ITEM 1A.
RISK FACTORS
The nature of our business subjects us to a number of uncertainties and risks. The following risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These important factors and other matters discussed herein could cause our future actual results or outcomes to differ materially.
OPERATING RISKS
Our financial performance depends on the successful operation of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.
Operating electric generating facilities, the coal mine and electric and natural gas transmission and distribution systems involves risks, including:
•
Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;
•
Interruptions to supply of fuel and other commodities used in generation and distribution. Our utilities purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit our utilities’ ability to operate their facilities;
•
Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;
•
Operating hazards such as leaks, mechanical problems and accidents, including explosions affecting our natural gas distribution system, which could impact public safety, reliability and customer confidence;
•
Operational limitations imposed by environmental and other regulatory requirements;
•
Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak Plant;
•
Labor relations. Approximately 25% of our employees are represented by a total of eight collective bargaining agreements;
•
Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2018, approximately 18% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;
•
Inability to recruit and retain skilled technical labor; and
•
Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions.
Changes in the interpretation of the Tax Cuts and Jobs Act (“TCJA”) could adversely affect us.
On December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and modifies or repeals many business deductions and credits. The new tax law contains several provisions that impacted our 2017 and 2018 financial results.
The TCJA includes provisions limiting interest deductibility in certain circumstances. While we expect to maintain deductibility of interest expense, the lower tax rate reduces the tax benefits associated with interest deductibility on holding company debt that is not recovered in the regulatory construct.
If there are future changes and amendments to the TCJA, and if we are unable to obtain reasonable outcomes with our utility regulators in passing future benefits of the TCJA back to customers, or if our interpretations on the provisions of depreciation or interest deductibility in the TCJA change, our results of operations, financial position or cash flows could be materially impacted.
Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce profitability.
The construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve many risks, including:
•
The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;
•
Contractual restrictions upon the timing of scheduled outages;
•
The cost of supplying or securing replacement power during scheduled and unscheduled outages;
•
The unavailability or increased cost of equipment;
•
The cost of recruiting and retaining or the unavailability of skilled labor;
•
Supply interruptions, work stoppages and labor disputes;
•
Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;
•
Opposition by members of public or special-interest groups;
•
Weather interferences;
•
Availability and cost of fuel supplies;
•
Unexpected engineering, environmental and geological problems; and
•
Unanticipated cost overruns.
The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.
Operating results can be adversely affected by variations from normal weather conditions.
Our utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial position or cash flows.
Our businesses are located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These events could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial position and cash flows.
Our Mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, strong winds, rain or flooding.
Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.
A portion of our net income is attributable to sales of wholesale and off-system electricity and natural gas. Energy prices are influenced by many factors outside our control, including, among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions, and the rules, regulations and actions of system operators in those markets. As a result, wholesale power markets may be subject to significant, unpredictable price fluctuations over relatively short periods of time.
Our Mining operations require reliable supply of replacement parts, explosives, fuel, tires and steel-related products. If the cost of these increase significantly, or if sources of supplies and mining equipment become unavailable to meet our replacement demands, our productivity and profitability could be lower than our current expectations.
Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.
Our revenues, results of operations and financial condition are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our results of operations, financial position or cash flows.
Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.
Our Electric Utilities, Gas Utilities and Power Generation segments rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to customers, to supply our natural gas-fired power plants and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.
Our utilities are subject to pipeline safety and system integrity laws and regulations that may require significant capital expenditures or significant increases in operating costs.
Compliance with pipeline safety and system integrity laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers through rates. Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers through rates and could result in a material impact on our results of operations, financial position or cash flows.
Our energy production, transmission and distribution activities, and our storage facilities for our natural gas involve numerous risks that may result in accidents and other catastrophic events that could give rise to additional costs and cause a substantial loss to us.
Inherent in our natural gas and electricity transmission and distribution activities, as well as in our transportation and storage of natural gas and our Mining operations, are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public lands), environmental pollution, impairment of our operations and substantial financial losses to us. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.
Threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways.
Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power, deliver natural gas and by delaying their development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.
The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.
A cyber attack may disrupt our operations, or lead to a loss or misuse of confidential and proprietary information and create a potential liability.
We use and operate sophisticated control, SCADA, and information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric and gas distribution systems, could result in a full or partial disruption of our electric and/or gas operations. Cyber attacks targeting other key information technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data as a result of a cyber attack could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.
We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems or our third-party vendors’ systems were to fail or be breached by a cyber attack or a computer virus and be unable to recover in a timely way, we would be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised which could have a material adverse effect not only on our financial results, but on our public reputation as well.
Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, SEC and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our operations and/or our financial results.
Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, wind and pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.
Our current or future development and expansion activities may not be successful, which could impair our ability to execute our growth strategy.
Execution of our growth plan is dependent on successful ongoing and future development and expansion activities. We can provide no assurance that we will be able to complete development projects or expansion activities we undertake or continue to develop attractive opportunities for growth. Factors that could cause our development and expansion activities to be unsuccessful include:
•
Our inability to obtain required governmental permits;
•
Our inability to complete capital projects in a timely manner;
•
Our inability to secure just and reasonable utility rates through regulatory proceedings;
•
Our inability to obtain financing on acceptable terms, or at all;
•
The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business;
•
Our inability to attract and retain management or other key personnel;
•
Our inability to negotiate acceptable construction, fuel supply, power sales or other material agreements;
•
Reduced growth in the demand for utility services in the markets we serve;
•
Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves or our power generation capacity;
•
Fuel prices or fuel supply constraints;
•
Pipeline capacity and transmission constraints;
•
Competition within our industry and with producers of competing energy sources; and
•
Changes in tax rates and policies.
Utilities
Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable.
Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.
If market or other conditions adversely affect operations or require us to make changes to our business strategy in any of our utility businesses, we may be forced to record a non-cash goodwill impairment charge. Any significant impairment of our goodwill related to these utilities would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.
We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2018. A substantial portion of the goodwill is related to the SourceGas Acquisition and the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in economic conditions and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.
Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.
Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.
Mining
If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.
We conduct surface mining operations that are subject to operations, reclamation and closure standards. We estimate our total reclamation liabilities based on permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers and by government regulators. The estimated liability can change significantly if actual costs vary from our original assumptions or if government regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or the timing of these expenses change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial position.
Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three-dimensional structural modeling, and any inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserves.
The process of estimating coal reserves is uncertain and requires interpretations and modeling. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserve estimates. The accuracy of reserve estimates is a function of engineering and geological interpretation, conditions encountered during actual reserve recovery and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that require reserve revisions either upward or downward from prior reserve estimates.
FINANCING RISKS
Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, cost of capital and other operating costs.
Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on reasonable terms, or at all. A credit rating downgrade, particularly to a sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.
Derivatives regulations could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.
We use natural gas derivative instruments for our hedging activities for our Gas and Electric Utilities’ operations. We may also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral for certain swap transactions we enter into. In addition, our exchange-traded futures contracts are subject to futures margin posting requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.
Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to accounting requirements associated with such activities.
We use various financial contracts and derivatives, including futures, forwards, options and swaps to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. The difference in accounting may result in volatility in reported results, even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.
Our use of derivative financial instruments could result in material financial losses.
From time to time, we have sought to limit a portion of the potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.
Market performance or changes in other assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or cash flows.
As discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria) and several defined post-retirement healthcare plans and non-qualified retirement plans that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial
assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.
We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.
As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital, equity or debt service funds.
There is no assurance as to the amount, if any, of future dividends because they depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.
We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings, and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices, and general economic and market conditions.
In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.
National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position or cash flows.
A future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.
Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting insurance businesses, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited to environmental hazards, fire-related liability from natural events or inadequate facility maintenance, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation of gas in pipelines.
Increasing costs associated with our healthcare plans and other benefits may adversely affect our results of operations, financial position or liquidity.
The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our healthcare plans may adversely affect our results of operations, financial position or cash flows.
Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery.
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.
A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perception of our business, operating results and stock price could be adversely affected.
ENVIRONMENTAL RISKS
Developments in federal and state laws concerning GHG regulations and air emissions relating to climate may adversely impact operations, financial results and materially increase our generation and production costs, which could render some of our generating units uneconomical to operate and maintain.
To the extent climate change occurs, our businesses could be adversely impacted. We believe it is likely that any such resulting impacts would occur very gradually over a very long period of time and thus would be difficult to quantify. Warmer temperatures in our natural gas service territories, or cooler temperatures in our electric service territories could adversely affect financial results through lower natural gas volumes delivered, lower MWh sold and associated lower revenues.
We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming and Colorado. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the section “Environmental Matters”.
Due to uncertainty as to the final outcome of federal climate regulation, legal challenges, state CPP developments or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial position or cash flows.
New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or reduction of load of coal-fired power generation facilities and potential increased load of our combined cycle natural gas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants
from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.
The business segments may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on the business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.
The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption.
Future regulations may require further reductions in emissions of mercury, hazardous pollutants, SO2, NOx, volatile organic compounds, particulate matter and GHG, which are released into the air when coal is burned. These requirements could require the installation of costly emission control technology or the implementation of other measures.
Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. The EPA was directed to repeal, revise and replace the CPP rule. At this time, it is not known what effect this will have on coal as a domestic energy source, and could have a significant impact on our mining operations.
Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our results of operations, financial position or cash flows could be adversely impacted.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 19, “Commitments and Contingencies”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Annual Report.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of December 31, 2018, we had 3,689 common shareholders of record and approximately 41,000 beneficial owners, representing all 50 states, the District of Columbia and 7 foreign countries.
We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 30, 2019 meeting, our Board of Directors declared a quarterly dividend of $0.505 per share, equivalent to an annual dividend of $2.02 per share. The 2019 equivalent rate of $2.02 per share would mark 2019 as the 49th consecutive annual dividend increase for the Company.
For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
UNREGISTERED SECURITIES ISSUED
There were no unregistered securities sold during 2018.
ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(Minor differences may result due to rounding)
SELECTED FINANCIAL DATA continued
____________________________________
(a)
The increase in 2016 includes the debt associated with the SourceGas acquisition (see Note 6 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K).
(b)
On November 1, 2017, we made the decision to divest our Oil and Gas assets. 2017 includes an after-tax fair value impairment on held-for-sale assets of $13 million. 2016 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax ceiling test impairment charges to crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million (see Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K).
(c)
On April 14, 2016, Black Hills Electric Generation sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2018, 2017 and 2016 was reduced by $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.
(d)
2017, 2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively. 2016 and 2015 also include after-tax internal labor costs attributable to the SourceGas Acquisition of $9.1 million and $3.0 million that otherwise would have been charged to other segments.
(e)
On November 1, 2018, we issued 6.3 million shares of common stock upon conversion of our Equity Units. In 2016, we issued 1.97 million shares at an average share price of $60.95 under our ATM equity offering program. In November 2015, we issued 6.3 million shares of common stock, par value $1.00 per share at a price of $40.25.
(f)
Calculated based on Net income (loss) from continuing operations available for common stock.
(g)
The increase in 2018 included a $73 million tax benefit resulting from legal entity restructuring. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
(h)
Net income (loss) from continuing operations for the year ended December 31, 2018 included approximately $4.0 million of income tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. The (expense) benefit impact to our operating segments and Corporate and Other for the year ended December. 31, 2018 was: Electric Utilities ($4.2) million; Gas Utilities $0.5 million; Power Generation ($0.7) million; Mining ($0.5) million; and Corporate and Other $0.9 million, respectively. Net Income from continuing operations for the year ended December 31, 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. The (expense) benefit impact to our operating segments and Corporate and Other for the year ended December 31, 2017 was: Electric Utilities $23 million; Gas Utilities ($6.8) million; Power Generation $24 million; Mining $2.7 million; and Corporate and Other ($35) million, respectively.
For additional information on our business segments see Item 7.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed 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.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2018, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2018.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of December 31, 2018. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.
Black Hills Corporation
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, the related notes, and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2019, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 19, 2019
We have served as the Company’s auditor since 2002.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2018, of the Company, and our report dated February 19, 2019 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 19, 2019
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Note 16 for additional disclosures related to Comprehensive Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Note 17 for supplemental disclosure of cash flow information.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
Dividends per share paid were $1.93, $1.81 and $1.68 for the years ended December 31, 2018, 2017 and 2016, respectively.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2018, 2017 and 2016
(1)
BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Segment Reporting
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming.
All of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5.
On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21.
Use of Estimates and Basis of Presentation
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5.
Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information.
Variable Interest Entities
We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.
Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12.
Cash and Cash Equivalents and Restricted Cash
We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash. For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash and cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, electric energy and capacity.
We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.
In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Following is a summary of accounts receivable as of December 31 (in thousands):
Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):
________________
(a) Represents allowance balances added with the SourceGas acquisition.
Revenue Recognition
Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:
•
Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.
•
Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black
Hills also sells excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.
•
Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.
•
Other non-regulated services - Our Gas and Electric Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.
The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the year ended December 31, 2018. Sales tax and other similar taxes are excluded from revenues.
The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.
Revenue Not in Scope of ASC 606
Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Black Hills Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Black Hills Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues.
Significant Judgments and Estimates
TCJA Revenue Reserve
The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $37 million during the year ended December 31, 2018. As of December 31, 2018, $19 million has been returned to customers and approximately $18 million remains in reserve as a current regulatory liability.
Unbilled Revenue
To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed above. We do not typically incur costs that would be capitalized to obtain or fulfill a contract.
Practical Expedients
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.
We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.
Materials, Supplies and Fuel
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our Natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.
Investments
We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared.
In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of December 31, 2018.
The following table presents the carrying value of our investments (in thousands) as of December 31:
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability.
The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.
Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.
Goodwill and Intangible Assets
Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives.
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process.
The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information.
Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies.
We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands):
Our intangible assets represent easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
_________________
(a)
The 2018 addition is related to the Busch Ranch 1 Wind Farm contract intangible asset. See Note 4 for further information.
(b)
Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.
Asset Retirement Obligations
Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability.
We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. Additional information is included in Note 8 and 21.
Fair Value Measurements
Financial Instruments
We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:
Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.
Level 2 - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 - Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.
Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. We currently do not have any Level 3 investments.
Valuation Methodologies for Derivatives
The commodity contracts for the Electric and Gas Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and options Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market pricing data. In addition, the fair value for the over-the-counter swaps and option derivatives, if material, include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.
Additional information on fair value measurements is included in Notes 10, 11 and 18 .
Derivatives and Hedging Activities
All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.
In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980.
We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists.
Deferred Financing Costs
Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Regulatory Accounting
Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.
We had the following regulatory assets and liabilities as of December 31 (in thousands):
__________
(a)
Recovery of costs, but we are not allowed a rate of return.
(b)
In addition to recovery of costs, we are allowed a rate of return.
(c)
In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. The recovery period for these costs is less than a year.
Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions. The recovery period for these costs is less than a year.
Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2018 are hedged over a maximum forward term of 2 years.
Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.
Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI, including costs being amortized from the Aquila and SourceGas Transactions.
Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.
Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details.
Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.
Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.
Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.
Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing.
Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016.
Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.
Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs.
Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the
income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.
Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense.
Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA.
Revenue Subject to Refund - Revenue subject to refund at December 31, 2018 represent revenue reserved as a result of the TCJA. See above “TCJA Revenue Reserve” under Revenue recognition for further disclosure.
See Note 13 for additional information on regulatory matters.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. See Notes 13 and 15 for additional information.
It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss).
We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.
Earnings per Share of Common Stock
Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans.
A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands):
The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive for the years ended December 31 (in thousands):
Business Combinations
We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for the SourceGas Acquisition.
Noncontrolling Interests
We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests.
Share-Based Compensation
We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.
Recently Issued Accounting Standards
Leases, ASU 2016-02
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the original guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.
We adopted this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we elected the practical expedient which provides for no assessment of these easements. Further, we adopted the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We elected the “package of three” practical expedient. We have implemented a new lease accounting system and adjusted related procedures and controls accordingly. On January 1, 2019, we will record an operating lease right of use asset and an off-setting operating lease obligation liability of approximately $3.2 million. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.
Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.
Simplifying the Test for Goodwill Impairment, 2017-04
In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows.
Recently Adopted Accounting Standards
Revenue from Contracts with Customers, ASU 2014-09
Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 1.
Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07
Effective January 1, 2018, we adopted ASU 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the year ended December 31, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15
Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.
Statement of Cash Flows: Restricted Cash, ASU 2016-18
Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, ASU 2018-02
In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU was issued to address industry concerns regarding the application of current accounting guidance to certain provisions of the new tax reform legislation. This ASU permits entities to make a one-time reclassification from AOCI to retained earnings for stranded tax effects resulting from the newly enacted corporate tax rate. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCI. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods therein, and early adoption is permitted. We have implemented this ASU effective December 22, 2017, the enactment date of the TCJA, which resulted in a reclassification of $7.0 million of stranded tax effects from AOCI to retained earnings. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.
Improvements to Employee Share-Based Payment Accounting, ASU 2016-09
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment of $3.2 million to Retained earnings in the Consolidated Balance Sheets as of the date of adoption, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.
(2) ACQUISITION
Acquisition of SourceGas
On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. SourceGas is a 100% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado.
Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million Equity Units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility.
In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million for the year ending December 31, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Consolidated Statements of Income.
Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income of $15 million, attributable to SourceGas for the period from February 12 through December 31, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers.
We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.
The final purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion, net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million, resulted in goodwill of $940 million. We had up to one year from the acquisition date to finalize the purchase price allocation. The working capital adjustment received in 2016 of $11 million reflected changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities.
Conditions of SourceGas Acquisition Regulatory Approval
The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions. We have met all conditions as set forth in the commissions’ approval orders.
Pro Forma Results (unaudited)
We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the year ended December 31, 2016. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2016:
We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the year ended December 31, 2016, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2016, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%.
These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2016, or that may be obtained in the future.
Seller’s noncontrolling interest
As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder for the 0.5% retained interest. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million.
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
_____________
(a)
The plant acquisition adjustment is included in rate base and is being recovered with 12 years remaining.
(b)
Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031.
_____________
(a)
Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides.
___________
(a)
Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $18 million.
___________
(a)
Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million.
(4) JOINTLY OWNED FACILITIES
Our consolidated financial statements include our share of several jointly-owned utility and non-regulated facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.
•
South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.
•
South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the SPP region. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.
•
South Dakota Electric owns 52% of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant.
•
Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations.
At December 31, 2018, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
Jointly Owned facility - Related Party
Colorado Electric owns 50% of the Busch Ranch I Wind Farm while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. On December 11, 2018, Black Hills Electric Generation purchased its 50% ownership interest in the 29 MW Busch Ranch I Wind Farm from AltaGas for $16 million. Colorado Electric retains responsibility for operations of the wind farm. We recorded this purchase as an asset acquisition at fair value with $8.7 million of the purchase price recorded as wind generation assets, and $7.6 million recorded as an intangible asset, reflective of the fair value of the PPA. Black Hills Electric Generation will provide its share of energy from the wind farm to Colorado Electric through a new PPA, which replaces the PPA Colorado Electric had with AltaGas, expiring in October 2037.
(5) BUSINESS SEGMENT INFORMATION
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
Segment information was as follows (in thousands):
__________________
(a)
The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
(b)
On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information.
_________________
(a)
Includes accruals for property, plant and equipment.
_______________
(a)
The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
________________
(a)
Income tax benefit (expense) includes a tax benefit of $73 million at our Gas Utilities resulting from legal entity restructuring. See Note 15.
________________
(a)
Discontinued operations includes oil and gas property impairments. See Note 21.
________________
(a)
Discontinued operations includes oil and gas property impairments. See Note 21.
Corporate expense reallocation
In accordance with GAAP, indirect corporate operating costs previously allocated to BHEP were not reclassified to discontinued operations. These corporate operating costs for 2017 were reallocated to our operating segments; allocated interest was reclassified to Corporate and Other. Indirect corporate operating costs for 2016 were reclassified to Corporate and Other. The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 is as follows (in thousands):
________________________
(a)
Includes interest allocations in 2017 and 2016 of approximately $4.9 million and $5.6 million, respectively.
(6) LONG-TERM DEBT
Long-term debt outstanding was as follows (dollars in thousands):
_______________
(a)
Variable interest rate, based on LIBOR plus a spread.
(b)
See Note 12 for RSN details.
(c)
Variable interest rate.
(d)
Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2018 and December 31, 2017, respectively.
Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2018.
Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by South Dakota Electric and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.
Debt Transactions
On December 12, 2018, we paid off the $250 million, 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to pay off this debt.
On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt.
The issuance of these new senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see Note 12). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate).
On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with this term loan is determined based upon our corporate credit rating from S&P, Fitch, and Moody’s for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings and Eurodollar borrowings were 0.000% and 0.700%, respectively, at
December 31, 2018.
On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan.
Amortization Expense
Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):
Dividend Restrictions
Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2018, we were in compliance with these covenants.
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2018:
•
Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2018, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.
(7) NOTES PAYABLE
Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2018, we were in compliance with all of these financial covenants.
We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):
Revolving Credit Facility and CP Program
On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at December 31, 2018. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2018. Margins and the commitment fee rate decreased in August 2018 due to our upgraded credit rating from S&P.
We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net (payments) under the CP Program during 2018 were $(26) million and our notes outstanding as of December 31, 2018 were $186 million. As of December 31, 2018, the weighted average interest rate on CP Program borrowings was 2.88%.
As of December 31, 2018 and December 31, 2017, we had outstanding letters of credit totaling approximately $22 million and approximately $27 million, respectively.
Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income (Loss). See Note 6 above for additional details.
Debt Covenants
Under our Revolving Credit Facility and term loan agreements we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries.
Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:
(8) ASSET RETIREMENT OBLIGATIONS
We have identified legal retirement obligations related to reclamation of coal mining sites in the Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment, retirement of gas pipelines at our Gas Utilities and asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment.
The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
_____________________
(a)
The Gas Utilities’ Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.
(b)
The increase in the Mining Revision to Prior Estimates was primarily driven by higher costs associated with back-filling the pit with overburden removed during the mining process.
We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time.
We had identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells. These obligations were classified as held for sale at December 31, 2017. See Note 21.
(9) RISK MANAGEMENT ACTIVITIES
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.
Market Risk
Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed to the following market risks, including, but not limited to:
•
Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand;
•
Interest rate risk associated with our variable debt.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.
Our credit exposure at December 31, 2018 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.
Utilities
The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.
For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss).
We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from January 2019 through December 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the
gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly.
The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of:
__________
(a)
Term reflects the maximum forward period hedged.
(b)
As of December 31, 2018, 1,542,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.
(c)
Volumes exclude contracts that qualify for normal purchase, normal sales exception.
Based on December 31, 2018 prices, a $0.4 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.
Cash Flow Hedges
The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2018, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2018, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred.
Derivatives Not Designated as Hedge Instruments
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2018, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our Utilities were $6.2 million and $12 million at December 31, 2018 and 2017, respectively.
(10) FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements
There have been no significant transfers between Level 1 and Level 2 derivative balances during 2018 or 2017. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.
A discussion of fair value of financial instruments is included in Note 11. Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 21. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):
Fair Value Measures by Balance Sheet Classification
As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis, aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.
The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):
Derivatives Offsetting
It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities.
As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2018 and 2017, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure.
Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2018 was as follows (in thousands):
Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2017 were as follows (in thousands):
(11) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):
_______________
(a)
Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy.
(b)
Notes payable consist of commercial paper borrowings. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
(c)
Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.
(d)
Carrying amount of long-term debt is net of deferred financing costs.
Cash and Cash Equivalents
Included in cash and cash equivalents is cash, money market mutual funds, and term deposits. As part of our cash management process, excess operating cash is invested in money market mutual funds with our bank. Money market mutual funds are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.
Restricted Cash and Equivalents
Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.
Notes Payable and Long-Term Debt
For additional information on our notes payable and long-term debt, see Note 6 and Note 7.
(12) EQUITY
Equity Units
On November 23, 2015, we issued 5.98 million Equity Units for total gross proceeds of $299 million. Each Equity Unit had a stated amount of $50.00 and consisted of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028.
On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued on November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units. See Note 6 for additional information.
Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds were used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt.
At-the-Market Equity Offering Program
On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017. During the twelve months ended December 31, 2016, we issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions.
Equity Compensation Plans`
Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 800,180 shares available to grant at December 31, 2018.
Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2018, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):
Stock Options
The Company has not issued any stock options since 2014 and has 68,749 stock options outstanding at December 31, 2018. The amount of stock options granted during the last three years, and related exercise activity are not material to the Company’s consolidated financial statements.
Restricted Stock
The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.
The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.
A summary of the status of the restricted stock and restricted stock units at December 31, 2018, was as follows:
The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows:
As of December 31, 2018, there was $8.9 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 years.
Performance Share Plan
Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.
The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.8 million at December 31, 2018 would be reclassified as a liability.
Outstanding performance periods at December 31 were as follows (shares in thousands):
A summary of the status of the Performance Share Plan at December 31 was as follows:
_____________________
(a)
The grant date fair values for the performance shares granted in 2018, 2017 and 2016 were determined by Monte Carlo simulation using a blended volatility of 21%, 23% and 24%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.
The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:
There were no performance plan payouts during the years ended December 31, 2018, 2017, and 2016.
On January 29, 2019, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2016 through December 31, 2018 performance period was at the 74.8 percentile of its peer group and confirmed a payout equal to 161.9% of target shares, valued at $5.7 million. The payout was fully accrued at December 31, 2018.
As of December 31, 2018, there was $3.2 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.8 years.
Shareholder Dividend Reinvestment and Stock Purchase Plan
We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2018, there were 253,418 shares of unissued stock available for future offering under the plan.
Preferred Stock
Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding.
Sale of Noncontrolling Interest in Subsidiary
Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes.
A partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.
Net income available for common stock for the years ended December 31, 2018, 2017 and 2016 was reduced by $14 million, $14 million, and $10 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments.
Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.
We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31:
(13) REGULATORY MATTERS
TCJA revenue reserve
The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform, was primarily from the change in the federal tax rate from 35% to 21% affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $37 million during the year ended December 31, 2018. As of December 31, 2018, $19 million has been returned to customers.
A list of states where benefits to customers of federal tax reform have been approved is summarized below.
In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below.
Excess Deferred Income Taxes
As of December 31, 2018 and 2017, we have a regulatory liability associated with TCJA related items of approximately $311 million and $301 million, respectively. The majority of this regulatory liability relates to excess deferred taxes resulting from the remeasurement of deferred tax assets and liabilities in 2017. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. See Note 15 for more information.
Electric Utilities Regulatory Activity
Corriedale Wind Project
On December 17, 2018, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a new $57 million, 40 MW wind generation project near Cheyenne, Wyoming. If approved, the 40 MW Corriedale Wind Energy Project would be jointly owned by South Dakota Electric and Wyoming Electric. The project would be largely constructed and placed in service during 2020.
Wyoming Electric Integrated Resource Plan
On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019.
Wyoming Electric Settlement
On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of December 31, 2018, we have recorded a liability of $6.0 million related to the PCA.
South Dakota Electric Common Use System (CUS)
The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.
South Dakota Electric Settlement
On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a 6-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances as of the settlement date of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset as of the settlement date of $14 million, previously unamortized, is also being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million. The June 16, 2017 settlement had no impact to base rates.
Gas Utilities Regulatory Activity
Colorado Gas
On October 10, 2018, we received approval from the CPUC for a request to consolidate our Colorado gas utility operations into a new utility entity. The Colorado portion of Black Hills Gas Distribution, LLC, will be combined with Black Hills/Colorado Gas Utility Company, Inc., into a new company named Black Hills Colorado Gas, Inc. The two companies being merged currently serve 187,000 Colorado customers doing business as Black Hills Energy. On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity.
Wyoming Gas
On November 20, 2018, we received approval from the WPSC for a CPCN to construct a new $54 million, 35-mile natural gas pipeline to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The pipeline, known as the Natural Bridge Pipeline, is planned to be placed in service in late 2019.
Arkansas Gas
On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new annual revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.
Wyoming Gas
On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.
Kansas Gas
On June 19, 2018, Kansas Gas received approval from the Kansas Corporation Commission for an annual increase in revenue of $0.6 million based on inclusion of approximately $8.0 million of eligible capital investments under the Gas System Reliability Rider. The Kansas Legislature passed legislation in 2018 enabling the annual eligible investments to double from approximately $8.0 million to $16 million effective January 1, 2019.
RMNG
In Colorado, new rates for RMNG went into effect June 1, 2018 after we reached a settlement which was approved by the CPUC. The settlement included $1.1 million in annual revenue increases and an extension of the SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.
Nebraska Gas
On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NPSC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered.
On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million, which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018.
(14) OPERATING LEASES
We have entered into lease agreements for office facilities, communication tower sites, land and equipment. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands):
_______________
(a)
The decrease in rent expense is primarily driven by current year expiration of office leases and by purchases of facilities previously leased.
The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
(15) INCOME TAXES
TCJA
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018 we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.
Tax benefit related to legal entity restructuring
As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018. As a result of these transactions, additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $73 million were recorded to income tax benefit (expense) on the Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities.
Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
Included in discontinued operations is a tax benefit of $2.6 million, $8.4 million and $49 million for 2018, 2017 and 2016, respectively.
The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
_______________
(a)
Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.
(b)
Legal entity restructuring - see above.
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
_________________________
(a)
The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded.
(b)
Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.
(c)
On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. During the year ended December 31, 2018, we recorded approximately $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded approximately $8.0 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017.
(d)
Legal entity restructuring - see above.
At December 31, 2018, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):
As of December 31, 2018, we had a $0.4 million valuation allowance against the state NOL carryforwards. Our 2018 analysis of the ability to utilize such NOLs resulted in a $0.4 million increase in the valuation allowance offset by a $1.2 million decrease from expired NOL. This resulted in an increase to tax expense of $0.4 million and a decrease to the state NOL carryforward of $1.2 million. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2018. This projected decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years. In certain states, the carryforward period is limited to 5 years. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.
The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.1 million.
We recognized no interest expense associated with income taxes for the years ended December 31, 2018, December 31, 2017 and December 31, 2016. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2018 and December 31, 2017.
The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which files a separate consolidated tax return from Black Hills Corporation and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. Black Hills Corporation is no longer subject to examination for tax years prior to 2015.
We had deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. In 2016, the settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable.
As of December 31, 2018, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2019.
State tax credits have been generated and are available to offset future state income taxes. At December 31, 2018, we had the following state tax credit carryforwards (in thousands):
As of December 31, 2018, we had an $11 million valuation allowance against the state tax credit carryforwards. Our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $3.5 million of which approximately $1.9 million resulted in an increase to tax expense. The remaining $1.6 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2018. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.
(16) OTHER COMPREHENSIVE INCOME
We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.
The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands):
Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):
(17) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(18) EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.
The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.
The SourceGas Retirement Savings Plan was merged into the Black Hills Corporation Retirement Savings Plan effective December 31, 2017. The plan design of the Black Hills Corporation 401(k) Plan applies to all eligible employees as of January 1, 2018.
Defined Benefit Pension Plan (Pension Plan)
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria.
The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.
The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2018, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 71% liability-hedging assets.
Our Pension Plan is funded in compliance with the federal government’s funding requirements.
Plan Assets
The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:
Supplemental Non-qualified Defined Benefit Plans
We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.
Plan Assets
We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.
Non-pension Defined Benefit Postretirement Healthcare Plans
BHC sponsors retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans for participating business units are pre-funded via VEBAs. Pre-65 retirees as well as a grandfathered group of post-65 Cheyenne Light, Fuel and Power (“CLFP”) retirees and a grandfathered group of post-65 former SourceGas employees who retired prior to January 1, 2017 receive their retiree medical benefits through the Black Hills self-insured retiree medical plans.
Healthcare coverage for Medicare-eligible BHC and Black Hills Utility Holdings retirees is provided through an individual market healthcare exchange. Medicare-eligible SourceGas employees who retired after December 31, 2016 also receive retiree medical coverage through an individual market healthcare exchange.
Plan Assets
We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provide for partial pre-funding via VEBAs and a Grantor Trust. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Kansas and Iowa. We do not pre-fund the Healthcare Plans for those employees outside Arkansas, Kansas and Iowa.
Plan Contributions
Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands):
While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2019.
Fair Value Measurements
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.
The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
_____________
(a)
Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.
_____________
(a)
Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.
Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:
Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.
Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1.
Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2.
AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.
Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.
Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2.
The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.
Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.
Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 20% of the shares may be redeemed at the end of each month with a 10-day notice and full redemptions are available at the end of each quarter with 45-day notice, and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.
Other Plan Information
The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI:
Benefit Obligations
Employee Benefit Plan Assets
____________________
(a)
Assets of VEBAs and Grantor Trust.
The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):
Accumulated Benefit Obligation
Components of Net Periodic Expense
Net periodic expense consisted of the following for the year ended December 31 (in thousands):
____________________
(a)
Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.
For the year ended December 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense, on the Consolidated Statements of Income. For the years ended December 31, 2017 and 2016, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Consolidated Statements of Income. See Note 1 for additional information.
AOCI
For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
Assumptions
_____________________________
(a)
The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs.
(b)
The expected rate of return on plan assets is 6.00% for the calculation of the 2019 net periodic pension cost.
The healthcare benefit obligation was determined at December 31 as follows:
Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details.
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
(19) COMMITMENTS AND CONTINGENCIES
Power Purchase and Transmission Services Agreements
Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:
•
Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.
•
South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.
•
South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp expiring December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.
•
Wyoming Electric’s PPA with Duke Energy’s Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.
•
Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric.
•
South Dakota Electric’s PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.
Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):
________________
(a)
On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I Wind Farm from AltaGas. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm.
(b)
PPAs with Cargill expired on December 31, 2016.
Power Purchase Agreement - Related Party
On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in the 29 MW Busch Ranch I Wind Farm, previously owned by AltaGas. Black Hills Electric Generation will provide its 14.5 MW share of energy from the wind farm to Colorado Electric through a new PPA that replaces the PPA that Colorado Electric had with AltaGas, expiring in October 2037.
Other Gas Supply Agreements
Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044.
Purchase Commitments
We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.
Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2018, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):
Purchases under these contracts totaled $27 million, $65 million and $31 million for 2018, 2017 and 2016, respectively.
The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands):
Future Purchase Agreement - Related Party
Wyoming Electric’s PPA for 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on December 31, 2022, includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.1 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35-year life starting January 1, 2009. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment.
Power Sales Agreements
Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:
•
During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.
•
South Dakota Electric has an agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.
•
During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.
•
South Dakota Electric has a PPA with MEAN expiring May 31, 2028. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.
•
South Dakota Electric has an agreement through December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.
Related Party Lease
Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.
Reimbursement Agreement
We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.
Environmental Matters
We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.
Solid Waste Disposal
Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.
In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.
Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.
Reclamation Liability
For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
Under its land lease for Busch Ranch I, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
See Note 8 for additional information.
Manufactured Gas Processing
As a result of the Aquila Transaction, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.0 million regulatory asset for manufactured gas processing sites; see Note 1.
As of December 31, 2018, our estimated liabilities for Iowa’s MGP site currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of the site as of December 31, 2018 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.
For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K.
Legal Proceedings
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.
In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.
(20) GUARANTEES
We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee.
We had the following guarantees in place as of (in thousands):
_______________________
(a)
We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.
(b)
BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made.
(21) DISCONTINUED OPERATIONS
Results of operations for discontinued operations have been classified as Net (loss) from discontinued operations in the accompanying Consolidated Statements of Income. Current assets and current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Consolidated Balance Sheets as “Current assets held for sale” and “Current liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our consolidated financial statements.
Oil and Gas Segment
On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of December 31, 2018, we have sold our oil and gas properties and completed the exit of the Oil and Gas business.
In 2017, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale were reasonable based on the information that was known when the estimates were made. At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no adjustments made to the fair value of our held for sale liabilities.
For the year ended December 31, 2018, we recorded $3.3 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of BHEP assets.
Total assets and liabilities of BHEP at December 31, 2017 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the final disposals occurring in 2018.
At December 31, 2017, the Oil and Gas segment’s net deferred tax assets were primarily comprised of basis differences on oil and gas properties.
BHEP’s Other current liabilities at December 31, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 consisted primarily of ARO obligations relating to plugging and abandonment of oil and gas wells.
Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):
Full Cost Accounting
Historically, we used the full cost method of accounting for oil and gas production activities. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized.
Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized.
Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period.
Impairment of long-lived assets
As discussed above, at December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required a write down of $20 million. There were no adjustments made to the fair value of our held for sale liabilities.
As a result of continued low commodity prices throughout 2016, we recorded non-cash ceiling test impairments of our Oil and Gas assets totaling approximately $92 million for the year ended December 31, 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead.
During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the ceiling test impairments noted above.
(22) OIL AND GAS RESERVES (Unaudited)
On November 1, 2017, we initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. On November 1, 2017, we stopped the use of the full-cost method of accounting for our oil and gas business. The assets and liabilities have been classified as held for sale and the results of operations are included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As a result, our oil and gas reserves were no longer considered significant in 2017. Oil and Gas reserves were considered significant in 2016. For more information, see Note 21.
Costs Incurred
Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
Reserves
The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and a reconciliation of the changes. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 31 years of practical experience in petroleum engineering and over 29 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
________________________
(a)
Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods.
(b)
A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production.
(c)
For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable.
Capitalized Costs
Following is information concerning capitalized costs for the years ended December 31 (in thousands):
Results of Operations
For more on oil and gas producing activities included in discontinued operations, see Note 21. Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
Unproved Properties
Unproved properties not subject to amortization at December 31, 2016 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million of interest during 2016 on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool.
The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):
Standardized Measure of Discounted Future Net Cash Flows
Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):
The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):
Changes in the standardized measure from “revisions of previous quantity estimates” were driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications were generally made at the well level each year through the reserve review process. These production profile modifications were based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments were reviewed each year and were often modified in response to current market conditions for items such as permitting and service availability.
(23) QUARTERLY HISTORICAL DATA (Unaudited)
The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2018 and 2017.
Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million, respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.
Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter.
Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition.
Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13 million.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2018. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2018, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting is presented on Page 86 of this Annual Report on Form 10-K.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2019 Annual Meeting of Shareholders, which is incorporated herein by reference.
Executive Officers
David R. Emery, age 56, has been Executive Chairman since January 1, 2019, Chairman and Chief Executive Officer from 2016 through 2018, and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer - Retail Business Segment from 2003 to 2004 and Vice President - Fuel Resources from 1997 to 2003. Mr. Emery has 29 years of experience with the Company.
Linden R. Evans, age 56, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer - Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 17 years of experience with the Company.
Scott A. Buchholz, age 57, has been our Senior Vice President - Chief Information Officer since the closing of the Aquila Transaction in 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 38 years of experience with the Company, including 28 years with Aquila.
Brian G. Iverson, age 56, has been Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary since February 1, 2019. He served as Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 15 years of experience with the Company.
Richard W. Kinzley, age 53, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 19 years of experience with the Company.
Jennifer C. Landis, age 44, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 17 years of experience with the Company.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information required under this item is set forth in the Proxy Statement for our 2019 Annual Meeting of Shareholders, which is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2019 Annual Meeting of Shareholders, which is incorporated herein by reference.
EQUITY COMPENSATION PLAN INFORMATION
The following table includes information as of December 31, 2018 with respect to our equity compensation plans. These plans include the 2005 Omnibus Incentive Plan and 2015 Omnibus Incentive Plan.
_________________________
(1)
Includes 187,362 full value awards outstanding as of December 31, 2018, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 235,748 shares of unvested restricted stock were outstanding as of December 31, 2018, which are not included in the above table because they have already been issued.
(2)
Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 2019 Annual Meeting of Shareholders, which is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 2019 Annual Meeting to Shareholders, which is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Consolidated Financial Statements
Financial statements required under this item are included in Item 8 of Part II
2.
Schedules
Schedule II - Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2018, 2017 and 2016
3.
Exhibits
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto.
SCHEDULE II
Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
3.
Exhibits
________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
†
Indicates a board of director or management compensatory plan.
ITEM 16.
FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.