. On June 22, 2016, the IURC issued an Order granting the Company a CPCN for the NOV required equipment. On July 21, 2016, the appellants initiated an appeal of the IURC's June 22, 2016 Order challenging the findings made by the IURC. On February 14, 2017, the Indiana Court of Appeals affirmed the IURC's June 22, 2016 Order. On February 20, 2018, the Company filed a request to commence recovery, under Senate Bill 251, of its already approved investments associated with the MATS and NOV Compliance Projects, including recovery of the authorized deferred balance. As proposed, recovery would reflect 80 percent of the authorized costs, including a return, recovery of depreciation and incremental operating expenses, and recovery of the prior deferred balance over a proposed period of 15 years. The remaining 20 percent will be deferred until the Company’s next base rate proceeding. No procedural schedule has been set, but the Company would expect an order in the first quarter of 2019. SIGECO Electric Demand Side Management (DSM) Program Filing On March 28, 2014, Indiana Senate Bill 340 was signed into law. The legislation allows for industrial customers to opt out of participating in energy efficiency programs and as a result of this legislation, most of the Company’s eligible industrial customers have since opted out of participation in the applicable energy efficiency programs. Indiana Senate Bill 412 (Senate Bill 412) requires electricity suppliers to submit energy efficiency plans to the IURC at least once every three years. Senate Bill 412 also requires the recovery of all program costs, including lost revenues and financial incentives associated with those plans and approved by the IURC. The Company made its first filing pursuant to this bill in June 2015, which proposed energy efficiency programs for calendar years 2016 and 2017. On March 23, 2016, the IURC issued an Order approving the Company’s 2016-2017 energy efficiency plan. The Order provided for cost recovery of program and administrative expenses and included performance incentives for reaching energy savings goals. The Order also included a lost margin recovery mechanism that would have limited recovery related to new programs to the shorter of four years or the life of the installed energy efficiency measure. Prior electric energy efficiency orders did not limit lost margin recovery in this manner. This ruling followed other IURC decisions implementing the same lost margin recovery limitation with respect to other electric utilities in Indiana. The Company appealed this lost margin recovery restriction based on the Company’s commitment to promote and drive participation in its energy efficiency programs. On March 7, 2017, the Indiana Court of Appeals reversed the IURC finding on the Company's 2016-2017 energy efficiency plan that the four year cap on lost margin recovery was arbitrary and the IURC failed to properly interpret the governing statute requiring it to review the utility's originally submitted DSM proposal and either approve or reject it as a whole, including the proposed lost margin recovery. The case was remanded to the IURC for further proceedings. On June 13, 2017, the Company filed additional testimony supporting the plan. In response to the proposals to cap lost margin recovery, the Company filed supplemental testimony that supported lost margin recovery based on the average measure life of the plan, estimated at nine years, on 90 percent of the direct energy savings attributed to the programs. Testimony of intervening parties was filed on July 26, 2017, opposing the Company's proposed lost margin recovery. An evidentiary hearing was held in September 2017. On December 20, 2017, the Commission issued an order approving the DSM Plan for 2016-2017 including the recovery of lost margins consistent with the Company's proposal. On January 22, 2018, certain intervening parties initiated an appeal to the Indiana Court of Appeals. An appeal schedule has not been set, and while no assurance as to the ultimate outcome can be provided, based upon the record of the proceedings, as well as the findings in the Commission’s order, the Company expects to prevail in this appeal. On April 10, 2017, the Company submitted its request for approval to the IURC of its Energy Efficiency Plan for calendar years 2018 through 2020. Consistent with prior filings, this filing included a request for continued cost recovery of program and administrative expenses, including performance incentives for reaching energy savings goals and continued recovery of lost margins consistent with the modified proposal in the 2016-2017 plan. Filed testimony of intervening parties was received on July 26, 2017, opposing the Company's proposed lost margin recovery. An evidentiary hearing was held in September 2017. On December 28, 2017, the Commission issued an order approving the 2018 through 2020 Plan, inclusive of recovery of lost margins consistent with the Order issued on December 20, 2017. On January 26, 2018, certain intervening parties initiated an appeal to the Indiana Court of Appeals. An appeal schedule has not been set, and while no assurance as to the ultimate outcome can be provided, based upon the record of the proceedings, as well as the findings in the Commission’s order, the Company expects to prevail in this appeal. For the twelve months ended December 31, 2017 , 2016 , and 2015 , the Company recognized electric utility revenue of $11.6 million , $11.1 million , and $10.1 million , respectively, associated with lost margin recovery approved by the Commission. FERC Return on Equity (ROE) Complaints On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against the MISO and various MISO transmission owners, including SIGECO (first complaint case). The joint parties sought to reduce the 12.38 percent base ROE used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent covering the refund period from November 12, 2013 through February 11, 2015 (first refund period). On September 28, 2016, the FERC issued a final order authorizing a 10.32 percent base ROE for the first refund period and prospectively through the date of the order in a second complaint case as detailed below. A second customer complaint case was filed on February 11, 2015 covering the refund period from February 12, 2015 through May 11, 2016 (second refund period). An initial decision from the FERC administrative law judge on June 30, 2016, authorized a base ROE of 9.70 percent for the second refund period. The FERC was expected to rule on the proposed order in the second complaint case in 2017, which would authorize a base ROE for this period and prospectively from the date of the order. The timing of such action is uncertain. Separately, on January 6, 2015, the FERC approved a MISO transmission owner joint request for an adder to the approved ROE. Under FERC regulations, transmission owners that are part of a Regional Transmission Organization (RTO) such as the MISO are authorized to earn an incentive of 50 basis points above the FERC approved ROE. The adder is applied retroactively from January 6, 2015 through May 11, 2016 and prospectively from the September 28, 2016 order in the first complaint case. The Company has reflected these results in its financial statements. As of December 31, 2017 , the Company had invested approximately $157.7 million in qualifying projects. The net plant balance for these projects totaled $133.5 million at December 31, 2017 . On April 14, 2017, the U.S. Court of Appeals for the District of Columbia circuit vacated the FERC Opinion in a prior case that established a new methodology for calculating ROE. This methodology was utilized in the final order in the Company's first complaint case, and the initial decision in the Company's second complaint case. The Appeals Court stated that FERC did not prove the existing ROE was not just and reasonable, failed to provide any reasoned basis for their selected ROE, and remanded to the FERC for further justification of its ROE calculation. The Company will continue to monitor this proceeding and evaluate any potential impacts on the Company's complaint cases but would not expect them to be material. Electric Generation Transition Plan As required by Indiana regulation, the Company filed its 2016 Integrated Resource Plan (IRP) with the IURC on December 16, 2016. The State requires each electric utility to perform and submit an IRP that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next twenty-year period. During 2016, the Company held three public stakeholder meetings to gather input and feedback as well as communicate results of the IRP process as it progressed. In developing its IRP, the Company considered both the cost to continue operating its existing generation units in a manner that complies with current and anticipated future environmental requirements, as well as various resource alternatives, such as the use of energy efficiency programs and renewable resources as part of its overall generation portfolio. After submission, parties to the IRP provided comments on the plan. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. The final report was issued on November 2, 2017. The Company has taken the comments provided in the report into consideration in its generation resource plans. The Company’s IRP considered a broad range of potential resources and variables and is focused on ensuring it offers a reliable, reasonably priced generation portfolio as well as a balanced energy mix. Consistent with the recommendations presented in the Company’s IRP and as a direct result of significant environmental investments required to comply with current regulations, the Company plans to retire a significant portion of its generating fleet by the end of 2023. On February 20, 2018, the Company filed a petition seeking authorization from the Commission to construct a new 800 - 900 MW natural gas combined cycle generating facility to replace this capacity at an approximate cost of $900 million , which includes the cost of a new natural gas pipeline to serve the plant. The Company is requesting a CPCN authorizing construction timelines and costs of new generation resources, as well as necessary unit retrofits, to implement the generation transition plan. In that filing, the Company seeks approval of its generation transition plan, including the authority to defer the cost of new generation, including the ability to accrue AFUDC and defer depreciation until the facility is placed in base rates. As a part of this same proceeding, the Company seeks recovery under Senate Bill 251 of costs to be incurred for environmental investments to be made at its F.B. Culley generating plant to comply with Effluent Limitation Guidelines and Coal Combustion Residuals rules. The F.B. Culley investments, estimated to be approximately $90 million , will begin in 2019 and will allow the F.B. Culley Unit 3 generating facility to comply with environmental requirements and continue to provide generating capacity to the Company’s electric customers. Under Senate Bill 251, the Company is seeking recovery of 80 percent of the approved costs, including a return, using a tracking mechanism, with the remaining 20 percent of the costs deferred for recovery in the Company’s next base rate proceeding. The Company expects an order from the Commission in this proceeding by the first half of 2019. On February 20, 2018, the Company announced it is finalizing details to install an additional 50 MW of universal solar energy, consistent with its IRP. The Company will seek authority from the IURC pursuant to Senate Bill 29 to recover the costs associated with the project. In addition, the Company intends to continue to offer energy efficiency programs annually. Similarly, as discussed in more detail below, the extension of preliminary compliance deadlines related to ELG implementation are not expected to have a significant impact on the Company’s long term preferred generation plan. On September 21, 2017, the Company and Alcoa agreed to continue the joint ownership and operation of Warrick Unit 4 through 2023. This aligns with the Company's long-term electric generation strategy, and the expected exit at the end of 2023 is consistent with the IRP which reflects having completed all planned unit retirements and bringing new resources online by that date. |
Environmental and Sustainabilit
Environmental and Sustainability Matters | 12 Months Ended |
Dec. 31, 2017 | |
Environmental Matters Disclosure [Abstract] | |
Environmental and Sustainability Matters | Environmental and Sustainability Matters The Company's parent initiated a corporate sustainability program in 2012 with the publication of the initial corporate sustainability report. Since that time, the Company and its parent continue to develop strategies that focus on environmental, social and governance (ESG) factors that contribute to the long-term growth of a sustainable business model. The sustainability policies and efforts, and in particular its policies and procedures designed to ensure compliance with applicable laws and regulations, are directly overseen by Vectren's Board of Directors through its Corporate Responsibility and Sustainability Committee, as well as vetted with Vectren's Board of Directors. Further discussion of key goals, strategies, and governance practices can be found in the Company’s current sustainability report, at www.vectren.com/sustainability, which received core level certification from the Global Reporting Initiative. In furtherance of the Company’s commitment to a sustainable business model, and as detailed further below, the Company is transitioning its electric generation portfolio from nearly total reliance on baseload coal to a fully diversified and balanced portfolio of fuels that will provide long term electric supply needs in a safe and reliable manner while dramatically lowering emissions of carbon and the carbon intensity of its electric generating fleet. If authorized by the Commission, by 2024, the Company plans to construct a new natural gas combined cycle plant to replace four coal-fired units totaling over 700 MWs which, when combined with its planned 54 MWs of new renewable generation, will achieve a 60 percent reduction in carbon emissions from 2005 levels, reduce carbon intensity to 980 lbs. CO2 / MMBTU, and position the Company to comply with future carbon emission reduction requirements. In addition to diversification of its fuel portfolio, the Company is also seeking authorization to significantly upgrade wastewater treatment for its remaining coal-fired unit and exploring opportunities to continue to recycle ash from its coal ash ponds. This generation diversification strategy aligns with the Company’s ongoing investments in new electric infrastructure through the approved $450 million grid modernization program, and is set forth in more detail in the Company’s upcoming 2018 corporate sustainability report. Further, as part of its commitment to a culture of compliance excellence and continuous improvement, the Company continues to enhance its Safety Management System (SMS) which was implemented several years ago. The risk analysis and process review provides valuable input into the assessment process used to drive the ongoing infrastructure improvement plans being executed by the Company’s gas and electric utilities. The Company is subject to extensive environmental regulation pursuant to a variety of federal, state, and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others. Environmental legislation and regulation also requires that facilities, sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company's current costs to comply with these laws and regulations are significant to its results of operations and financial condition. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Senate Bill 251 is also applicable to federal environmental mandates impacting SIGECO's electric operations. Coal Ash Waste Disposal, Ash Ponds and Water Coal Combustion Residuals Rule In April 2015, the EPA finalized its Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). The final rule allows beneficial reuse of ash and the majority of the ash generated by the Company’s generating plants will continue to be reused. As it relates to the CCR Rule, the Water Infrastructure Improvements for the Nation (WIIN) Act was passed in December 2016 by Congress that would provide for enforcement of the federal program by states under approved state programs rather than citizen suits. Additionally, aspects of the CCR rule are currently being challenged by multiple parties in judicial review proceedings. In August, the EPA issued guidance to states to clarify their ability to implement the Federal CCR rule through state permit programs as allowed in the WIIN Act legislation. Alternative compliance mechanisms for groundwater, corrective action and other areas of the rule could be granted under the regulatory oversight of a state enforced program. On September 14, 2017, the EPA announced its intent to reconsider portions of the Federal CCR rule in line with the guidance issued to states. While the state program development and EPA reconsideration move forward, the existing CCR compliance obligations remain in effect. Under the existing CCR rule, the Company is required to complete a series of integrity assessments, including seismic modeling given the Company’s facilities are located within two seismic zones, and groundwater monitoring studies to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place, with bottom ash handling conversions completed. In late 2015, using general utility industry data, the Company prepared cost estimates for the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the closure alternatives contemplated in the final rule. The resulting estimates ranged from approximately $35 million to $80 million . These estimates contemplated final capping and monitoring costs of the ponds at both F.B. Culley and A.B. Brown generating stations. These rules are not applicable to the Company's Warrick generating unit, as this unit has historically been part of a larger generating station that predominantly serves an adjacent industrial facility. Throughout 2016 and 2017, the Company has continued to refine site specific estimates and now estimates the costs to be in the range of $45 million to $135 million . Significant factors impacting the resulting cost estimates include the closure time frame and the method of closure. Current estimates contemplate complete removal under the assumption of beneficial reuse of the ash at A.B. Brown, as well as implications of the Company’s generation transition plan. Ongoing analysis, the continued refinement of assumptions, or the inability to beneficially reuse the ash, either from a technological or economical perspective, could result in estimated costs in excess of the current range. As of December 31, 2017, the Company had recorded an approximate $40 million asset retirement obligation (ARO). The recorded ARO reflects the present value of the approximate $45 million in estimated costs in the range above. These assumptions and estimations are subject to change in the future and could materially impact the amount of the estimated ARO. In order to maintain current operations of the ponds, the Company spent approximately $17 million on the reinforcement of the ash pond dams and other operational changes in 2016 to meet the more stringent 2,500 year seismic event structural and safety standard in the CCR rule. Effluent Limitation Guidelines (ELG) Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. In September 2015, the EPA finalized revisions to the existing steam electric ELG setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELG will be implemented when existing water discharge permits for the plants are renewed, with compliance activities expected to commence where operations continue, within the 2018-2023 time frame. The ELG work in tandem with the aforementioned CCR requirements, effectively prohibiting the use of less costly lined sediment basin options for disposal of coal combustion residuals, and virtually mandate conversions to dry bottom ash handling. At the time of ELG finalization, the wastewater discharge permit for the A.B. Brown power plant had an expiration date of October 2016 and, for the F.B. Culley plant, a date of December 2016, and final renewals were issued by the Indiana Department of Environmental Management (IDEM) in February 2017 and March 2017, respectively. As part of the permit renewals, the Company requested alternate compliance dates for ELG, which were approved by IDEM. For plants identified in the Company’s preferred IRP to be retired prior to December 31, 2023, the Company has requested those plants would not require new treatment technology, which was approved by IDEM provided the Company notifies IDEM within one year of issuance of the renewal of its intent to retire the unit. For the F.B. Culley 3 plant, the Company requested a 2020 compliance date for dry bottom ash and 2023 compliance date for flue gas desulfurization wastewater, which was approved by IDEM and finalized in the permit renewal. Discussion of these environmental investments at the F.B. Culley 3 plant are included in the generation transition plan in Footnote 17 in the Company’s Consolidated Financial Statements included in Item 8. On April 13, 2017, as part of the Administration's regulatory reform initiative, which is focused on the number and nature of regulations, the EPA granted petitions to reconsider the ELG rule, and indicated it would stay the current implementation deadlines in the rule during the pendency of the reconsideration. The EPA has also sought a stay of the current judicial review litigation in federal district court. The court has yet to grant the indefinite stay sought by EPA, and instead placed the parties on a periodic status update schedule. On September 13, 2017, EPA finalized a rule postponing certain interim compliance dates by two years, but did not postpone the final compliance deadline of December 31, 2023. As the Company does not currently have short-term ELG implementation deadlines in its recently renewed wastewater discharge permits, the Company does not anticipate immediate impacts from the EPA’s two-year extension of preliminary implementation deadlines due to the longer compliance time frames granted by IDEM, and will continue to work with IDEM to evaluate further implementation plans. Moreover, the Company believes the two year extension of the ELG preliminary implementation deadlines and reconsideration process does not impact its preferred generation plan as modeled in the IRP because the final compliance deadline of December 31, 2023 is still in place and enhanced wastewater treatment for scrubber discharge water will still be required by a reconsidered ELG rule even if the EPA revises stringency levels. Cooling Water Intake Structures Section 316(b) of the Clean Water Act requires generating facilities use the “best technology available” (BTA) to minimize adverse environmental impacts on a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. A final rule was issued by the EPA on May 19, 2014. The final rule does not mandate cooling water tower retrofits but requires that IDEM conduct a case-by-case assessment of BTA for each facility. The final rule lists seven presumptive technologies which would qualify as BTA. These technologies range from intake screen modifications to cooling water tower retrofits. Ecological and technology assessment studies must be completed prior to determining BTA for the Company’s facilities. The Company is currently undertaking the required ecological studies and anticipates timely compliance in 2021-2022. To comply, the Company believes capital investments will likely be in the range of $4 million to $8 million . Air Quality Ozone NAAQS On November 26, 2014, the EPA proposed to tighten the current National Ambient Air Quality Standard (NAAQS) for ozone from the current standard of 75 parts per billion (ppb) to a level within the range of 65 to 70 ppb. On October 1, 2015, the EPA finalized a new NAAQS for ozone at the high end of the range, or 70 ppb. On September 16, 2016, Indiana submitted its initial determination to the EPA recommending counties in southwest Indiana, specifically Vanderburgh, Posey and Warrick, be declared in attainment of the new more stringent ozone standard based upon air monitoring data from 2014-2016. In November 2017, EPA finalized its designations of Vanderburgh, Posey, and Warrick counties as being in attainment with the current 70 ppb standard. One Hour SO2 NAAQS On February 16, 2016, the EPA notified states of the commencement of a 120 day consultation period between IDEM and the EPA with respect to the EPA's recommendations for new non-attainment designations for the 2010 One Hour SO2 NAAQS. Identified on the list was Posey County, Indiana, where the Company's A.B. Brown Generating Station is located. While the Company is in compliance with all applicable SO2 limits in its permits, the Company reached an agreement with IDEM on voluntary measures the Company was able to implement without significant incremental costs to ensure Posey County remains in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. Climate Change and Carbon Strategy On August 3, 2015, the EPA released its final Clean Power Plan rule (CPP) which required a 32 percent reduction in carbon emissions from 2005 levels. This would result in a final emission rate goal for Indiana of 1,242 lb. CO2/MWh to be achieved by 2030 and implemented through a state implementation plan. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation initiated by Indiana and 23 other states as a coalition challenging the rule. In January 2016, the reviewing court denied the states’ and other parties requests to stay the implementation of the CPP pending completion of judicial review. On January 26, 2016, 29 states and state agencies, including the 24 state coalition referenced above, filed a request for immediate stay of implementation of the rule with the U.S. Supreme Court. On February 9, 2016, the U.S. Supreme Court granted the stay request to delay the implementation of the regulation while being challenged in court. Oral argument was held in September 2016. The stay will remain in place while the lower court concludes its review. In March 2017, as part of the ongoing regulatory reform efforts of the Administration, the EPA filed a motion with the U.S. Court of Appeals for the District of Columbia circuit to suspend litigation pending the EPA’s reconsideration of the CPP rule, which was granted on April 28, 2017. Moreover, as indicated above, in October, 2017, EPA published its proposal to repeal the CPP. Comments to the repeal proposal are due in April 2018. EPA's repeal proposal was quickly followed by an advanced notice of proposed rulemaking intended to solicit public comments on issues related to formulating a CPP replacement rule, which are similarly due in April 2018. Repeal without replacement of the CPP could create potential litigation risk arising from the absence of direct federal regulation in this area that courts have previously determined preempt common law nuisance claims. Impact of Legislative Actions & Other Initiatives is Unknown At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. However, Vectren's generation transition plan, as set forth in its electric generation and compliance filing, will achieve 60 percent reductions in 2005 GHG emission levels by 2025, positioning the Company to comply with future regulatory or legislative actions with respect to mandatory GHG reductions. In addition to the federal programs, the United States and 194 other countries agreed by consensus to limit GHG emissions beginning after 2020 in the 2015 United Nations Framework Convention on Climate Change Paris Agreement. The United States has proposed a 26-28 percent GHG emission reduction from 2005 levels by 2025. The Administration has indicated it intends to withdraw the United States' participation; however the Agreement provides that parties cannot petition to withdraw until November 2019. Since 2005 through 2017, the Company has achieved reduced emissions of CO2 by an average of 35 percent (on a tonnage basis), and will increase that total to 60 percent at the conclusion of its generation transition plan, well above the 32 percent reduction that would be required under the CPP. While the litigation and the EPA's reconsideration of the CPP rules remains uncertain, the Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units. Manufactured Gas Plants In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds. In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/ feasibility study (RI/FS) was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites. The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $44.2 million ( $23.9 million at Indiana Gas and $20.3 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP). With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received approximately $15.7 million of the expected $15.8 million in insurance recoveries. The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2017 and 2016 , approximately $2.5 million and $2.9 million , respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: At December 31, 2017 2016 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,579.5 $ 1,715.2 $ 1,380.1 $ 1,495.3 Short-term borrowings & notes payable 179.5 179.5 194.4 194.4 Cash & cash equivalents 9.8 9.8 9.4 9.4 Natural gas purchase instrument assets (1) 0.5 0.5 — — Natural gas purchase instrument liabilities (2) 4.5 4.5 — — Interest rate swap liabilities (3) 1.4 1.4 — — Restricted cash — — 0.9 0.9 (1) P resented in "Other investments" on the Consolidated Balance Sheets. (2) P resented in "Deferred credits & other liabilities" on the Consolidated Balance Sheets. (3) Presented in "Deferred credits & other liabilities" on the Consolidated Balance Sheets. Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date. Under current regulatory treatment, call premiums on reacquisition of utility-related long-term debt are generally recovered in customer rates over the life of the refunding issue. Accordingly, any reacquisition of this debt would not be expected to have a material effect on the Company's results of operations. The Company’s Indiana gas utilities entered into four five -year forward purchase arrangements to hedge the variable price of natural gas for a portion of the Company’s gas supply. These arrangements, approved by the IURC, replaced normal purchase or normal sale long-term physical fixed-price purchases. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Gains and losses on these derivative contracts are deferred as regulatory liabilities or assets and are refunded to or collected from customers through the Company’s respective gas cost recovery mechanisms. The Company, through SIGECO, executed forward starting interest rate swaps during 2017 providing that on January 1, 2020, the Company will begin hedging the variability in interest rates on the 2013 Series A, B, and E Notes, as described in Note 6, through final maturity dates. The Company values these contracts using a pricing model that incorporates market-based information, and are classified within Level 2 of the fair value hierarchy. Regulatory orders require SIGECO to include the impact of its interest rate risk management activities, such as gains and losses arising from these swaps, in its cost of capital utilized in rate cases and other periodic filings. |
Segment Reporting
Segment Reporting | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Reporting | Segment Reporting The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west-central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Company is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Operations. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized below: Year Ended December 31, (In millions) 2017 2016 2015 Revenues Gas Utility Services $ 812.7 $ 771.7 $ 792.6 Electric Utility Services 569.6 605.8 601.6 Other Operations 45.6 42.2 40.7 Eliminations (45.3 ) (41.9 ) (40.4 ) Total revenues $ 1,382.6 $ 1,377.8 $ 1,394.5 Profitability Measure - Net Income Gas Utility Services $ 115.5 $ 76.1 $ 64.4 Electric Utility Services 75.2 84.7 82.6 Other Operations (14.9 ) 12.8 13.9 Total net income $ 175.8 $ 173.6 $ 160.9 Amounts Included in Profitability Measures Depreciation & Amortization Gas Utility Services $ 118.9 $ 108.1 $ 98.6 Electric Utility Services 89.5 87.1 85.6 Other Operations 26.1 23.9 24.6 Total depreciation & amortization $ 234.5 $ 219.1 $ 208.8 Interest Expense Gas Utility Services $ 43.0 $ 40.1 $ 35.8 Electric Utility Services 25.8 27.0 27.8 Other Operations 3.8 2.6 2.7 Total interest expense $ 72.6 $ 69.7 $ 66.3 Income Taxes Gas Utility Services $ 25.4 $ 47.1 $ 40.8 Electric Utility Services 41.4 50.1 49.3 Other Operations (6.1 ) 2.3 (2.0 ) Total income taxes $ 60.7 $ 99.5 $ 88.1 Capital Expenditures Gas Utility Services $ 391.4 $ 358.5 $ 291.2 Electric Utility Services 105.3 106.4 87.6 Other Operations 60.1 39.0 25.7 Non-cash costs & changes in accruals (2.6 ) (7.3 ) (5.3 ) Total capital expenditures $ 554.2 $ 496.6 $ 399.2 At December 31, (In millions) 2017 2016 2015 Assets Gas Utility Services $ 3,457.8 $ 3,091.0 $ 2,706.9 Electric Utility Services 1,820.3 1,788.4 1,778.3 Other Operations, net of eliminations 219.7 161.5 107.5 Total assets $ 5,497.8 $ 5,040.9 $ 4,592.7 |
Additional Balance Sheet & Oper
Additional Balance Sheet & Operational Information | 12 Months Ended |
Dec. 31, 2017 | |
Additional Balance Sheet and Operational Information [Abstract] | |
Additional Balance Sheet & Operational Information | Additional Balance Sheet & Operational Information Inventories consist of the following: At December 31, (In millions) 2017 2016 Gas in storage – at LIFO cost $ 36.0 $ 37.0 Materials & supplies 37.0 38.1 Coal & oil for electric generation - at average cost 43.1 42.6 Other 1.4 1.3 Total inventories $ 117.5 $ 119.0 Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost is less than the carrying value at December 31, 2017 by $2.0 million . Based on the average cost of gas purchased during December, the cost of replacing inventories carried at LIFO cost exceeded carrying value at December 31, 2016 by $1.0 million . Prepayments & other current assets in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2017 2016 Prepaid gas delivery service $ 26.6 $ 26.4 Prepaid taxes 2.6 8.0 Other prepayments & current assets 3.5 4.2 Total prepayments & other current assets $ 32.7 $ 38.6 Other investments in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2017 2016 Cash surrender value of life insurance policies $ 25.4 $ 20.4 Restricted cash & other investments 1.3 0.9 Total other investments $ 26.7 $ 21.3 Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2017 2016 Refunds to customers & customer deposits $ 51.4 $ 49.4 Accrued taxes 55.8 44.8 Accrued interest 17.9 16.4 Accrued salaries & other 28.9 29.5 Total accrued liabilities $ 154.0 $ 140.1 Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2017 2016 Asset retirement obligation, January 1 $ 106.6 $ 81.9 Accretion 4.3 3.8 Changes in estimates, net of cash payments (4.0 ) 20.9 Asset retirement obligation, December 31 $ 106.9 $ 106.6 Other – net in the Consolidated Statements of Income consists of the following: Year Ended December 31, (In millions) 2017 2016 2015 AFUDC - borrowed funds $ 24.8 $ 20.3 $ 16.3 AFUDC - equity funds 2.6 2.2 2.6 Nonutility plant capitalized interest 1.2 1.0 0.4 Interest income — 0.3 0.6 Other income 2.0 2.5 (1.2 ) Total other – net $ 30.6 $ 26.3 $ 18.7 Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2017 2016 2015 Cash paid (received) for: Interest $ 71.2 $ 69.6 $ 66.2 Income taxes (6.1 ) 6.7 (23.1 ) As of December 31, 2017 and 2016 , the Company has accruals related to utility and nonutility plant purchases totaling approximately $27.5 million and $27.4 million , respectively. |
Subsidiary Guarantor & Consolid
Subsidiary Guarantor & Consolidating Information | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Subsidiary Guarantor & Consolidating Information | Subsidiary Guarantor & Consolidating Information The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO, are guarantors of the Company’s $400 million in short-term credit facilities, of which $180 million was outstanding at December 31, 2017 , and the Company’s $1.2 billion in unsecured senior notes outstanding at December 31, 2017 . The guarantees are full and unconditional and joint and several, and the Company has no subsidiaries other than the subsidiary guarantors. However, it does have operations other than those of the subsidiary guarantors. Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are wholly owned, separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level. Consolidating Statement of Income for the year ended December 31, 2017 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 812.7 $ — $ — $ 812.7 Electric utility 569.6 — — 569.6 Other — 45.6 (45.3 ) 0.3 Total operating revenues 1,382.3 45.6 (45.3 ) 1,382.6 OPERATING EXPENSES Cost of gas sold 271.5 — — 271.5 Cost of fuel & purchased power 171.8 — — 171.8 Other operating 378.6 35.7 (43.9 ) 370.4 Depreciation & amortization 208.4 26.0 0.1 234.5 Taxes other than income taxes 53.8 2.0 0.1 55.9 Total operating expenses 1,084.1 63.7 (43.7 ) 1,104.1 OPERATING INCOME 298.2 (18.1 ) (1.6 ) 278.5 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 190.7 (190.7 ) — Other – net 28.2 50.3 (47.9 ) 30.6 Total other income (expense) 28.2 241.0 (238.6 ) 30.6 Interest expense 68.8 53.3 (49.5 ) 72.6 INCOME BEFORE INCOME TAXES 257.6 169.6 (190.7 ) 236.5 Income taxes 66.9 (6.2 ) — 60.7 NET INCOME $ 190.7 $ 175.8 $ (190.7 ) $ 175.8 Consolidating Statement of Income for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 771.7 $ — $ — $ 771.7 Electric utility 605.8 — — 605.8 Other — 42.2 (41.9 ) 0.3 Total operating revenues 1,377.5 42.2 (41.9 ) 1,377.8 OPERATING EXPENSES Cost of gas sold 266.7 — — 266.7 Cost of fuel & purchased power 183.6 — — 183.6 Other operating 374.0 — (40.4 ) 333.6 Depreciation & amortization 195.2 23.8 0.1 219.1 Taxes other than income taxes 56.8 1.5 — 58.3 Total operating expenses 1,076.3 25.3 (40.3 ) 1,061.3 OPERATING INCOME 301.2 16.9 (1.6 ) 316.5 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 160.8 (160.8 ) — Other – net 24.0 48.3 (46.0 ) 26.3 Total other income (expense) 24.0 209.1 (206.8 ) 26.3 Interest expense 67.2 50.1 (47.6 ) 69.7 INCOME BEFORE INCOME TAXES 258.0 175.9 (160.8 ) 273.1 Income taxes 97.2 2.3 — 99.5 NET INCOME $ 160.8 $ 173.6 $ (160.8 ) $ 173.6 Consolidating Statement of Income for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 792.6 $ — $ — $ 792.6 Electric utility 601.6 — — 601.6 Other — 40.7 (40.4 ) 0.3 Total operating revenues 1,394.2 40.7 (40.4 ) 1,394.5 OPERATING EXPENSES Cost of gas sold 305.4 — — 305.4 Cost of fuel & purchased power 187.5 — — 187.5 Other operating 376.9 — (37.8 ) 339.1 Depreciation & amortization 184.2 24.3 0.3 208.8 Taxes other than income taxes 55.2 1.8 0.1 57.1 Total operating expenses 1,109.2 26.1 (37.4 ) 1,097.9 OPERATING INCOME 285.0 14.6 (3.0 ) 296.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 147.0 (147.0 ) — Other – net 15.7 42.7 (39.7 ) 18.7 Total other income (expense) 15.7 189.7 (186.7 ) 18.7 Interest expense 63.7 45.3 (42.7 ) 66.3 INCOME BEFORE INCOME TAXES 237.0 159.0 (147.0 ) 249.0 Income taxes 90.0 (1.9 ) — 88.1 NET INCOME $ 147.0 $ 160.9 $ (147.0 ) $ 160.9 Consolidating Balance Sheet as of December 31, 2017 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 8.2 $ 1.6 $ — $ 9.8 Accounts receivable - less reserves 109.2 0.3 — 109.5 Intercompany receivables — 227.5 (227.5 ) — Accrued unbilled revenues 123.7 — — 123.7 Inventories 117.5 — — 117.5 Recoverable fuel & natural gas costs 19.2 — — 19.2 Prepayments & other current assets 28.9 12.6 (8.8 ) 32.7 Total current assets 406.7 242.0 (236.3 ) 412.4 Utility Plant Original cost 7,015.4 — — 7,015.4 Less: accumulated depreciation & amortization 2,738.7 — — 2,738.7 Net utility plant 4,276.7 — — 4,276.7 Investments in consolidated subsidiaries — 1,741.0 (1,741.0 ) — Notes receivable from consolidated subsidiaries — 970.7 (970.7 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 26.3 0.4 — 26.7 Nonutility plant - net 1.6 197.0 — 198.6 Goodwill - net 205.0 — — 205.0 Regulatory assets 298.7 15.3 — 314.0 Other assets 62.5 1.8 (0.1 ) 64.2 TOTAL ASSETS $ 5,277.7 $ 3,168.2 $ (2,948.1 ) $ 5,497.8 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 179.4 $ 42.4 $ — $ 221.8 Intercompany payables 8.3 — (8.3 ) — Payables to other Vectren companies 25.2 8.1 — 33.3 Accrued liabilities 147.7 15.1 (8.8 ) 154.0 Short-term borrowings — 179.5 — 179.5 Intercompany short-term borrowings 120.2 — (120.2 ) — Current maturities of long-term debt — 100.0 — 100.0 Current maturities of long-term debt due to VUHI 99.0 — (99.0 ) — Total current liabilities 579.8 345.1 (236.3 ) 688.6 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 384.5 1,095.0 — 1,479.5 Long-term debt due to VUHI 970.7 — (970.7 ) — Total long-term debt - net 1,355.2 1,095.0 (970.7 ) 1,479.5 Deferred Income Taxes & Other Liabilities Deferred income taxes 455.3 2.2 — 457.5 Regulatory liabilities 936.1 1.1 — 937.2 Deferred credits & other liabilities 210.3 2.0 (0.1 ) 212.2 Total deferred credits & other liabilities 1,601.7 5.3 (0.1 ) 1,606.9 Common Shareholder's Equity Common stock (no par value) 890.7 877.5 (890.7 ) 877.5 Retained earnings 850.3 845.3 (850.3 ) 845.3 Total common shareholder's equity 1,741.0 1,722.8 (1,741.0 ) 1,722.8 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 5,277.7 $ 3,168.2 $ (2,948.1 ) $ 5,497.8 Consolidating Balance Sheet as of December 31, 2016 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 7.6 $ 1.8 $ — $ 9.4 Accounts receivable - less reserves 102.4 0.2 — 102.6 Intercompany receivables 17.5 157.1 (174.6 ) — Accrued unbilled revenues 112.0 — — 112.0 Inventories 119.0 — — 119.0 Recoverable fuel & natural gas costs 29.9 — — 29.9 Prepayments & other current assets 36.5 4.4 (2.3 ) 38.6 Total current assets 424.9 163.5 (176.9 ) 411.5 Utility Plant Original cost 6,545.4 — — 6,545.4 Less: accumulated depreciation & amortization 2,562.5 — — 2,562.5 Net utility plant 3,982.9 — — 3,982.9 Investments in consolidated subsidiaries — 1,577.2 (1,577.2 ) — Notes receivable from consolidated subsidiaries — 945.4 (945.4 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 20.9 0.4 — 21.3 Nonutility plant - net 1.7 163.1 — 164.8 Goodwill - net 205.0 — — 205.0 Regulatory assets 190.0 16.2 — 206.2 Other assets 53.9 3.7 (8.6 ) 49.0 TOTAL ASSETS $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 194.6 $ 10.8 $ — $ 205.4 Intercompany payables 14.8 — (14.8 ) — Payables to other Vectren companies 25.4 — — 25.4 Accrued liabilities 126.0 16.4 (2.3 ) 140.1 Short-term borrowings — 194.4 — 194.4 Intercompany short-term borrowings 142.3 17.5 (159.8 ) — Current maturities of long-term debt 49.1 — — 49.1 Total current liabilities 552.2 239.1 (176.9 ) 614.4 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 335.2 995.8 — 1,331.0 Long-term debt due to VUHI 945.4 — (945.4 ) — Total long-term debt - net 1,280.6 995.8 (945.4 ) 1,331.0 Deferred Income Taxes & Other Liabilities Deferred income taxes 855.4 (0.9 ) — 854.5 Regulatory liabilities 452.4 1.3 — 453.7 Deferred credits & other liabilities 161.7 10.2 (8.6 ) 163.3 Total deferred credits & other liabilities 1,469.5 10.6 (8.6 ) 1,471.5 Common Shareholder's Equity Common stock (no par value) 844.4 831.2 (844.4 ) 831.2 Retained earnings 732.8 792.8 (732.8 ) 792.8 Total common shareholder's equity 1,577.2 1,624.0 (1,577.2 ) 1,624.0 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 Consolidating Statement of Cash Flows for the year ended December 31, 2017 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH FROM OPERATING ACTIVITIES $ 398.5 $ 48.3 $ — $ 446.8 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 123.9 198.9 (124.3 ) 198.5 Additional capital contribution from parent 46.3 46.3 (46.3 ) 46.3 Requirements for: Dividends to parent (73.1 ) (123.3 ) 73.1 (123.3 ) Net change in intercompany short-term borrowings (22.1 ) (17.5 ) 39.6 — Net change in short-term borrowings — (14.9 ) — (14.9 ) Net cash from financing activities 75.0 89.5 (57.9 ) 106.6 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 73.1 (73.1 ) — Other investing activities 2.7 — — 2.7 Requirements for: Capital expenditures, excluding AFUDC equity (491.6 ) (62.6 ) — (554.2 ) Consolidated subsidiary investments — (46.3 ) 46.3 — Other costs (2.4 ) — — (2.4 ) Changes in restricted cash 0.9 — — 0.9 Net change in long-term intercompany notes receivable — (124.3 ) 124.3 — Net change in short-term intercompany notes receivable 17.5 22.1 (39.6 ) — Net cash from investing activities (472.9 ) (138.0 ) 57.9 (553.0 ) Net change in cash & cash equivalents 0.6 (0.2 ) — 0.4 Cash & cash equivalents at beginning of period 7.6 1.8 — 9.4 Cash & cash equivalents at end of period $ 8.2 $ 1.6 $ — $ 9.8 Consolidating Statement of Cash Flows for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH FROM OPERATING ACTIVITIES $ 352.2 $ 45.2 $ — $ 397.4 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 109.4 — (109.4 ) — Additional capital contribution from parent 31.3 31.3 (31.3 ) 31.3 Requirements for: Dividends to parent (82.0 ) (116.1 ) 82.0 (116.1 ) Retirement of long-term debt (13.0 ) — — (13.0 ) Net change in intercompany short-term borrowings 11.9 (33.7 ) 21.8 — Net change in short-term borrowings — 179.9 — 179.9 Net cash from financing activities 57.6 61.4 (36.9 ) 82.1 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 82.0 (82.0 ) — Other investing activities 15.3 — — 15.3 Requirements for: Capital expenditures, excluding AFUDC equity (461.7 ) (34.9 ) — (496.6 ) Consolidated subsidiary investments — (31.3 ) 31.3 — Changes in restricted cash 5.0 — — 5.0 Net change in long-term intercompany notes receivable — (109.4 ) 109.4 — Net change in short-term intercompany notes receivable 33.7 (11.9 ) (21.8 ) — Net cash from investing activities (407.7 ) (105.5 ) 36.9 (476.3 ) Net change in cash & cash equivalents 2.1 1.1 — 3.2 Cash & cash equivalents at beginning of period 5.5 0.7 — 6.2 Cash & cash equivalents at end of period $ 7.6 $ 1.8 $ — $ 9.4 Consolidating Statement of Cash Flows for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH FROM OPERATING ACTIVITIES $ 460.3 $ 32.6 $ — $ 492.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 126.8 199.0 (89.5 ) 236.3 Additional capital contribution from parent 6.2 6.2 (6.2 ) 6.2 Requirements for: Dividends to parent (103.2 ) (110.4 ) 103.2 (110.4 ) Retirement of long-term debt (20.0 ) (75.0 ) — (95.0 ) Net change in intercompany short-term borrowings (40.7 ) 51.2 (10.5 ) — Net change in short-term borrowings — (141.9 ) — (141.9 ) Net cash from financing activities (30.9 ) (70.9 ) (3.0 ) (104.8 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 103.2 (103.2 ) — Other investing activities — 3.9 — 3.9 Requirements for: Capital expenditures, excluding AFUDC equity (373.7 ) (25.5 ) — (399.2 ) Consolidated subsidiary investments — (6.2 ) 6.2 — Changes in restricted cash (5.9 ) — — (5.9 ) Net change in long-term intercompany notes receivable — (89.5 ) 89.5 — Net change in short-term intercompany notes receivable (51.2 ) 40.7 10.5 — Net cash from investing activities (430.8 ) 26.6 3.0 (401.2 ) Net change in cash & cash equivalents (1.4 ) (11.7 ) — (13.1 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 5.5 $ 0.7 $ — $ 6.2 |
Impact of Recently Issued Accou
Impact of Recently Issued Accounting Guidance | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Changes and Error Corrections [Abstract] | |
Impact of Recently Issued Accounting Guidance | Impact of Recently Issued Accounting Guidance Revenue Recognition In May 2014, the FASB issued new accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The amendments in this guidance state an entity should 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. This new guidance requires improved disclosures to help users of financial statements better understand the nature, amount, timing, and uncertainty of revenue that is recognized. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Company plans to adopt the guidance under the modified retrospective method. The cumulative effect adjustment to retained earnings will be immaterial. In July 2015, the FASB approved a one year deferral that became effective through an ASU in August and changed the effective date to annual reporting periods beginning after December 15, 2017, including interim periods, with early adoption permitted, but not before the original effective date of December 15, 2016. The Company has finalized the assessment process of all revenue streams for the standard’s impact on the Consolidated Balance Sheets, Consolidated Statements of Operations, and disclosures and has identified all material revenue streams. The Company has determined that all material revenue streams fall under the scope of the standard. The standard will result in no significant changes to the Company's pattern of revenue recognition. The Company has adopted the guidance effective January 1, 2018. Leases In February 2016, the FASB issued new accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. This ASU requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease. In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. This ASU is effective for the interim and annual reporting periods beginning January 1, 2019, although it can be early adopted, with a modified retrospective approach for leases that commenced prior to the date of adoption. The Company is currently evaluating the standard to determine the impact it will have on the financial statements and will adopt the guidance effective January 1, 2019. Stock Compensation In March 2016, the FASB issued new accounting guidance intended to simplify several aspects of accounting for share-based payment transactions, including the income tax consequences. This ASU was effective for annual periods beginning after December 15, 2016, and interim periods therein. Most of the Company's parent's share-based awards are settled via cash payments, most of which are funded by the Company, and were therefore not impacted by this standard. The Company's parent's adoption of this standard did not have a material impact on the financial statements. Presentation of Net Periodic Pension and Postretirement Benefit Costs In March 2017, the FASB issued new accounting guidance to improve the presentation of net periodic pension and postretirement benefit costs. This ASU is effective for annual periods beginning after December 15, 2017, and relevant interim periods. This ASU requires the Company to report the service cost component incurred by the Company's parent and allocated to the Company in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost allocated to the Company are required to be presented in the income statement separately from the service cost component and outside of income from operations. Capitalization of net benefit cost is limited to only the service cost component of benefit costs, when applicable. The ASU requires retrospective presentation of the service and non-service costs components in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company has finalized its assessment of the standard and the adoption will have an immaterial impact on the financial statements. The Company has adopted the guidance effective January 1, 2018. Other Recently Issued Standards Management believes other recently issued standards, which are not yet effective, will not have a material impact on the Company's financial condition, results of operations, or cash flows upon adoption. |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Data (Unaudited) | Quarterly Financial Data (Unaudited) Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2017 and 2016 follows: (In millions) Q1 Q2 Q3 Q4 2017 Results of Operations: Operating revenues $ 425.0 $ 285.9 $ 279.7 $ 392.1 Operating income 113.5 49.7 58.0 57.5 Net income 65.9 25.5 30.8 53.6 2016 Results of Operations: Operating revenues $ 423.4 $ 279.8 $ 291.3 $ 383.5 Operating income 106.8 52.2 64.0 93.5 Net income 61.1 26.3 34.9 51.3 |
SCHEDULE II VALUATION AND QUALI
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | 12 Months Ended |
Dec. 31, 2017 | |
Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | SCHEDULE II Vectren Utility Holdings, Inc. and Subsidiaries VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged Charged Deductions Balance at Beginning to to Other from End of Description Of Year Expenses Accounts Reserves, Net Year (In millions) VALUATION AND QUALIFYING ACCOUNTS: Year 2017 – Accumulated provision for uncollectible accounts $ 4.1 $ 5.7 $ — $ 5.9 $ 3.9 Year 2016 – Accumulated provision for uncollectible accounts $ 3.0 $ 6.6 $ — $ 5.5 $ 4.1 Year 2015 – Accumulated provision for uncollectible accounts $ 3.9 $ 6.9 $ — $ 7.8 $ 3.0 |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after appropriate elimination of intercompany transactions. |
Subsequent Events Review | Subsequent Events Review Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. |
Cash and Cash Equivalents | Cash & Cash Equivalents Highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. |
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed. |
Inventories | Inventories In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities is recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed. |
Property, Plant & Equipment | Property, Plant & Equipment Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. Utility Plant & Related Depreciation Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income . When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility Plant , with an offsetting charge to Accumulated depreciation , resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO. The Company’s portion of jointly owned Utility Plant , along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage. Nonutility Plant & Related Depreciation The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses. Impairment Reviews Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. |
Goodwill | Goodwill Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at an operating segment level because the components within the segments are similar. These tests are performed at least annually and at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the carrying amount, an impairment loss is recognized in operations. |
Regulation | Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power All metered gas rates in Indiana contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. Regulatory Assets & Liabilities Regulatory assets represent certain incurred costs, which will result in probable future cash recoveries from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate. The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation. |
Asset Retirement Obligations | Asset Retirement Obligations A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral. |
Energy Contracts & Derivatives | Energy Contracts & Derivatives The Company will periodically execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value depends on the intended use of the derivative and resulting designation. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale (NPNS), it is exempt from mark-to-market accounting. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases, and wind farm and other electric generating contracts. When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets . The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. The offset to contracts affected by regulatory accounting treatment, which includes most of the Company's executed and financial contracts, are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources or from internal models |
Revenues | Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of an accounting period in Accrued unbilled revenues . Substantially all revenue sources are subject to unbilled accruals. |
MISO Transactions | MISO Transactions With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as other utilities in the region. The Company is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues . On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms. |
Excise and Utility Receipts Taxes | Excise & Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $29.1 million in 2017 , $28.3 million in 2016 , and $29.4 million in 2015 . Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes . |
Operating Segments | Operating Segments The Company's chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. |
Fair Value Measurements | Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets, and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs. |
Other Significant Policies | Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes (Note 5). |
Utility & Nonutility Plant (Tab
Utility & Nonutility Plant (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Cost of Utility Plant, together with depreciation rates expressed as a percentage of original costs | The original cost of Utility Plant , together with depreciation rates expressed as a percentage of original cost, follows: At and For the Year Ended December 31, (In millions) 2017 2016 Original Cost Depreciation Rates as a Percent of Original Cost Original Cost Depreciation Rates as a Percent of Original Cost Gas utility plant $ 3,969.6 3.4 % $ 3,587.5 3.4 % Electric utility plant 2,833.5 3.3 % 2,752.0 3.3 % Common utility plant 59.0 3.2 % 56.3 3.2 % Construction work in progress 70.7 — 63.0 — Asset retirement obligations 82.6 — 86.6 — Total original cost $ 7,015.4 $ 6,545.4 |
Nonutility Plant, net of accumulated depreciation and amortization | Nonutility Plant, net of accumulated depreciation and amortization follows: At December 31, (In millions) 2017 2016 Computer hardware & software $ 155.6 $ 120.5 Land & buildings 37.1 37.6 All other 5.9 6.7 Nonutility plant - net $ 198.6 $ 164.8 |
Regulatory Assets & Liabiliti27
Regulatory Assets & Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets | Regulatory assets consist of the following: At December 31, (In millions) 2017 2016 Future amounts recoverable from ratepayers related to: Net deferred income taxes $ 6.2 $ (17.1 ) Asset retirement obligations & other 24.3 — 30.5 (17.1 ) Amounts deferred for future recovery related to: Cost recovery riders & other 142.4 91.6 142.4 91.6 Amounts currently recovered in customer rates related to: Indiana authorized trackers 75.9 64.2 Ohio authorized trackers 28.4 22.2 Loss on reacquired debt & hedging costs 22.7 24.1 Deferred coal costs 14.1 21.2 141.1 131.7 Total regulatory assets $ 314.0 $ 206.2 |
Transactions with Other Vectr28
Transactions with Other Vectren Companies and Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Transactions with Other Vectren Companies and Affiliates [Abstract] | |
Components of income tax expense and utilization of investment tax credits | The components of income tax expense and amortization of investment tax credits follow: Year Ended December 31, (In millions) 2017 2016 2015 Current: Federal $ 10.0 $ (1.4 ) $ (1.9 ) State 4.8 4.2 4.2 Total current taxes 14.8 2.8 2.3 Deferred: Federal 43.9 93.5 81.7 State 2.4 3.7 4.6 Total deferred taxes 46.3 97.2 86.3 Amortization of investment tax credits (0.4 ) (0.5 ) (0.5 ) Total income tax expense $ 60.7 $ 99.5 $ 88.1 |
Reconciliation of the federal statutory rate to the effective income tax rate | A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, 2017 2016 2015 Statutory rate 35.0 % 35.0 % 35.0 % State and local taxes-net of federal benefit 2.8 2.6 2.8 Deferred tax revaluation-tax law change (9.8 ) — — Amortization of investment tax credit (0.2 ) (0.2 ) (0.2 ) Domestic production deduction (1.1 ) (0.5 ) (0.9 ) Research and development credit (0.3 ) (0.8 ) (2.0 ) All other - net (0.7 ) 0.3 0.7 Effective tax rate 25.7 % 36.4 % 35.4 % |
Significant components of the net deferred tax liability (assets) | Significant components of the net deferred tax liability follow: At December 31, (In millions) 2017 2016 Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 537.2 $ 821.6 Regulatory assets recoverable through future rates 7.9 17.6 Alternative minimum tax carryforward (12.2 ) (29.3 ) Employee benefit obligations (0.3 ) 10.2 U.S. federal charitable contributions carryforwards (6.2 ) — Regulatory liabilities to be settled through future rates (116.2 ) (15.9 ) Deferred fuel costs 16.2 25.9 Other – net 31.1 24.4 Net noncurrent deferred tax liability $ 457.5 $ 854.5 |
Borrowing Arrangements (Tables)
Borrowing Arrangements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Short term borrowing arrangements | Following is certain information regarding the Company's short-term borrowing arrangement: (In millions) 2017 2016 2015 Year End Balance Outstanding $ 179.5 $ 194.4 $ 14.5 Weighted Average Interest Rate 1.92 % 1.05 % 0.55 % Annual Average Balance Outstanding $ 172.4 $ 59.8 $ 53.8 Weighted Average Interest Rate 1.30 % 0.71 % 0.38 % Maximum Month End Balance Outstanding $ 238.7 $ 194.4 $ 121.5 |
Long term senior unsecured obligations and first mortgage bonds outstanding by subsidiary | Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow: At December 31, (In millions) 2017 2016 Utility Holdings Fixed Rate Senior Unsecured Notes 2018, 5.75% $ 100.0 $ 100.0 2020, 6.28% 100.0 100.0 2021, 4.67% 55.0 55.0 2023, 3.72% 150.0 150.0 2026, 5.02% 60.0 60.0 2028, 3.20% 45.0 45.0 2032, 3.26% 100.0 — 2035, 6.10% 75.0 75.0 2035, 3.90% 25.0 25.0 2041, 5.99% 35.0 35.0 2042, 5.00% 100.0 100.0 2043, 4.25% 80.0 80.0 2045, 4.36% 135.0 135.0 2047, 3.93% 100.0 — 2055, 4.51% 40.0 40.0 Total Utility Holdings 1,200.0 1,000.0 SIGECO First Mortgage Bonds 2022, 2013 Series C, current adjustable rate 1.565%, tax exempt 4.6 4.6 2024, 2013 Series D, current adjustable rate 1.565%, tax exempt 22.5 22.5 2025, 2014 Series B, current adjustable rate 1.565%, tax-exempt 41.3 41.3 2029, 1999 Series, 6.72% 80.0 80.0 2037, 2013 Series E, current adjustable rate 1.565%, tax exempt 22.0 22.0 2038, 2013 Series A, 4.00%, tax exempt 22.2 22.2 2043, 2013 Series B, 4.05%, tax exempt 39.6 39.6 2044, 2014 Series A, 4.00%, tax exempt 22.3 22.3 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt 23.0 23.0 2055, 2015 Series Warrick County, 2.375%, tax-exempt 15.2 15.2 Total SIGECO 292.7 292.7 Indiana Gas Fixed Rate Senior Unsecured Notes 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 1.0 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 Total Indiana Gas 96.0 96.0 Total long-term debt outstanding 1,588.7 1,388.7 Current maturities of long-term debt (100.0 ) (49.1 ) Debt issuance costs (8.6 ) (7.9 ) Unamortized debt premium & discount - net (0.6 ) (0.7 ) Total long-term debt-net $ 1,479.5 $ 1,331.0 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Carrying value and estimated fair value of other financial instruments | The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow: At December 31, 2017 2016 (In millions) Carrying Amount Est. Fair Value Carrying Amount Est. Fair Value Long-term debt $ 1,579.5 $ 1,715.2 $ 1,380.1 $ 1,495.3 Short-term borrowings & notes payable 179.5 179.5 194.4 194.4 Cash & cash equivalents 9.8 9.8 9.4 9.4 Natural gas purchase instrument assets (1) 0.5 0.5 — — Natural gas purchase instrument liabilities (2) 4.5 4.5 — — Interest rate swap liabilities (3) 1.4 1.4 — — Restricted cash — — 0.9 0.9 (1) P resented in "Other investments" on the Consolidated Balance Sheets. (2) P resented in "Deferred credits & other liabilities" on the Consolidated Balance Sheets. (3) Presented in "Deferred credits & other liabilities" on the Consolidated Balance Sheets. |
Segment Reporting (Tables)
Segment Reporting (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting | Information related to the Company’s business segments is summarized below: Year Ended December 31, (In millions) 2017 2016 2015 Revenues Gas Utility Services $ 812.7 $ 771.7 $ 792.6 Electric Utility Services 569.6 605.8 601.6 Other Operations 45.6 42.2 40.7 Eliminations (45.3 ) (41.9 ) (40.4 ) Total revenues $ 1,382.6 $ 1,377.8 $ 1,394.5 Profitability Measure - Net Income Gas Utility Services $ 115.5 $ 76.1 $ 64.4 Electric Utility Services 75.2 84.7 82.6 Other Operations (14.9 ) 12.8 13.9 Total net income $ 175.8 $ 173.6 $ 160.9 Amounts Included in Profitability Measures Depreciation & Amortization Gas Utility Services $ 118.9 $ 108.1 $ 98.6 Electric Utility Services 89.5 87.1 85.6 Other Operations 26.1 23.9 24.6 Total depreciation & amortization $ 234.5 $ 219.1 $ 208.8 Interest Expense Gas Utility Services $ 43.0 $ 40.1 $ 35.8 Electric Utility Services 25.8 27.0 27.8 Other Operations 3.8 2.6 2.7 Total interest expense $ 72.6 $ 69.7 $ 66.3 Income Taxes Gas Utility Services $ 25.4 $ 47.1 $ 40.8 Electric Utility Services 41.4 50.1 49.3 Other Operations (6.1 ) 2.3 (2.0 ) Total income taxes $ 60.7 $ 99.5 $ 88.1 Capital Expenditures Gas Utility Services $ 391.4 $ 358.5 $ 291.2 Electric Utility Services 105.3 106.4 87.6 Other Operations 60.1 39.0 25.7 Non-cash costs & changes in accruals (2.6 ) (7.3 ) (5.3 ) Total capital expenditures $ 554.2 $ 496.6 $ 399.2 At December 31, (In millions) 2017 2016 2015 Assets Gas Utility Services $ 3,457.8 $ 3,091.0 $ 2,706.9 Electric Utility Services 1,820.3 1,788.4 1,778.3 Other Operations, net of eliminations 219.7 161.5 107.5 Total assets $ 5,497.8 $ 5,040.9 $ 4,592.7 |
Additional Balance Sheet & Op32
Additional Balance Sheet & Operational Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Additional Balance Sheet and Operational Information [Abstract] | |
Summary of inventories | Inventories consist of the following: At December 31, (In millions) 2017 2016 Gas in storage – at LIFO cost $ 36.0 $ 37.0 Materials & supplies 37.0 38.1 Coal & oil for electric generation - at average cost 43.1 42.6 Other 1.4 1.3 Total inventories $ 117.5 $ 119.0 |
Summary of prepayments and other current assets | Prepayments & other current assets in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2017 2016 Prepaid gas delivery service $ 26.6 $ 26.4 Prepaid taxes 2.6 8.0 Other prepayments & current assets 3.5 4.2 Total prepayments & other current assets $ 32.7 $ 38.6 |
Other utility and corporate investments in the consolidated balance sheets | Other investments in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2017 2016 Cash surrender value of life insurance policies $ 25.4 $ 20.4 Restricted cash & other investments 1.3 0.9 Total other investments $ 26.7 $ 21.3 |
Summary of accrued liabilities | Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, (In millions) 2017 2016 Refunds to customers & customer deposits $ 51.4 $ 49.4 Accrued taxes 55.8 44.8 Accrued interest 17.9 16.4 Accrued salaries & other 28.9 29.5 Total accrued liabilities $ 154.0 $ 140.1 |
Asset retirement obligation | Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows: (In millions) 2017 2016 Asset retirement obligation, January 1 $ 106.6 $ 81.9 Accretion 4.3 3.8 Changes in estimates, net of cash payments (4.0 ) 20.9 Asset retirement obligation, December 31 $ 106.9 $ 106.6 |
Other, net in the consolidated statements of income | Other – net in the Consolidated Statements of Income consists of the following: Year Ended December 31, (In millions) 2017 2016 2015 AFUDC - borrowed funds $ 24.8 $ 20.3 $ 16.3 AFUDC - equity funds 2.6 2.2 2.6 Nonutility plant capitalized interest 1.2 1.0 0.4 Interest income — 0.3 0.6 Other income 2.0 2.5 (1.2 ) Total other – net $ 30.6 $ 26.3 $ 18.7 |
Supplemental cash flow information | Supplemental Cash Flow Information: Year Ended December 31, (In millions) 2017 2016 2015 Cash paid (received) for: Interest $ 71.2 $ 69.6 $ 66.2 Income taxes (6.1 ) 6.7 (23.1 ) |
Subsidiary Guarantor & Consol33
Subsidiary Guarantor & Consolidating Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Condensed Consolidating Statements of Income | Consolidating Statement of Income for the year ended December 31, 2017 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 812.7 $ — $ — $ 812.7 Electric utility 569.6 — — 569.6 Other — 45.6 (45.3 ) 0.3 Total operating revenues 1,382.3 45.6 (45.3 ) 1,382.6 OPERATING EXPENSES Cost of gas sold 271.5 — — 271.5 Cost of fuel & purchased power 171.8 — — 171.8 Other operating 378.6 35.7 (43.9 ) 370.4 Depreciation & amortization 208.4 26.0 0.1 234.5 Taxes other than income taxes 53.8 2.0 0.1 55.9 Total operating expenses 1,084.1 63.7 (43.7 ) 1,104.1 OPERATING INCOME 298.2 (18.1 ) (1.6 ) 278.5 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 190.7 (190.7 ) — Other – net 28.2 50.3 (47.9 ) 30.6 Total other income (expense) 28.2 241.0 (238.6 ) 30.6 Interest expense 68.8 53.3 (49.5 ) 72.6 INCOME BEFORE INCOME TAXES 257.6 169.6 (190.7 ) 236.5 Income taxes 66.9 (6.2 ) — 60.7 NET INCOME $ 190.7 $ 175.8 $ (190.7 ) $ 175.8 Consolidating Statement of Income for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 771.7 $ — $ — $ 771.7 Electric utility 605.8 — — 605.8 Other — 42.2 (41.9 ) 0.3 Total operating revenues 1,377.5 42.2 (41.9 ) 1,377.8 OPERATING EXPENSES Cost of gas sold 266.7 — — 266.7 Cost of fuel & purchased power 183.6 — — 183.6 Other operating 374.0 — (40.4 ) 333.6 Depreciation & amortization 195.2 23.8 0.1 219.1 Taxes other than income taxes 56.8 1.5 — 58.3 Total operating expenses 1,076.3 25.3 (40.3 ) 1,061.3 OPERATING INCOME 301.2 16.9 (1.6 ) 316.5 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 160.8 (160.8 ) — Other – net 24.0 48.3 (46.0 ) 26.3 Total other income (expense) 24.0 209.1 (206.8 ) 26.3 Interest expense 67.2 50.1 (47.6 ) 69.7 INCOME BEFORE INCOME TAXES 258.0 175.9 (160.8 ) 273.1 Income taxes 97.2 2.3 — 99.5 NET INCOME $ 160.8 $ 173.6 $ (160.8 ) $ 173.6 Consolidating Statement of Income for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Reclassifications and Eliminations Consolidated OPERATING REVENUES Gas utility $ 792.6 $ — $ — $ 792.6 Electric utility 601.6 — — 601.6 Other — 40.7 (40.4 ) 0.3 Total operating revenues 1,394.2 40.7 (40.4 ) 1,394.5 OPERATING EXPENSES Cost of gas sold 305.4 — — 305.4 Cost of fuel & purchased power 187.5 — — 187.5 Other operating 376.9 — (37.8 ) 339.1 Depreciation & amortization 184.2 24.3 0.3 208.8 Taxes other than income taxes 55.2 1.8 0.1 57.1 Total operating expenses 1,109.2 26.1 (37.4 ) 1,097.9 OPERATING INCOME 285.0 14.6 (3.0 ) 296.6 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies — 147.0 (147.0 ) — Other – net 15.7 42.7 (39.7 ) 18.7 Total other income (expense) 15.7 189.7 (186.7 ) 18.7 Interest expense 63.7 45.3 (42.7 ) 66.3 INCOME BEFORE INCOME TAXES 237.0 159.0 (147.0 ) 249.0 Income taxes 90.0 (1.9 ) — 88.1 NET INCOME $ 147.0 $ 160.9 $ (147.0 ) $ 160.9 |
Condensed Consolidating Balance Sheets | Consolidating Balance Sheet as of December 31, 2017 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 8.2 $ 1.6 $ — $ 9.8 Accounts receivable - less reserves 109.2 0.3 — 109.5 Intercompany receivables — 227.5 (227.5 ) — Accrued unbilled revenues 123.7 — — 123.7 Inventories 117.5 — — 117.5 Recoverable fuel & natural gas costs 19.2 — — 19.2 Prepayments & other current assets 28.9 12.6 (8.8 ) 32.7 Total current assets 406.7 242.0 (236.3 ) 412.4 Utility Plant Original cost 7,015.4 — — 7,015.4 Less: accumulated depreciation & amortization 2,738.7 — — 2,738.7 Net utility plant 4,276.7 — — 4,276.7 Investments in consolidated subsidiaries — 1,741.0 (1,741.0 ) — Notes receivable from consolidated subsidiaries — 970.7 (970.7 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 26.3 0.4 — 26.7 Nonutility plant - net 1.6 197.0 — 198.6 Goodwill - net 205.0 — — 205.0 Regulatory assets 298.7 15.3 — 314.0 Other assets 62.5 1.8 (0.1 ) 64.2 TOTAL ASSETS $ 5,277.7 $ 3,168.2 $ (2,948.1 ) $ 5,497.8 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 179.4 $ 42.4 $ — $ 221.8 Intercompany payables 8.3 — (8.3 ) — Payables to other Vectren companies 25.2 8.1 — 33.3 Accrued liabilities 147.7 15.1 (8.8 ) 154.0 Short-term borrowings — 179.5 — 179.5 Intercompany short-term borrowings 120.2 — (120.2 ) — Current maturities of long-term debt — 100.0 — 100.0 Current maturities of long-term debt due to VUHI 99.0 — (99.0 ) — Total current liabilities 579.8 345.1 (236.3 ) 688.6 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 384.5 1,095.0 — 1,479.5 Long-term debt due to VUHI 970.7 — (970.7 ) — Total long-term debt - net 1,355.2 1,095.0 (970.7 ) 1,479.5 Deferred Income Taxes & Other Liabilities Deferred income taxes 455.3 2.2 — 457.5 Regulatory liabilities 936.1 1.1 — 937.2 Deferred credits & other liabilities 210.3 2.0 (0.1 ) 212.2 Total deferred credits & other liabilities 1,601.7 5.3 (0.1 ) 1,606.9 Common Shareholder's Equity Common stock (no par value) 890.7 877.5 (890.7 ) 877.5 Retained earnings 850.3 845.3 (850.3 ) 845.3 Total common shareholder's equity 1,741.0 1,722.8 (1,741.0 ) 1,722.8 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 5,277.7 $ 3,168.2 $ (2,948.1 ) $ 5,497.8 Consolidating Balance Sheet as of December 31, 2016 (in millions): ASSETS Subsidiary Parent Guarantors Company Eliminations Consolidated Current Assets Cash & cash equivalents $ 7.6 $ 1.8 $ — $ 9.4 Accounts receivable - less reserves 102.4 0.2 — 102.6 Intercompany receivables 17.5 157.1 (174.6 ) — Accrued unbilled revenues 112.0 — — 112.0 Inventories 119.0 — — 119.0 Recoverable fuel & natural gas costs 29.9 — — 29.9 Prepayments & other current assets 36.5 4.4 (2.3 ) 38.6 Total current assets 424.9 163.5 (176.9 ) 411.5 Utility Plant Original cost 6,545.4 — — 6,545.4 Less: accumulated depreciation & amortization 2,562.5 — — 2,562.5 Net utility plant 3,982.9 — — 3,982.9 Investments in consolidated subsidiaries — 1,577.2 (1,577.2 ) — Notes receivable from consolidated subsidiaries — 945.4 (945.4 ) — Investments in unconsolidated affiliates 0.2 — — 0.2 Other investments 20.9 0.4 — 21.3 Nonutility plant - net 1.7 163.1 — 164.8 Goodwill - net 205.0 — — 205.0 Regulatory assets 190.0 16.2 — 206.2 Other assets 53.9 3.7 (8.6 ) 49.0 TOTAL ASSETS $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent Guarantors Company Eliminations Consolidated Current Liabilities Accounts payable $ 194.6 $ 10.8 $ — $ 205.4 Intercompany payables 14.8 — (14.8 ) — Payables to other Vectren companies 25.4 — — 25.4 Accrued liabilities 126.0 16.4 (2.3 ) 140.1 Short-term borrowings — 194.4 — 194.4 Intercompany short-term borrowings 142.3 17.5 (159.8 ) — Current maturities of long-term debt 49.1 — — 49.1 Total current liabilities 552.2 239.1 (176.9 ) 614.4 Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 335.2 995.8 — 1,331.0 Long-term debt due to VUHI 945.4 — (945.4 ) — Total long-term debt - net 1,280.6 995.8 (945.4 ) 1,331.0 Deferred Income Taxes & Other Liabilities Deferred income taxes 855.4 (0.9 ) — 854.5 Regulatory liabilities 452.4 1.3 — 453.7 Deferred credits & other liabilities 161.7 10.2 (8.6 ) 163.3 Total deferred credits & other liabilities 1,469.5 10.6 (8.6 ) 1,471.5 Common Shareholder's Equity Common stock (no par value) 844.4 831.2 (844.4 ) 831.2 Retained earnings 732.8 792.8 (732.8 ) 792.8 Total common shareholder's equity 1,577.2 1,624.0 (1,577.2 ) 1,624.0 TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 4,879.5 $ 2,869.5 $ (2,708.1 ) $ 5,040.9 |
Condensed Consolidating Statements of Cash Flows | Consolidating Statement of Cash Flows for the year ended December 31, 2017 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH FROM OPERATING ACTIVITIES $ 398.5 $ 48.3 $ — $ 446.8 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 123.9 198.9 (124.3 ) 198.5 Additional capital contribution from parent 46.3 46.3 (46.3 ) 46.3 Requirements for: Dividends to parent (73.1 ) (123.3 ) 73.1 (123.3 ) Net change in intercompany short-term borrowings (22.1 ) (17.5 ) 39.6 — Net change in short-term borrowings — (14.9 ) — (14.9 ) Net cash from financing activities 75.0 89.5 (57.9 ) 106.6 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 73.1 (73.1 ) — Other investing activities 2.7 — — 2.7 Requirements for: Capital expenditures, excluding AFUDC equity (491.6 ) (62.6 ) — (554.2 ) Consolidated subsidiary investments — (46.3 ) 46.3 — Other costs (2.4 ) — — (2.4 ) Changes in restricted cash 0.9 — — 0.9 Net change in long-term intercompany notes receivable — (124.3 ) 124.3 — Net change in short-term intercompany notes receivable 17.5 22.1 (39.6 ) — Net cash from investing activities (472.9 ) (138.0 ) 57.9 (553.0 ) Net change in cash & cash equivalents 0.6 (0.2 ) — 0.4 Cash & cash equivalents at beginning of period 7.6 1.8 — 9.4 Cash & cash equivalents at end of period $ 8.2 $ 1.6 $ — $ 9.8 Consolidating Statement of Cash Flows for the year ended December 31, 2016 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH FROM OPERATING ACTIVITIES $ 352.2 $ 45.2 $ — $ 397.4 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 109.4 — (109.4 ) — Additional capital contribution from parent 31.3 31.3 (31.3 ) 31.3 Requirements for: Dividends to parent (82.0 ) (116.1 ) 82.0 (116.1 ) Retirement of long-term debt (13.0 ) — — (13.0 ) Net change in intercompany short-term borrowings 11.9 (33.7 ) 21.8 — Net change in short-term borrowings — 179.9 — 179.9 Net cash from financing activities 57.6 61.4 (36.9 ) 82.1 CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 82.0 (82.0 ) — Other investing activities 15.3 — — 15.3 Requirements for: Capital expenditures, excluding AFUDC equity (461.7 ) (34.9 ) — (496.6 ) Consolidated subsidiary investments — (31.3 ) 31.3 — Changes in restricted cash 5.0 — — 5.0 Net change in long-term intercompany notes receivable — (109.4 ) 109.4 — Net change in short-term intercompany notes receivable 33.7 (11.9 ) (21.8 ) — Net cash from investing activities (407.7 ) (105.5 ) 36.9 (476.3 ) Net change in cash & cash equivalents 2.1 1.1 — 3.2 Cash & cash equivalents at beginning of period 5.5 0.7 — 6.2 Cash & cash equivalents at end of period $ 7.6 $ 1.8 $ — $ 9.4 Consolidating Statement of Cash Flows for the year ended December 31, 2015 (in millions): Subsidiary Guarantors Parent Company Eliminations Consolidated NET CASH FROM OPERATING ACTIVITIES $ 460.3 $ 32.6 $ — $ 492.9 CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt, net of issuance costs 126.8 199.0 (89.5 ) 236.3 Additional capital contribution from parent 6.2 6.2 (6.2 ) 6.2 Requirements for: Dividends to parent (103.2 ) (110.4 ) 103.2 (110.4 ) Retirement of long-term debt (20.0 ) (75.0 ) — (95.0 ) Net change in intercompany short-term borrowings (40.7 ) 51.2 (10.5 ) — Net change in short-term borrowings — (141.9 ) — (141.9 ) Net cash from financing activities (30.9 ) (70.9 ) (3.0 ) (104.8 ) CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions — 103.2 (103.2 ) — Other investing activities — 3.9 — 3.9 Requirements for: Capital expenditures, excluding AFUDC equity (373.7 ) (25.5 ) — (399.2 ) Consolidated subsidiary investments — (6.2 ) 6.2 — Changes in restricted cash (5.9 ) — — (5.9 ) Net change in long-term intercompany notes receivable — (89.5 ) 89.5 — Net change in short-term intercompany notes receivable (51.2 ) 40.7 10.5 — Net cash from investing activities (430.8 ) 26.6 3.0 (401.2 ) Net change in cash & cash equivalents (1.4 ) (11.7 ) — (13.1 ) Cash & cash equivalents at beginning of period 6.9 12.4 — 19.3 Cash & cash equivalents at end of period $ 5.5 $ 0.7 $ — $ 6.2 |
Quarterly Financial Data (Una34
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized quarterly financial data | Summarized quarterly financial data for 2017 and 2016 follows: (In millions) Q1 Q2 Q3 Q4 2017 Results of Operations: Operating revenues $ 425.0 $ 285.9 $ 279.7 $ 392.1 Operating income 113.5 49.7 58.0 57.5 Net income 65.9 25.5 30.8 53.6 2016 Results of Operations: Operating revenues $ 423.4 $ 279.8 $ 291.3 $ 383.5 Operating income 106.8 52.2 64.0 93.5 Net income 61.1 26.3 34.9 51.3 |
Organization and Nature of Op35
Organization and Nature of Operations (Details) | 12 Months Ended |
Dec. 31, 2017customerpublic_utility | |
Public Utilities, General Disclosures [Line Items] | |
Operating utility companies | public_utility | 3 |
Natural Gas Customers | Indiana Gas | Indiana | |
Public Utilities, General Disclosures [Line Items] | |
Approximate number of customers | 592,400 |
Natural Gas Customers | SIGECO | Indiana | |
Public Utilities, General Disclosures [Line Items] | |
Approximate number of customers | 111,500 |
Natural Gas Customers | Vectren Energy Delivery of Ohio | Ohio | |
Public Utilities, General Disclosures [Line Items] | |
Approximate number of customers | 318,100 |
Electric Customers | SIGECO | Indiana | |
Public Utilities, General Disclosures [Line Items] | |
Approximate number of customers | 145,200 |
Summary of Significant Accoun36
Summary of Significant Accounting Policies (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Goodwill impairments | $ 0 | $ 0 | $ 0 |
Excise taxes and a portion of utility receipts taxes | $ 29,100,000 | $ 28,300,000 | $ 29,400,000 |
Utility & Nonutility Plant - Ut
Utility & Nonutility Plant - Utility Plant (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | |
Utility & Nonutility Plant | ||
Original cost | $ 7,015.4 | $ 6,545.4 |
Utility Group | ||
Utility & Nonutility Plant | ||
Original cost | 7,015.4 | 6,545.4 |
Utility Group | Gas utility plant | ||
Utility & Nonutility Plant | ||
Original cost | $ 3,969.6 | $ 3,587.5 |
Depreciation Rates as a Percent of Original Cost | 3.40% | 3.40% |
Utility Group | Electric utility plant | ||
Utility & Nonutility Plant | ||
Original cost | $ 2,833.5 | $ 2,752 |
Depreciation Rates as a Percent of Original Cost | 3.30% | 3.30% |
Utility Group | Common utility plant | ||
Utility & Nonutility Plant | ||
Original cost | $ 59 | $ 56.3 |
Depreciation Rates as a Percent of Original Cost | 3.20% | 3.20% |
Utility Group | Construction work in progress | ||
Utility & Nonutility Plant | ||
Original cost | $ 70.7 | $ 63 |
Depreciation Rates as a Percent of Original Cost | 0.00% | 0.00% |
Utility Group | Asset retirement obligations | ||
Utility & Nonutility Plant | ||
Original cost | $ 82.6 | $ 86.6 |
Depreciation Rates as a Percent of Original Cost | 0.00% | 0.00% |
Utility Group | SIGECO | ||
Utility & Nonutility Plant | ||
SIGECO's share of cost of Warrick unit 4 | $ 191 | |
SIGECO's share of accumulated depreciation of Warrick unit 4 | $ 119.7 | |
Utility Group | Warrick Power Plant | ||
Utility & Nonutility Plant | ||
Size of Unit 4 Warrick Power Plant (in megawatts) | MW | 300 |
Utility & Nonutility Plant - No
Utility & Nonutility Plant - Non Utility Plant (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | |||
Nonutility plant - net | $ 198.6 | $ 164.8 | |
Nonutility Group | |||
Property, Plant and Equipment [Line Items] | |||
Nonutility plant - net | 198.6 | 164.8 | |
Accumulated depreciation and amortization | 285.6 | 264.7 | |
Capitalized interest | 1.2 | 1 | $ 0.4 |
Nonutility Group | Computer hardware & software | |||
Property, Plant and Equipment [Line Items] | |||
Nonutility plant - net | 155.6 | 120.5 | |
Nonutility Group | Land & buildings | |||
Property, Plant and Equipment [Line Items] | |||
Nonutility plant - net | 37.1 | 37.6 | |
Nonutility Group | All other | |||
Property, Plant and Equipment [Line Items] | |||
Nonutility plant - net | $ 5.9 | $ 6.7 |
Regulatory Assets & Liabiliti39
Regulatory Assets & Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 314 | $ 206.2 |
Regulatory liabilities | (937.2) | (453.7) |
Regulatory assets currently being recovered in base rates | $ 23 | |
Weighted average recovery period of regulatory assets currently being recovered (in years) | 20 years | |
Deferred tax regulatory liability due to revaluation of deferred taxes at reduced federal tax rate | $ 446 | |
Removal Costs | ||
Regulatory Assets [Line Items] | ||
Regulatory liabilities | (477) | (452) |
Deferred taxes | ||
Regulatory Assets [Line Items] | ||
Regulatory liabilities | (459) | |
Future amounts recoverable from ratepayers related to: | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 30.5 | |
Regulatory liabilities | (17.1) | |
Future amounts recoverable from ratepayers related to: | Deferred taxes | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 6.2 | |
Regulatory liabilities | (17.1) | |
Future amounts recoverable from ratepayers related to: | Asset retirement obligations & other | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 24.3 | 0 |
Amounts deferred for future recovery related to: | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 142.4 | 91.6 |
Amounts deferred for future recovery related to: | Cost recovery riders & other | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 142.4 | 91.6 |
Amounts currently recovered in customer rates related to: | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 141.1 | 131.7 |
Amounts currently recovered in customer rates related to: | Indiana authorized trackers | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 75.9 | 64.2 |
Amounts currently recovered in customer rates related to: | Ohio authorized trackers | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 28.4 | 22.2 |
Amounts currently recovered in customer rates related to: | Loss on reacquired debt & hedging costs | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | 22.7 | 24.1 |
Amounts currently recovered in customer rates related to: | Deferred coal costs | ||
Regulatory Assets [Line Items] | ||
Regulatory assets | $ 14.1 | $ 21.2 |
Transactions with Other Vectr40
Transactions with Other Vectren Companies and Affiliates - Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)pension_plan | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Transactions with Other Vectren Companies and Affiliates [Line Items] | |||
Company contributions | $ 0 | $ 15,000,000 | $ 19,600,000 |
Deferred credits & other liabilities | 212,200,000 | 163,300,000 | |
Accrued liabilities and deferred credits and other liabilities | 55,700,000 | 42,300,000 | |
Tax benefit | 23,200,000 | ||
Excess federal income taxes | 333,400,000 | ||
Investment tax credits | 1,200,000 | 1,600,000 | |
Alternative minimum tax carryforward | 12,200,000 | 29,300,000 | |
Net liability for unrecognized tax benefits | $ 1,300,000 | 1,100,000 | |
Defined Benefit Pension Plans | |||
Transactions with Other Vectren Companies and Affiliates [Line Items] | |||
Number of closed qualified defined benefit pension plans | pension_plan | 3 | ||
Company contributions | $ 0 | $ 15,000,000 | |
Funded status as a percent | 92.00% | 92.00% | |
Net periodic benefit cost | $ 8,200,000 | $ 6,100,000 | 7,000,000 |
Other assets | 61,300,000 | 40,900,000 | |
Other Postretirement Benefits Plan | |||
Transactions with Other Vectren Companies and Affiliates [Line Items] | |||
Deferred credits & other liabilities | 47,000,000 | 12,200,000 | |
VISCO | |||
Transactions with Other Vectren Companies and Affiliates [Line Items] | |||
Expenses from transactions with other Vectren companies and affiliates | 157,100,000 | 117,800,000 | 109,500,000 |
Support Services & Purchases | |||
Transactions with Other Vectren Companies and Affiliates [Line Items] | |||
Corporate allocations | $ 64,100,000 | $ 57,600,000 | $ 52,300,000 |
Transactions with Other Vectr41
Transactions with Other Vectren Companies and Affiliates - Components of Income Tax Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current: | |||
Federal | $ 10 | $ (1.4) | $ (1.9) |
State | 4.8 | 4.2 | 4.2 |
Total current taxes | 14.8 | 2.8 | 2.3 |
Deferred: | |||
Federal | 43.9 | 93.5 | 81.7 |
State | 2.4 | 3.7 | 4.6 |
Total deferred taxes | 46.3 | 97.2 | 86.3 |
Amortization of investment tax credits | (0.4) | (0.5) | (0.5) |
Total income tax expense | $ 60.7 | $ 99.5 | $ 88.1 |
Transactions with Other Vectr42
Transactions with Other Vectren Companies and Affiliates - Reconciliation of Federal Statutory Rate to Effective Income Tax Rate (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Transactions with Other Vectren Companies and Affiliates [Abstract] | |||
Statutory rate | 35.00% | 35.00% | 35.00% |
State and local taxes-net of federal benefit | 2.80% | 2.60% | 2.80% |
Deferred tax revaluation-tax law change | (9.80%) | 0.00% | 0.00% |
Amortization of investment tax credit | (0.20%) | (0.20%) | (0.20%) |
Domestic production deduction | (1.10%) | (0.50%) | (0.90%) |
Research and development credit | (0.30%) | (0.80%) | (2.00%) |
All other - net | (0.70%) | 0.30% | 0.70% |
Effective tax rate | 25.70% | 36.40% | 35.40% |
Transactions with Other Vectr43
Transactions with Other Vectren Companies and Affiliates - Deferred Tax Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Transactions with Other Vectren Companies and Affiliates [Abstract] | ||
Depreciation & cost recovery timing differences | $ 537.2 | $ 821.6 |
Regulatory assets recoverable through future rates | 7.9 | 17.6 |
Alternative minimum tax carryforward | (12.2) | (29.3) |
Employee benefit obligations, deferred tax asset | (0.3) | |
Employee benefit obligations, deferred tax liability | 10.2 | |
U.S. federal charitable contributions carryforwards | (6.2) | 0 |
Regulatory liabilities to be settled through future rates | (116.2) | (15.9) |
Deferred fuel costs | 16.2 | 25.9 |
Other – net | 31.1 | 24.4 |
Net noncurrent deferred tax liability | $ 457.5 | $ 854.5 |
Borrowing Arrangements - Short-
Borrowing Arrangements - Short-Term Borrowings (Details) - USD ($) | Jul. 14, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Short-term borrowings [Abstract] | ||||
Short-term borrowing capacity | $ 400,000,000 | |||
Short term borrowings available | 220,000,000 | |||
Year End | ||||
Balance Outstanding | $ 179,500,000 | $ 194,400,000 | $ 14,500,000 | |
Weighted Average Interest Rate | 1.92% | 1.05% | 0.55% | |
Annual Average | ||||
Balance Outstanding | $ 172,400,000 | $ 59,800,000 | $ 53,800,000 | |
Balance Outstanding | 1.30% | 0.71% | 0.38% | |
Maximum Month End Balance Outstanding | $ 238,700,000 | $ 194,400,000 | $ 121,500,000 | |
Line of Credit | ||||
Short-term borrowings [Abstract] | ||||
Credit agreement increase amount | $ 50,000,000 | |||
Line of Credit | Revolving Credit Facility | ||||
Short-term borrowings [Abstract] | ||||
Short-term borrowing capacity | 400,000,000 | |||
Line of Credit | Bridge Loan | ||||
Short-term borrowings [Abstract] | ||||
Short-term borrowing capacity | 10,000,000 | |||
Line of Credit | Letter of Credit | ||||
Short-term borrowings [Abstract] | ||||
Short-term borrowing capacity | $ 20,000,000 |
Borrowing Arrangements - Long-t
Borrowing Arrangements - Long-term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 1,588.7 | $ 1,388.7 |
Current maturities of long-term debt | (100) | (49.1) |
Debt issuance costs | (8.6) | (7.9) |
Unamortized debt premium & discount - net | (0.6) | (0.7) |
Total long-term debt-net | 1,479.5 | 1,331 |
Utility Holdings | Fixed Rate Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | 1,200 | 1,000 |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2018, 5.75% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 100 | 100 |
Fixed rate stated percentage (in hundredths) | 5.75% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2020, 6.28% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 100 | 100 |
Fixed rate stated percentage (in hundredths) | 6.28% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2021, 4.67% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 55 | 55 |
Fixed rate stated percentage (in hundredths) | 4.67% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2023, 3.72% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 150 | 150 |
Fixed rate stated percentage (in hundredths) | 3.72% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2026, 5.02% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 60 | 60 |
Fixed rate stated percentage (in hundredths) | 5.02% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2028, 3.20% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 45 | 45 |
Fixed rate stated percentage (in hundredths) | 3.20% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2032, 3.26% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 100 | 0 |
Fixed rate stated percentage (in hundredths) | 3.26% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2035, 6.10% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 75 | 75 |
Fixed rate stated percentage (in hundredths) | 6.10% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2035, 3.90% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 25 | 25 |
Fixed rate stated percentage (in hundredths) | 3.90% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2041, 5.99% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 35 | 35 |
Fixed rate stated percentage (in hundredths) | 5.99% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2042, 5.00% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 100 | 100 |
Fixed rate stated percentage (in hundredths) | 5.00% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2043, 4.25% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 80 | 80 |
Fixed rate stated percentage (in hundredths) | 4.25% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2045, 4.36% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 135 | 135 |
Fixed rate stated percentage (in hundredths) | 4.36% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2047, 3.93% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 100 | 0 |
Fixed rate stated percentage (in hundredths) | 3.93% | |
Utility Holdings | Fixed Rate Senior Unsecured Notes | 2055, 4.51% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 40 | 40 |
Fixed rate stated percentage (in hundredths) | 4.51% | |
SIGECO | First Mortgage Bonds | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 292.7 | 292.7 |
SIGECO | First Mortgage Bonds | 2022, 2013 Series C, current adjustable rate 1.565%, tax exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 4.6 | 4.6 |
Fixed rate stated percentage (in hundredths) | 1.565% | |
SIGECO | First Mortgage Bonds | 2024, 2013 Series D, current adjustable rate 1.565%, tax exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 22.5 | 22.5 |
Fixed rate stated percentage (in hundredths) | 1.565% | |
SIGECO | First Mortgage Bonds | 2025, 2014 Series B, current adjustable rate 1.565%, tax-exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 41.3 | 41.3 |
Fixed rate stated percentage (in hundredths) | 1.565% | |
SIGECO | First Mortgage Bonds | 2029, 1999 Series, 6.72% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 80 | 80 |
Fixed rate stated percentage (in hundredths) | 6.72% | |
SIGECO | First Mortgage Bonds | 2037, 2013 Series E, current adjustable rate 1.565%, tax exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 22 | 22 |
Fixed rate stated percentage (in hundredths) | 1.565% | |
SIGECO | First Mortgage Bonds | 2038, 2013 Series A, 4.00%, tax exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 22.2 | 22.2 |
Fixed rate stated percentage (in hundredths) | 4.00% | |
SIGECO | First Mortgage Bonds | 2043, 2013 Series B, 4.05%, tax exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 39.6 | 39.6 |
Fixed rate stated percentage (in hundredths) | 4.05% | |
SIGECO | First Mortgage Bonds | 2044, 2014 Series A, 4.00%, tax exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 22.3 | 22.3 |
Fixed rate stated percentage (in hundredths) | 4.00% | |
SIGECO | First Mortgage Bonds | 2055, 2015 Series Mt. Vernon, 2.375%, tax-exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 23 | 23 |
Fixed rate stated percentage (in hundredths) | 2.375% | |
SIGECO | First Mortgage Bonds | 2055, 2015 Series Warrick County, 2.375%, tax-exempt | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 15.2 | 15.2 |
Fixed rate stated percentage (in hundredths) | 2.375% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 96 | 96 |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2025, Series E, 6.53% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 10 | 10 |
Fixed rate stated percentage (in hundredths) | 6.53% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2027, Series E, 6.42% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 5 | 5 |
Fixed rate stated percentage (in hundredths) | 6.42% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2027, Series E, 6.68% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 1 | 1 |
Fixed rate stated percentage (in hundredths) | 6.68% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2027, Series F, 6.34% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 20 | 20 |
Fixed rate stated percentage (in hundredths) | 6.34% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2028, Series F, 6.36% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 10 | 10 |
Fixed rate stated percentage (in hundredths) | 6.36% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2028, Series F, 6.55% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 20 | 20 |
Fixed rate stated percentage (in hundredths) | 6.55% | |
Indiana Gas | Fixed Rate Senior Unsecured Notes | 2029, Series G, 7.08% | ||
Debt Instrument [Line Items] | ||
Total long-term debt outstanding | $ 30 | $ 30 |
Fixed rate stated percentage (in hundredths) | 7.08% |
Borrowing Arrangements - Narrat
Borrowing Arrangements - Narrative (Details) | Jun. 01, 2016USD ($) | Dec. 31, 2017USD ($) | Sep. 22, 2017USD ($) | Sep. 14, 2017USD ($)issuance | Jul. 14, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | $ 1,588,700,000 | $ 1,388,700,000 | |||||
Debt maturing within 12 months following date of latest balance sheet | 100,000,000 | ||||||
Debt maturing within three years following date of latest balance sheet | 100,000,000 | ||||||
Debt maturing within four years following date of latest balance sheet | 55,000,000 | ||||||
Debt maturing within five years following date of latest balance sheet | 4,600,000 | ||||||
Debt maturing thereafter 5 years following date of the latest balance sheet | 1,319,900,000 | ||||||
Debt maturing within two years following date of latest balance sheet | 0 | ||||||
Long-term debt | 1,200,000,000 | ||||||
Short-term borrowings | $ 179,500,000 | 194,400,000 | $ 14,500,000 | ||||
Debt to consolidated total capitalization - maximum ratio | 65.00% | ||||||
Senior Notes | Guaranteed Senior Notes, Series A | |||||||
Debt Instrument [Line Items] | |||||||
Principal amount of notes | $ 100,000,000 | ||||||
Fixed rate stated percentage (in hundredths) | 3.26% | ||||||
Senior Notes | Guaranteed Senior Notes, Series B | |||||||
Debt Instrument [Line Items] | |||||||
Principal amount of notes | $ 100,000,000 | ||||||
Fixed rate stated percentage (in hundredths) | 3.93% | ||||||
SIGECO | Variable Rate Tax-Exempt Bonds | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | $ 41,300,000 | $ 152,000,000 | |||||
Number of debt issuances | issuance | 3 | ||||||
SIGECO | Variable Rate Tax-Exempt Bonds | 2013 Series C Notes due 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | $ 4,600,000 | ||||||
SIGECO | Variable Rate Tax-Exempt Bonds | 2013 Series D Notes due 2024 | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | 22,500,000 | ||||||
SIGECO | Variable Rate Tax-Exempt Bonds | 2013 Series E Notes due 2037 | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | $ 22,000,000 | ||||||
SIGECO | Fixed Rate Tax-Exempt Bonds | 2013 Series A Notes due 2038 | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | 22,200,000 | ||||||
SIGECO | Fixed Rate Tax-Exempt Bonds | 2013 Series B Notes due 2043 | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | $ 39,600,000 | ||||||
SIGECO | First Mortgage Bonds | |||||||
Debt Instrument [Line Items] | |||||||
Total long-term debt outstanding | $ 292,700,000 | $ 292,700,000 | |||||
Annual sinking fund requirement fixed percentage (in hundredths) | 1.00% | ||||||
Utility plant remaining unfunded under mortgage indenture | $ 1,500,000,000 | ||||||
Gross utility plant balance subject to the mortgage indenture | 3,400,000,000 | ||||||
SIGECO | First Mortgage Bonds | First Mortgage Bonds 2016 1986 Series 8.875% | |||||||
Debt Instrument [Line Items] | |||||||
Fixed rate stated percentage (in hundredths) | 8.875% | ||||||
Extinguishment of debt | $ 13,000,000 | ||||||
Debt Issuance Amount | $ 25,000,000 | ||||||
SIGECO | First Mortgage Bonds | Bonds subject to mandatory tender in September 2017 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | 124,000,000 | ||||||
SIGECO | First Mortgage Bonds | Bond Subject To Mandatory Tender In 2020 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | 38,200,000 | ||||||
SIGECO | First Mortgage Bonds | Bond Subject To Mandatory Tender In 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | 85,800,000 | ||||||
SIGECO | First Mortgage Bonds | Options Callable in 2017 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | 84,100,000 | ||||||
SIGECO | First Mortgage Bonds | Options Callable in 2018 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | 39,600,000 | ||||||
SIGECO | First Mortgage Bonds | Options Callable March 1 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | 22,200,000 | ||||||
SIGECO | First Mortgage Bonds | Options Callable in 2019 | |||||||
Debt Instrument [Line Items] | |||||||
Settlement terms, maximum amount | $ 22,300,000 |
Common Shareholder's Equity (De
Common Shareholder's Equity (Details) - USD ($) $ in Millions | 12 Months Ended | 24 Months Ended | 36 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Additional capital contribution | $ 46.3 | $ 31.3 | $ 6.2 | ||
Common Shareholders Equity | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Additional capital contribution | $ 65 | $ 83.8 | |||
Proceeds from new share issues | $ 18.8 |
Commitments & Contingencies (De
Commitments & Contingencies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Future minimum operating lease payments due within one year of the balance sheet date | $ 1.1 | ||
Future minimum operating lease payments due within the second year of the balance sheet date | 0.9 | ||
Future minimum operating lease payments due within the third year of the balance sheet date | 0.6 | ||
Future minimum operating lease payments due within the fourth year of the balance sheet date | 0.6 | ||
Future minimum operating lease payments due within the fifth year of the balance sheet date | 0.5 | ||
Future minimum operating lease payments due after the fifth year of the balance sheet date | 1.4 | ||
Lease expense | 1.3 | $ 1.1 | $ 0.8 |
Letters of credit outstanding | $ 8.4 |
Gas Rate and Regulatory Matte49
Gas Rate and Regulatory Matters (Details) - USD ($) | Feb. 21, 2018 | Aug. 03, 2017 | Aug. 31, 2014 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jan. 24, 2018 | Mar. 31, 2016 |
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Regulatory assets | $ 314,000,000 | $ 206,200,000 | ||||||
Other – net | 30,600,000 | 26,300,000 | $ 18,700,000 | |||||
Indiana Recovery and Deferral Mechanisms | Indiana | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Regulatory assets | $ 22,700,000 | 21,900,000 | ||||||
Length of project plan required for recovery under new legislation | 7 years | 7 years | ||||||
Indiana Recovery and Deferral Mechanisms | Indiana | Indiana Gas | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Allowable capital expenditures under Vectren South program | $ 20,000,000 | |||||||
Limitations of deferrals of debt-related post in service carrying costs | 4 years | |||||||
Indiana Recovery and Deferral Mechanisms | Indiana | SIGECO | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Allowable capital expenditures under Vectren South program | $ 3,000,000 | |||||||
Limitations of deferrals of debt-related post in service carrying costs | 3 years | |||||||
Senate Bill 251 and 560 | Indiana | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Regulatory assets | $ 78,000,000 | 51,100,000 | ||||||
Investment in infrastructure modernization project | $ 890,000,000 | |||||||
Projects not approved for recovery | 80,000,000 | |||||||
Capital expenditure increase | $ 65,000,000 | |||||||
Senate Bill 251 and 560 | Indiana | Subsequent Event | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Capital expenditure increase | $ 105,000,000 | |||||||
Project spend life to date | 482,000,000 | |||||||
Capital expenditures | $ 995,000,000 | |||||||
Senate Bill 251 | Indiana | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Operating expenses requested for recovery | $ 15,000,000 | |||||||
Capital investments requested for recovery | $ 17,000,000 | |||||||
Recovery period | 4 years | |||||||
Ohio Recovery and Deferral Mechanisms | Ohio | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Capital investments on projects | 321,100,000 | 261,100,000 | ||||||
Regulatory asset associated with DRR deferrals of depreciation and post in-service carrying costs | 31,200,000 | 24,400,000 | ||||||
Ohio House Bill 95 | Ohio | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Impact on customer bill per month | 1.50 | |||||||
Other – net | $ 66,100,000 | $ 41,900,000 | ||||||
Ohio House Bill 95 | Ohio | Subsequent Event | ||||||||
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement [Line Items] | ||||||||
Period to recover costs of capital improvements | 10 years |
Electric Rate and Regulatory 50
Electric Rate and Regulatory Matters (Details) $ in Millions | Feb. 20, 2018USD ($)MW | Jun. 13, 2017 | May 18, 2017USD ($) | Mar. 07, 2017 | Feb. 23, 2017USD ($) | Mar. 23, 2016 | Apr. 30, 2017USD ($) | Oct. 31, 2017USD ($) | Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($)meeting | Dec. 31, 2015USD ($) | Aug. 30, 2017USD ($)projectMW | Sep. 28, 2016 | Jun. 30, 2016 | Jan. 06, 2015 | Nov. 12, 2013 |
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Number of solar projects with authority to recover costs | project | 3 | |||||||||||||||
Added universal solar generation | MW | 4 | |||||||||||||||
Added rooftop solar generation | MW | 4 | |||||||||||||||
Added battery storage resources | MW | 1 | |||||||||||||||
SIGECO Electric Environmental Compliance Filing | ||||||||||||||||
Estimated cost of equipment to comply with MATS | $ 12.8 | |||||||||||||||
Estimated cost of equipment required by the NOV | 4.7 | |||||||||||||||
SIGECO Electric Demand Side Management (DSM) Program Filing | ||||||||||||||||
Estimated average measure of life of lost margin recover plan | 9 years | |||||||||||||||
Electric utility | 569.6 | $ 605.8 | $ 601.6 | |||||||||||||
FERC Return On Equity (ROE) Complaint | ||||||||||||||||
Current return on equity used in MISO transmission owners rates | 12.38% | |||||||||||||||
Reduced return on equity percentage sought by third party through joint complaint | 9.15% | |||||||||||||||
FERC authorized base ROE percentage for first refund period | 10.32% | 0.50% | ||||||||||||||
FERC authorized base ROE percentage for second refund period | 9.70% | |||||||||||||||
Investment in qualifying projects | 157.7 | |||||||||||||||
Net investment in qualifying projects | 133.5 | |||||||||||||||
Electric Modernization Program - SB 560 | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Capital expenditures | $ 500 | |||||||||||||||
Length of project plan required for recovery under new legislation | 7 years | |||||||||||||||
Project spend life to date | $ 446 | |||||||||||||||
Investment In Plan | $ 7.1 | |||||||||||||||
Requested recover in rates of investments | $ 31 | |||||||||||||||
Regulatory assets | 4.3 | |||||||||||||||
Renewable Generation - SB 29 | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Capital expenditures under project plan | $ 16 | |||||||||||||||
SIGECO Electric Environmental Compliance Filing | ||||||||||||||||
SIGECO Electric Environmental Compliance Filing | ||||||||||||||||
Amount of capital investments to date in equipment for mercury control | 30 | |||||||||||||||
Amount of capital investments to date in equipment to control sulfur trioxide emissions | 40 | |||||||||||||||
Electric Demand Side Management Filing | ||||||||||||||||
SIGECO Electric Demand Side Management (DSM) Program Filing | ||||||||||||||||
Maximum period for recovery under energy efficiency program | 4 years | 4 years | ||||||||||||||
Electric utility | $ 11.6 | $ 11.1 | $ 10.1 | |||||||||||||
Electric Generation and Compliance | ||||||||||||||||
FERC Return On Equity (ROE) Complaint | ||||||||||||||||
Number of public stakeholder meetings | meeting | 3 | |||||||||||||||
Subsequent Event | Electric Generation and Compliance | ||||||||||||||||
FERC Return On Equity (ROE) Complaint | ||||||||||||||||
Gas combined cycle generating facility, cost | $ 900 | |||||||||||||||
Requested recovery of environmental investments | $ 90 | |||||||||||||||
Universal solar energy | MW | 50 | |||||||||||||||
Subsequent Event | Electric Generation and Compliance | Minimum | ||||||||||||||||
FERC Return On Equity (ROE) Complaint | ||||||||||||||||
Power of gas combined cycle generating facility | MW | 800 | |||||||||||||||
Subsequent Event | Electric Generation and Compliance | Maximum | ||||||||||||||||
FERC Return On Equity (ROE) Complaint | ||||||||||||||||
Power of gas combined cycle generating facility | MW | 900 |
Environmental and Sustainabil51
Environmental and Sustainability Matters (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)lb / MWhunitsiteMW | Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($) | |
Site Contingency [Line Items] | |||
Number of coal fired units | unit | 4 | ||
Natural gas combined cycle plant power | MW | 700 | ||
New renewable generation, power | MW | 54 | ||
Emission rate after installation of new technology | lb / MWh | 980 | ||
Grid modernization costs | $ 450 | ||
Coal Ash Waste Disposal, Ash Ponds and Water | |||
Asset retirement obligation | 106.9 | $ 81.9 | $ 106.6 |
Estimated spend for ash pond dam reinforcement and other operational changes | $ 17 | ||
Renewal to retire unit period | 1 year | ||
Air Quality | |||
Percentage of coal fired generating fleet currently being scrubbed for SO2 (in hundredths) | 100.00% | ||
Percentage of coal fired generating fleet currently controlled for NOx (in hundredths) | 90.00% | ||
Climate Change and Carbon Strategy | |||
Reduction of carbon dioxide emissions | 35.00% | ||
Manufactured Gas Plants | |||
Environmental remediation expense | $ 44.2 | ||
Accrued costs included in other liabilities | $ 2.5 | $ 2.9 | |
SIGECO | |||
Manufactured Gas Plants | |||
Number of sites identified with potential remedial responsibility for entity (in number of sites) | site | 5 | ||
Environmental remediation expense | $ 20.3 | ||
Insurance recoveries | 15.7 | ||
Total estimated insurance recoveries | $ 15.8 | ||
Indiana Gas | |||
Manufactured Gas Plants | |||
Number of sites identified with potential remedial responsibility for entity (in number of sites) | site | 26 | ||
Environmental remediation expense | $ 23.9 | ||
Insurance recoveries | 20.8 | ||
Ash Ponds | SIGECO | |||
Coal Ash Waste Disposal, Ash Ponds and Water | |||
Asset retirement obligation | 40 | ||
Minimum | |||
Coal Ash Waste Disposal, Ash Ponds and Water | |||
Estimated capital expenditures to comply with Ash Pond and Coal Ash disposal regulations - lower range | 35 | ||
Ash Pond and Coal Ash disposal exit costs revised anticipated cost | 45 | ||
Estimated capital expenditures to comply with Clean Water Act | 4 | ||
Maximum | |||
Coal Ash Waste Disposal, Ash Ponds and Water | |||
Estimated capital expenditures to comply with Ash Pond and Coal Ash disposal regulations - lower range | $ 80 | ||
Ash Pond and Coal Ash disposal exit costs revised anticipated cost | 135 | ||
Estimated capital expenditures to comply with Clean Water Act | $ 8 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)agreement | Dec. 31, 2016USD ($) | |
Forward Contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Number of forward purchase arrangements agreement | agreement | 4 | |
Term of purchase arrangements | 5 years | |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | $ 1,579.5 | $ 1,380.1 |
Short-term borrowings & notes payable | 179.5 | 194.4 |
Cash & cash equivalents | 9.8 | 9.4 |
Natural gas purchase instrument assets | 0.5 | 0 |
Natural gas purchase instrument liabilities | 4.5 | 0 |
Interest rate swap liabilities | 1.4 | 0 |
Restricted cash | 0 | 0.9 |
Est. Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt | 1,715.2 | 1,495.3 |
Short-term borrowings & notes payable | 179.5 | 194.4 |
Cash & cash equivalents | 9.8 | 9.4 |
Natural gas purchase instrument assets | 0.5 | 0 |
Natural gas purchase instrument liabilities | 4.5 | 0 |
Interest rate swap liabilities | 1.4 | 0 |
Restricted cash | $ 0 | $ 0.9 |
Segment Reporting (Details)
Segment Reporting (Details) customer in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017USD ($)customer | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)customersegment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Segment Reporting Information [Line Items] | |||||||||||
Portion of Indiana that is provided natural gas distribution and transportation services by the gas utility services segment | 66.67% | 66.67% | |||||||||
Number of customers (greater than) | customer | 1 | 1 | |||||||||
Number of operating segments in Utility group | segment | 3 | ||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Revenues | $ 392.1 | $ 279.7 | $ 285.9 | $ 425 | $ 383.5 | $ 291.3 | $ 279.8 | $ 423.4 | $ 1,382.6 | $ 1,377.8 | $ 1,394.5 |
Profitability Measure - Net Income | 53.6 | $ 30.8 | $ 25.5 | $ 65.9 | 51.3 | $ 34.9 | $ 26.3 | $ 61.1 | 175.8 | 173.6 | 160.9 |
Depreciation & Amortization | 234.5 | 219.1 | 208.8 | ||||||||
Interest expense | 72.6 | 69.7 | 66.3 | ||||||||
Income Taxes | 60.7 | 99.5 | 88.1 | ||||||||
Capital Expenditures | 554.2 | 496.6 | 399.2 | ||||||||
Assets | 5,497.8 | 5,040.9 | 5,497.8 | 5,040.9 | 4,592.7 | ||||||
Gas Utility Services | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Profitability Measure - Net Income | 115.5 | 76.1 | 64.4 | ||||||||
Depreciation & Amortization | 118.9 | 108.1 | 98.6 | ||||||||
Interest expense | 43 | 40.1 | 35.8 | ||||||||
Income Taxes | 25.4 | 47.1 | 40.8 | ||||||||
Capital Expenditures | 391.4 | 358.5 | 291.2 | ||||||||
Assets | 3,457.8 | 3,091 | 3,457.8 | 3,091 | 2,706.9 | ||||||
Electric Utility Services | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Profitability Measure - Net Income | 75.2 | 84.7 | 82.6 | ||||||||
Depreciation & Amortization | 89.5 | 87.1 | 85.6 | ||||||||
Interest expense | 25.8 | 27 | 27.8 | ||||||||
Income Taxes | 41.4 | 50.1 | 49.3 | ||||||||
Capital Expenditures | 105.3 | 106.4 | 87.6 | ||||||||
Assets | 1,820.3 | 1,788.4 | 1,820.3 | 1,788.4 | 1,778.3 | ||||||
Other Operations | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Profitability Measure - Net Income | (14.9) | 12.8 | 13.9 | ||||||||
Depreciation & Amortization | 26.1 | 23.9 | 24.6 | ||||||||
Interest expense | 3.8 | 2.6 | 2.7 | ||||||||
Income Taxes | (6.1) | 2.3 | (2) | ||||||||
Capital Expenditures | 60.1 | 39 | 25.7 | ||||||||
Assets | $ 219.7 | $ 161.5 | 219.7 | 161.5 | 107.5 | ||||||
Non-cash costs & changes in accruals | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Capital Expenditures | (2.6) | (7.3) | (5.3) | ||||||||
Operating Segments | Gas Utility Services | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Revenues | 812.7 | 771.7 | 792.6 | ||||||||
Operating Segments | Electric Utility Services | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Revenues | 569.6 | 605.8 | 601.6 | ||||||||
Operating Segments | Other Operations | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Revenues | 45.6 | 42.2 | 40.7 | ||||||||
Eliminations | |||||||||||
Amounts Included in Profitability Measures [Abstract] | |||||||||||
Revenues | $ (45.3) | $ (41.9) | $ (40.4) |
Additional Balance Sheet & Op54
Additional Balance Sheet & Operational Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Inventory, Net [Abstract] | |||
Gas in storage – at LIFO cost | $ 36 | $ 37 | |
Materials & supplies | 37 | 38.1 | |
Coal & oil for electric generation - at average cost | 43.1 | 42.6 | |
Other | 1.4 | 1.3 | |
Total inventories | 117.5 | 119 | |
Amount by which cost of replacing inventories carried at LIFO cost exceeded carrying value | 2 | 1 | |
Prepayments and other current assets [Abstract] | |||
Prepaid gas delivery service | 26.6 | 26.4 | |
Prepaid taxes | 2.6 | 8 | |
Other prepayments & current assets | 3.5 | 4.2 | |
Total prepayments & other current assets | 32.7 | 38.6 | |
Other utility and corporate investments [Abstract] | |||
Cash surrender value of life insurance policies | 25.4 | 20.4 | |
Restricted cash & other investments | 1.3 | 0.9 | |
Total other investments | 26.7 | 21.3 | |
Accrued liabilities [Abstract] | |||
Refunds to customers & customer deposits | 51.4 | 49.4 | |
Accrued taxes | 55.8 | 44.8 | |
Accrued interest | 17.9 | 16.4 | |
Accrued salaries & other | 28.9 | 29.5 | |
Total accrued liabilities | 154 | 140.1 | |
Asset Retirement Obligation [Roll Forward] | |||
Asset retirement obligation, beginning balance | 106.6 | 81.9 | |
Accretion | 4.3 | 3.8 | |
Changes in estimates, net of cash payments | (4) | 20.9 | |
Asset retirement obligation, ending balance | 106.9 | 106.6 | $ 81.9 |
Other - net in the consolidated statement of income [Abstract] | |||
AFUDC - borrowed funds | 24.8 | 20.3 | 16.3 |
AFUDC - equity funds | 2.6 | 2.2 | 2.6 |
Nonutility plant capitalized interest | 1.2 | 1 | 0.4 |
Interest income | 0 | 0.3 | 0.6 |
Other income | 2 | 2.5 | (1.2) |
Total other – net | 30.6 | 26.3 | 18.7 |
Cash paid (received) for [Abstract] | |||
Interest | 71.2 | 69.6 | 66.2 |
Income taxes | (6.1) | 6.7 | $ (23.1) |
Accruals related to utility and nonutility plant purchases [Abstract] | |||
Accruals related to utility and nonutility plant purchases | $ 27.5 | $ 27.4 |
Subsidiary Guarantor & Consol55
Subsidiary Guarantor & Consolidating Information - Narrative (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)public_utility | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Operating utility companies | public_utility | 3 | ||
Short-term borrowing capacity | $ 400 | ||
Short-term borrowings | 179.5 | $ 194.4 | $ 14.5 |
Unsecured debt | $ 1,200 |
Subsidiary Guarantor & Consol56
Subsidiary Guarantor & Consolidating Information - Income Statement (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
OPERATING REVENUES | |||||||||||
Gas utility | $ 812.7 | $ 771.7 | $ 792.6 | ||||||||
Electric utility | 569.6 | 605.8 | 601.6 | ||||||||
Other | 0.3 | 0.3 | 0.3 | ||||||||
Total operating revenues | $ 392.1 | $ 279.7 | $ 285.9 | $ 425 | $ 383.5 | $ 291.3 | $ 279.8 | $ 423.4 | 1,382.6 | 1,377.8 | 1,394.5 |
OPERATING EXPENSES | |||||||||||
Cost of gas sold | 271.5 | 266.7 | 305.4 | ||||||||
Cost of fuel & purchased power | 171.8 | 183.6 | 187.5 | ||||||||
Other operating | 370.4 | 333.6 | 339.1 | ||||||||
Depreciation & amortization | 234.5 | 219.1 | 208.8 | ||||||||
Taxes other than income taxes | 55.9 | 58.3 | 57.1 | ||||||||
Total operating expenses | 1,104.1 | 1,061.3 | 1,097.9 | ||||||||
OPERATING INCOME | 57.5 | 58 | 49.7 | 113.5 | 93.5 | 64 | 52.2 | 106.8 | 278.5 | 316.5 | 296.6 |
OTHER INCOME (EXPENSE) | |||||||||||
Equity in earnings of consolidated companies | 0 | 0 | 0 | ||||||||
Other – net | 30.6 | 26.3 | 18.7 | ||||||||
Total other income (expense) | 30.6 | 26.3 | 18.7 | ||||||||
Interest expense | 72.6 | 69.7 | 66.3 | ||||||||
INCOME BEFORE INCOME TAXES | 236.5 | 273.1 | 249 | ||||||||
Income taxes | 60.7 | 99.5 | 88.1 | ||||||||
NET INCOME | $ 53.6 | $ 30.8 | $ 25.5 | $ 65.9 | $ 51.3 | $ 34.9 | $ 26.3 | $ 61.1 | 175.8 | 173.6 | 160.9 |
Reclassifications and Eliminations | |||||||||||
OPERATING REVENUES | |||||||||||
Gas utility | 0 | 0 | 0 | ||||||||
Electric utility | 0 | 0 | 0 | ||||||||
Other | (45.3) | (41.9) | (40.4) | ||||||||
Total operating revenues | (45.3) | (41.9) | (40.4) | ||||||||
OPERATING EXPENSES | |||||||||||
Cost of gas sold | 0 | 0 | 0 | ||||||||
Cost of fuel & purchased power | 0 | 0 | 0 | ||||||||
Other operating | (43.9) | (40.4) | (37.8) | ||||||||
Depreciation & amortization | 0.1 | 0.1 | 0.3 | ||||||||
Taxes other than income taxes | 0.1 | 0 | 0.1 | ||||||||
Total operating expenses | (43.7) | (40.3) | (37.4) | ||||||||
OPERATING INCOME | (1.6) | (1.6) | (3) | ||||||||
OTHER INCOME (EXPENSE) | |||||||||||
Equity in earnings of consolidated companies | (190.7) | (160.8) | (147) | ||||||||
Other – net | (47.9) | (46) | (39.7) | ||||||||
Total other income (expense) | (238.6) | (206.8) | (186.7) | ||||||||
Interest expense | (49.5) | (47.6) | (42.7) | ||||||||
INCOME BEFORE INCOME TAXES | (190.7) | (160.8) | (147) | ||||||||
Income taxes | 0 | 0 | 0 | ||||||||
NET INCOME | (190.7) | (160.8) | (147) | ||||||||
Subsidiary Guarantors | Reportable Legal Entities | |||||||||||
OPERATING REVENUES | |||||||||||
Gas utility | 812.7 | 771.7 | 792.6 | ||||||||
Electric utility | 569.6 | 605.8 | 601.6 | ||||||||
Other | 0 | 0 | 0 | ||||||||
Total operating revenues | 1,382.3 | 1,377.5 | 1,394.2 | ||||||||
OPERATING EXPENSES | |||||||||||
Cost of gas sold | 271.5 | 266.7 | 305.4 | ||||||||
Cost of fuel & purchased power | 171.8 | 183.6 | 187.5 | ||||||||
Other operating | 378.6 | 374 | 376.9 | ||||||||
Depreciation & amortization | 208.4 | 195.2 | 184.2 | ||||||||
Taxes other than income taxes | 53.8 | 56.8 | 55.2 | ||||||||
Total operating expenses | 1,084.1 | 1,076.3 | 1,109.2 | ||||||||
OPERATING INCOME | 298.2 | 301.2 | 285 | ||||||||
OTHER INCOME (EXPENSE) | |||||||||||
Equity in earnings of consolidated companies | 0 | 0 | 0 | ||||||||
Other – net | 28.2 | 24 | 15.7 | ||||||||
Total other income (expense) | 28.2 | 24 | 15.7 | ||||||||
Interest expense | 68.8 | 67.2 | 63.7 | ||||||||
INCOME BEFORE INCOME TAXES | 257.6 | 258 | 237 | ||||||||
Income taxes | 66.9 | 97.2 | 90 | ||||||||
NET INCOME | 190.7 | 160.8 | 147 | ||||||||
Parent Company | Reportable Legal Entities | |||||||||||
OPERATING REVENUES | |||||||||||
Gas utility | 0 | 0 | 0 | ||||||||
Electric utility | 0 | 0 | 0 | ||||||||
Other | 45.6 | 42.2 | 40.7 | ||||||||
Total operating revenues | 45.6 | 42.2 | 40.7 | ||||||||
OPERATING EXPENSES | |||||||||||
Cost of gas sold | 0 | 0 | 0 | ||||||||
Cost of fuel & purchased power | 0 | 0 | 0 | ||||||||
Other operating | 35.7 | 0 | 0 | ||||||||
Depreciation & amortization | 26 | 23.8 | 24.3 | ||||||||
Taxes other than income taxes | 2 | 1.5 | 1.8 | ||||||||
Total operating expenses | 63.7 | 25.3 | 26.1 | ||||||||
OPERATING INCOME | (18.1) | 16.9 | 14.6 | ||||||||
OTHER INCOME (EXPENSE) | |||||||||||
Equity in earnings of consolidated companies | 190.7 | 160.8 | 147 | ||||||||
Other – net | 50.3 | 48.3 | 42.7 | ||||||||
Total other income (expense) | 241 | 209.1 | 189.7 | ||||||||
Interest expense | 53.3 | 50.1 | 45.3 | ||||||||
INCOME BEFORE INCOME TAXES | 169.6 | 175.9 | 159 | ||||||||
Income taxes | (6.2) | 2.3 | (1.9) | ||||||||
NET INCOME | $ 175.8 | $ 173.6 | $ 160.9 |
Subsidiary Guarantor & Consol57
Subsidiary Guarantor & Consolidating Information - Balance Sheet (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
ASSETS | ||||
Cash & cash equivalents | $ 9.8 | $ 9.4 | $ 6.2 | $ 19.3 |
Accounts receivable - less reserves | 109.5 | 102.6 | ||
Intercompany receivables | 0 | 0 | ||
Accrued unbilled revenues | 123.7 | 112 | ||
Inventories | 117.5 | 119 | ||
Recoverable fuel & natural gas costs | 19.2 | 29.9 | ||
Prepayments & other current assets | 32.7 | 38.6 | ||
Total current assets | 412.4 | 411.5 | ||
Original cost | 7,015.4 | 6,545.4 | ||
Less: accumulated depreciation & amortization | 2,738.7 | 2,562.5 | ||
Net utility plant | 4,276.7 | 3,982.9 | ||
Investments in consolidated subsidiaries | 0 | 0 | ||
Notes receivable from consolidated subsidiaries | 0 | 0 | ||
Investments in unconsolidated affiliates | 0.2 | 0.2 | ||
Other investments | 26.7 | 21.3 | ||
Nonutility plant - net | 198.6 | 164.8 | ||
Goodwill | 205 | 205 | ||
Regulatory assets | 314 | 206.2 | ||
Other assets | 64.2 | 49 | ||
TOTAL ASSETS | 5,497.8 | 5,040.9 | 4,592.7 | |
LIABILITIES & SHAREHOLDER'S EQUITY | ||||
Accounts payable | 221.8 | 205.4 | ||
Intercompany payables | 0 | 0 | ||
Payables to other Vectren companies | 33.3 | 25.4 | ||
Accrued liabilities | 154 | 140.1 | ||
Short-term borrowings | 179.5 | 194.4 | 14.5 | |
Intercompany short-term borrowings | 0 | 0 | ||
Current maturities of long-term debt | 100 | 49.1 | ||
Current maturities of long-term debt due to VUHI | 0 | |||
Total current liabilities | 688.6 | 614.4 | ||
Long-term debt - net of current maturities & debt subject to tender | 1,479.5 | 1,331 | ||
Long-term debt due to VUHI | 0 | 0 | ||
Total long-term debt - net | 1,479.5 | 1,331 | ||
Deferred income taxes | 457.5 | 854.5 | ||
Regulatory liabilities | 937.2 | 453.7 | ||
Deferred credits & other liabilities | 212.2 | 163.3 | ||
Total deferred credits & other liabilities | 1,606.9 | 1,471.5 | ||
Common stock (no par value) | 877.5 | 831.2 | ||
Retained earnings | 845.3 | 792.8 | ||
Total common shareholder's equity | 1,722.8 | 1,624 | ||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | 5,497.8 | 5,040.9 | ||
Eliminations | ||||
ASSETS | ||||
Cash & cash equivalents | 0 | 0 | 0 | 0 |
Accounts receivable - less reserves | 0 | 0 | ||
Intercompany receivables | (227.5) | (174.6) | ||
Accrued unbilled revenues | 0 | 0 | ||
Inventories | 0 | 0 | ||
Recoverable fuel & natural gas costs | 0 | 0 | ||
Prepayments & other current assets | (8.8) | (2.3) | ||
Total current assets | (236.3) | (176.9) | ||
Original cost | 0 | 0 | ||
Less: accumulated depreciation & amortization | 0 | 0 | ||
Net utility plant | 0 | 0 | ||
Investments in consolidated subsidiaries | (1,741) | (1,577.2) | ||
Notes receivable from consolidated subsidiaries | (970.7) | (945.4) | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Other investments | 0 | 0 | ||
Nonutility plant - net | 0 | 0 | ||
Goodwill | 0 | 0 | ||
Regulatory assets | 0 | 0 | ||
Other assets | (0.1) | (8.6) | ||
TOTAL ASSETS | (2,948.1) | (2,708.1) | ||
LIABILITIES & SHAREHOLDER'S EQUITY | ||||
Accounts payable | 0 | 0 | ||
Intercompany payables | (8.3) | (14.8) | ||
Payables to other Vectren companies | 0 | 0 | ||
Accrued liabilities | (8.8) | (2.3) | ||
Short-term borrowings | 0 | 0 | ||
Intercompany short-term borrowings | (120.2) | (159.8) | ||
Current maturities of long-term debt | 0 | 0 | ||
Current maturities of long-term debt due to VUHI | (99) | |||
Total current liabilities | (236.3) | (176.9) | ||
Long-term debt - net of current maturities & debt subject to tender | 0 | 0 | ||
Long-term debt due to VUHI | (970.7) | (945.4) | ||
Total long-term debt - net | (970.7) | (945.4) | ||
Deferred income taxes | 0 | 0 | ||
Regulatory liabilities | 0 | 0 | ||
Deferred credits & other liabilities | (0.1) | (8.6) | ||
Total deferred credits & other liabilities | (0.1) | (8.6) | ||
Common stock (no par value) | (890.7) | (844.4) | ||
Retained earnings | (850.3) | (732.8) | ||
Total common shareholder's equity | (1,741) | (1,577.2) | ||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | (2,948.1) | (2,708.1) | ||
Subsidiary Guarantors | Reportable Legal Entities | ||||
ASSETS | ||||
Cash & cash equivalents | 8.2 | 7.6 | 5.5 | 6.9 |
Accounts receivable - less reserves | 109.2 | 102.4 | ||
Intercompany receivables | 0 | 17.5 | ||
Accrued unbilled revenues | 123.7 | 112 | ||
Inventories | 117.5 | 119 | ||
Recoverable fuel & natural gas costs | 19.2 | 29.9 | ||
Prepayments & other current assets | 28.9 | 36.5 | ||
Total current assets | 406.7 | 424.9 | ||
Original cost | 7,015.4 | 6,545.4 | ||
Less: accumulated depreciation & amortization | 2,738.7 | 2,562.5 | ||
Net utility plant | 4,276.7 | 3,982.9 | ||
Investments in consolidated subsidiaries | 0 | 0 | ||
Notes receivable from consolidated subsidiaries | 0 | 0 | ||
Investments in unconsolidated affiliates | 0.2 | 0.2 | ||
Other investments | 26.3 | 20.9 | ||
Nonutility plant - net | 1.6 | 1.7 | ||
Goodwill | 205 | 205 | ||
Regulatory assets | 298.7 | 190 | ||
Other assets | 62.5 | 53.9 | ||
TOTAL ASSETS | 5,277.7 | 4,879.5 | ||
LIABILITIES & SHAREHOLDER'S EQUITY | ||||
Accounts payable | 179.4 | 194.6 | ||
Intercompany payables | 8.3 | 14.8 | ||
Payables to other Vectren companies | 25.2 | 25.4 | ||
Accrued liabilities | 147.7 | 126 | ||
Short-term borrowings | 0 | 0 | ||
Intercompany short-term borrowings | 120.2 | 142.3 | ||
Current maturities of long-term debt | 0 | 49.1 | ||
Current maturities of long-term debt due to VUHI | 99 | |||
Total current liabilities | 579.8 | 552.2 | ||
Long-term debt - net of current maturities & debt subject to tender | 384.5 | 335.2 | ||
Long-term debt due to VUHI | 970.7 | 945.4 | ||
Total long-term debt - net | 1,355.2 | 1,280.6 | ||
Deferred income taxes | 455.3 | 855.4 | ||
Regulatory liabilities | 936.1 | 452.4 | ||
Deferred credits & other liabilities | 210.3 | 161.7 | ||
Total deferred credits & other liabilities | 1,601.7 | 1,469.5 | ||
Common stock (no par value) | 890.7 | 844.4 | ||
Retained earnings | 850.3 | 732.8 | ||
Total common shareholder's equity | 1,741 | 1,577.2 | ||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | 5,277.7 | 4,879.5 | ||
Parent Company | Reportable Legal Entities | ||||
ASSETS | ||||
Cash & cash equivalents | 1.6 | 1.8 | $ 0.7 | $ 12.4 |
Accounts receivable - less reserves | 0.3 | 0.2 | ||
Intercompany receivables | 227.5 | 157.1 | ||
Accrued unbilled revenues | 0 | 0 | ||
Inventories | 0 | 0 | ||
Recoverable fuel & natural gas costs | 0 | 0 | ||
Prepayments & other current assets | 12.6 | 4.4 | ||
Total current assets | 242 | 163.5 | ||
Original cost | 0 | 0 | ||
Less: accumulated depreciation & amortization | 0 | 0 | ||
Net utility plant | 0 | 0 | ||
Investments in consolidated subsidiaries | 1,741 | 1,577.2 | ||
Notes receivable from consolidated subsidiaries | 970.7 | 945.4 | ||
Investments in unconsolidated affiliates | 0 | 0 | ||
Other investments | 0.4 | 0.4 | ||
Nonutility plant - net | 197 | 163.1 | ||
Goodwill | 0 | 0 | ||
Regulatory assets | 15.3 | 16.2 | ||
Other assets | 1.8 | 3.7 | ||
TOTAL ASSETS | 3,168.2 | 2,869.5 | ||
LIABILITIES & SHAREHOLDER'S EQUITY | ||||
Accounts payable | 42.4 | 10.8 | ||
Intercompany payables | 0 | 0 | ||
Payables to other Vectren companies | 8.1 | 0 | ||
Accrued liabilities | 15.1 | 16.4 | ||
Short-term borrowings | 179.5 | 194.4 | ||
Intercompany short-term borrowings | 0 | 17.5 | ||
Current maturities of long-term debt | 100 | 0 | ||
Current maturities of long-term debt due to VUHI | 0 | |||
Total current liabilities | 345.1 | 239.1 | ||
Long-term debt - net of current maturities & debt subject to tender | 1,095 | 995.8 | ||
Long-term debt due to VUHI | 0 | 0 | ||
Total long-term debt - net | 1,095 | 995.8 | ||
Deferred income taxes | 2.2 | (0.9) | ||
Regulatory liabilities | 1.1 | 1.3 | ||
Deferred credits & other liabilities | 2 | 10.2 | ||
Total deferred credits & other liabilities | 5.3 | 10.6 | ||
Common stock (no par value) | 877.5 | 831.2 | ||
Retained earnings | 845.3 | 792.8 | ||
Total common shareholder's equity | 1,722.8 | 1,624 | ||
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ 3,168.2 | $ 2,869.5 |
Subsidiary Guarantor & Consol58
Subsidiary Guarantor & Consolidating Information - Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | 24 Months Ended | 36 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2017 | |
Condensed Cash Flow Statements, Captions [Line Items] | |||||
NET CASH FROM OPERATING ACTIVITIES | $ 446.8 | $ 397.4 | $ 492.9 | ||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||
Long-term debt, net of issuance costs | 198.5 | 0 | 236.3 | ||
Additional capital contribution from parent | 46.3 | 31.3 | 6.2 | ||
Dividends to parent | (123.3) | (116.1) | (110.4) | ||
Retirement of long-term debt | 0 | (13) | (95) | ||
Net change in intercompany short-term borrowings | 0 | 0 | 0 | ||
Net change in short-term borrowings | (14.9) | 179.9 | (141.9) | ||
Net cash from financing activities | 106.6 | 82.1 | (104.8) | ||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||
Consolidated subsidiary distributions | 0 | 0 | 0 | ||
Proceeds from other investing activities | 2.7 | 15.3 | 3.9 | ||
Capital expenditures, excluding AFUDC equity | (554.2) | (496.6) | (399.2) | ||
Consolidated subsidiary investments | 0 | 0 | 0 | ||
Other costs | (2.4) | 0 | 0 | ||
Changes in restricted cash | 0.9 | 5 | (5.9) | ||
Net change in long-term intercompany notes receivable | 0 | 0 | 0 | ||
Net change in short-term intercompany notes receivable | 0 | 0 | 0 | ||
Net cash from investing activities | (553) | (476.3) | (401.2) | ||
Net change in cash & cash equivalents | 0.4 | 3.2 | (13.1) | ||
Cash & cash equivalents at beginning of period | 9.4 | 6.2 | 19.3 | $ 6.2 | $ 19.3 |
Cash & cash equivalents at end of period | 9.8 | 9.4 | 6.2 | 9.8 | 9.8 |
Eliminations | |||||
Condensed Cash Flow Statements, Captions [Line Items] | |||||
NET CASH FROM OPERATING ACTIVITIES | 0 | 0 | 0 | ||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||
Long-term debt, net of issuance costs | (124.3) | (109.4) | (89.5) | ||
Additional capital contribution from parent | (46.3) | (31.3) | (6.2) | ||
Dividends to parent | 73.1 | 82 | 103.2 | ||
Retirement of long-term debt | 0 | 0 | |||
Net change in intercompany short-term borrowings | 39.6 | 21.8 | (10.5) | ||
Net change in short-term borrowings | 0 | 0 | 0 | ||
Net cash from financing activities | (57.9) | (36.9) | (3) | ||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||
Consolidated subsidiary distributions | (73.1) | (82) | (103.2) | ||
Proceeds from other investing activities | 0 | 0 | 0 | ||
Capital expenditures, excluding AFUDC equity | 0 | 0 | 0 | ||
Consolidated subsidiary investments | 46.3 | 31.3 | 6.2 | ||
Other costs | 0 | ||||
Changes in restricted cash | 0 | 0 | 0 | ||
Net change in long-term intercompany notes receivable | 124.3 | 109.4 | 89.5 | ||
Net change in short-term intercompany notes receivable | (39.6) | (21.8) | 10.5 | ||
Net cash from investing activities | 57.9 | 36.9 | 3 | ||
Net change in cash & cash equivalents | 0 | 0 | 0 | ||
Cash & cash equivalents at beginning of period | 0 | 0 | 0 | 0 | 0 |
Cash & cash equivalents at end of period | 0 | 0 | 0 | 0 | 0 |
Subsidiary Guarantors | Reportable Legal Entities | |||||
Condensed Cash Flow Statements, Captions [Line Items] | |||||
NET CASH FROM OPERATING ACTIVITIES | 398.5 | 352.2 | 460.3 | ||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||
Long-term debt, net of issuance costs | 123.9 | 109.4 | 126.8 | ||
Additional capital contribution from parent | 46.3 | 31.3 | 6.2 | ||
Dividends to parent | (73.1) | (82) | (103.2) | ||
Retirement of long-term debt | (13) | (20) | |||
Net change in intercompany short-term borrowings | (22.1) | 11.9 | (40.7) | ||
Net change in short-term borrowings | 0 | 0 | 0 | ||
Net cash from financing activities | 75 | 57.6 | (30.9) | ||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||
Consolidated subsidiary distributions | 0 | 0 | 0 | ||
Proceeds from other investing activities | 2.7 | 15.3 | 0 | ||
Capital expenditures, excluding AFUDC equity | (491.6) | (461.7) | (373.7) | ||
Consolidated subsidiary investments | 0 | 0 | 0 | ||
Other costs | (2.4) | ||||
Changes in restricted cash | 0.9 | 5 | (5.9) | ||
Net change in long-term intercompany notes receivable | 0 | 0 | 0 | ||
Net change in short-term intercompany notes receivable | 17.5 | 33.7 | (51.2) | ||
Net cash from investing activities | (472.9) | (407.7) | (430.8) | ||
Net change in cash & cash equivalents | 0.6 | 2.1 | (1.4) | ||
Cash & cash equivalents at beginning of period | 7.6 | 5.5 | 6.9 | 5.5 | 6.9 |
Cash & cash equivalents at end of period | 8.2 | 7.6 | 5.5 | 8.2 | 8.2 |
Parent Company | Reportable Legal Entities | |||||
Condensed Cash Flow Statements, Captions [Line Items] | |||||
NET CASH FROM OPERATING ACTIVITIES | 48.3 | 45.2 | 32.6 | ||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||
Long-term debt, net of issuance costs | 198.9 | 0 | 199 | ||
Additional capital contribution from parent | 46.3 | 31.3 | 6.2 | ||
Dividends to parent | (123.3) | (116.1) | (110.4) | ||
Retirement of long-term debt | 0 | (75) | |||
Net change in intercompany short-term borrowings | (17.5) | (33.7) | 51.2 | ||
Net change in short-term borrowings | (14.9) | 179.9 | (141.9) | ||
Net cash from financing activities | 89.5 | 61.4 | (70.9) | ||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||
Consolidated subsidiary distributions | 73.1 | 82 | 103.2 | ||
Proceeds from other investing activities | 0 | 0 | 3.9 | ||
Capital expenditures, excluding AFUDC equity | (62.6) | (34.9) | (25.5) | ||
Consolidated subsidiary investments | (46.3) | (31.3) | (6.2) | ||
Other costs | 0 | ||||
Changes in restricted cash | 0 | 0 | 0 | ||
Net change in long-term intercompany notes receivable | (124.3) | (109.4) | (89.5) | ||
Net change in short-term intercompany notes receivable | 22.1 | (11.9) | 40.7 | ||
Net cash from investing activities | (138) | (105.5) | 26.6 | ||
Net change in cash & cash equivalents | (0.2) | 1.1 | (11.7) | ||
Cash & cash equivalents at beginning of period | 1.8 | 0.7 | 12.4 | 0.7 | 12.4 |
Cash & cash equivalents at end of period | $ 1.6 | $ 1.8 | $ 0.7 | $ 1.6 | $ 1.6 |
Quarterly Financial Data (Una59
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 392.1 | $ 279.7 | $ 285.9 | $ 425 | $ 383.5 | $ 291.3 | $ 279.8 | $ 423.4 | $ 1,382.6 | $ 1,377.8 | $ 1,394.5 |
Operating income | 57.5 | 58 | 49.7 | 113.5 | 93.5 | 64 | 52.2 | 106.8 | 278.5 | 316.5 | 296.6 |
Net income | $ 53.6 | $ 30.8 | $ 25.5 | $ 65.9 | $ 51.3 | $ 34.9 | $ 26.3 | $ 61.1 | $ 175.8 | $ 173.6 | $ 160.9 |
SCHEDULE II VALUATION AND QUA60
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Accumulated provision for uncollectible accounts - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||
Balance, at beginning of year | $ 4.1 | $ 3 | $ 3.9 |
Additions charged to expenses | 5.7 | 6.6 | 6.9 |
Additions charged to other accounts | 0 | 0 | 0 |
Deductions from Reserves, Net | 5.9 | 5.5 | 7.8 |
Balance, at end of period | $ 3.9 | $ 4.1 | $ 3 |