ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
VECTREN CORPORATION |
INDIANA | 35-2086905 | |
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | |
One Vectren Square | 47708 | |
(Address of principal executive offices) | (Zip Code) |
Title of each class | Name of each exchange on which registered | |
Common – Without Par | New York Stock Exchange |
Common Stock - Without Par Value | 83,040,212 | January 31, 2018 | ||
Class | Number of Shares | Date |
Administration: President Trump’s Administration | IRP: Integrated Resource Plan |
AFUDC: allowance for funds used during construction | kV: Kilovolt |
ASC: Accounting Standards Codification | MDth / MMDth: thousands / millions of dekatherms |
ASU: Accounting Standards Update | MISO: Midcontinent Independent System Operator |
BTU / MMBTU: British thermal units / millions of BTU | MCF / BCF: thousands / billions of cubic feet |
DOT: Department of Transportation | MW: megawatts |
EPA: Environmental Protection Agency | MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours) |
FAC: Fuel Adjustment Clause | NERC: North American Electric Reliability Corporation |
FASB: Financial Accounting Standards Board | OCC: Ohio Office of the Consumer Counselor |
FERC: Federal Energy Regulatory Commission | OUCC: Indiana Office of the Utility Consumer Counselor |
GAAP: Generally Accepted Accounting Principles | PHMSA: Pipeline and Hazardous Materials Safety Administration |
GCA: Gas Cost Adjustment | PUCO: Public Utilities Commission of Ohio |
IURC: Indiana Utility Regulatory Commission | TCJA: Tax Cuts and Jobs Act |
IRC: Internal Revenue Code | Throughput: combined gas sales and gas transportation volumes |
IDEM: Indiana Department of Environmental Management | XBRL: eXtensible Business Reporting Language |
Mailing Address: One Vectren Square Evansville, Indiana 47708 | Phone Number: (812) 491-4000 | Investor Relations Contact: David E. Parker Director, Investor Relations vvcir@vectren.com |
Item Number | Page Number | |
Part I | ||
1 | ||
1A | Risk Factors | |
1B | Unresolved Staff Comments | |
2 | Properties | |
3 | Legal Proceedings | |
4 | Mine Safety Disclosures | |
Part II | ||
5 | Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities | |
6 | Selected Financial Data | |
7 | Management's Discussion and Analysis of Results of Operations and Financial Condition | |
7A | Quantitative and Qualitative Disclosures About Market Risk | |
8 | Financial Statements and Supplementary Data | |
9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |
9A | Controls and Procedures, including Management’s Assessment of Internal Controls over Financial Reporting | |
9B | Other Information | |
Part III | ||
10 | Directors, Executive Officers and Corporate Governance | |
11 | Executive Compensation | |
12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
13 | Certain Relationships, Related Transactions and Director Independence | |
14 | Principal Accountant Fees and Services | |
Part IV | ||
15 | Exhibits and Financial Statement Schedules | |
Signatures | ||
Date of summer peak load | 7/21/2017 | 6/22/2016 | 7/29/2015 | 8/27/2014 | 8/30/2013 | ||||||||||
Total load at peak | 1,042 | 1,096 | 1,088 | 1,095 | 1,102 | ||||||||||
Generating capability | 1,248 | 1,248 | 1,248 | 1,298 | 1,298 | ||||||||||
Purchase supply (effective capacity) | 36 | 37 | 37 | 38 | 38 | ||||||||||
Interruptible contracts & direct load control | 53 | 75 | 72 | 71 | 48 | ||||||||||
Total power supply capacity | 1,337 | 1,360 | 1,357 | 1,407 | 1,384 | ||||||||||
Reserve margin at peak | 28 | % | 24 | % | 25 | % | 22 | % | 25 | % |
Current Rating | ||
Standard | ||
Moody’s | & Poor’s | |
Vectren Corporation's corporate credit rating | not rated | A- |
Utility Holdings and Indiana Gas senior unsecured debt | A2 | A- |
Utility Holdings commercial paper program | P-1 | A-2 |
SIGECO’s senior secured debt | Aa3 | A |
Cash | Common Stock Price Range | |||||||
Dividend | High | Low | ||||||
2017 | ||||||||
First Quarter | $0.420 | $59.03 | $51.50 | |||||
Second Quarter | $0.420 | $62.79 | $58.03 | |||||
Third Quarter | $0.420 | $68.30 | $57.48 | |||||
Fourth Quarter | $0.450 | $69.86 | $64.00 | |||||
2016 | ||||||||
First Quarter | $0.400 | $51.00 | $39.43 | |||||
Second Quarter | $0.400 | $52.68 | $46.96 | |||||
Third Quarter | $0.400 | $53.33 | $47.87 | |||||
Fourth Quarter | $0.420 | $53.05 | $46.52 |
Year Ended December 31, | ||||||||||||||||||||
(In millions, except per share data) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
Operating Data: | ||||||||||||||||||||
Operating revenues | $ | 2,657.3 | $ | 2,448.3 | $ | 2,434.7 | $ | 2,611.7 | $ | 2,491.2 | ||||||||||
Operating income | $ | 318.4 | $ | 381.5 | $ | 361.8 | $ | 314.5 | $ | 333.6 | ||||||||||
Net income | $ | 216.0 | $ | 211.6 | $ | 197.3 | $ | 166.9 | $ | 136.6 | ||||||||||
Weighted average common shares outstanding | 83.0 | 82.8 | 82.7 | 82.5 | 82.3 | |||||||||||||||
Fully diluted common shares outstanding | 83.0 | 82.8 | 82.7 | 82.5 | 82.4 | |||||||||||||||
Basic earnings per share | ||||||||||||||||||||
on common stock | $ | 2.60 | $ | 2.55 | $ | 2.39 | $ | 2.02 | $ | 1.66 | ||||||||||
Diluted earnings per share | ||||||||||||||||||||
on common stock | $ | 2.60 | $ | 2.55 | $ | 2.39 | $ | 2.02 | $ | 1.66 | ||||||||||
Dividends per share on common stock | $ | 1.710 | $ | 1.620 | $ | 1.540 | $ | 1.460 | $ | 1.425 | ||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Total assets | $ | 6,239.3 | $ | 5,800.7 | $ | 5,400.0 | $ | 5,137.8 | $ | 5,079.5 | ||||||||||
Long-term debt, net | $ | 1,738.7 | $ | 1,589.9 | $ | 1,712.9 | $ | 1,339.1 | $ | 1,767.9 | ||||||||||
Common shareholders' equity | $ | 1,849.3 | $ | 1,768.1 | $ | 1,683.8 | $ | 1,606.6 | $ | 1,554.3 | ||||||||||
As further discussed in Note 8 of the Consolidated Financial Statements included in Item 8 herein, net income in 2017 include a $45.3 million net tax benefit associated with the impact of the federal corporate income tax rate reduction on the revaluation of the Company's non rate-regulated deferred income tax balance as of December 31, 2017. Also, reflected in net income is a non-recurring charge of $45.3 million, after tax, or $69.7 million in operating income for the non-recurring multi-year contribution to the Vectren Foundation in 2017. | ||||||||||||||||||||
Results include the loss on disposition and operating results of Coal Mining in 2014 and the loss on disposition and operating results attributable to the Company's investment in ProLiance in 2013. Coal Mining results for the year ended December 31, 2014, inclusive of the loss on sale, were a loss of $21.1 million. ProLiance results for the year ended December 31 2013, inclusive of the loss on sale, were a loss of $26.8 million. |
Twelve Months Ended December 31, 2017 | ||||||||||||
(In millions, except EPS) | GAAP Measure | Deferred Tax Revaluation (Gain) / Loss | Other Operating Charge | Non-GAAP Measure | ||||||||
Consolidated | ||||||||||||
Net Income | $ | 216.0 | $ | (45.3 | ) | $ | 45.3 | $ | 216.0 | |||
Basic EPS | $ | 2.60 | $ | (0.55 | ) | $ | 0.55 | $ | 2.60 | |||
Utility Group | ||||||||||||
Net Income | $ | 175.8 | $ | (23.2 | ) | $ | 23.2 | $ | 175.8 | |||
Basic EPS | $ | 2.12 | $ | (0.28 | ) | $ | 0.28 | $ | 2.12 | |||
Utility Group Segments | ||||||||||||
Gas Utility - Net Income | $ | 115.5 | $ | (27.3 | ) | $ | — | $ | 88.2 | |||
Electric Utility - Net Income | $ | 75.2 | $ | — | $ | — | $ | 75.2 | ||||
Other Utility Ops - Net Income | $ | (14.9 | ) | $ | 4.1 | $ | 23.2 | $ | 12.4 | |||
Nonutility Group | ||||||||||||
Net Income | $ | 41.1 | $ | (22.3 | ) | $ | 22.1 | $ | 40.9 | |||
Basic EPS | $ | 0.49 | $ | (0.27 | ) | $ | 0.27 | $ | 0.49 | |||
Corp & Other | ||||||||||||
Net Income | $ | (0.9 | ) | $ | 0.2 | $ | — | $ | (0.7 | ) | ||
Basic EPS | $ | (0.01 | ) | $ | — | $ | — | $ | (0.01 | ) | ||
Other Operating Expense | ||||||||||||
Consolidated | $ | 1,115.9 | $ | — | $ | (69.7 | ) | $ | 1,046.2 | |||
Utility Group | $ | 370.4 | $ | — | $ | (35.7 | ) | $ | 334.7 | |||
Income Tax Expense | ||||||||||||
Consolidated | $ | 46.4 | $ | 45.3 | $ | 24.4 | $ | 116.1 | ||||
Utility Group | $ | 60.7 | $ | 23.2 | $ | 12.5 | $ | 96.4 | ||||
Nonutility Group | $ | (13.5 | ) | $ | 22.3 | $ | 11.9 | $ | 20.7 | |||
Corp & Other | $ | (0.8 | ) | $ | (0.2 | ) | $ | — | $ | (1.0 | ) |
Year Ended December 31, | ||||||||||||
(In millions, except per share data) | 2017 | 2016 | 2015 | |||||||||
Net income | $ | 216.0 | $ | 211.6 | $ | 197.3 | ||||||
Attributed to: | ||||||||||||
Utility Group | $ | 175.8 | $ | 173.6 | $ | 160.9 | ||||||
Nonutility Group | 41.1 | 36.9 | 36.3 | |||||||||
Corporate & Other | (0.9 | ) | 1.1 | 0.1 | ||||||||
Basic EPS | $ | 2.60 | $ | 2.55 | $ | 2.39 | ||||||
Attributed to: | ||||||||||||
Utility Group | $ | 2.12 | $ | 2.10 | $ | 1.95 | ||||||
Nonutility Group | 0.49 | 0.44 | 0.44 | |||||||||
Corporate & Other | (0.01 | ) | 0.01 | — | ||||||||
Year Ended December 31, | ||||||||||||
(In millions, except per share data) | 2017 | 2016 | 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 | 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 | 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 | 249.0 | |||||||||
Income taxes | 60.7 | 99.5 | 88.1 | |||||||||
NET INCOME | $ | 175.8 | $ | 173.6 | $ | 160.9 | ||||||
CONTRIBUTION TO VECTREN BASIC EPS | $ | 2.12 | $ | 2.10 | $ | 1.95 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Gas utility revenues | $ | 812.7 | $ | 771.7 | $ | 792.6 | ||||||
Cost of gas sold | 271.5 | 266.7 | 305.4 | |||||||||
Total gas utility margin | $ | 541.2 | $ | 505.0 | $ | 487.2 | ||||||
Margin attributed to: | ||||||||||||
Residential & commercial customers | $ | 412.3 | $ | 385.9 | $ | 360.8 | ||||||
Industrial customers | 73.9 | 67.1 | 61.4 | |||||||||
Other | 8.4 | 7.4 | 9.3 | |||||||||
Regulatory expense recovery mechanisms | 46.6 | 44.6 | 55.7 | |||||||||
Total gas utility margin | $ | 541.2 | $ | 505.0 | $ | 487.2 | ||||||
Sold & transported volumes in MMDth attributed to: | ||||||||||||
Residential & commercial customers | 97.1 | 97.2 | 104.9 | |||||||||
Industrial customers | 122.2 | 127.0 | 125.3 | |||||||||
Total sold & transported volumes | 219.3 | 224.2 | 230.2 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Electric utility revenues | $ | 569.6 | $ | 605.8 | $ | 601.6 | ||||||
Cost of fuel & purchased power | 171.8 | 183.6 | 187.5 | |||||||||
Total electric utility margin | $ | 397.8 | $ | 422.2 | $ | 414.1 | ||||||
Margin attributed to: | ||||||||||||
Residential & commercial customers | $ | 254.9 | $ | 261.2 | $ | 258.6 | ||||||
Industrial customers | 96.9 | 112.1 | 109.7 | |||||||||
Other | 5.6 | 5.8 | 4.5 | |||||||||
Regulatory expense recovery mechanisms | 9.6 | 13.7 | 9.6 | |||||||||
Subtotal: retail | $ | 367.0 | $ | 392.8 | $ | 382.4 | ||||||
Wholesale power & transmission system margin | 30.8 | 29.4 | 31.7 | |||||||||
Total electric utility margin | $ | 397.8 | $ | 422.2 | $ | 414.1 | ||||||
Electric volumes sold in GWh attributed to: | ||||||||||||
Residential & commercial customers | 2,638.8 | 2,729.0 | 2,714.4 | |||||||||
Industrial customers | 2,096.5 | 2,722.3 | 2,721.5 | |||||||||
Other customers | 22.3 | 22.9 | 22.2 | |||||||||
Total retail volumes | 4,757.6 | 5,474.2 | 5,458.1 | |||||||||
Wholesale | 463.2 | 136.1 | 337.8 | |||||||||
Total volumes sold | 5,220.8 | 5,610.3 | 5,795.9 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
MISO Transmission system margin | $ | 25.5 | $ | 25.1 | $ | 25.5 | ||||||
MISO Off-system margin | 5.3 | 4.3 | 6.2 | |||||||||
Total wholesale margin | $ | 30.8 | $ | 29.4 | $ | 31.7 |
• | An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions; |
• | Provisions for enhanced use of renewable energy sources as a supplement to baseload generation including effective energy conservation, demand side management, and generation efficiency measures; |
• | Inclusion of incentives for research and development and investment in advanced clean coal technology; and |
• | A strategy supporting alternative energy technologies and biofuels and continued increase in the domestic supply of natural gas and oil to reduce dependence on foreign oil. |
• | Since 2005 and through 2017, the Company has achieved a reduction in emissions of CO2 of 30 percent (on a tonnage basis) through the retirement of F.B. Culley Unit 1, expiration of municipal contracts, electric conservation, the addition of renewable generation, and the installation of more efficient dense pack turbine technology. The three year average emission reduction for the period 2015 to 2017 is 35 percent from 2005 levels. |
• | Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs. Vectren's annual sustainability report continues to receive Core level certification by the Global Reporting Initiative and demonstrates the Company's commitment to sustainability and transparency in operations. The Company's current sustainability report can be found at www.vectren.com/sustainability; |
• | Implementing home and business energy efficiency initiatives in the Company’s Indiana and Ohio gas utility service territories such as offering rebates on high efficiency furnaces, programmable thermostats, and insulation and duct sealing; |
• | Implementing home and business energy efficiency initiatives in the electric service territory such as rebate programs on central air conditioning units, LED lighting, home weatherization and energy audits; |
• | Building a renewable energy portfolio to complement base load generation in advance of mandated renewable energy portfolio standards; |
• | Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans; |
• | Further reducing the Company’s carbon footprint by building a more sustainable vehicle fleet with lower overall fuel consumption; |
• | Reducing methane emissions through becoming a founding partner in the EPA Natural Gas STAR Methane Challenge Program. The Company's primary method for reducing methane emissions is through continued replacement of bare steel and cast iron gas distribution pipeline assets; |
• | Working with the Company’s gas supply administrator in Indiana to maximize the amount of natural gas delivered to our customers that has been sourced from members of The Environmental Partnership, an organization that includes many of the major oil and gas producers in the U.S and who have committed to continuously improving the industry’s environmental performance; |
• | Developing renewable energy and energy efficiency performance contracting projects through its Energy Services segment; and |
• | Helping energy producers install pipes that allow for more natural gas power generation and reduced gas flaring as well as serving distribution integrity management programs that reduce methane leaks, through its Infrastructure Services segment. |
Year Ended December 31, | ||||||||||||
(In millions, except per share amounts) | 2017 | 2016 | 2015 | |||||||||
NET INCOME | $ | 41.1 | $ | 36.9 | $ | 36.3 | ||||||
CONTRIBUTION TO VECTREN BASIC EPS | $ | 0.49 | $ | 0.44 | $ | 0.44 | ||||||
NET INCOME (LOSS) ATTRIBUTED TO: | ||||||||||||
Infrastructure Services | $ | 32.3 | $ | 25.0 | $ | 29.7 | ||||||
Energy Services | 10.7 | 12.5 | 7.3 | |||||||||
Other Businesses | (1.9 | ) | (0.6 | ) | (0.7 | ) |
Utility Group Borrowings | Nonutility Group Borrowings | |||||||||||||||||||||||
(In millions) | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
As of Year End | ||||||||||||||||||||||||
Balance Outstanding | $ | 179.5 | $ | 194.4 | $ | 14.5 | $ | 70.0 | $ | — | $ | — | ||||||||||||
Weighted Average Interest Rate | 1.92 | % | 1.05 | % | 0.55 | % | 2.68 | % | N/A | N/A | ||||||||||||||
Annual Average | ||||||||||||||||||||||||
Balance Outstanding | $ | 172.4 | $ | 59.8 | $ | 53.8 | $ | 12.2 | $ | 0.2 | $ | 24.8 | ||||||||||||
Weighted Average Interest Rate | 1.30 | % | 0.71 | % | 0.38 | % | 2.44 | % | 1.60 | % | 1.33 | % | ||||||||||||
Maximum Month End Balance Outstanding | $ | 238.7 | $ | 194.4 | $ | 121.5 | $ | 70.0 | $ | 6.3 | $ | 69.1 |
(In millions) | Total | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | |||||||||||||||||||||
Long-term debt (1) | $ | 1,838.7 | $ | 100.0 | $ | 60.0 | $ | 100.0 | $ | 55.0 | $ | 79.6 | $ | 1,444.1 | ||||||||||||||
Short-term debt | 249.5 | 249.5 | — | — | — | — | — | |||||||||||||||||||||
Long-term debt interest commitments | 1,198.1 | 83.1 | 76.3 | 71.0 | 69.1 | 66.6 | 832.0 | |||||||||||||||||||||
Plant, nonutility plant, and other purchase commitments | 51.0 | 25.0 | 7.1 | 5.5 | 5.4 | 4.0 | 4.0 | |||||||||||||||||||||
Operating leases | 40.0 | 14.2 | 10.2 | 4.9 | 2.7 | 2.3 | 5.7 | |||||||||||||||||||||
Total (2) | $ | 3,377.3 | $ | 471.8 | $ | 153.6 | $ | 181.4 | $ | 132.2 | $ | 152.5 | $ | 2,285.8 |
(1) | The debt due in 2018 is comprised of debt issued by Utility Holdings. |
(2) | The Company has other long-term liabilities that total approximately $285 million. This amount is comprised of the following: pension obligations $49 million; postretirement obligations $36 million; deferred compensation and share-based compensation obligations $79 million; asset retirement obligations $107 million; and other obligations including unrecognized tax benefits, and environmental remediation obligations, totaling $14 million. Based on the nature of these items, their expected settlement dates cannot be estimated. |
• | 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. |
• | Factors affecting utility operations such as unfavorable or unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to coal and natural gas costs; unanticipated changes to gas transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints. |
• | New or proposed legislation, litigation and government regulation or other actions, such as changes in, rescission of or additions to tax laws or rates, pipeline safety regulation and environmental laws and regulations, including laws governing air emissions, carbon, waste water discharges and the handling and disposal of coal combustion residuals that could impact the continued operation, and/or cost recovery of generation plant costs and related assets. Compliance with respect to these regulations could substantially change the operation and nature of the Company’s utility operations. |
• | Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornadoes, terrorist acts, physical attacks, cyber attacks, or other similar occurrences could adversely affect the Company's facilities, operations, financial condition, results of operations, and reputation. |
• | Approval and timely recovery of new capital investments related to the electric generation transition plan, discussed further herein, including timely approval to build and own generation, ability to meet capacity requirements, ability to procure resources needed to build new generation at a reasonable cost, ability to appropriately estimate costs of new generation, the effects of construction delays and cost overruns, ability to fully recover the investments made in retiring portions of the current generation fleet, scarcity of resources and labor, and workforce retention, development and training. |
• | Increased competition in the energy industry, including the effects of industry restructuring, unbundling, and other sources of energy. |
• | Regulatory factors such as uncertainty surrounding the composition of state regulatory commissions, adverse regulatory changes, unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under regulation, interpretation of regulatory-related legislation by the IURC and/or PUCO and appellate courts that review decisions issued by the agencies, and the frequency and timing of rate increases. |
• | Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight. |
• | Economic conditions including the effects of inflation, commodity prices, and monetary fluctuations. |
• | Economic conditions, including increased potential for lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas, electricity, and other nonutility products and services; economic impacts of changes in business strategy on both gas and electric large customers; lower residential and commercial customer counts; variance from normal population growth and changes in customer mix; higher operating expenses; and reductions in the value of investments. |
• | Volatile natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense. |
• | Volatile oil prices and the potential impact on customer consumption and price of other fuel commodities. |
• | Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. |
• | The performance of projects undertaken by the Company’s nonutility businesses and the success of efforts to realize value from, invest in and develop new opportunities, including but not limited to, the Company’s Infrastructure Services, Energy Services, and remaining ProLiance Holdings assets. |
• | Factors affecting Infrastructure Services, including the level of success in bidding contracts; fluctuations in volume and mix of contracted work; mix of projects received under blanket contracts; unanticipated cost increases in completion of the contracted work; funding requirements associated with multiemployer pension and benefit plans; changes in legislation and regulations impacting the industries in which the customers served operate; the effects of weather; failure to properly estimate the cost to construct projects; the ability to attract and retain qualified employees in a fast growing market where skills are critical; cancellation and/or reductions in the scope of projects by customers; credit worthiness of customers; ability to obtain materials and equipment required to perform services; and changing market conditions, including changes in the market prices of oil and natural gas that would affect the demand for infrastructure construction. |
• | Factors affecting Energy Services, including unanticipated cost increases in completion of the contracted work; changes in legislation and regulations impacting the industries in which the customers served operate; changes in economic influences impacting customers served; failure to properly estimate the cost to construct projects; risks associated with projects owned or operated; failure to appropriately design, construct, or operate projects; the ability to attract and retain qualified employees; cancellation and/or reductions in the scope of projects by customers; changes in the timing of being awarded projects; credit worthiness of customers; lower energy prices negatively impacting the economics of performance contracting business; and changing market conditions. |
• | Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness. |
• | Risks associated with material business transactions such as acquisitions and divestitures, including, without limitation, legal and regulatory delays; the related time and costs of implementing such transactions; integrating operations as part of these transactions; and possible failures to achieve expected gains, revenue growth and/or expense savings from such transactions. |
• | Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving compliance with federal and state laws and interpretations of these laws. |
At December 31, | ||||||||
2017 | 2016 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash & cash equivalents | $ | 16.6 | $ | 68.6 | ||||
Accounts receivable - less reserves of $5.1 & $6.0, respectively | 262.9 | 225.3 | ||||||
Accrued unbilled revenues | 207.1 | 172.4 | ||||||
Inventories | 126.6 | 129.9 | ||||||
Recoverable fuel & natural gas costs | 19.2 | 29.9 | ||||||
Prepayments & other current assets | 47.0 | 52.7 | ||||||
Total current assets | 679.4 | 678.8 | ||||||
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 | 19.7 | 20.4 | ||||||
Other utility & corporate investments | 43.7 | 34.1 | ||||||
Other nonutility investments | 9.6 | 16.1 | ||||||
Nonutility plant - net | 464.1 | 423.9 | ||||||
Goodwill | 293.5 | 293.5 | ||||||
Regulatory assets | 416.8 | 308.8 | ||||||
Other assets | 35.8 | 42.2 | ||||||
TOTAL ASSETS | $ | 6,239.3 | $ | 5,800.7 |
At December 31, | ||||||||
2017 | 2016 | |||||||
LIABILITIES & SHAREHOLDERS' EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 366.2 | $ | 302.2 | ||||
Accrued liabilities | 222.3 | 207.7 | ||||||
Short-term borrowings | 249.5 | 194.4 | ||||||
Current maturities of long-term debt | 100.0 | 124.1 | ||||||
Total current liabilities | 938.0 | 828.4 | ||||||
Long-term Debt - Net of Current Maturities | 1,738.7 | 1,589.9 | ||||||
Deferred Credits & Other Liabilities | ||||||||
Deferred income taxes | 491.3 | 905.7 | ||||||
Regulatory liabilities | 937.2 | 453.7 | ||||||
Deferred credits & other liabilities | 284.8 | 254.9 | ||||||
Total deferred credits & other liabilities | 1,713.3 | 1,614.3 | ||||||
Commitments & Contingencies (Notes 7, 17-20) | ||||||||
Common Shareholders' Equity | ||||||||
Common stock (no par value) - issued & outstanding 83.0 & 82.9 shares, respectively | 736.9 | 729.8 | ||||||
Retained earnings | 1,113.7 | 1,039.6 | ||||||
Accumulated other comprehensive (loss) | (1.3 | ) | (1.3 | ) | ||||
Total common shareholders' equity | 1,849.3 | 1,768.1 | ||||||
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY | $ | 6,239.3 | $ | 5,800.7 |
Year Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
OPERATING REVENUES | ||||||||||||
Gas utility | $ | 812.7 | $ | 771.7 | $ | 792.6 | ||||||
Electric utility | 569.6 | 605.8 | 601.6 | |||||||||
Nonutility | 1,275.0 | 1,070.8 | 1,040.5 | |||||||||
Total operating revenues | 2,657.3 | 2,448.3 | 2,434.7 | |||||||||
OPERATING EXPENSES | ||||||||||||
Cost of gas sold | 271.5 | 266.7 | 305.4 | |||||||||
Cost of fuel & purchased power | 171.8 | 183.6 | 187.5 | |||||||||
Cost of nonutility revenues | 444.2 | 363.4 | 355.0 | |||||||||
Other operating | 1,115.9 | 932.2 | 909.2 | |||||||||
Depreciation & amortization | 276.2 | 260.0 | 256.3 | |||||||||
Taxes other than income taxes | 59.3 | 60.9 | 59.5 | |||||||||
Total operating expenses | 2,338.9 | 2,066.8 | 2,072.9 | |||||||||
OPERATING INCOME | 318.4 | 381.5 | 361.8 | |||||||||
OTHER INCOME | ||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | (1.1 | ) | (0.2 | ) | (0.6 | ) | ||||||
Other income – net | 32.8 | 28.7 | 20.3 | |||||||||
Total other income | 31.7 | 28.5 | 19.7 | |||||||||
Interest expense | 87.7 | 85.5 | 84.5 | |||||||||
INCOME BEFORE INCOME TAXES | 262.4 | 324.5 | 297.0 | |||||||||
Income taxes | 46.4 | 112.9 | 99.7 | |||||||||
NET INCOME | $ | 216.0 | $ | 211.6 | $ | 197.3 | ||||||
WEIGHTED AVERAGE AND DILUTED COMMON SHARES | ||||||||||||
OUTSTANDING | 83.0 | 82.8 | 82.7 | |||||||||
BASIC AND DILUTED EARNINGS PER SHARE OF COMMON | ||||||||||||
STOCK | $ | 2.60 | $ | 2.55 | $ | 2.39 |
Year Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
NET INCOME | $ | 216.0 | $ | 211.6 | $ | 197.3 | ||||||
Pension & other benefits | ||||||||||||
Amounts arising during the year | (5.6 | ) | (10.1 | ) | 1.2 | |||||||
Reclassifications to periodic cost | 5.4 | 4.7 | 6.9 | |||||||||
Deferrals to regulatory assets | 0.2 | 5.3 | (8.0 | ) | ||||||||
Pension & other benefits costs, net of tax | — | (0.1 | ) | 0.1 | ||||||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | — | (0.1 | ) | 0.1 | ||||||||
TOTAL COMPREHENSIVE INCOME | $ | 216.0 | $ | 211.5 | $ | 197.4 |
Year Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net income | $ | 216.0 | $ | 211.6 | $ | 197.3 | ||||||
Adjustments to reconcile net income to cash from operating activities: | ||||||||||||
Depreciation & amortization | 276.2 | 260.0 | 256.3 | |||||||||
Deferred income taxes & investment tax credits | 19.0 | 100.1 | 80.4 | |||||||||
Provision for uncollectible accounts | 5.9 | 6.9 | 8.1 | |||||||||
Expense portion of pension & postretirement benefit cost | 5.4 | 3.6 | 6.8 | |||||||||
Other non-cash items - net | 12.9 | 7.8 | 7.3 | |||||||||
Changes in working capital accounts: | ||||||||||||
Accounts receivable & accrued unbilled revenues | (80.9 | ) | (39.6 | ) | (15.4 | ) | ||||||
Inventories | 3.3 | 3.9 | (15.2 | ) | ||||||||
Recoverable/refundable fuel & natural gas costs | 10.7 | (37.8 | ) | 15.2 | ||||||||
Prepayments & other current assets | 5.7 | 22.9 | 20.3 | |||||||||
Accounts payable, including to affiliated companies | 65.9 | 40.7 | (0.5 | ) | ||||||||
Accrued liabilities | 15.6 | 22.7 | (0.9 | ) | ||||||||
Employer contributions to pension & postretirement plans | (4.6 | ) | (19.6 | ) | (26.5 | ) | ||||||
Changes in noncurrent assets | (40.6 | ) | (44.0 | ) | (21.9 | ) | ||||||
Changes in noncurrent liabilities | (11.7 | ) | (15.1 | ) | (6.1 | ) | ||||||
Net cash from operating activities | 498.8 | 524.1 | 505.2 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Proceeds from: | ||||||||||||
Long-term debt, net of issuance costs | 198.5 | — | 385.5 | |||||||||
Dividend reinvestment plan & other common stock issuances | 6.3 | 6.3 | 6.2 | |||||||||
Requirements for: | ||||||||||||
Dividends on common stock | (141.9 | ) | (134.2 | ) | (127.3 | ) | ||||||
Retirement of long-term debt | (75.0 | ) | (73.0 | ) | (170.0 | ) | ||||||
Other financing activities | — | — | 0.2 | |||||||||
Net change in short-term borrowings | 55.1 | 179.9 | (141.9 | ) | ||||||||
Net cash from financing activities | 43.0 | (21.0 | ) | (47.3 | ) | |||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Proceeds from sale of assets and other collections | 11.3 | 33.0 | 27.5 | |||||||||
Requirements for: | ||||||||||||
Capital expenditures, excluding AFUDC equity | (602.6 | ) | (542.0 | ) | (476.9 | ) | ||||||
Other costs | (3.4 | ) | (5.2 | ) | (14.3 | ) | ||||||
Changes in restricted cash | 0.9 | 5.0 | (5.9 | ) | ||||||||
Net cash from investing activities | (593.8 | ) | (509.2 | ) | (469.6 | ) | ||||||
Net change in cash & cash equivalents | (52.0 | ) | (6.1 | ) | (11.7 | ) | ||||||
Cash & cash equivalents at beginning of period | 68.6 | 74.7 | 86.4 | |||||||||
Cash & cash equivalents at end of period | $ | 16.6 | $ | 68.6 | $ | 74.7 |
Accumulated | ||||||||||||||||||
Common Stock | Other | |||||||||||||||||
Shares | Amount | Retained Earnings | Comprehensive Income (Loss) | Total | ||||||||||||||
Balance at January 1, 2015 | 82.6 | $ | 715.7 | $ | 892.2 | $ | (1.3 | ) | $ | 1,606.6 | ||||||||
Net income | 197.3 | 197.3 | ||||||||||||||||
Other comprehensive income (loss) | 0.1 | 0.1 | ||||||||||||||||
Common stock: | ||||||||||||||||||
Issuance: option exercises & dividend reinvestment plan | 0.2 | 6.2 | 6.2 | |||||||||||||||
Dividends ($1.540 per share) | (127.3 | ) | (127.3 | ) | ||||||||||||||
Other | 0.9 | 0.9 | ||||||||||||||||
Balance at December 31, 2015 | 82.8 | 722.8 | 962.2 | (1.2 | ) | 1,683.8 | ||||||||||||
Net income | 211.6 | 211.6 | ||||||||||||||||
Other comprehensive income (loss) | (0.1 | ) | (0.1 | ) | ||||||||||||||
Common stock: | ||||||||||||||||||
Issuance: option exercises & dividend reinvestment plan | 0.1 | 6.3 | 6.3 | |||||||||||||||
Dividends ($1.620 per share) | (134.2 | ) | (134.2 | ) | ||||||||||||||
Other | 0.7 | 0.7 | ||||||||||||||||
Balance at December 31, 2016 | 82.9 | 729.8 | 1,039.6 | (1.3 | ) | 1,768.1 | ||||||||||||
Net income | 216.0 | 216.0 | ||||||||||||||||
Other comprehensive income (loss) | — | |||||||||||||||||
Common stock: | ||||||||||||||||||
Issuance: dividend reinvestment plan | 0.1 | 6.3 | 6.3 | |||||||||||||||
Dividends ($1.710 per share) | (141.9 | ) | (141.9 | ) | ||||||||||||||
Other | 0.8 | 0.8 | ||||||||||||||||
Balance at December 31, 2017 | 83.0 | $ | 736.9 | $ | 1,113.7 | $ | (1.3 | ) | $ | 1,849.3 |
Level 1 | Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access. |
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. |
At 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 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Vehicles & equipment | $ | 220.2 | $ | 207.4 | ||||
Computer hardware & software | 156.5 | 121.8 | ||||||
Land & buildings | 77.1 | 77.9 | ||||||
All other | 10.3 | 16.8 | ||||||
Nonutility plant - net | $ | 464.1 | $ | 423.9 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Future amounts recoverable from ratepayers related to: | ||||||||
Benefit obligations (See Note 9) | $ | 102.8 | $ | 102.6 | ||||
Net deferred income taxes (See Note 8) | 6.2 | (17.1 | ) | |||||
Asset retirement obligations & other | 24.3 | — | ||||||
133.3 | 85.5 | |||||||
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 and other | 14.1 | 21.2 | ||||||
141.1 | 131.7 | |||||||
Total regulatory assets | $ | 416.8 | $ | 308.8 |
As of | |||
December 31, | |||
(In millions) | 2017 | ||
Cash | $ | 0.8 | |
Investment in LA Storage | 22.4 | ||
Total investment in ProLiance | $ | 23.2 | |
Included in: | |||
Investments in unconsolidated affiliates | $ | 18.8 | |
Other nonutility investments | $ | 4.4 |
(In millions) | At December 31, | |||||||||||||||
2017 | 2016 | |||||||||||||||
Amortizing | Non-amortizing | Amortizing | Non-amortizing | |||||||||||||
Customer-related assets | $ | 18.6 | $ | — | $ | 20.9 | $ | — | ||||||||
Market-related assets | 6.6 | 6.0 | — | 13.0 | ||||||||||||
Intangible assets, net | $ | 25.2 | $ | 6.0 | $ | 20.9 | $ | 13.0 |
Year Ended December 31, | |||||||||
2017 | 2016 | 2015 | |||||||
Statutory rate: | 35.0 | % | 35.0 | % | 35.0 | % | |||
State & local taxes-net of federal benefit | 3.4 | 2.8 | 3.6 | ||||||
Deferred tax revaluation-tax law change | (17.3 | ) | — | — | |||||
Amortization of investment tax credit | (0.2 | ) | (0.3 | ) | (0.2 | ) | |||
Domestic production deduction | (1.4 | ) | (0.4 | ) | (1.0 | ) | |||
Energy efficiency building deductions | — | (1.7 | ) | (2.3 | ) | ||||
Research and development credit | (0.3 | ) | (0.6 | ) | (1.6 | ) | |||
Other tax credits | (0.1 | ) | (0.1 | ) | (0.1 | ) | |||
All other-net | (1.4 | ) | 0.1 | 0.2 | |||||
Effective tax rate | 17.7 | % | 34.8 | % | 33.6 | % |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Noncurrent deferred tax liabilities (assets): | ||||||||
Depreciation & cost recovery timing differences | $ | 593.7 | $ | 902.4 | ||||
Regulatory assets recoverable through future rates | 7.9 | 17.6 | ||||||
Alternative minimum tax carryforward | (12.2 | ) | (29.3 | ) | ||||
Employee benefit obligations | (9.3 | ) | (8.1 | ) | ||||
Net operating loss & other carryforwards (net of valuation allowances) | (4.1 | ) | (3.2 | ) | ||||
U.S. federal charitable contributions carryforwards | (12.2 | ) | — | |||||
Regulatory liabilities to be settled through future rates | (116.2 | ) | (15.9 | ) | ||||
Impairments | (0.6 | ) | (2.5 | ) | ||||
Deferred fuel costs-net | 16.2 | 25.9 | ||||||
Other-net | 28.1 | 18.8 | ||||||
Net noncurrent deferred tax liability | $ | 491.3 | $ | 905.7 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Current: | ||||||||||||
Federal | $ | 20.5 | $ | 6.8 | $ | 10.8 | ||||||
State | 6.9 | 6.0 | 8.5 | |||||||||
Total current taxes | 27.4 | 12.8 | 19.3 | |||||||||
Deferred: | ||||||||||||
Federal | 16.7 | 97.6 | 79.0 | |||||||||
State | 2.7 | 3.6 | 2.0 | |||||||||
Total deferred taxes | 19.4 | 101.2 | 81.0 | |||||||||
Amortization of investment tax credits | (0.4 | ) | (1.1 | ) | (0.6 | ) | ||||||
Total income tax expense | $ | 46.4 | $ | 112.9 | $ | 99.7 |
Pension Benefits | Other Benefits | |||||||||||||||||||||||
(In millions) | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
Service cost | $ | 6.5 | $ | 7.0 | $ | 7.9 | $ | 0.2 | $ | 0.3 | $ | 0.4 | ||||||||||||
Interest cost | 13.7 | 14.7 | 14.6 | 1.5 | 1.7 | 2.0 | ||||||||||||||||||
Expected return on plan assets | (21.0 | ) | (22.8 | ) | (22.5 | ) | — | — | — | |||||||||||||||
Amortization of prior service cost (benefit) | 0.4 | 0.4 | 0.7 | (2.4 | ) | (2.9 | ) | (3.0 | ) | |||||||||||||||
Amortization of actuarial loss | 7.4 | 7.2 | 8.5 | — | — | 0.7 | ||||||||||||||||||
Settlement charge | 2.1 | — | 0.6 | — | — | — | ||||||||||||||||||
Net periodic benefit cost (benefit) | $ | 9.1 | $ | 6.5 | $ | 9.8 | $ | (0.7 | ) | $ | (0.9 | ) | $ | 0.1 |
Pension Benefits | Other Benefits | |||||||||||||||||
2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||
Discount rate | 4.07 | % | 4.31 | % | 4.05 | % | 4.04 | % | 4.21 | % | 3.95 | % | ||||||
Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | N/A | N/A | N/A | |||||||||
Expected return on plan assets | 7.00 | % | 7.50 | % | 7.50 | % | N/A | N/A | N/A | |||||||||
Expected increase in Consumer Price Index | N/A | N/A | N/A | 2.50 | % | 2.50 | % | 2.50 | % |
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Projected benefit obligation, beginning of period | $ | 350.4 | $ | 348.3 | $ | 40.5 | $ | 43.5 | ||||||||
Service cost – benefits earned during the period | 6.5 | 7.0 | 0.2 | 0.3 | ||||||||||||
Interest cost on projected benefit obligation | 13.7 | 14.7 | 1.5 | 1.7 | ||||||||||||
Plan participants' contributions | — | — | 1.2 | 1.1 | ||||||||||||
Plan amendments | 1.4 | — | — | — | ||||||||||||
Actuarial loss (gain) | 25.4 | 8.7 | 1.3 | (1.6 | ) | |||||||||||
Settlement loss | 0.5 | — | — | — | ||||||||||||
Benefit payments | (31.4 | ) | (28.3 | ) | (4.7 | ) | (4.5 | ) | ||||||||
Projected benefit obligation, end of period | $ | 366.5 | $ | 350.4 | $ | 40.0 | $ | 40.5 |
Pension Benefits | Other Benefits | |||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||
Discount rate | 3.61 | % | 4.07 | % | 3.57 | % | 4.04 | % | ||||
Rate of compensation increase | 3.50 | % | 3.50 | % | N/A | N/A | ||||||
Expected increase in Consumer Price Index | N/A | N/A | 2.50 | % | 2.50 | % |
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Plan assets at fair value, beginning of period | $ | 304.5 | $ | 296.9 | $ | — | $ | — | ||||||||
Actual return on plan assets | 41.9 | 19.7 | — | — | ||||||||||||
Employer contributions | 1.1 | 16.2 | 3.5 | 3.4 | ||||||||||||
Plan participants' contributions | — | — | 1.2 | 1.1 | ||||||||||||
Benefit payments | (31.4 | ) | (28.3 | ) | (4.7 | ) | (4.5 | ) | ||||||||
Fair value of plan assets, end of period | $ | 316.1 | $ | 304.5 | $ | — | $ | — |
As of December 31, 2017 | ||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Domestic equity funds | $ | 140.2 | $ | — | $ | — | $ | 140.2 | ||||||||
International equity funds | 46.8 | — | — | 46.8 | ||||||||||||
Bond funds | 43.6 | — | — | 43.6 | ||||||||||||
Real estate, commodity & other funds | 6.2 | — | 4.5 | 10.7 | ||||||||||||
Investments measured at net asset value (a) | — | — | — | 74.8 | ||||||||||||
Total plan investments | $ | 236.8 | $ | — | $ | 4.5 | $ | 316.1 |
As of December 31, 2016 | ||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Domestic equity funds | $ | 135.1 | $ | — | $ | — | $ | 135.1 | ||||||||
International equity funds | 42.0 | — | — | 42.0 | ||||||||||||
Bond funds | 44.6 | — | — | 44.6 | ||||||||||||
Real estate, commodity & other funds | 6.0 | — | 4.4 | 10.4 | ||||||||||||
Investments measured at net asset value (a) | — | — | — | 72.4 | ||||||||||||
Total plan investments | $ | 227.7 | $ | — | $ | 4.4 | $ | 304.5 |
(In millions) | 2017 | 2016 | ||||||
Fair value, beginning of year | $ | 4.4 | $ | 4.3 | ||||
Unrealized gains related to investments still held at reporting date | 0.2 | 0.2 | ||||||
Purchases, sales & settlements, net | (0.1 | ) | (0.1 | ) | ||||
Fair value, end of year | $ | 4.5 | $ | 4.4 |
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Qualified Plans | ||||||||||||||||
Projected benefit obligation, end of period | $ | (343.4 | ) | $ | (329.7 | ) | $ | (40.0 | ) | $ | (40.5 | ) | ||||
Fair value of plan assets, end of period | 316.1 | 304.5 | — | — | ||||||||||||
Funded Status of Qualified Plans, end of period | (27.3 | ) | (25.2 | ) | (40.0 | ) | (40.5 | ) | ||||||||
Projected benefit obligation of SERP Plan, end of period | (22.9 | ) | (20.6 | ) | — | — | ||||||||||
Total funded status, end of period | $ | (50.2 | ) | $ | (45.8 | ) | $ | (40.0 | ) | $ | (40.5 | ) | ||||
Accrued liabilities | $ | 1.1 | $ | 1.2 | $ | 4.1 | $ | 4.5 | ||||||||
Deferred credits & other liabilities | $ | 49.1 | $ | 44.6 | $ | 35.9 | $ | 36.0 |
Pensions | Other Benefits | ||||||||||||||||
(In millions) | Prior Service Cost | Net (Gain) or Loss | Prior Service Cost | Net (Gain) or Loss | |||||||||||||
Balance at January 1, 2015 | $ | 2.0 | $ | 111.7 | $ | (17.1 | ) | $ | 10.9 | ||||||||
Amounts arising during the period | 0.5 | 6.9 | — | (8.6 | ) | ||||||||||||
Reclassification to benefit costs | (0.7 | ) | (8.5 | ) | 3.0 | (0.7 | ) | ||||||||||
Balance at December 31, 2015 | $ | 1.8 | $ | 110.1 | $ | (14.1 | ) | $ | 1.6 | ||||||||
Amounts arising during the period | — | 11.7 | — | (1.6 | ) | ||||||||||||
Reclassification to benefit costs | (0.4 | ) | (7.2 | ) | 2.9 | — | |||||||||||
Balance at December 31, 2016 | $ | 1.4 | $ | 114.6 | $ | (11.2 | ) | $ | — | ||||||||
Amounts arising during the period | 1.3 | 3.1 | — | 1.2 | |||||||||||||
Reclassification to benefit costs | (0.4 | ) | (7.4 | ) | 2.4 | — | |||||||||||
Balance at December 31, 2017 | $ | 2.3 | $ | 110.3 | $ | (8.8 | ) | $ | 1.2 |
(In millions) | 2017 | 2016 | ||||||||||||||
Pensions | Other Benefits | Pensions | Other Benefits | |||||||||||||
Prior service cost | $ | 2.3 | $ | (8.8 | ) | $ | 1.4 | $ | (11.2 | ) | ||||||
Unamortized actuarial loss | 110.3 | 1.2 | 114.6 | — | ||||||||||||
112.6 | (7.6 | ) | 116.0 | (11.2 | ) | |||||||||||
Less: Regulatory asset deferral | (110.2 | ) | 7.4 | (113.6 | ) | 11.0 | ||||||||||
AOCI before taxes | $ | 2.4 | $ | (0.2 | ) | $ | 2.4 | $ | (0.2 | ) |
(In millions) | ||||||||||||||||
Pension Protection Act Zone Status | Multiemployer Contributions | |||||||||||||||
Pension Fund | EIN/Pension Plan Number | 2017 | 2016 | FIP/RP Status Pending/Implemented | 2017 | 2016 | 2015 | Surcharge Imposed | ||||||||
Central Pension Fund | 36-6052390-001 | Green | Green | No | $9.3 | $7.4 | $7.2 | No | ||||||||
Indiana Laborers Pension Fund (1) | 35-6027150-001 | Yellow | Yellow | Implemented | 5.0 | 4.4 | 4.1 | No | ||||||||
Pipeline Industry Benefit Fund | 73-6146433-001 | Green | Green | No | 4.9 | 3.0 | 4.0 | No | ||||||||
Laborers District Fund of Ohio | 31-6129964-001 | Green | Green | No | 3.3 | 2.0 | 1.5 | No | ||||||||
Ohio Operating Engineers Pension Fund | 31-6129968-001 | Green | Green | No | 2.8 | 2.1 | 2.2 | No | ||||||||
Operating Eng. Local 324 Fund (2) | 38-1900637-001 | Red | Yellow | Implemented | 2.5 | 1.6 | 1.6 | No | ||||||||
Other | 14.3 | 14.5 | 12.1 | |||||||||||||
Total Contributions | $42.1 | $35.0 | $32.7 |
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 | ||||||
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 | ||||||
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 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Vectren Capital Corp. | ||||||||
Fixed Rate Senior Unsecured Notes | ||||||||
2017, 3.48% | — | 75.0 | ||||||
2019, 7.30% | 60.0 | 60.0 | ||||||
2022, 3.33% | 75.0 | 75.0 | ||||||
2025, 4.53% | 50.0 | 50.0 | ||||||
2030, 3.90% | 75.0 | 75.0 | ||||||
Total Vectren Capital Corp. | 260.0 | 335.0 | ||||||
Total long-term debt outstanding | 1,848.7 | 1,723.7 | ||||||
Current maturities of long-term debt | (100.0 | ) | (124.1 | ) | ||||
Debt issuance costs | (9.4 | ) | (9.0 | ) | ||||
Unamortized debt premium & discount-net | (0.6 | ) | (0.7 | ) | ||||
Total long-term debt-net | $ | 1,738.7 | $ | 1,589.9 |
• | 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. |
Utility Group Borrowings | Nonutility Group Borrowings | |||||||||||||||||||||||
(In millions) | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
As of Year End | ||||||||||||||||||||||||
Balance Outstanding | $ | 179.5 | $ | 194.4 | $ | 14.5 | $ | 70.0 | $ | — | $ | — | ||||||||||||
Weighted Average Interest Rate | 1.92 | % | 1.05 | % | 0.55 | % | 2.68 | % | N/A | N/A | ||||||||||||||
Annual Average | ||||||||||||||||||||||||
Balance Outstanding | $ | 172.4 | $ | 59.8 | $ | 53.8 | $ | 12.2 | $ | 0.2 | $ | 24.8 | ||||||||||||
Weighted Average Interest Rate | 1.30 | % | 0.71 | % | 0.38 | % | 2.44 | % | 1.60 | % | 1.33 | % | ||||||||||||
Maximum Month End Balance Outstanding | $ | 238.7 | $ | 194.4 | $ | 121.5 | $ | 70.0 | $ | 6.3 | $ | 69.1 |
Year Ended December 31, | ||||||||||||
(In millions, except per share data) | 2017 | 2016 | 2015 | |||||||||
Numerator: | ||||||||||||
Reported net income (Numerator for Basic and Diluted EPS) | $ | 216.0 | $ | 211.6 | $ | 197.3 | ||||||
Denominator: | ||||||||||||
Weighted-average common shares outstanding (Basic and Diluted EPS) | 83.0 | 82.8 | 82.7 | |||||||||
Basic and diluted earnings per share | $ | 2.60 | $ | 2.55 | $ | 2.39 |
2015 | 2016 | 2017 | ||||||||||||||||||||||||||
Beginning of Year | Changes During | End of Year | Changes During | End of Year | Changes During | End of Year | ||||||||||||||||||||||
(In millions) | Balance | Year | Balance | Year | Balance | Year | Balance | |||||||||||||||||||||
Pension & other benefit costs | (2.2 | ) | 0.1 | (2.1 | ) | (0.1 | ) | (2.2 | ) | — | (2.2 | ) | ||||||||||||||||
Deferred income taxes | 0.9 | — | 0.9 | — | 0.9 | — | 0.9 | |||||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (1.3 | ) | $ | 0.1 | $ | (1.2 | ) | $ | (0.1 | ) | $ | (1.3 | ) | $ | — | $ | (1.3 | ) |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Total cost of share-based compensation | $ | 40.2 | $ | 30.0 | $ | 19.4 | ||||||
Less capitalized cost | 8.6 | 7.0 | 4.8 | |||||||||
Total in other operating expense | 31.6 | 23.0 | 14.6 | |||||||||
Less income tax benefit in earnings | 12.3 | 9.0 | 5.7 | |||||||||
After tax effect of share-based compensation | $ | 19.3 | $ | 14.0 | $ | 8.9 |
Equity Awards | ||||||||||||||
Wtd. Avg. | ||||||||||||||
Grant Date | Liability Awards | |||||||||||||
Units | Fair value | Units | Fair value | |||||||||||
Awards at January 1, 2016 | 15,373 | $ | 31.63 | 646,487 | ||||||||||
Granted | 4,052 | 30.19 | 448,176 | |||||||||||
Vested | (11,711 | ) | 30.19 | (462,203 | ) | |||||||||
Forfeited | (1,382 | ) | 31.87 | (20,880 | ) | |||||||||
Awards at December 31, 2016 | 6,332 | $ | 33.42 | 611,580 | $ | 52.15 | ||||||||
Granted | 1,779 | 36.29 | 385,776 | |||||||||||
Vested | (7,648 | ) | 33.25 | (395,452 | ) | |||||||||
Forfeited | — | — | (8,364 | ) | ||||||||||
Awards at December 31, 2017 | 463 | $ | 46.21 | 593,540 | $ | 65.02 |
At December 31, | ||||||||||||||||
2017 | 2016 | |||||||||||||||
(In millions) | Carrying Amount | Est. Fair Value | Carrying Amount | Est. Fair Value | ||||||||||||
Long-term debt | $ | 1,838.7 | $ | 1,981.2 | $ | 1,714.0 | $ | 1,835.8 | ||||||||
Short-term borrowings & notes payable | 249.5 | 249.5 | 194.4 | 194.4 | ||||||||||||
Cash & cash equivalents | 16.6 | 16.6 | 68.6 | 68.6 | ||||||||||||
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 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Revenues | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 1,382.6 | 1,377.8 | 1,394.5 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 996.1 | 813.3 | 843.3 | |||||||||
Energy Services | 281.8 | 260.0 | 199.9 | |||||||||
Total Nonutility Group | 1,277.9 | 1,073.3 | 1,043.2 | |||||||||
Eliminations, net of Corporate & Other Revenues | (3.2 | ) | (2.8 | ) | (3.0 | ) | ||||||
Consolidated Revenues | $ | 2,657.3 | $ | 2,448.3 | $ | 2,434.7 | ||||||
Profitability Measures - Net Income | ||||||||||||
Utility Group 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 Utility Group Net Income | 175.8 | 173.6 | 160.9 | |||||||||
Nonutility Group Net Income (Loss) | ||||||||||||
Infrastructure Services | 32.3 | 25.0 | 29.7 | |||||||||
Energy Services | 10.7 | 12.5 | 7.3 | |||||||||
Other Businesses | (1.9 | ) | (0.6 | ) | (0.7 | ) | ||||||
Total Nonutility Group Net Income | 41.1 | 36.9 | 36.3 | |||||||||
Corporate & Other Net Income | (0.9 | ) | 1.1 | 0.1 | ||||||||
Consolidated Net Income | $ | 216.0 | $ | 211.6 | $ | 197.3 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Amounts Included in Profitability Measures | ||||||||||||
Depreciation & Amortization | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 234.5 | 219.1 | 208.8 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 39.7 | 38.2 | 44.5 | |||||||||
Energy Services | 1.9 | 2.5 | 2.7 | |||||||||
Other Businesses | 0.1 | 0.2 | 0.3 | |||||||||
Total Nonutility Group | 41.7 | 40.9 | 47.5 | |||||||||
Consolidated Depreciation & Amortization | $ | 276.2 | $ | 260.0 | $ | 256.3 | ||||||
Interest Expense | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 72.6 | 69.7 | 66.3 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 13.8 | 12.8 | 16.0 | |||||||||
Energy Services | 0.6 | 1.9 | 1.2 | |||||||||
Other Businesses | 1.0 | 0.9 | 1.2 | |||||||||
Total Nonutility Group | 15.4 | 15.6 | 18.4 | |||||||||
Corporate & Other | (0.3 | ) | 0.2 | (0.2 | ) | |||||||
Consolidated Interest Expense | $ | 87.7 | $ | 85.5 | $ | 84.5 | ||||||
Income Taxes | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 60.7 | 99.5 | 88.1 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | (12.9 | ) | 17.9 | 19.6 | ||||||||
Energy Services | (1.5 | ) | (3.5 | ) | (7.7 | ) | ||||||
Other Businesses | 0.9 | 0.3 | 1.5 | |||||||||
Total Nonutility Group | (13.5 | ) | 14.7 | 13.4 | ||||||||
Corporate & Other | (0.8 | ) | (1.3 | ) | (1.8 | ) | ||||||
Consolidated Income Taxes | $ | 46.4 | $ | 112.9 | $ | 99.7 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Capital Expenditures | ||||||||||||
Utility Group | ||||||||||||
Gas Utility Services | $ | 391.4 | $ | 358.5 | $ | 291.2 | ||||||
Electric Utility Services | 105.3 | 106.4 | 87.6 | |||||||||
Other Operations | 57.9 | 39.0 | 25.7 | |||||||||
Non-cash costs & changes in accruals | (3.7 | ) | (7.1 | ) | (6.2 | ) | ||||||
Total Utility Group | 550.9 | 496.8 | 398.3 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 48.4 | 43.2 | 78.1 | |||||||||
Energy Services | 3.2 | 1.8 | 0.5 | |||||||||
Other Businesses, net of eliminations | 0.1 | 0.2 | — | |||||||||
Total Nonutility Group | 51.7 | 45.2 | 78.6 | |||||||||
Consolidated Capital Expenditures | $ | 602.6 | $ | 542.0 | $ | 476.9 | ||||||
At December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Assets | ||||||||||||
Utility Group | ||||||||||||
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 | 220.1 | 161.5 | 107.5 | |||||||||
Total Utility Group | 5,498.2 | 5,040.9 | 4,592.7 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 552.6 | 513.9 | 554.5 | |||||||||
Energy Services | 155.8 | 182.7 | 160.3 | |||||||||
Other Businesses, net of eliminations and reclassifications | 59.1 | 53.3 | 64.0 | |||||||||
Total Nonutility Group | 767.5 | 749.9 | 778.8 | |||||||||
Corporate & Other | 449.1 | 628.4 | 742.4 | |||||||||
Eliminations | (475.5 | ) | (618.5 | ) | (713.9 | ) | ||||||
Consolidated Assets | $ | 6,239.3 | $ | 5,800.7 | $ | 5,400.0 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Gas in storage – at LIFO cost | $ | 36.0 | $ | 37.0 | ||||
Coal & oil for electric generation - at average cost | 43.1 | 42.6 | ||||||
Materials & supplies | 46.2 | 48.9 | ||||||
Other | 1.3 | 1.4 | ||||||
Total inventories | $ | 126.6 | $ | 129.9 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Prepaid gas delivery service | $ | 26.6 | $ | 26.4 | ||||
Prepaid taxes | 3.8 | 8.2 | ||||||
Other prepayments & current assets | 16.6 | 18.1 | ||||||
Total prepayments & other current assets | $ | 47.0 | $ | 52.7 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
ProLiance Holdings, LLC | $ | 18.9 | $ | 19.2 | ||||
Other nonutility partnerships & corporations | 0.6 | 1.0 | ||||||
Other utility investments | 0.2 | 0.2 | ||||||
Total investments in unconsolidated affiliates | $ | 19.7 | $ | 20.4 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Cash surrender value of life insurance policies | $ | 42.2 | $ | 33.1 | ||||
Restricted cash & other investments | 1.5 | 1.0 | ||||||
Total other utility & corporate investments | $ | 43.7 | $ | 34.1 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Utility Group | ||||||||
Gas Utility Services | $ | 205.0 | $ | 205.0 | ||||
Nonutility Group | ||||||||
Infrastructure Services | 58.8 | 58.8 | ||||||
Energy Services | 29.7 | 29.7 | ||||||
Consolidated goodwill | $ | 293.5 | $ | 293.5 |
At December 31, | ||||||||
(In millions) | 2017 | 2016 | ||||||
Refunds to customers & customer deposits | $ | 51.4 | $ | 49.4 | ||||
Accrued taxes | 55.7 | 46.5 | ||||||
Accrued interest | 19.6 | 18.2 | ||||||
Deferred compensation & post retirement benefits | 6.4 | 6.6 | ||||||
Accrued salaries & other | 89.2 | 87.0 | ||||||
Total accrued liabilities | $ | 222.3 | $ | 207.7 |
(In millions) | 2017 | 2016 | ||||||
Asset retirement obligation, January 1 | $ | 106.7 | $ | 82.0 | ||||
Accretion | 4.3 | 3.8 | ||||||
Changes in estimates, net of cash payments | (4.0 | ) | 20.9 | |||||
Asset retirement obligation, December 31 | 107.0 | 106.7 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
ProLiance Holdings, LLC | $ | (0.3 | ) | $ | (0.5 | ) | $ | (0.8 | ) | |||
Other | (0.8 | ) | 0.3 | 0.2 | ||||||||
Total equity in earnings (losses) of unconsolidated affiliates | $ | (1.1 | ) | $ | (0.2 | ) | $ | (0.6 | ) |
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, net | 1.0 | 1.3 | 1.3 | |||||||||
Other nonutility investment impairment charges | — | — | (0.1 | ) | ||||||||
All other income | 3.2 | 3.9 | (0.2 | ) | ||||||||
Total other income – net | $ | 32.8 | $ | 28.7 | $ | 20.3 |
Year Ended December 31, | ||||||||||||
(In millions) | 2017 | 2016 | 2015 | |||||||||
Cash paid (received) for: | ||||||||||||
Interest | $ | 86.4 | $ | 86.6 | $ | 84.2 | ||||||
Income taxes | 9.6 | (3.6 | ) | 4.8 |
(In millions, except per share amounts) | Q1 | Q2 | Q3 | Q4 | ||||||||||||||
2017 | ||||||||||||||||||
Operating revenues | $ | 624.5 | $ | 630.7 | $ | 691.2 | $ | 711.0 | ||||||||||
Operating income | 101.4 | 72.8 | 107.5 | 36.8 | ||||||||||||||
Net income | 55.4 | 37.6 | 61.9 | 61.2 | ||||||||||||||
Earnings per share: | ||||||||||||||||||
Basic and Diluted | $ | 0.67 | $ | 0.45 | $ | 0.75 | $ | 0.74 | ||||||||||
2016 | ||||||||||||||||||
Operating revenues | $ | 584.8 | $ | 533.7 | $ | 631.0 | $ | 699.0 | ||||||||||
Operating income | 92.2 | 63.9 | 105.5 | 120.7 | ||||||||||||||
Net income | 48.3 | 32.3 | 61.4 | 69.6 | ||||||||||||||
Earnings per share: | ||||||||||||||||||
Basic and Diluted | $ | 0.58 | $ | 0.39 | $ | 0.74 | $ | 0.84 |
A | B | C | ||||||||||||||||||
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||||||||||||
Equity compensation plans approved by | ||||||||||||||||||||
security holders | — | $ | — | 3,257,946 | (1) | |||||||||||||||
Equity compensation plans not approved | ||||||||||||||||||||
by security holders | — | — | — | |||||||||||||||||
Total | — | $ | — | 3,257,946 |
(1) | After December 31, 2017, and as of February 23, 2018, the following share-based units were issued under the Plan: 144,200 to named and non-named executive officers of the Company, and 15,820 to members of the Board of Directors. Based upon the performance measure of the 2015 grant, as approved by the Compensation and Benefits Committee of the Board of Directors on February 23, 2018, 90,116 share-based units were issued to named and non-named executive officers, including former retirees whose 2015 grants also remained subject to performance. |
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 | $ | 6.0 | $ | 5.9 | $ | — | $ | 6.8 | $ | 5.1 | ||||||||||
Year 2016 – Accumulated provision for | ||||||||||||||||||||
uncollectible accounts | $ | 5.6 | $ | 6.9 | $ | — | $ | 6.5 | $ | 6.0 | ||||||||||
Year 2015 – Accumulated provision for | ||||||||||||||||||||
uncollectible accounts | $ | 6.0 | $ | 8.1 | $ | — | $ | 8.5 | $ | 5.6 | ||||||||||
Year 2017 – Reserve for impaired | ||||||||||||||||||||
notes receivable | $ | 0.6 | $ | 0.4 | $ | — | $ | — | $ | 1.0 | ||||||||||
Year 2016 – Reserve for impaired | ||||||||||||||||||||
notes receivable | $ | 0.2 | $ | 0.4 | $ | — | $ | — | $ | 0.6 | ||||||||||
Year 2015 – Reserve for impaired | ||||||||||||||||||||
notes receivable | $ | — | $ | 0.2 | $ | — | $ | — | $ | 0.2 |
Exhibit Number | Document |
21.1 | List of Company’s Significant Subsidiaries |
23.1 | Consent of Independent Registered Public Accounting Firm |
31.1 | Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32 | Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
101.INS | XBRL Instance Document |
101.SCH | XBRL Taxonomy Extension Schema |
101.CAL | XBRL Taxonomy Calculation Linkbase |
101.DEF | XBRL Taxonomy Extension Definition Linkbase |
101.LAB | XBRL Taxonomy Extension Labels Linkbase |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase |
3.1 | Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000. (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.) |
4.1 | Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993, File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).) March 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.) April 1, 2005 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.1) March 1, 2006 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.2) December 1, 2007 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.3) August 1, 2009 (Filed and designated in Form 10-K, for the year ended December 31, 2009, File No. 1-15467, as Exhibit 4.1) April 1, 2013 (filed and designated in Form 8-K, dated April 30, 2013, File No. 1-15467, as Exhibit 4.1) September 1, 2014 (filed and designated in Form 8-K dated September 25, 2014 File No. 1-15467, as Exhibit 4.1) September 1, 2015 (filed and designated in Form 8-K dated September 10, 2015 File No. 1-15467, as Exhibit 4.1) |
4.2 | Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly known as First Trust National Association, which was formerly known as Bank of America Illinois, which was formerly known as Continental Bank, National Association. Inc.'s. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.); First Supplemental Indenture thereto dated as of February 15, 1991. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto dated as of September 15, 1991, (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto dated as of September 15, 1991 (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto dated as of December 2, 1992, (Filed and designated in Current Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000, (Filed and designated in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494, as Exhibit 4.) |
4.9 | |
4.10 | |
4.11 | |
4.12 |
10.5 | |
10.6 |
10.16 | |
10.17 | |
10.18 | |
10.19 | |
10.20 |
Signature | Title | Date | ||
/s/ Carl L. Chapman | Chairman, President, and Chief Executive Officer | February 21, 2018 | ||
Carl L. Chapman | (Principal Executive Officer) | |||
/s/ M. Susan Hardwick | Executive Vice President and Chief Financial Officer | February 21, 2018 | ||
M. Susan Hardwick | (Principal Accounting and Financial Officer) | |||
/s/ Derrick Burks | Director | February 21, 2018 | ||
Derrick Burks | ||||
/s/ James H. DeGraffenreidt, Jr. | Director | February 21, 2018 | ||
James H. DeGraffenreidt, Jr. | ||||
/s/ John D. Engelbrecht | Director | February 21, 2018 | ||
John D. Engelbrecht | ||||
/s/ Anton H. George | Director | February 21, 2018 | ||
Anton H. George | ||||
/s/ Robert G. Jones | Director | February 21, 2018 | ||
Robert G. Jones | ||||
/s/ Patrick K. Mullen | Director | February 21, 2018 | ||
Patrick K. Mullen | ||||
/s/ R. Daniel Sadlier | Director | February 21, 2018 | ||
R. Daniel Sadlier | ||||
/s/ Michael L. Smith | Director | February 21, 2018 | ||
Michael L. Smith | ||||
/s/ Teresa J. Tanner | Director | February 21, 2018 | ||
Teresa J. Tanner | ||||
/s/ Jean L. Wojtowicz | Director | February 21, 2018 | ||
Jean L. Wojtowicz |
Name of Entity | State of Incorporation/ Jurisdiction | Doing Business As | ||
Vectren Utility Holdings, Inc. | Indiana | |||
Southern Indiana Gas and Electric Company | Indiana | Vectren Energy Delivery of Indiana, Inc. | ||
Indiana Gas Company, Inc. | Indiana | Vectren Energy Delivery of Indiana, Inc. | ||
Vectren Energy Delivery of Ohio, Inc. | Ohio | |||
Vectren Capital, Corp. | Indiana | |||
Vectren Enterprises, Inc. | Indiana | |||
Vectren Energy Marketing and Services, Inc. | Indiana | |||
Vectren Energy Services Corporation | Indiana | |||
Energy Systems Group, LLC | Indiana | |||
Vectren Utility Services, Inc. | Indiana | |||
Vectren Infrastructure Services Corporation | Indiana | |||
Miller Pipeline, LLC | Indiana | |||
Minnesota Limited, LLC | Minnesota | |||
Vectren Financial Group, Inc. | Indiana | |||
Southern Indiana Properties, Inc. | Indiana | |||
Energy Realty, Inc. | Indiana | |||
Vectren Ventures, Inc. | Indiana | |||
Vectren Affiliated Utilities, Inc. | Indiana | |||
Vectren Coal Mining, Inc. | Indiana | |||
Vectren Solutions, Inc. | Indiana |
Name of Entity | State of Incorporation/ Jurisdiction | Doing Business As | ||
ProLiance Holdings, LLC | Indiana |
1. | I have reviewed this Annual Report on Form 10-K of Vectren Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
/s/ Carl L. Chapman |
Carl L. Chapman |
Chairman, President, and Chief Executive Officer |
1. | I have reviewed this Annual Report on Form 10-K of Vectren Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
/s/ M. Susan Hardwick |
M. Susan Hardwick |
Executive Vice President and Chief Financial Officer |
/s/ M. Susan Hardwick | /s/ Carl L. Chapman | |
(Signature of Authorized Officer) | (Signature of Authorized Officer) | |
M. Susan Hardwick | Carl L. Chapman | |
(Typed Name) | (Typed Name) | |
Executive Vice President and Chief Financial Officer | Chairman, President, and Chief Executive Officer | |
(Title) | (Title) |
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Document And Entity Information - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Jan. 31, 2018 |
Jun. 30, 2017 |
|
Document and Entity Information [Abstract] | |||
Entity Registrant Name | VECTREN CORP | ||
Entity Central Index Key | 0001096385 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 83,040,212 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 4,842,190,088 |
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Current Assets | ||
Reserves | $ 5.1 | $ 6.0 |
Common Shareholders' Equity | ||
Common stock, shares issued (in shares) | 83.0 | 82.9 |
Common stock shares outstanding (in shares) | 83.0 | 82.9 |
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Statement of Comprehensive Income [Abstract] | |||
NET INCOME | $ 216.0 | $ 211.6 | $ 197.3 |
Pension & other benefits | |||
Amounts arising during the year | (5.6) | (10.1) | 1.2 |
Reclassifications to periodic cost | 5.4 | 4.7 | 6.9 |
Deferrals to regulatory assets | 0.2 | 5.3 | (8.0) |
Pension & other benefits costs, net of tax | 0.0 | (0.1) | 0.1 |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | 0.0 | (0.1) | 0.1 |
TOTAL COMPREHENSIVE INCOME | $ 216.0 | $ 211.5 | $ 197.4 |
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Statement of Stockholders' Equity [Abstract] | |||
Dividends (in dollars per share) | $ 1.710 | $ 1.620 | $ 1.54 |
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 Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings or VUHI), serves as the intermediate holding company for three 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). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005. Vectren was incorporated under the laws of Indiana on June 10, 1999. 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. The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. Enterprises also has other legacy businesses that have investments in energy-related opportunities and services and other investments. All of the above is collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services. |
Summary of Significant Accounting Policies |
12 Months Ended | ||||||||||
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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 pension and postretirement benefit obligations, 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. The Infrastructure Services segment, through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provides underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. In accordance with consolidation guidance under ASC 980, fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services, are appropriately not eliminated in consolidation. 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 are 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 that 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 that 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. Investments in Unconsolidated Affiliates Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in earnings (losses) of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other income – net when received. Investments are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an investment's fair value to its carrying value. Investments, when necessary, include adjustments for declines in value judged to be other than temporary. 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 that are 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. Postretirement Obligations & Costs The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income. The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment. 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. Product Warranties, Performance Guarantees & Other Guarantees Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations. While not significant for the periods presented, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances. These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party. 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, certain 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 include most of the Company's executed energy 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, derivative activity is not material to these financial statements. Income Taxes As discussed in Note 8 in the Company’s Consolidated Financial Statements included in Item 8, on December 22, 2017, comprehensive federal tax legislation was enacted, referred to as the Tax Cuts and Jobs Act (“TCJA”). 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, to the extent considered in ratemaking, 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. Revenues Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. 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 that of 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. Share-Based Compensation The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on an expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. 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 has three operating segments within its Utility Group, three operating segments in its Nonutility Group, and a Corporate and Other segment. Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. 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:
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. |
Utility & Nonutility Plant |
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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:
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:
Nonutility Plant is presented net of accumulated depreciation and amortization of $506.9 million and $460.8 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. In 2016, the estimated depreciable lives for certain pieces of equipment at Minnesota Limited, LLC were reevaluated and extended due to a change in service life of the equipment. As a result of this evaluation, the Company extended the estimated useful life of certain pieces of equipment effective January 1, 2016. The effect of this change in estimate was a reduction of annual depreciation expense of approximately $9.6 million. |
Regulatory Assets & Liabilities |
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Regulatory Assets and Liabilities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets & Liabilities | Regulatory Assets & Liabilities Regulatory Assets Regulatory assets consist of the following:
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 that future recovery is probable. Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income. The Company records a Regulatory asset for that portion related to its rate regulated utilities. See Note 09. 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. |
Investment in ProLiance Holdings, LLC |
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Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||
Investment in ProLiance Holdings, LLC | Investment in ProLiance Holdings, LLC The Company has an investment in ProLiance Holdings, LLC (ProLiance), an affiliate of the Company and Citizens Energy Group (Citizens). Much of the ProLiance business was sold on June 18, 2013 when ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC. The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC (LA Storage). Consistent with its ownership percentage, the Company is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. The Company's remaining investment at December 31, 2017, shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows.
LA Storage, LLC Storage Asset Investment ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with a 25 percent interest, which it accounts for using the equity method. The project, which includes a pipeline system, is expected to include 12-19 Bcf of storage capacity, and has the potential for further expansion. This pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and can connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities. Approximately 12 Bcf of the storage, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to further develop the caverns. The timing and extent of development of these caverns and pipeline system is dependent on market conditions, including pricing, need for storage and transmission capacity, and development of the liquefied natural gas market, among other factors. To date, development activity has been modest due to the current low demand for storage facilities. The development of the storage market and related pricing are critical assumptions in the analysis of the recoverability of the investment's carrying value. At December 31, 2017 and 2016, ProLiance's investment in the joint venture was $36.8 million and $36.7 million, respectively. |
Nonutility Legacy Holdings |
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Nonutility Real Estate Other Legacy Holdings [Abstract] | |
Nonutility Legacy Holdings | Nonutility Legacy Holdings Within the nonutility group, there are legacy investments involved in other ventures. As of December 31, 2017 and 2016, total remaining legacy investments, other than the investment in ProLiance, included in the Other Businesses portfolio totaled $6.7 million and $7.0 million, respectively. For the period presented, the remaining investment relates to a debt security related to the sale of commercial real estate of $5.1 million and other investments of $1.6 million. During 2015, the Company sold its investment in commercial real estate property and holds a debt security related to that transaction. |
Intangible Assets |
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Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangible Assets | Intangible Assets Intangible assets, which are included in Other assets, consist of the following:
Effective January 1, 2017, the Company reclassified an approximate $7 million market-related asset from non-amortizing to amortizing. As of December 31, 2017, the weighted average remaining life for amortizing customer-related assets is 13 years. These amortizing intangible assets have no significant residual values. Intangible assets are presented net of accumulated amortization totaling $14.6 million for customer-related assets and $4.3 million for market-related assets at December 31, 2017 and $12.0 million for customer-related assets and $4.5 million for market-related assets at December 31, 2016. Annual amortization associated with intangible assets totaled $2.6 million in 2017, $2.5 million in 2016 and $3.1 million in 2015. Amortization should approximate (in millions) $2.6 per year from 2018 through 2022. Intangible assets are primarily in the Nonutility Group. |
Income Taxes |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | Income Taxes Tax Cuts and Jobs Act 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 $45.3 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 resulting in a $23.2 million benefit for the Utility Group, $22.3 million benefit for the Nonutility businesses, and $0.2 million expense for Corporate & Other. The portion of the benefit attributable to Utility Group operations relates to assets which are not included for regulatory rate making purposes, 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 for the Utility Group. 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. A reconciliation of the federal statutory rate to the effective income tax rate follows:
On February 9, 2018, through the signing into law of the Bipartisan Budget Act of 2018, Section 179D of the Internal Revenue Code, which provides for the energy efficiency commercial buildings tax deduction, was retroactively extended to 2017 for one year. Any impacts will be reflected in 2018 results pursuant to ASC 740 related to accounting for retroactive effects of legislation. Significant components of the net deferred tax liability follow:
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 credit carryforwards 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 in future periods. In addition, the Company has $4.1 million in state net operating losses and $12.2 million in U.S. federal charitable contributions carryforwards, which will expire in 5 to 20 years. The net operating loss carryforward and other carryforwards were reduced for the impacts of unrecognized tax benefits and a valuation allowance relating primarily to state net operating loss carryforwards. At December 31, 2017 and 2016, the valuation allowance was $10.1 million and $8.3 million, respectively. The components of income tax expense follow:
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 $1.2 million, respectively, at December 31, 2017 and 2016. The Company 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 the Company's U.S. federal income tax returns for tax years through December 31, 2012. The State of Indiana, the Company'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. 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. |
Retirement Plans & Other Postretirement Benefits |
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Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement Plans & Other Postretirement Benefits | Retirement Plans & Other Postretirement Benefits At December 31, 2017, the Company maintains three closed qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement benefit plan includes health care and life insurance benefits which are a combination of self-insured and fully insured programs. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.” Net Periodic Benefit Costs A summary of the components of net periodic benefit cost for the three years ended December 31, 2017 follows:
A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility Plant following the allocation of current employee labor costs. Costs capitalized in 2017, 2016, and 2015 are estimated at $3.0 million, $1.9 million, and $3.1 million, respectively. The Company decreased the weighted average discount rate used to measure periodic cost from 4.31 percent in 2016 to 4.07 percent in 2017 due to lower benchmark interest rates that approximated the expected duration of the Company’s benefit obligations as of that valuation date. The Company derives its discount rate by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans' projected benefit payments. For fiscal year 2018, the weighted average discount rate assumption will decrease to 3.61 percent for the defined benefit pension plans, based on decreased benchmark interest rates. The weighted averages of significant assumptions used to determine net periodic benefit costs follow:
The Company uses a "building block" approach to develop an expected long-term rate of return. In 2017, the Company lowered to 7.0 percent this long-term assumption based on continued lower interest rates. The 2018 assumption is also 7.0 percent. Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs. The Company’s plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI). Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants. Projected Benefit Obligations A reconciliation of the Company’s benefit obligations at December 31, 2017 and 2016 follows:
The increase in the projected benefit obligation in 2017 is primarily due to a decrease in the discount rate used to measure the obligation at year end. The accumulated benefit obligation for all defined benefit pension plans was $356.5 million and $339.8 million at December 31, 2017 and 2016, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels. The accumulated benefit obligation differs from the projected benefit obligation disclosed in the table above in that it includes no assumptions about future compensation levels. Material Assumptions The benefit obligation as of December 31, 2017 and 2016 was calculated using the following weighted average assumptions:
For the projected benefit obligation calculation at December 31, 2017, the mortality assumed for determining future lump sums reflects the latest IRS mortality table (2019) and the latest mortality improvement scales released by the Society of Actuaries. To calculate the 2017 ending postretirement benefit obligation, medical claims costs in 2018 were assumed to be 7.0 percent higher than those incurred in 2017. That trend, beginning at 7.0 percent in 2018, is assumed to reach its ultimate trending increase of 5.0 percent by 2025 and remain level thereafter. A one-percentage point increase or decrease in assumed health care cost trend rates would have changed the benefit obligation by approximately $0.2 million. Plan Assets A reconciliation of the Company’s plan assets at December 31, 2017 and 2016 follows:
The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes. The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk. The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate. Both the equity and debt securities have a blend of domestic and international exposures. Objectives do not target a specific return by asset class. The portfolios’ return is monitored in total. Following is a description of the valuation methodologies used for trust assets measured at fair value. Mutual Funds The fair values of mutual funds are derived from the daily closing price as reported by the fund as these instruments have active markets (Level 1 inputs). Common Collective Trust Funds (CTF’s) The Company’s plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager. These trust funds typically give investors a wider range of investment options through this pooling of funds than those generally available to investors on an individual basis. However, unlike mutual funds, these trusts are not publicly traded in an active market. The funds are valued at the net asset value of the underlying investments. The net asset value is used as a practical expedient to estimate fair value. In relation to these investments, there are no unfunded commitments. Also, the Plan can exchange shares with minimal restrictions, however, certain events may exist where share exchanges are restricted for up to 31 days. The fair values of the Company’s pension and other retirement plan assets at December 31, 2017 and December 31, 2016 by asset category and by fair value hierarchy are as follows:
(a) In accordance with Subtopic 820-10, certain investments that were measured at net asset value per share, or its equivalent, have not been classified in the fair value hierarchy. Guaranteed Annuity Contract One of the Company’s pension plans is party to a group annuity contract with John Hancock Life Insurance Company (John Hancock). At December 31, 2017 and 2016, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $4.2 million and $4.0 million, respectively. If funds retained by John Hancock are not sufficient to satisfy retirement payments due to these retirees, the shortfall must be funded by the Company. The composite investment return, net of manager fees and other charges for the years ended December 31, 2017 and 2016 was 3.25 percent and 3.60 percent, respectively. The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment. There is no unfunded commitment related to this investment. A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:
Funded Status The funded status of the plans as of December 31, 2017 and 2016 follows:
Expected Cash Flows The Company expects to make contributions totaling $3.5 million to the qualified pension plans in 2018. In addition, the Company expects to make contributions totaling approximately $1.1 million into the SERP plan and approximately $2.9 million into the postretirement plan. Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2017 are approximately (in millions) $28.8 in 2018, $43.0 in 2019, $30.1 in 2020, $27.3 in 2021, $28.6 in 2022, and $132.7 in years 2023-2027. Expected benefit payments projected to be required for postretirement benefits during the years following 2017 (in millions) are approximately $4.1 in 2018, $4.4 in 2019, $4.7 in 2020, $4.9 in 2021, $4.9 in 2022, and $23.1 in years 2023-2027. Prior Service Cost and Actuarial Gains and Losses Following is a roll forward of prior service cost and actuarial gains and losses.
Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2017 and 2016.
Related to pension plans, $0.5 million of prior service cost and $8.5 million of actuarial gain/loss is expected to be amortized to cost in 2018. Related to other benefits, no actuarial gain/loss is expected to be amortized to periodic cost in 2018, and $2.2 million of prior service cost is expected to reduce costs in 2018. Multiemployer Benefit Plan The Company, through its Infrastructure Services operating segment, participates in several industry wide multiemployer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multiemployer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers, 2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers, and 3) if the Company ceases its participation in its multiemployer pension plans, the Company may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability. Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable. Expense associated with multiemployer plans was $42.1 million, $35.0 million and $32.7 million for the years ended December 31, 2017, 2016, and 2015, respectively. During 2017, the Company made contributions to these multiemployer plans on behalf of employees that participate in approximately 250 local unions. Contracts with these unions are negotiated with trade agreements through two primary contractor associations. These trade agreements have varying expiration dates ranging from 2017 through 2021. The average contribution related to these local unions was less than $0.2 million, and the largest contribution was $4.8 million. Multiple unions can contribute to a single multiemployer plan. The Company made contributions to at least 50 plans in 2017, six of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan. The Company's participation in the significant plans is outlined in the following table. The Employer Identification Number (EIN) / Pension Plan Number column provides the EIN and three digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2017 and 2016 is for the plan year end at January 31, 2017 and 2016 for the Central Pension Fund, May 31, 2017 and 2016 for the Indiana Laborers Fund, December 31, 2016 and 2015 for the Pipeline Industry Benefit Fund, December 31, 2016 and 2015 for the Laborers District Council & Contractors’ Pension Fund of Ohio, July 31, 2016 and 2015 for the Ohio Operating Engineers Pension Fund and April 30, 2017 and 2016 for the Operating Engineers Local 324 Fringe Benefit Fund respectively. The Company's participation in the significant plans is outlined in the following table. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending / Implemented column indicates plans for which a funding improvement plan ("FIP") or rehabilitation plan ("RP") is either pending or has been implemented. The multiemployer contributions listed in the table below are the Company's multiemployer contributions made in 2017, 2016, and 2015. Federal law requires pension plans in endangered status to adopt a FIP aimed at restoring the financial health of the plan. In December 2014, the Multiemployer Pension Reform Act of 2014 was passed and permanently extended the Pension Protection Act of 2006 multiemployer plan critical and endangered status funding rules, among other things, including providing a provision for a plan sponsor to suspend or reduce benefit payments to preserve plans in critical and declining status.
(1) The Indiana Laborers Pension Fund was in “endangered” status for the Plan Year ending May 31, 2017. In an effort to improve the Plan’s funding situation, the trustees adopted a FIP on December 17, 2015 and updated on December 20, 2016. The funding improvement period is June 1, 2017 to May 31, 2027 or the date the Fund’s actuary certifies it has emerged from endangered status. (2) The Operating Engineers Local #324 Fringe Benefits Fund was certified to be in "critical” status for the plan year ending April 30, 2017. In an effort to improve the Plan's funding situation, on March 17, 2011, the trustees adopted a Plan Amendment, which reduced benefit accruals, eliminated some ancillary benefits, and adopted a rehabilitation plan that will be effective from May 1, 2013 through April 30, 2023 or until the Plan is no longer in critical status. On April 27, 2015, the trustees updated the rehabilitation plan to change the annual standard for meeting the requirements of the rehabilitation plan. The annual standard is that actuarial projections updated for each year show the Fund is expected to remain solvent for a 20-year projection period. While not considered significant to the Company, there are two plans in red zone status receiving Company contributions. There are five plans where Company contributions exceed 5 percent of each plan's total contributions and one of these plans was considered significant to the Company. Defined Contribution Plan The Company also has defined contribution retirement savings plans qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives. During 2017, 2016 and 2015, the Company made contributions to these plans of $13.2 million, $12.1 million, and $11.0 million, respectively. |
Borrowing Arrangements |
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Borrowing Arrangements | Borrowing Arrangements Long-Term Debt Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
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
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). 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 10, 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. Vectren Capital Unsecured Note Retirements On December 15, 2017 and March 11, 2016, Vectren Capital senior unsecured notes matured totaling $75 million and $60 million, respectively. Interest rates on the matured bonds were 3.48 percent and 6.92 percent, respectively. The repayment of debt was funded from the Company's cash on hand and Nonutility short-term borrowing arrangements. 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. $61.8 million is callable in 2018, as previously noted, and $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 five years following 2017 (in millions) are $100 in 2018, $60 in 2019, $100 in 2020, $55 in 2021, $80 in 2022, and $1,444 thereafter. Debt Guarantees Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings' debt. Vectren Capital's long-term debt outstanding at December 31, 2017 was $260 million. Vectren Capital had $70 million short-term obligations outstanding at December 31, 2017. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by its wholly owned subsidiaries and regulated utilities Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term obligations outstanding at December 31, 2017 approximated $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. Short-Term Borrowings On July 14, 2017, Utility Holdings closed on renegotiated credit agreements with existing lenders. These credit agreements mature on July 14, 2022 and replaced bank credit agreements that had an original maturity date of October 31, 2019. Utility Holdings' new credit facility totals $400 million with a $10 million swing line sublimit and a $20 million letter of credit sublimit. The Utility Holdings credit agreement is jointly and severally guaranteed by its wholly owned subsidiaries Indiana Gas, SIGECO, and VEDO and is a backup facility for Utility Holdings' commercial paper program. Vectren Capital's new credit facility totals $200 million with a $40 million swing line sublimit and a $80 million letter of credit sublimit. The Vectren Capital credit agreement funds the short-term borrowing needs of the Company's corporate and nonutility operations and is guaranteed by Vectren Corporation. The total $600 million of short-term borrowing capacity between the two lines remains unchanged; however, the Utility Holdings credit agreement commitment was increased by $50 million as compared to the prior credit agreement, and the Vectren Capital credit agreement commitment was decreased by $50 million as compared to the prior credit agreement. As reduced by borrowings currently outstanding, approximately $220 million was available for the Utility Group operations and $130 million was available for the wholly owned Nonutility Group and corporate operations at December 31, 2017. The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market but maintains the ability to use the Utility Holdings' short-term borrowing facility when necessary. Throughout the years presented, Utility Holdings has successfully placed commercial paper as needed. Following is certain information regarding these short-term borrowing arrangements:
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Common Shareholder's Equity |
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Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Common Shareholder's Equity | Common Shareholders’ Equity Authorized, Reserved Common and Preferred Shares At December 31, 2017 and 2016, the Company was authorized to issue 480 million shares of common stock and 20 million shares of preferred stock. Of the authorized common shares, approximately 4.6 million shares at December 31, 2017 and 2016 were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan. At December 31, 2017 and 2016, there were 392.4 million and 392.5 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital. |
Earnings Per Share |
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Earnings Per Share | Earnings Per Share The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed. The amount of net income attributable to participating securities is immaterial. Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive. The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2017:
For the periods presented, all equity based instruments were dilutive and immaterial. |
Accumulated Other Comprehensive Income |
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Accumulated Other Comprehensive Income | Accumulated Other Comprehensive Income A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
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Share-Based Compensation & Deferred Compensation Arrangements |
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Share-Based Compensation & Deferred Compensation Arrangements | Share-Based Compensation & Deferred Compensation Arrangements The Company has share-based compensation programs to encourage corporate and subsidiary officers, key non-officer employees, and non-employee directors to remain with the Company and to more closely align their interests with those of the Company’s shareholders. Under these programs, the Company issues both performance-based and time-vested awards. All share-based compensation programs are shareholder approved. Currently, awards issued to a majority of the officers are performance-based, accrue dividends that are also subject to performance measures, and are settled in cash. In addition, the Company maintains a deferred compensation plan for officers and non-employee directors where participants can invest earned compensation and vested share-based awards in phantom Company stock units, among other options. Certain vesting grants provide for accelerated vesting if there is a change in control or upon the participant’s retirement. Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income:
Share-Based Awards & Other Awards The vesting of awards issued to officers is contingent upon meeting total return and return on equity performance objectives. Grants to officers generally vest at the end of a three-year performance period. Based on performance objectives, the number of awards could double or could be entirely forfeited. Non-employee directors receive a portion of their fees in share-based awards. These awards to non-employee directors are not performance-based and generally vest over one year. The majority of officers and non-employee directors must choose between either settling awards in cash or deferring awards into a deferred compensation plan (where the value is eventually withdrawn in cash). The number of such awards that may settle in shares, but are accounted for as liability awards due to their potential to be taken in cash when withdrawn from the deferred compensation plan, was approximately or less than 100,000 units as of December 31, 2017, 2016 and 2015. Most officer, non-officer employee, and non-employee director awards are accounted for as liability awards at their settlement date fair value. The limited number of share awards to certain subsidiary officers that must be settled in shares are accounted for in equity at their grant date fair value. A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2017 and 2016, and changes during the years ended December 31, 2017 and 2016, follow:
As of December 31, 2017, there was $14.2 million of total unrecognized compensation cost associated with outstanding grants. That cost is expected to be recognized over a weighted-average period of 1.1 years. The total fair value of shares vested for liability awards during the years ended December 31, 2017, 2016, and 2015 was $25.1 million, $23.7 million, and $16.6 million, respectively. The total fair value of equity awards vesting during the years ended December 31, 2017, 2016, and 2015 was $0.5 million, $0.6 million, $1.1 million, respectively. Deferred Compensation Plans The Company has nonqualified deferred compensation plans, which permit eligible officers and non-employee directors to defer portions of their compensation and vested share-based compensation. A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts. The measurement funds are similar to the funds in the Company's corporate defined contribution plan and include an investment in phantom stock units of the Company. The account balance fluctuates with the investment returns on those funds. The liability associated with these plans totaled $61.4 million and $40.9 million at December 31, 2017 and 2016 respectively. Other than $1.2 million and $0.9 million which is classified in Accrued liabilities at December 31, 2017 and 2016, respectively, the liability is included in Deferred credits & other liabilities. The impact of these plans on Other operating expenses was expense of $13.1 million in 2017, $4.3 million in 2016 and $0.1 million in 2015. The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2017, 2016, and 2015, was expense of $10.1 million, expense of $3.8 million, and income of $0.4 million, respectively. The Company has certain investments currently funded primarily through corporate-owned life insurance policies. These investments, which are consolidated, are available to pay deferred compensation benefits. These investments are also subject to the claims of the Company's creditors. The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $42.2 million and $33.1 million at December 31, 2017 and 2016, respectively. Those investments generated earnings of $5.9 million in 2017, earnings of $3.5 million in 2016, and losses of $2.1 million in 2015. This activity is reflected in Other operating expenses. |
Commitments & Contingencies |
12 Months Ended |
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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 $14.2 in 2018, $10.1 in 2019, $4.9 in 2020, $2.7 in 2021, $2.3 in 2022, and $5.8 thereafter. Total lease expense, for these type of commitments, (in millions) was $16.5 in 2017, $13.0 in 2016, and $11.1 in 2015. The Company’s regulated utilities have both firm and non-firm commitments, some of which are between five and twenty year agreements, to purchase natural gas, coal, and electricity, as well as certain transportation and storage rights. 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. Performance Guarantees & Product Warranties In the normal course of business, wholly owned subsidiaries, such as Energy Systems Group, LLC (ESG), a subsidiary of the Energy Services operating segment, issue payment and performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors and subcontractors, and support warranty obligations. Specific to ESG's role as a general contractor in the performance contracting industry, at December 31, 2017, there are 66 open surety bonds supporting future performance. The average face amount of these obligations is $9.8 million, and the largest obligation has a face amount of $75.9 million. The maximum exposure from these obligations is limited to the level of uncompleted work and further limited by bonds issued to ESG by various contractors. At December 31, 2017, approximately 29 percent of work was yet to be completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. Based on a history of meeting performance obligations and installed products operating effectively, no liability or cost has been recognized for the periods presented as the Company assesses the likelihood of loss as remote. Since inception, ESG has paid a de minimis amount on energy savings guarantees. Corporate Guarantees & Other Support The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries. These guarantees do not represent incremental consolidated obligations; but rather, represent guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral. At December 31, 2017, parent level guarantees support a maximum of $373 million of ESG's performance contracting commitments, warranty obligations, project guarantees, and energy savings guarantees. Given the infrequent occurrence of any performance shortfalls historically on any of these commitments, no reserve for a potential liability has been deemed warranted. Further, an energy facility operated by ESG and managed by Keenan Ft. Detrick Energy, LLC (Keenan), is governed by an operations agreement. Under this agreement, all payment obligations to Keenan are also guaranteed by the Company. The Company guarantee of the Keenan operations agreement does not state a maximum guarantee. Due to the nature of work performed under this contract, the Company cannot estimate a maximum potential amount of future payments but assesses the likelihood of loss as remote based on, primarily, the nature of the project. The Company has not been called on to perform under these guarantees historically. While there can be no assurance that performance under these provisions will not be required in the future, the Company believes that the likelihood of a material amount being incurred under these provisions is remote given the nature of the projects, the manner in which the savings estimates are developed, and the fact that the value of the guarantees decrease over time as actual savings are achieved. The Company from time to time, and primarily through Vectren Capital, issues letters of credit that support consolidated operations. At December 31, 2017, letters of credit outstanding total $36.3 million. Legal & 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 |
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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 now 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 Ohio 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. Ohio 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 Ohio 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 Matters |
12 Months Ended |
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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 Integrated Resource Plan 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 process. In that filing, the Company seeks approval of its generation 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 Sustainability Matters |
12 Months Ended |
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Dec. 31, 2017 | |
Environmental Matters Disclosure [Abstract] | |
Environmental and Sustainability Matters | Environmental and Sustainability Matters The Company initiated a corporate sustainability program in 2012 with the publication of the initial corporate sustainability report. Since that time, the Company continues 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 the Company's Corporate Responsibility and Sustainability Committee, as well as vetted with the Company'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 and 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's 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 preferred IRP. 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 (ELGs) 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 ELGs 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 ELGs 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 ELGs 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 ELGs, 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 December 31, 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 |
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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:
(1) Presented in "Other utility & corporate investments" on the Consolidated Balance Sheets. (2) Presented 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 10, 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. Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At December 31, 2017 and 2016, the fair value for these financial instruments was not estimated. The carrying value of these investments at December 31, 2017 and 2016 was approximately $9.6 million and $16.1 million, respectively. |
Segment Reporting |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting | Segment Reporting The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other. The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s 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 Utility Group is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other operations. During the periods presented, the Nonutility Group had the following operating segments: Infrastructure Services, Energy Services, and Other Businesses. Energy Services, through the wholly owned subsidiary Energy Systems Group, LLC, provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation, and combined heat and power projects. The Infrastructure Services segment, through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provides underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. Fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services 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 Minnesota Limited was awarded in a competitive process. Corporate and Other includes unallocated corporate expenses such as advertising and certain charitable contributions, among other activities, that benefit the Company’s other operating segments. Total assets in all periods presented reflect the retrospective impacts of the adoption in 2015 of ASU 2015-17, Balance Sheet Classification of Deferred Taxes and the retrospective impacts of the adoption in 2016 of ASU 2015-03, Presentation of Debt Issuance Costs. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows:
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Additional Balance Sheet & Operational Information |
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Additional Balance Sheet & Operational Information | Additional Balance Sheet & Operational Information Inventories consist of the following:
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 consist of the following:
Investments in unconsolidated affiliates consist of the following:
Other utility & corporate investments consist of the following:
Goodwill by operating segment follows:
Accrued liabilities consist of the following:
Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows:
Equity in earnings (losses) of unconsolidated affiliates consists of the following:
Other income (expense) – net consists of the following:
Supplemental Cash Flow Information:
As of December 31, 2017 and 2016, the Company has accruals related to utility and nonutility plant purchases totaling approximately $28.6 million and $30.0 million, respectively. |
Impact of Recently Issued Accounting Guidance |
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Dec. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [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 share-based awards are settled via cash payments and were therefore not impacted by this standard. The Company'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 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 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 (Unaudited) |
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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:
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SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES |
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Valuation and Qualifying Accounts [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES | SCHEDULE II Vectren Corporation and Subsidiaries VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
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Summary of Significant Accounting Policies (Policies) |
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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. The Infrastructure Services segment, through wholly owned subsidiaries Miller Pipeline, LLC and Minnesota Limited, LLC, provides underground pipeline construction and repair services for customers that include Vectren Utility Holdings' utilities. In accordance with consolidation guidance under ASC 980, fees incurred by Vectren Utility Holdings and its subsidiaries for these pipeline construction and repair services, are appropriately not eliminated in consolidation. |
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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. |
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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. |
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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. |
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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 are 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. |
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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 that 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 that 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. |
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Investments in Unconsolidated Affiliates | Investments in Unconsolidated Affiliates Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in earnings (losses) of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other income – net when received. Investments are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an investment's fair value to its carrying value. Investments, when necessary, include adjustments for declines in value judged to be other than temporary. |
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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. |
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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 that are 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. |
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Postretirement Obligations & Costs | Postretirement Obligations & Costs The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income. The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment. |
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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. |
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Product Warranties, Performance Guarantees & Other Guarantees | Product Warranties, Performance Guarantees & Other Guarantees Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations. |
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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, certain 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 include most of the Company's executed energy 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. |
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Income Taxes | Income Taxes As discussed in Note 8 in the Company’s Consolidated Financial Statements included in Item 8, on December 22, 2017, comprehensive federal tax legislation was enacted, referred to as the Tax Cuts and Jobs Act (“TCJA”). 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, to the extent considered in ratemaking, 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. |
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Revenues | Revenues Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. |
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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 that of 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. |
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Share-Based Compensation | Share-Based Compensation The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on an expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. |
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Excise & Utility Receipts Taxes | Excise & Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. |
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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 has three operating segments within its Utility Group, three operating segments in its Nonutility Group, and a Corporate and Other segment. |
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Fair Value Measurements | Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. 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:
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. |
Utility & Nonutility Plant (Tables) |
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Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost of Utility Plant | The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:
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Nonutility Plant, Net of Depreciation and Amortization | Nonutility Plant, net of accumulated depreciation and amortization follows:
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Regulatory Assets & Liabilities (Tables) |
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets | Regulatory assets consist of the following:
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Investment in ProLiance Holdings, LLC (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||
Summarized Financial Information of Equity Investment | The Company's remaining investment at December 31, 2017, shown at its 61 percent ownership share of the individual net assets of ProLiance, is as follows.
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Intangible Assets (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangible assets | Intangible assets, which are included in Other assets, consist of the following:
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Income Taxes (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reconciliation of the Federal Statutory Rate to Effective Income Tax Rate | A reconciliation of the federal statutory rate to the effective income tax rate follows:
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Significant Components of Net Deferred Tax Liability | Significant components of the net deferred tax liability follow:
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Components of Income Tax Expense | The components of income tax expense follow:
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Retirement Plans & Other Postretirement Benefits (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of components of net periodic benefit cost | A summary of the components of net periodic benefit cost for the three years ended December 31, 2017 follows:
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Schedule of assumptions used | The benefit obligation as of December 31, 2017 and 2016 was calculated using the following weighted average assumptions:
The weighted averages of significant assumptions used to determine net periodic benefit costs follow:
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Schedule of changes in projected benefit obligations | A reconciliation of the Company’s benefit obligations at December 31, 2017 and 2016 follows:
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Schedule of changes in fair value of plan assets | A reconciliation of the Company’s plan assets at December 31, 2017 and 2016 follows:
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Fair values of pension and other retirement plan assets by category and fair value hierarchy | The fair values of the Company’s pension and other retirement plan assets at December 31, 2017 and December 31, 2016 by asset category and by fair value hierarchy are as follows:
(a) In accordance with Subtopic 820-10, certain investments that were measured at net asset value per share, or its equivalent, have not been classified in the fair value hierarchy. |
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Schedule of effect of significant unobservable inputs, changes in plan assets | A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:
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Schedule of net funded status of plans | The funded status of the plans as of December 31, 2017 and 2016 follows:
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Schedule of net periodic benefit cost not yet recognized | Following is a roll forward of prior service cost and actuarial gains and losses.
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Reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations | Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2017 and 2016.
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Schedule of Multiemployer Contributions In Current Year | The multiemployer contributions listed in the table below are the Company's multiemployer contributions made in 2017, 2016, and 2015. Federal law requires pension plans in endangered status to adopt a FIP aimed at restoring the financial health of the plan. In December 2014, the Multiemployer Pension Reform Act of 2014 was passed and permanently extended the Pension Protection Act of 2006 multiemployer plan critical and endangered status funding rules, among other things, including providing a provision for a plan sponsor to suspend or reduce benefit payments to preserve plans in critical and declining status.
(1) The Indiana Laborers Pension Fund was in “endangered” status for the Plan Year ending May 31, 2017. In an effort to improve the Plan’s funding situation, the trustees adopted a FIP on December 17, 2015 and updated on December 20, 2016. The funding improvement period is June 1, 2017 to May 31, 2027 or the date the Fund’s actuary certifies it has emerged from endangered status. (2) The Operating Engineers Local #324 Fringe Benefits Fund was certified to be in "critical” status for the plan year ending April 30, 2017. In an effort to improve the Plan's funding situation, on March 17, 2011, the trustees adopted a Plan Amendment, which reduced benefit accruals, eliminated some ancillary benefits, and adopted a rehabilitation plan that will be effective from May 1, 2013 through April 30, 2023 or until the Plan is no longer in critical status. On April 27, 2015, the trustees updated the rehabilitation plan to change the annual standard for meeting the requirements of the rehabilitation plan. The annual standard is that actuarial projections updated for each year show the Fund is expected to remain solvent for a 20-year projection period. |
Borrowing Arrangements (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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:
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Short term borrowing arrangements | Following is certain information regarding these short-term borrowing arrangements:
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Earnings Per Share (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basic and dilutive earnings per share calculation | The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2017:
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Accumulated Other Comprehensive Income (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components and changes in accumulated other comprehensive income | A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
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Share-Based Compensation & Deferred Compensation Arrangements (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reconciliation of total cost of share-based awards to the after tax effect on net income | Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income:
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Performance based units outstanding | A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2017 and 2016, and changes during the years ended December 31, 2017 and 2016, follow:
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Fair Value Measurements (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, by Balance Sheet Grouping | The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:
(1) Presented in "Other utility & corporate investments" on the Consolidated Balance Sheets. (2) Presented 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) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information | Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows:
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Additional Balance Sheet & Operational Information (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Balance Sheet and Operational Information [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of inventories | Inventories consist of the following:
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Summary of prepayments and other current assets | Prepayments & other current assets consist of the following:
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Schedule of investments in unconsolidated affiliates | Investments in unconsolidated affiliates consist of the following:
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Other utility and corporate investments in the consolidated balance sheets | Other utility & corporate investments consist of the following:
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Goodwill by operating segment | Goodwill by operating segment follows:
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Accrued Liabilities | Accrued liabilities consist of the following:
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Asset retirement obligation | Asset retirement obligations included in Deferred credits and other liabilities in the Consolidated Balance Sheets roll forward as follows:
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Equity in earnings (losses) of unconsolidated affiliates | Equity in earnings (losses) of unconsolidated affiliates consists of the following:
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Other, net in the consolidated statements of income | Other income (expense) – net consists of the following:
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Supplemental cash flow information | Supplemental Cash Flow Information:
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Quarterly Financial Data (Unaudited) (Tables) |
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial data for 2017 and 2016 follows:
|
Summary of Significant Accounting Policies (Details) |
9 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017
segment
|
Dec. 31, 2017
USD ($)
segment
|
Dec. 31, 2016
USD ($)
|
Dec. 31, 2015
USD ($)
|
|
Segment Reporting Information [Line Items] | ||||
Goodwill impairments | $ | $ 0 | $ 0 | $ 0 | |
Excise taxes and a portion of utility receipts taxes | $ | $ 29,100,000 | $ 28,300,000 | $ 29,400,000 | |
Utility Group | ||||
Segment Reporting Information [Line Items] | ||||
Number of operating segments in Utility group | segment | 3 | |||
Number of operating segments | segment | 3 |
Nonutility Legacy Holdings (Details) - USD ($) $ in Millions |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Schedule of Equity Method Investments [Line Items] | ||
Restricted cash & other investments | $ 43.7 | $ 34.1 |
Other nonutility investments | 9.6 | 16.1 |
Nonutility Group | ||
Schedule of Equity Method Investments [Line Items] | ||
Debt security related to the sale of commercial real estate | 5.1 | |
Other nonutility investments | 1.6 | |
Legacy Investments, Other Than ProLiance | Nonutility Group | ||
Schedule of Equity Method Investments [Line Items] | ||
Restricted cash & other investments | $ 6.7 | $ 7.0 |
Income Taxes - Narrative (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Operating Loss Carryforwards [Line Items] | ||
Tax Cuts and Jobs Act of 2017 tax benefit | $ 45.3 | |
Investment tax credits | 1.2 | $ 1.6 |
State net operating loss carryforwards | 4.1 | 3.2 |
Charitable contributions carryforwards | 12.2 | 0.0 |
Valuation allowance | 10.1 | 8.3 |
Uncertain tax positions [Abstract] | ||
Net liability for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the deferred income taxes and are benefits | 1.3 | $ 1.2 |
Utility Group | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Cuts and Jobs Act of 2017 tax benefit | 23.2 | |
Excess federal deferred income taxes from Tax Cuts and Jobs Act of 2017 | 333.4 | |
Nonutility Group | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Cuts and Jobs Act of 2017 tax benefit | 22.3 | |
Corporate and Other | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Cuts and Jobs Act of 2017 tax benefit | $ (0.2) |
Income Taxes - Reconciliation of Statutory Rate to Effective Tax Rate (Details) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Income Tax Disclosure [Abstract] | |||
Statutory rate: | 35.00% | 35.00% | 35.00% |
State & local taxes-net of federal benefit | 3.40% | 2.80% | 3.60% |
Deferred tax revaluation-tax law change | (17.30%) | 0.00% | 0.00% |
Amortization of investment tax credit | (0.20%) | (0.30%) | (0.20%) |
Domestic production deduction | (1.40%) | (0.40%) | (1.00%) |
Energy efficiency building deductions | (0.00%) | (1.70%) | (2.30%) |
Research and development credit | (0.30%) | (0.60%) | (1.60%) |
Other tax credits | (0.10%) | (0.10%) | (0.10%) |
All other-net | (1.40%) | 0.10% | 0.20% |
Effective tax rate | 17.70% | 34.80% | 33.60% |
Income Taxes - Net Deferred Tax Liability (Details) - USD ($) $ in Millions |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Income Tax Disclosure [Abstract] | ||
Depreciation & cost recovery timing differences | $ 593.7 | $ 902.4 |
Regulatory assets recoverable through future rates | 7.9 | 17.6 |
Alternative minimum tax carryforward | (12.2) | (29.3) |
Employee benefit obligations | (9.3) | (8.1) |
Employee benefit obligations | (4.1) | (3.2) |
Net operating loss & other carryforwards (net of valuation allowances) | (12.2) | 0.0 |
Regulatory liabilities to be settled through future rates | (116.2) | (15.9) |
Impairments | (0.6) | (2.5) |
Deferred fuel costs-net | 16.2 | 25.9 |
Other-net | 28.1 | 18.8 |
Net noncurrent deferred tax liability | $ 491.3 | $ 905.7 |
Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Current: | |||
Federal | $ 20.5 | $ 6.8 | $ 10.8 |
State | 6.9 | 6.0 | 8.5 |
Total current taxes | 27.4 | 12.8 | 19.3 |
Deferred: | |||
Federal | 16.7 | 97.6 | 79.0 |
State | 2.7 | 3.6 | 2.0 |
Total deferred taxes | 19.4 | 101.2 | 81.0 |
Amortization of investment tax credits | (0.4) | (1.1) | (0.6) |
Total income tax expense | $ 46.4 | $ 112.9 | $ 99.7 |
Retirement Plans & Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $ 6.5 | $ 7.0 | $ 7.9 |
Interest cost | 13.7 | 14.7 | 14.6 |
Expected return on plan assets | (21.0) | (22.8) | (22.5) |
Amortization of prior service cost (benefit) | 0.4 | 0.4 | 0.7 |
Amortization of actuarial loss | 7.4 | 7.2 | 8.5 |
Settlement charge | 2.1 | 0.0 | 0.6 |
Net periodic benefit cost (benefit) | 9.1 | 6.5 | 9.8 |
Other Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 0.2 | 0.3 | 0.4 |
Interest cost | 1.5 | 1.7 | 2.0 |
Expected return on plan assets | 0.0 | 0.0 | 0.0 |
Amortization of prior service cost (benefit) | (2.4) | (2.9) | (3.0) |
Amortization of actuarial loss | 0.0 | 0.0 | 0.7 |
Settlement charge | 0.0 | 0.0 | 0.0 |
Net periodic benefit cost (benefit) | $ (0.7) | $ (0.9) | $ 0.1 |
Retirement Plans & Other Postretirement Benefits - Assumptions Used in Calculation for Net Periodic Benefit Cost (Details) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Defined Benefit Plan Disclosure [Line Items] | |||
Rate of compensation increase | 3.50% | 3.50% | 3.50% |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.07% | 4.31% | 4.05% |
Expected return on plan assets | 7.00% | 7.50% | 7.50% |
Other Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.04% | 4.21% | 3.95% |
Expected increase in Consumer Price Index | 2.50% | 2.50% | 2.50% |
Retirement Plans & Other Postretirement Benefits - Fair Value of Guaranteed Annuity Contract (Details) - Level 3 - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Fair value of guaranteed annuity contract [Abstract] | ||
Fair value, beginning of year | $ 4.4 | $ 4.3 |
Unrealized gains related to investments still held at reporting date | 0.2 | 0.2 |
Purchases, sales & settlements, net | (0.1) | (0.1) |
Fair value, end of year | $ 4.5 | $ 4.4 |
Retirement Plans & Other Postretirement Benefits - Amounts in AOCI (Details) - USD ($) $ in Millions |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
---|---|---|---|---|
Pension Benefits | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Prior service cost | $ 2.3 | $ 1.4 | $ 1.8 | $ 2.0 |
Unamortized actuarial loss | 110.3 | 114.6 | 110.1 | 111.7 |
Sub total | 112.6 | 116.0 | ||
Less: Regulatory asset deferral | (110.2) | (113.6) | ||
AOCI before taxes | 2.4 | 2.4 | ||
Other Benefits | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Prior service cost | (8.8) | (11.2) | (14.1) | (17.1) |
Unamortized actuarial loss | 1.2 | 0.0 | $ 1.6 | $ 10.9 |
Sub total | (7.6) | (11.2) | ||
Less: Regulatory asset deferral | 7.4 | 11.0 | ||
AOCI before taxes | $ (0.2) | $ (0.2) |
Common Shareholder's Equity (Details) - shares |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Stockholders' Equity Note [Abstract] | ||
Common stock, shares authorized for issue (in shares) | 480,000,000 | 480,000,000 |
Preferred stock , shares authorized for issue (in shares) | 20,000,000 | 20,000,000 |
Number of shares reserved for issuance under share-based compensation plans, benefit plans, and dividend reinvestment plan (in shares) | 4,600,000 | 4,600,000 |
Authorized shares of common stock available for issuance (in shares) | 392,400,000 | 392,500,000 |
Authorized shares of preferred stock available for issuance (in shares) | 20,000,000 | 20,000,000 |
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ 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 |
|
Earnings Per Share [Abstract] | |||||||||||
Net income | $ 61.2 | $ 61.9 | $ 37.6 | $ 55.4 | $ 69.6 | $ 61.4 | $ 32.3 | $ 48.3 | $ 216.0 | $ 211.6 | $ 197.3 |
Weighted average common shares outstanding (Basic and Diluted EPS) (in shares) | 83.0 | 82.8 | 82.7 | ||||||||
Basic and Diluted earnings per share (in dollars per share) | $ 0.74 | $ 0.75 | $ 0.45 | $ 0.67 | $ 0.84 | $ 0.74 | $ 0.39 | $ 0.58 | $ 2.60 | $ 2.55 | $ 2.39 |
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Deferred income taxes | $ 0.9 | $ 0.9 | $ 0.9 | $ 0.9 |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning of year | 1,768.1 | |||
End of year | 1,849.3 | 1,768.1 | ||
Pension & other benefit costs | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning of year | (2.2) | (2.1) | (2.2) | |
Change during the year | 0.0 | (0.1) | 0.1 | |
End of year | (2.2) | (2.2) | (2.1) | |
Accumulated other comprehensive income (loss) | ||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||
Beginning of year | (1.3) | (1.2) | ||
Change during the year | 0.0 | (0.1) | 0.1 | |
End of year | $ (1.3) | $ (1.3) | $ (1.2) |
Share-Based Compensation & Deferred Compensation Arrangements - Reconciliation of Total Cost of Share-Based Awards to After Tax Effect (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Total cost of share-based compensation | $ 40.2 | $ 30.0 | $ 19.4 |
Less capitalized cost | 8.6 | 7.0 | 4.8 |
Total in other operating expense | 31.6 | 23.0 | 14.6 |
Less income tax benefit in earnings | 12.3 | 9.0 | 5.7 |
After tax effect of share-based compensation | $ 19.3 | $ 14.0 | $ 8.9 |
Segment Reporting - Narrative (Details) customer in Millions, $ in Millions |
9 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017
segment
|
Dec. 31, 2017
USD ($)
customer
group
|
Dec. 31, 2016
USD ($)
|
Dec. 31, 2015
USD ($)
|
|
Segment Reporting Information [Line Items] | ||||
Number of operating groups | group | 3 | |||
Portion of Indiana that is provided natural gas distribution and transportation services by the Gas Utility Services segment (in hundredths) | 66.67% | |||
Number of customers | customer | 1 | |||
Utility Group | ||||
Segment Reporting Information [Line Items] | ||||
Number of operating segments | segment | 3 | |||
Fees incurred for pipeline construction and repair services | $ | $ 157.1 | $ 117.8 | $ 109.5 |
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ 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 | $ 711.0 | $ 691.2 | $ 630.7 | $ 624.5 | $ 699.0 | $ 631.0 | $ 533.7 | $ 584.8 | $ 2,657.3 | $ 2,448.3 | $ 2,434.7 |
Operating income | 36.8 | 107.5 | 72.8 | 101.4 | 120.7 | 105.5 | 63.9 | 92.2 | 318.4 | 381.5 | 361.8 |
Net income | $ 61.2 | $ 61.9 | $ 37.6 | $ 55.4 | $ 69.6 | $ 61.4 | $ 32.3 | $ 48.3 | $ 216.0 | $ 211.6 | $ 197.3 |
Earnings per share [Abstract] | |||||||||||
Basic and Diluted earnings per share (in dollars per share) | $ 0.74 | $ 0.75 | $ 0.45 | $ 0.67 | $ 0.84 | $ 0.74 | $ 0.39 | $ 0.58 | $ 2.60 | $ 2.55 | $ 2.39 |
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Accumulated Provision for Uncollectible Accounts | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance, at beginning of year | $ 6.0 | $ 5.6 | $ 6.0 |
Additions Charged to Expenses | 5.9 | 6.9 | 8.1 |
Additions Charged to Other Accounts | 0.0 | 0.0 | 0.0 |
Deductions from Reserves, Net | 6.8 | 6.5 | 8.5 |
Balance, at end of period | 5.1 | 6.0 | 5.6 |
Reserve for Impaired Notes Receivable | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance, at beginning of year | 0.6 | 0.2 | 0.0 |
Additions Charged to Expenses | 0.4 | 0.4 | 0.2 |
Additions Charged to Other Accounts | 0.0 | 0.0 | 0.0 |
Deductions from Reserves, Net | 0.0 | 0.0 | 0.0 |
Balance, at end of period | $ 1.0 | $ 0.6 | $ 0.2 |
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