Competition

See a discussion on competition within the utility industry in "Item 1A Risk Factors, Utility Operating Risks" which is incorporated by reference herein.

 

Regulatory, Environmental, and EnvironmentalSustainability Matters

See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s regulatory environment, environmental, and environmentalsustainability matters.

Nonutility Group

The Company is involved in nonutility activities in two primary business areas: Infrastructure Services and Energy Services. Prior to August 29, 2014, the Company had activities in its Coal Mining business and, prior to June 18, 2013, in its Energy Marketing business.

Infrastructure Services

Infrastructure Services provides underground pipeline construction and repair to utility infrastructureservices through its wholly owned subsidiaries Miller Pipeline, LLC (Miller or Miller Pipeline) and Minnesota Limited, LLC (Minnesota Limited).  Infrastructure Services provides services to many utilities, including the Company’s utilities, as well as other industries.  Infrastructure Services generated approximately $996 million in revenues for 2017, compared to $813 million in 2016 and $843 million in gross revenues for 2015, compared to $779 million in 2014 and $784 million in 2013.2015.  

Backlog represents the amount of gross revenue the Company expects to realize from work to be performed in the future on uncompleted contracts, including new contractual agreements on which work has not begun.  Infrastructure Services operates primarily under two types of contracts, blanket contracts and bid contracts.  Using blanket contracts, customers are not contractually committed to specific volumes of services, however the Company expects to be chosen to perform work needed by a customer in a given time frame.  These contracts are typically awarded on an annual or multi-year basis. For blanket work, backlog represents an estimate of the amount of gross revenue that the Company expects to realize from work to be performed in the next twelve months on existing contracts or contracts the Company reasonably expects to be renewed or awarded based upon recent history or discussions with customers. Under bid contracts, customers are contractually committed to a specific service to be performed for a specific price, whether in total for a project or on a per unit basis.  At December 31, 2015,2017, Infrastructure Services had an estimated backlog of blanket contracts of $475$480 million and a backlog of bid contracts of $190$245 million, for a total backlog of $665$725 million.  The estimated backlog at December 31, 20142016 was $500$435 million for blanket contracts and $125$290 million for bid contracts, for a total of $625$725 million.

The backlog amounts above reflect estimates of revenues to be realized under blanket contracts.realized. Projects included in backlog can be subject to delays or cancellation as a result of regulatory requirements, adverse weather conditions, customer requirements, among other factors, which could cause actual revenue amounts to differ significantly from the estimates and revenues to be realized in periods other than originally expected.

See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding additional narrative of Infrastructure Services business matters.

Energy Services

See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding additional narrative of Energy Services business matters.

The Company has an investment in and loans to ProLiance Holdings, a nonutility affiliate of the Company and Citizens Energy Group.LLC (ProLiance). On June 18, 2013, ProLiance Holdings exited the natural gas marketing business through the disposition of certain of the net assets, along with the long-term pipeline and storage commitments, of its energy marketing business, ProLiance Energy, LLC to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd. ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States.  ProLiance Energy's customers included, among others, the Company’s Indiana utilities as well as Citizens’ utilities.  The Company's remaining investment in ProLiance relates primarily to an investment in LA Storage, LLC. 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. Additional information regarding the investment in ProLiance is included in Note 75 in the Company's Consolidated Financial Statements included in Item 8.  

Personnel

As of December 31, 2015,2017, the Company and its consolidated subsidiaries had approximately 5,6005,500 employees.  Of those employees, 700 are subject to collective bargaining arrangements negotiated by Utility Holdings and 3,0002,800 are subject to collective bargaining arrangements negotiated by Infrastructure Services.

Utility Holdings

In June 2015, the Company reached a three-year agreement with Local 175 of the Utility Workers Union of America, ending October 31, 2018. This labor agreement relates to employees of VEDO.

In May 2015, the Company reached a three-year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 23, 2018. This labor agreement relates to employees of SIGECO.

Infrastructure Services

The Company, through its Infrastructure Services subsidiaries, negotiates various trade agreements through contractor associations.  The two primary associations are the Distribution Contractors Association (DCA) and the Pipeline Contractors Association (PLCA).  These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters.  The trade agreements through the DCA have varying expiration dates in 2016, 20172020, 2021 and 2020.2022. The trade agreements through the PLCA expire at various times in 2017.2020. In addition, these subsidiaries have various project agreements and small local agreements.  These agreements expire upon completion of a specific project or on various dates throughout the year.

ITEM 1A.  RISK FACTORS

The Company is actively engaged in long-term strategic planning through initiative assessment, development and development.execution. The strategic planning process consistently engages the Company's Board of Directors and is updated as the Company's strategic environment changes. The result of that process is regularly communicated to all stakeholders, including investors, through a robust Investor Relations program. Further, the Company has a robuststrong compliance and risk management program that promotes a culture of compliance. The Company is, however, subject to a variety of risks including execution on its strategies. Investors should consider carefully the following factors that could cause the Company’s operating results and financial condition to be materially adversely affected.

Corporate Risks

Vectren is a holding company, and its assets consist primarily of investments in its subsidiaries.

Dividends on the Company’s common stock depend on the earnings, financial condition, capital requirements and cash flow of its subsidiaries, principally Utility Holdings and Enterprises, and the distribution or other payment of earnings from those entities to the Company.  Should the earnings, financial condition, capital requirements, or cash flow, of, or legal requirements applicable to them restrict their ability to pay dividends or make other payments to the Company, its ability to pay dividends on its common stock could be limited and its stock price could be adversely affected.  The Company’s results of operations, future growth, and earnings and dividend goals also will depend on the performance of its subsidiaries.  Additionally, certain of the Company’s lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio.

Deterioration in generalA deterioration of current economic conditions may have adverse impacts.

Economic conditions may have some negative impact on both gas and electric large customersindustrial and wholesale power sales.commercial customers.  This impact may include volatility and unpredictability in the demand for natural gas and electricity, tempered growth strategies, significant conservation measures, and perhaps plant closures, production cutbacks, or bankruptcies.  Economic conditions may also cause reductions in residential and commercial customer counts and lower revenues.  It is also possible

Financial market volatility could have adverse impacts.

The capital and credit markets may experience volatility and disruption.  If market disruption and volatility occurs, there can be no assurance that the Company will not experience adverse effects, which may be material.  These effects may include, but are not limited to, difficulties in accessing the short and long-term debt capital markets and the commercial paper market, increased

borrowing costs associated with short-term debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources.  Finally, there is no assurance the Company will have access to the equity capital markets to obtain financing when necessary or desirable.

A downgrade (or negative outlook) in or withdrawal of Vectren’s credit ratings could negatively affect its ability to access capital and its cost.

The current outlook for both Moody's and Standard & Poor’s is stable. Both rating agencies categorize the ratings of the above securities as investment grade.  A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating.  Standard & Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.

If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or initiate negative outlooks thereon, or withdraw the Company's ratings or, in each case, the ratings of its subsidiaries, it may significantly limit the Company's access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would likely increase.  In addition, the Company would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease.  Finally, there is no assurance that the Company will have access to the equity capital markets to obtain financing when necessary or desirable.

Utility Operating Risks

Vectren’s gas and electric utility sales are concentrated in the Midwest.

The operations of the Company’s regulated utilities are concentrated in central and southern Indiana and west centralwest-central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest.  These industries include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings, polycarbonate resin (Lexan®) and plastic products; gypsum products; electrical equipment, metal specialties, glass and steel finishing; pharmaceutical and nutritional products; gasoline and oil products; ethanol; and coal mining. Changing market conditions, including changing regulation, changes in market prices of oil or other commodities, or changes in

Vectren’s regulated utilities operate in an increasingly competitive industry, which may affect its future earnings.

A significant portion of Vectren’s electric utility sales are space heating and cooling.  Accordingly, its operating results may fluctuate with variability of weather.

The Company’s electric utility sales are sensitive to variations in weather conditions.  In this regard, many customers rely on electricity to heat and cool their homes and businesses and, as a result, the Company’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather. Accordingly, demand for electricity used for heating purposes is generally at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. The Company forecasts utility sales on the basis of normal weather.  Since the Company does not have a weather-normalization mechanism for its electric operations, significant variations

from normal weather could have a material impact on its earnings.  However, the impact of weather on the gas operations in the Company’s Indiana territories has been significantly mitigated through the implementation of a normal temperature adjustment mechanism.  Additionally, the implementation of a straight fixed variable rate design mitigates most weather variations related to Ohio residential and commercial gas sales.

Vectren’s utilities are exposed to increasing regulation, including pipeline safety, environmental, and cybersecurity regulation.

The Company's utilities are subject to regulation by federal, state, and local regulatory authorities and are exposed to public policy decisions that may negatively impact the Company's earnings.  In particular, the Company is subject to regulation by the FERC, the NERC, the EPA, the IURC, the PUCO, the DOT, including PHMSA, the Department of Energy (DOE), the Occupational Safety and Health Administration (OSHA), and the Department of Homeland Security (DHS).  These authorities regulate many aspects of its generation, transmission and distribution operations, including construction and maintenance of facilities, operations, and safety.  In addition, the IURC, the PUCO, and the FERC approve its utility-related debt and equity issuances, regulate the rates that the Company's utilities can charge customers, the rate of return that the Company's utilities are authorized to earn, and their ability to timely recover gas and fuel costs and investments in infrastructure.  Further, there are consumer advocates and other parties that may intervene in regulatory proceedings and affect regulatory outcomes.

Trends Toward Stricter Standards

With the historical trend toward stricter standards, greater regulation, more extensive permit requirements, and an increase in the number and types of assets operated that are subject to regulation, the Company's investment in infrastructure and the associated operating costs have increased and are expected tomay increase in the future.  As examples of the trend toward stricter regulation,

Pipeline Safety Considerations

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe, efficient, and reliable manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and improvement.  The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law on January 3, 2012.2012 and on March 18, 2016 PHMSA published a notice of proposed rulemaking on the safety of gas transmission and gathering lines. The rule, expected to be finalized in 2019, 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. In December 2016, PHMSA issued interim final rules related to integrity management for storage operations. While some compliance costs remain uncertain, the Pipeline Safety Law resultedthese rules result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure; and therefore, resultstorage infrastructure. As such, the rule results in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businessesand transmission systems as evidenced by recent regulatory filings and resulting Commission Orders in Indiana and Ohio byfor Indiana Gas, SIGECO, and VEDO.

Environmental Considerations

Climate Change and Renewable Energy Considerations

The Company and the State of Indiana are subject to the requirements of the Clean Power Plan (CPP) rule, which requires a 32 percent reduction in carbon emissions from 2005 levels. While implementation of the rule remains uncertain due to the U.S. Supreme Court stay that was granted in February 2016 to delay the regulation while being challenged in court and a more recent proposal from the EPA which, if finalized, would result in the repeal of the CPP, regulations as written in the final rule may substantially affect both the costs and operating characteristics of the Company’sCompany's fossil fuel generating plantsplans and natural gas distribution businesses. A preliminary investigation demonstrated costsbusiness. In addition to comply wouldregulatory risk, the Company may be significant, first with regardsubject to operating expensesclimate change lawsuits which could result in substantial penalties or damages. Moreover, evolving investor sentiment related to the use of fossil fuels and later for capital expenditures as technology becomes availableinitiatives to control greenhouserestrict continued production of fossil fuels may have substantial impacts on the Company's electric generation and natural gas (GHG) emissions. However, these compliance cost estimates were based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. At this time compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain.distribution businesses.

Evolving Physical Security and Cybersecurity Standards and Considerations

The frequency, size and variety of physical security and cybersecurity threats against companies with critical infrastructure companies continues to grow, as do the evolving frameworks, standards and regulations intended to keep pace with and address these threats. There continues to be a marked increase in interest from both federal and state regulatory agencies related to physical security and cybersecurity in general, and specifically in critical infrastructure sectors, including the electric and natural gas sectors. The Company has dedicated internal and third party physical security and cybersecurity teams and maintains vigilance with regard to the communication and assessment of physical security and cybersecurity risks and the measures employed to protect information technology assets, critical infrastructure, the Company and its customers from these threats. Physical security and cybersecurity threats, however, constantly evolve in attempts to identify and capitalize on any weakness or unprotected areas. If these measures were to fail or if a breach were to occur, it could result in impairment or loss of critical functions, operating reliability, customer, or other confidential information. The ultimate effects, which are difficult to quantify with any certainty, are partially limited through insurance.

Increasing regulation and infrastructure replacement programs could affect Vectren's utility rates charged to customers, its costs, and its profitability.

Any additional expenses or capital incurred by the Company's utilities, as it relates to complying with increasing regulation and other infrastructure replacement activities are expected to be recovered from customers in its service territories through increased rates.  Increased rates have an impact on the economic health of the communities served.  New regulations could also negatively impact industries in the Company's service territory, including industries in which the Company operates.territories.

The Company's utilities' ability to obtain rate increases and to maintain current authorized rates of return depends in part on continued interpretation of laws within the current regulatory framework. There can be no assurance that the Company will be able to obtain rate increases, or rate supplements, or earn currently authorized rates of return. Indiana and Ohio have passed laws allowing utilities to recover a significant amount of the costs of complying with federal mandates or other infrastructure replacement expenditures, and in Ohio, other capital investments outside of a base rate proceeding. However, these activities may have at least a short-term adverse impact on the Company's cash flow and financial condition.

In addition, failure to comply with new or existing laws and regulations may result in fines, penalties, or injunctive measures and may not be recoverable from customers and could result in a material adverse effect on the Company's financial condition and results of operations.

Vectren's regulated energy delivery operations are subject to various risks.

A variety of hazards and operations risks, such as leaks, accidental explosions, and mechanical problems, are inherent in the Company’s gas and electric distribution and transmission activities.  If such events occur, they could cause substantial financial losses and result in injury to or loss of human life, significant damage to property, environmental pollution, and impairment of operations.  The location of pipelines, storage facilities, and the electric grid near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks.  These activities may subject the Company to litigation or administrative proceedings from time to time.  Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties or be resolved on unfavorable terms.  In accordance with customary industry practices, the Company maintains insurance against a significant portion, but not all, of these risks and

losses. To the extent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect the Company’s financial condition and results of operations.

Vectren’s regulated power supply operations are subject to various risks.

The Company’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, and increased purchase power costs.  Such operational risks can arise from circumstances such as facility shutdowns due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; and natural disasters. A recent change in operation announced by Alcoa could impact the future operations of a 300 MW unit at the Warrick Power Plant that is jointly owned with Alcoa Generating Corporation (AGC) as tenants in common. See Note 3 to the Company's Consolidated Financial Statements included in Item 8 for additional information. Finally,Further, the Company's coal supply is purchased largely from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier could impact operations.

The Company participates in the MISO.

The Company is a member of the MISO, which serves the electric 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.  As a result of such control, the Company’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted.

The need to expend capital for improvements to the regional electric transmission system, both to the Company’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected tocould be significant.  The Company timely

Also, the MISO allocates operating costs and the cost of multi-value projects throughout the region to its participating utilities such as the Company’s regulated electric utility, and such costs are significant.  Adjustments to these operating costs, including adjustments that result from participants entering or leaving the MISO, could cause increases or decreases to customer bills.  The Company timely recovers its portion of MISO operating expenses as tracked costs.

Volatility in the wholesale price of natural gas, coal, and electricity could reduce earnings and working capital.

The Company’s regulated operations have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal, and purchased power for the benefit of retail customers due to current state regulations, which, subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms.  However, significant volatility in the price of natural gas, coal, or purchased power may cause existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders, and new customers to select alternative sources of energy.  Decreases in volumes sold could reduce earnings.  The decrease would be more significant in the absence of constructive regulatory orders, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs.  A decline in new customers could impede growth in future earnings. In addition, during periods when commodity prices are higher than historical levels, working capital costs could increase due to higher carrying costs of inventories and cost recovery mechanisms, and customers may have trouble paying

higher bills leading to increased bad debt expenses. Additionally, significant oil price fluctuations and their economic impact on the ability to continue shale gas drilling may impact the pricesprice of natural gas and purchased power.

Increased conservation efforts and technology advances, which result in improved energy efficiency or the development of alternative energy sources, may result in reduced demand for the Company’s energy products and services.

The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and air conditioners and other heating and cooling devices as well as lighting, may reduce the demand for energy products. Prices for natural gas are subject to fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, the Company's prices generally increase, which may lead to customer conservation. Federal and state regulation may require mandatory conservation measures, which would reduce the demand for energy products. Certain federal or state regulation may also impose restrictions on building construction and design in efforts to increase conservation which may reduce demand for natural gas.gas and electricity. In addition, the Company's customers, especially large commercial and industrial customers, may choose to employ various technological advances to develop alternative energy sources, such as the construction and development of wind power, solar technology, or electric cogeneration facilities. Increased conservation efforts and the utilization of technological advances to increase energy efficiency or to develop alternate energy sources could lead to a reduction in demand for the Company’s energy products and services, which could have an adverse effect on its revenues and overall results of operations. Similar to many states, Indiana has permitted small customers to engage in net metering for several years.  In 2017, the Indiana Legislature passed a bill that provided for the phase out of subsidies being provided to those customers. The Company has experienced some growth in these applications, but the overall level of net metering on its system remains relatively low.

Nonutility Operating Risks

The performance of Vectren’s nonutility businesses is subject to certain risks.

Execution of the Company’s nonutility business strategies and the success of efforts to invest in and develop new opportunities in the nonutility business area are subject to a number of risks.  These risks include, but are not limited to, the effects of weather; changing market conditions, including changes in market prices for various forms of energy; failure of installed performance contracting products to operate as planned; failure to properly estimate the cost to construct projects; loss of key management and knowledge-based employees, including the inability to attract and retain qualified employees; the inability to effectively maintain regulatory compliance programs; potential legislation or regulations that may limit CO2 and other greenhouse gasesgas emissions; operating accidents that may require environmental remediation; creditworthiness of customers

The Company’s nonutility businesses support its regulated utilities pursuant to service contracts by providing infrastructure services.  In most instances, the Company’s ability to maintain these service contracts depends upon regulatory discretion, and there can be no assurance that it will be able to obtain future service contracts, or that existing arrangements will not be revisited.

Nonutility infrastructure services operations could be adversely affected by a number of factors.

Infrastructure Services results are dependent on a number of factors.  The industry is competitive and many of the contracts are subject to a bidding process.  Should Infrastructure Services be unsuccessful in bidding contracts, results of operations could be impacted.  Infrastructure Services enters into a variety of contracts, some of which are fixed price.  Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work, the profit margin realized on any single project could be reduced.  Additionally, Infrastructure Services contributes to several multiemployer pension plans under collective bargaining agreements with unions representing employees covered by those agreements.  A significant increase to the funding requirements could adversely impact financial condition, results of operations, and cash flows.  Changes in legislation and regulations impacting the sectors in which the customers served by Infrastructure Services operate could impact operating results.  Other risks include, but are not limited to: failure to properly construct pipeline infrastructure; cancellation of projects by customers and/or reductions in the scope of the projects; changes in the timing of projects; the inability to obtain materials and equipment required to perform

services from suppliers and manufacturers; and changes in the market prices of oil and natural gas that would affect the demand for infrastructure construction.

Nonutility energy services operations could be adversely affected by a number of factors.

Energy Services results are dependent on a number of factors.  The industry is competitive and many of the contracts are subject to a bidding process.  Should Energy Services be unsuccessful in bidding contracts or losefor certain federal licensing,Indefinite Delivery/Indefinite Quantity (IDIQ) contracts, results of operations could be impacted.  Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work, the profit margin realized on any single project could be reduced.  Changes in legislation, regulations and regulationsgovernment policies impacting the industries in which the customers served by Energy Services, operate could impact operating results.  Other risks include, but are not limited to: continuation of the federal Energy Savings Performance Contracting (ESPC) and Utility Energy Services Contract (UESC) programs; the inability of customers to source outside financing forfinance projects; risks associated with projects owned or operated; failure to appropriately design, construct, or operate projects; and cancellation of projects by customers and/or reductions in the scope of the projects.

Other Corporate Operating Risks

The CompanyVectren is exposed to physical and financial risks related to the uncertainty of climate change.

A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to the Company’s service territories.  These impacts could include, but are not limited to, population shifts; changes in the level of annual rainfall; changes in the overall average temperature; and changes to the frequency and severity of weather events such as thunderstorms, wind, tornadoes, and ice storms that can damage infrastructure.  Such changes could impact the Company in a number of ways including the number and type of customers in the Company’s service territories; an increase to the cost of providing service; an increase in the amount of service interruptions; impacts to the Company's workforce; and an increase in the likelihood of capital expenditures to replace damaged infrastructure.

To the extent climate change impacts a region’s economic health, it may also impact the Company’s revenues, costs, and capital structure and thus the need for changes to rates charged to regulated customers.  Rate changes themselves can impact the economic health of the communities served and may in turn adversely affect the Company’s operating results.

Customers' energy needs vary with weather conditions. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease. Increased energy use due to weather changes may require additional generating resources, transmission, and other infrastructure to serve increased load. Decreased energy use may require the Company to retire current infrastructure that is no longer needed.

Vectren’s subsidiariesnonutility operations have performance and warranty obligations, some of which are guaranteed by Vectren.

In the normal course of business, certain subsidiaries of the Company issue performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and support warranty obligations.  Vectren Corporation, as the parent company, will from time to time guarantee its subsidiaries’ commitments.  These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral.  The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees.

Certain of Vectren's nonutility operations face a customer concentration risk. The loss of such a customer would result in a decline in revenue and could have an adverse effect on the results of operations and cash flows.

From time to time, revenues and total outstanding receivables from various customers of Infrastructure Services canmay individually account for more than 5 percent of the Company's consolidated operating revenues and receivables, respectively. While the Company believes that the loss of any one customer would not have a material impact on its financial position or results of

operations, the loss of a customer of this significance or a significant decline in related customer revenues could have an adverse effect on the results of operations and cash flows of Infrastructure Services.

From time to time, Vectren is subject to material litigation and regulatory proceedings.

From time to time, the Company may be subject to material litigation and regulatory proceedings, including matters involving compliance with federal and state laws, regulations or other matters.  There can be no assurance that the outcome of these matters will not have a material adverse effect on the Company’s business, prospects, corporate reputation, results of operations, or financial condition.

The investment performance of pension plan holdings and other factors impacting pension plan costs could impact Vectren’s liquidity and results of operations.

The costs associated with the Company sponsored retirement plans, including certain multiemployer plans at Infrastructure Services, are dependent on a number of factors, such as the rates of return on plan assets; discount rates; the level of interest rates used to measure funding levels; changes in actuarial assumptions;assumptions including assumed mortality; future government regulations; changes in plan design, and Company contributions.  In addition, the Company could be required to provide for significant funding of these defined benefit pension plans.  Such cash funding obligations could have a material impact on liquidity by reducing cash flows for other purposes and could negatively affect results of operations.

Catastrophic events, such as terrorist attacks, acts of civil unrest, and acts of God, may adversely affect Vectren’s facilities and operations, corporate reputation, financial condition and corporate reputation.results from operations.

Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornadoes, terrorist acts, cyber attacks or similar occurrences could adversely affect the Company’s facilities, operations, corporate reputation, financial condition and results of operations.  Either a direct act against Company-owned generating facilities or transmission and distribution infrastructure or an act against the infrastructure of neighboring utilities or interstate pipelines that are used by the Company to transport power and natural gas could result in the Company being unable to deliver natural gas or electricity for a prolonged period. Additionally, an act against the Company's nonutility businesses could result in the Company being unable to provide utility infrastructure services, or performance-based energy contracting services, or sustainable infrastructure services. In the event of a severe disruption resulting from such events, the Company has contingency plans and employs crisis management to respond and recover operations. Despite these measures, if such an occurrence were to occur, results of operations and financial condition could be materially adversely affected.

Cyber attacks or similar occurrences may adversely affect Vectren's facilities, operations, corporate reputation, financial condition and results of operations.

The Company relies on information technology networks, telecommunications, and systems to, among other things, 1) operate its generating facilities,facilities; 2) engage in asset management activities,and customer service activities; 3) process, transmit and store sensitive electronic information including intellectual property, proprietary business information and that of the Company’s suppliers and business partners, personally identifiable information of customers and employees, and data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities, and 4) process financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal, and tax requirements. Despite the Company’s security measures, any information technology system may be vulnerable to attacks by hackers or breached due to malfeasance, employee error, sabotage, or other disruptions. Security breaches, extended outage or general communication disruption of this information technology infrastructure could lead to system disruptions, business interruption, generating facility shutdowns or unauthorized disclosure of confidential information. In particular, any data loss or information security lapses resulting in the compromise of personal information or the improper use or disclosure of sensitive or classified information could result in claims, remediation costs, regulatory sanctions against the Company, loss of current and future contracts, and serious harm to the Company's reputation. While the Company has implemented policies, procedures, protective technologies, and controls to prevent and detect these activities, not all disruptions and misconduct may be prevented. In the event of a severe infrastructure system disruption or generating facility shutdown resulting from such events, the Company has contingency plans and employs crisis management to respond and recover operations. Despite these measures, if such an attack or security breach were to

occur, results of operations and financial condition could be materially adversely affected. The ultimate effects, which are difficult to quantify with any certainty, are partially limited through insurance.

Workforce risks could affect Vectren’s financial results.

The Company is subject to various workforce risks, including but not limited to, the risk that it will be unable to 1) attract and retain qualified and diverse personnel; 2) effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; 3) react to a pandemic illness; 4) manage the migration to more defined contribution and high deductible employee benefit packages; and 5) that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.

Vectren’s ability to effectively manage its third party contractors, agents, and business partners could have a significant impact on the Company’s business and reputation.

The Company relies on third party contractors and other agents and business partners to perform some of the services provided to its customers, as well as assist with the monitoring of physical security and cybersecurity functions. Any misconduct by these third parties, or the Company’s inability to properly manage them, could adversely impact the provision of services to customers and the quality of services provided. Misconduct could include fraud or other improper activities, such as falsifying records and violations of laws. Other examples could include the failure to comply with the Company’s policies and procedures or with government procurement regulations, regulations regarding the use and safeguarding of classified or other protected information, legislation regarding the pricing of labor and other costs in government contracts, laws and regulations relating to

Vectren may not have adequate insurance coverage for all potential liabilities.

Natural risks, as well as other hazards associated with the Company’s operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The Company maintains an amount of insurance protection that management believes is appropriate, but there can be no assurance that the amount of insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject. A claim for which the Company is not adequately insured could materially harm the Company’s financial condition. Further, due to the cyclical nature of the insurance markets, management cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently in place.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

Gas Utility Services

Indiana Gas owns and operates fourfive active gas storage fields located in Indiana covering 58,10061,124 acres of land with an estimated ready delivery from storage capability of 5.66.79 BCF of gas with maximum peak day delivery capabilities of 155,500164,000 MCF per day.  Indiana Gas also owns and operates three propaneliquified petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery of 33,000 MCF of manufactured gas per day.  In addition to its company ownedcompany-owned storage and propane capabilities, Indiana Gas has contracted for 16.115.1 BCF of interstate natural gas pipeline storage service with a maximum peak day delivery capability of 239,200230,000 MMBTU per day.  Indiana Gas’ gas delivery system includes approximately 13,00013,200 miles of distribution and transmission mains, all of which are in Indiana except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported by Indiana Gas to ultimate customers in Indiana.

SIGECO owns and operates three active underground gas storage fields located in Indiana covering 6,100 acres of land with an estimated ready delivery from storage capability of 5.37.03 BCF of gas with maximum peak day delivery capabilities of 88,000109,000 MCF per day.  In addition to its company owned storage delivery capabilities, SIGECO has contracted for 0.4 BCF of interstate natural gas pipeline storage service with a maximum peak day delivery capability of 16,80017,000 MMBTU per day.  SIGECO's gas delivery system includes 3,2003,300 miles of distribution and transmission mains, all of which are located in Indiana.

SIGECO's transmission system consists of 1,0271,028 circuit miles of 345Kv, 138Kv345kV, 138kV and 69Kv69kV lines.  The transmission system also includes 3634 substations with an installed capacity of 4,8284,900 megavolt amperes (Mva).  The electric distribution system includes 4,5504,543 circuit miles of lower voltage overhead lines and 418462 trench miles of conduit containing 2,2082,405 circuit miles of underground distribution cable.  The distribution system also includes 9185 distribution substations with an installed capacity of 1,9872,100 Mva and 54,76754,919 distribution transformers with an installed capacity of 2,3472,440 Mva.

SIGECO owns utility property outside of Indiana approximating 24 miles of 138Kv138kV and 345Kv345kV electric transmission lines, which are included in the 1,0271,028 circuit miles discussed above. These assets are located in Kentucky and interconnect with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky.

Property Serving as Collateral

SIGECO's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures.

ITEM 3.  LEGAL PROCEEDINGS

The Company is party to various legal proceedings and 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. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated financial statements are included in “Item 8 Financial Statements and Supplementary Data.”

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

PART II

ITEM 5.  MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER

PURCHASES OF EQUITY SECURITIES

Market Data, Dividends Paid, and Holders of Record

On November 5, 20152, 2017 the board of directors declared a dividend of $0.40$0.45 per share, payable on December 1, 2015,2017, to common shareholders of record on November 16, 2015.15, 2017.

As of January 31, 2016,2018, there were 8,2177,759 registered shareholders of the Company’s common stock.

Quarterly Share Purchases

Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans; however, no such open market purchases were made during the quarter ended December 31, 2015.2017.

Dividend Policy

Common stock dividends are payable at the discretion of the Board of Directors, out of legally available funds.  The Company’s policy is to target a 60 to 65 percent payout;consolidated payout ratio; however, this percentage has varied and could continue to vary due to short-term earnings volatility.  The Company has increased its dividend for 5658 consecutive years.  While the Company is under no contractual obligation to do so, it intends to continue to pay dividends and to increase the dividend annually.  Nevertheless, should the Company’s financial condition, operating results, capital requirements, or other relevant factors change, future dividend payments, and the amounts of these dividends, will be reassessed.

ITEM 6.  SELECTED FINANCIAL DATA

The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Executive Summary of Consolidated Results of Operations

In this discussion and analysis, the Company analyzes contributions to consolidated earnings and earnings per share from its Utility Group and Nonutility Group separately. Because each group operates independently and offers different energy related products and services, the analysis separately addresses the opportunities and risks that arise from each group's distinct competencies and business strategies.

The Utility Group generates revenue primarily from the delivery of natural gas and electric service to its customers.  The primary source of cash flow for the Utility Group results from the collection of customer bills and payment for goods and services procured for the delivery of gas and electric services. The Company segregates its regulated utility operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The activities of, and revenues and cash flows generated by, the Nonutility Group are closely linked to the utility industry, and the results of those operations are generally impacted by factors similar to those impacting the overall utility industry.  In addition, there are other operations, referred to herein as Corporate and Other, that include unallocated corporate expenses such as advertising and certain charitable contributions, among other activities.

The Company has a disclosure committee consisting of senior management as well as financial management.  The committee is actively involved in the preparation and review of the Company’s SEC filings.

Results for the year ended December 31, 20152017 were earnings of $197.3$216.0 million, or $2.39$2.60 per share, compared to earnings of $166.9$211.6 million, or $2.02$2.55 per share for the year ended December 31, 20142016 and $136.6$197.3 million, or $1.66$2.39 per share for the year ended December 31, 2013. Results include the operating results and the loss on the sale of Vectren Fuels, through the date of sale of August 29, 2014, when the Company exited the coal mining business. In June 2013, ProLiance Holdings, LLC (ProLiance or ProLiance Holdings) exited the gas marketing business through the disposition of certain net assets of its energy marketing subsidiary, ProLiance Energy, LLC (ProLiance Energy). In 2014, excluding the loss on the disposition and operating results attributable to Vectren Fuels, consolidated net income for the year was $188.0 million, or $2.28 per share. In 2013, excluding the impact of the loss on disposition and operating results attributable to the Company's investment in ProLiance, consolidated net income was $174.1 million, or $2.12 per share.

Use of Non-GAAP Performance Measures and Per Share Measures

This discussion and analysis contains non-GAAP financial measures that exclude the results related to Coal Mining in 2014the revaluation of deferred income taxes as of December 31, 2017 as a result of the Tax Cuts and ProLiance in 2013,Jobs Act ("TCJA") that was signed into law on December 22, 2017, and a 2017 expense related to a non-recurring multi-year contribution to the respective years of disposition.Vectren Foundation, a 501(c)(3) charitable organization, affiliated with but separate from Vectren Corporation.

Management uses consolidated net income consolidatedand earnings per share and Nonutility Group net income (loss)(EPS), excluding the results from Coal Mining in 2014 and ProLiance in 2013,non-recurring activity, to evaluate its results. Coal Mining and ProLiance results that are excluded from the GAAP measures are inclusive of holding company costs (corporate allocations, interest and taxes). Management believes analyzing underlying and ongoing business trends is aided by the removal of Coal Mining and ProLiance resultsthis non-recurring activity and the rationale for using such non-GAAP measures is that the Company has now exited the coal mining and gas marketing businesses.would not expect these items to be indicative of ongoing operations. Management believes this presentation provides the best representation of the overall results and certain components of the financial statements for ongoing operations.

A material limitation associated with the use of these measures is that measures excluding Coal Mining and ProLiance results donon-recurring activity does not include all costsactivity recognized in accordance with GAAP. Management compensates for this limitation by prominently displaying a reconciliation of these non-GAAP performance measures to their closest GAAP performance measures. This display also provides financial statement users the option of analyzing results as management does or by analyzing GAAP results.

Contribution to Vectren's basic EPS

Per share earnings contributions of the Utility Group, Nonutility Group excluding Coal Mining results in 2014 and ProLiance results in 2013, and Corporate and Other are presented and are non-GAAP measures. Such per share amounts are based on the earnings contribution of each group included in the Company’s consolidated results divided by the Company’s basic average shares outstanding during the period. The earnings per share of the groups do not represent a direct legal interest in the assets and liabilities allocated to the groups; instead they represent a direct equity interest in the Company's assets and liabilities as a whole. These non-GAAP measures are used by management to evaluate the performance of individual businesses. In addition, other items giving rise to period over period variances, such as weather, may be presented on an after tax and per share basis.  These amounts are calculated at a statutory tax rate divided by the Company’s basic average shares outstanding during the period. Accordingly, management believes these measures are

useful to investors in understanding each business’ contribution to consolidated earnings per share and in analyzing consolidated period to period changes and the potential for earnings per share contributions in future periods. Per share amounts of the Utility Group and the Nonutility Group are reconciled to the GAAP financial measure of basic EPS by combining the two. Any resulting differences are attributable to results from Corporate and Other operations. The non-GAAP financial measures disclosed by the Company should not be considered a substitute for, or superior to, financial measures calculated in accordance with GAAP, and the financial results calculated in accordance with GAAP.

The following table reconciles consolidated net income, consolidated basic EPS and Nonutility Group net income (loss)certain components of the financial statements from the GAAP measure to those results excluding Coal Mining resultsthe non-GAAP measure for non-recurring activity in 2014 and ProLiance results in 2013, the respective years of disposition.2017.

Detailed Discussion of Results of Operations

Results of Operations of the Utility Group

The Regulatory Environment

Gas and electric operations are regulated by the IURC, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters specific to its Indiana customers (the operations of SIGECO and Indiana Gas).  The retail gas operations of VEDO are subject to regulation by the PUCO.

Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather.  Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed, and as the Company’s utilities have implemented conservation programs.  In the

In all natural gas service territories, the commissions have authorized bare steel and cast iron replacement programs.  In Indiana, state laws were passed in 2012 and 2013 that expand the ability of utilities to recover, outside of a base rate proceeding, certain costs of federally mandated projects and other significant gas distribution and transmission infrastructure replacement investments. Legislation was passed in 2011 in Ohio that supportsupports the investment in other capital projects, allowing

the utility to defer the impacts of these investments until its next base rate case. The Company has received approval to implement these mechanisms in both states.

In 2017, SIGECO’s electric service territory started recovering certain costs of significant electric distribution and transmission infrastructure replacement investments. The electric service territory also currently recovers certain transmission investments outside of base rates.  The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives.

Tracked Operating Expenses

Gas costs and fuel costs incurred to serve Indiana customers are two of the Company’s most significant operating expenses.  Rates charged to natural gas customers in Indiana contain a gas cost adjustment clause.clause (GCA). The GCA clause allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on actual experience and subject to caps that are based on historical experience.  Electric rates contain a fuel adjustment clause (FAC) that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel.  The net energy cost of purchased power, subject to an approved variable benchmark based on The New York Mercantile Exchange (NYMEX) natural gas prices, is also timely recovered through the FAC.

GCA and FAC procedures involve periodic filings and IURC hearings to establish price adjustments for a designated future period.  The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred. Since April 2010, the Company has not been the supplier of natural gas in its Ohio territory.

The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test.  In the periods presented, the Company has not been impacted by the earnings test.

In Indiana, gas pipeline integrity management operating costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of typical base rate recovery.  In addition, certain operating costs, including depreciation associated with federally mandated investments, gas and electric distribution and transmission infrastructure replacement investments, and regional electric transmission assets not in base rates are also recovered by mechanisms outside of typical base rate recovery.  

In Ohio, expenses such as uncollectible accounts expense, costs associated with exiting the merchant function, and costs associated with the infrastructure replacement program and other gas distribution capital expenditures are subject to recovery outside of base rates. 

Revenues and margins in both states are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.

Over the last eight years, regulatory orders establishing new base rates have been received by each utility.  SIGECO’s electric territory received an order in April 2011, with rates effective May 2011, and its gas territory received an order and implemented rates in August 2007.  Indiana Gas received its most recent base ratean order and implemented rates in February 2008, and VEDO received an order in January 2009, with implementation in February 2009.  The orders authorize a return on equity

See the Rate and Regulatory Matters section of this discussion and analysis for more specific information on significant proceedings involving the Company’s utilities over the last three years.

Utility Group Margin

In addition, the Company separately reflects regulatory expense recovery mechanisms within Gas utility margin and Electric utility margin.  These amounts represent dollar-for-dollar recovery of other operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility.  Following is a discussion and analysis of margin generated from regulated utility operations.

Gas utility marginUtility Margin

Gas utility margin and throughput by customer type follows:

Electric utility marginUtility Margin (Electric utility revenues less Cost of fuel & purchased power)

Electric utility margin and volumes sold by customer type follows:

Electric retail utility margins were $382.4$367.0 million for the year ended December 31, 20152017 and, compared to 2014,2016, decreased by $6.7$25.8 million. Results reflect a decrease in large customer margin of $15.2 million, primarily due to the completion of a large customer transitioning to a cogeneration facility resulting in lower usage of approximately 610 GWh in 2017. Electric results,margin, which areis not protected by weather normalizing mechanisms, reflectreflects a $3.6$5.4 million decrease from weather in small customer margin related to weather as heating degree days were 8880 percent of normal compared to 84 percent of normal in 2015 compared to 107 percent of normal in 2014. While2016 and cooling degree days were 111 percent of normal in 2015 compared to 104125 percent of normal in 2014,2016. Margin from regulatory expense recovery mechanism decreased $4.1 million in 2017.

Electric retail utility margins were $392.8 million for the year ended December 31, 2016 and, compared to 2015, increased by $10.4 million. Electric margin reflects a $3.0 million increase from weather in small customer margin resulting from the increase inas cooling degree days only partially offset the large decrease caused by the warmer winterwere 125 percent of normal in 2016 compared to 111 percent of normal in 2015. As energy conservation initiatives continue, the Company's lost revenue recovery mechanism related to electric conservation programs contributed increased margin of $0.7$2.4 million compared to the prior year.year, however was offset by a decrease in small customer usage of $1.2 million. Results also reflect a decreasean increase in large customer usage of $1.5$2.2 million largely driven by timing of customer plant maintenance resulting in lower customer throughput.throughput in 2015. Margin from regulatory expense recovery mechanisms decreased $2.0increased $4.1 million as operating expenses associated with the electric conservation programs decreased.

The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of the MISO’s regional transmission expansion plans and also markets and sells its generating and transmission capacity to optimize the return on its owned assets.  Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load.  Further detail of MISO off-system margin and transmission system margin follows:

Utility Group Operating Expenses

Other Operating

 

Depreciation & Amortization

Taxes Other Than Income Taxes

Other Income-Net

Income Taxes

For the year ended December 31, 2015,2017, Utility Group federal and state income taxes were $88.1$60.7 million, compared to $83.2$99.5 million in 20142016 and $85.3$88.1 million in 2013.  While2015.  The decrease in tax expense in 2017 compared to 2016 is due primarily to the tax benefit from the revaluation of deferred income taxes increasedrelated non-rate regulated balances in an amount totaling $23.2 as a result of the TJCA enacted on December 22, 2017, and lower income before taxes as a result of the multi-year funding of the Vectren Foundation. The increase in income taxes in 2016 compared to 2015 is primarily due to increased income in 2015, the income tax rate in 2015 decreased from 2014 due to an increase in2016 and research and development tax credits. The decreasecredits recognized in income taxes in 2014 compared to 2013 was due to the revaluation of Utility Group deferred income taxes related to the sale of Vectren Fuels, Inc. in 2014. Additionally, 2015 and 2014 reflect increases in tax deductions for domestic production activity compared to 2013.2015. 

Gas Rate and Regulatory Matters

In April 2011, Indiana Senate Bill 251 (Senate Bill 251) was signed into Indiana law. The law 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 Commission,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.

In April 2013, Indiana Senate Bill 560 (Senate Bill 560) was signed into Indiana law. This legislation 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, that, 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 and recoveredfor 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.

Indiana Recovery and Deferral Mechanisms

Requests for Recovery under Indiana Regulatory Mechanisms

On September 26, 2014,In March 2016, the OUCC filedIURC issued an appealOrder re-approving approximately $890 million of the IURC's finding that the remaining value of retired assets replaced during theCompany’s gas infrastructure modernization projects should not be netted against the cost being recoveredrequested in the tracking mechanism.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 June 2015,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 issued an opinion in favor ofaffirmed 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 that affirmed the IURC's August 2014 Orderhas received additional Orders approving the infrastructure plan.

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 Company’s initial request for recovery of the revenue requirement through June 30, 2014 as part of its approved seven-year plan. Also, consistent with the guidelines set forth in the original August 2014 Order, the IURC approved the Company’s update to its seven-year plan, to reflect changes to project prioritization as a result of both additional risk modeling and changes to estimated project costs.

At December 31, 20152017 and December 31, 2014,2016, the Company has regulatory assets related to the Plan totaling $28.6$78.0 million and $11.4$51.1 million, respectively, associated with the return on investment as well as the deferral of depreciation and other operating expenses.respectively.

Electric Rate and Regulatory Matters

In JulyAs 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, a coalition of twenty-one states, including Indiana, filed a petition with the U.S. Supreme Court seeking reviewremaining investment going into service in 2016. As of December 31, 2017, the decision of the appellate court that found the EPA appropriately based its decisionCompany has approximately $12.8 million deferred related to list coaldepreciation and oil fired generation units as a source of the pollutants at issue solely on those pollutants’ impact on public health. On June 29, 2015, the U.S. Supreme Court reversed the appellate court decision on the basis of the EPA’s failureoperating expenses, and $4.7 million deferred related to consider costs before determining whether it was appropriate and necessary to regulate steam electric generating units under Section 112 of the Clean Air Act. The Court did not vacate the rule, but remanded the MATS rule back to the appellate court for further proceedings consistent with the opinion.post-in-service carrying costs. MATS compliance was required to commencebeginning April 16, 2015, and the Company continues to operate in full compliance with the MATS rule. On December 15, 2015, the appellate court agreed to keep the current MATS rule in place while the agency completes the supplemental cost analysis ordered by the Court.

that affirmed the IURC’s findings with regard to equipment required to comply with MATS and certain national pollutant discharge elimination system rules (approximately $35 million). The Courtbut remanded the case back to the IURC so that it can maketo determine whether a certificate of public convenience and necessity (CPCN) should be issued for the findings required by statute with regard to equipment required by the NOV. On June 22, 2016, the IURC issued an Order granting the Company a CPCN for the NOV (approximately $40 million).required equipment. On February 12,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.

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 reopenconstruct 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 evidentiary recordcost 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 case in order to submit additional evidence.Company’s next base rate proceeding. The Company has opposedexpects an order from the motion and believes the IURC already has a sufficient recordCommission in this case. As it pertains to the equipment requirement requiredproceeding by the NOV, given the Commission’s previous approvalfirst half of this project, the Company believes the Commission will make these findings and issue a new order in support of the project.2019.

On February 16, 2016,20, 2018, the EPA notified statesCompany 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 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 compliance with all applicable SO2 limits ina safe and reliable manner while dramatically lowering emissions of carbon and the carbon intensity of its permits,electric generating fleet. If authorized by the Commission, by 2024 the Company is currently workingplans 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 stateCompany’s ongoing

Further, as part of Indiana on voluntary measures thatits commitment to a culture of compliance excellence and continuous improvement, the Company may take without significant incrementalcontinues 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 ensure that Posey County remainscomply with these laws and regulations are significant to its results of operations and financial condition. Similar to the costs associated with federal mandates in attainment with the 2010 One Hour SO2 NAAQS. The Company's coal-fired generating fleetPipeline Safety Law, Senate Bill 251 is 100 percent scrubbed for SO2 and 90 percent controlled for NOx.also applicable to federal environmental mandates impacting SIGECO's electric operations.

Coal Ash Waste Disposal, Ash Ponds and Water

Coal Combustion Residuals Rule

In December 2014,April 2015, the EPA releasedfinalized its final Coal Combustion Residuals (CCR) rule which regulates ash as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). On April 17, 2015, the final rule was published in the Federal Register. The final rule allows beneficial reuse of ash and the Companymajority of the ash generated by the Company’s generating plants will continue to reuse a majority of its ash. Legislation is currently being consideredbe 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 through citizen suits. Additionally, aspects of the CCR rule isare currently being challenged by multiple parties in judicial review proceedings. Opening briefs were filed by those partiesIn August, the EPA issued guidance to states to clarify their ability to implement the Federal CCR rule through state permit programs as allowed in Decemberthe WIIN Act legislation. Alternative compliance mechanisms for groundwater, corrective action and other areas of 2015,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 full briefing not expectedthe guidance issued to be complete until May 2016.states.  While the state program development and EPA reconsideration move forward, the existing CCR compliance obligations remain in effect.

Under the finalexisting 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 preliminary cost estimates to retirefor the retirement of the ash ponds at the end of their useful lives, based on its interpretation of the available closure alternatives contemplated in the final rule thatrule. 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. At this time the Company does not believe that theseThese rules are not applicable to itsthe Company's Warrick generating unit, as this unit ishas historically been part of a larger generating station that predominantly serves an adjacent industrial facility. The

Throughout 2016 and 2017, the Company continueshas continued to refine site specific estimates and now estimates the assumptions, engineering analyses andcosts to be in the range of $45 million to $135 million. Significant factors impacting the resulting cost estimates. Furtherestimates 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, and the continued refinement of assumptions, mayor the inability to beneficially reuse the ash, either from a technological or economical perspective, could result in estimated costs that could be significantly in excess of the current range of $35 million to $80 million.range.

At September 30, 2015,As of December 31, 2017, the Company had recorded an approximate $25$40 million asset retirement obligation (ARO). The recorded ARO reflectedreflects the present value of the approximate $35$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.

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. OnIn September, 30, 2015, the EPA released finalfinalized 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. Current wastewater discharge permits for the Brown and Culley power plants expire in October and December 2016, respectively. The Company is working with the State on permit renewals which will include a compliance schedule for ELGs. In no event will compliance with the ELGs be required prior to November 2018. The ELGs work in tandem with the recently releasedaforementioned 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.

Cooling Water Intake Structures

Section 316(b) of the Clean Water Act requires that 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 state level 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 that capital investments will likely be in the range of $4 million to $8 million.