While management expects that the SourceGas Transaction will result in various benefits, including a significant amount of operating efficiencies and other financial and operational benefits, there can be no assurance regarding when or the extent to which we will be able to realize these operating efficiencies or other benefits. Events outside of our control, including but not limited to regulatory changes or developments, could also adversely affect our ability to realize the anticipated benefits from the transaction.

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, oil and gas properties, the coal mine and electric and natural gas distribution systems involves risks, including:

Operational limitations imposed by environmental and other regulatory requirements;

Interruptions to supply of fuel and other commodities used in generation and distribution. ~~The Utilities Group purchases~~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 ~~the Utilities Group’s~~our utilities’ ability to operate their facilities;

Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak plant;

Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2016, approximately 27% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;

Inability to recruit and retain skilled technical labor;

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, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;

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;

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. For example, as described in more detail under “Legal Proceedings,” a fire investigator concluded that a forest and grassland fire in the western Black Hills of Wyoming and South Dakota in 2012 was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power, and claims have been made against us related to the fire;outages;

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; and

Labor relations. Approximately ~~30%~~27% of our employees are represented by a total of ~~six~~seven collective bargaining agreements.

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. ~~Because~~Demand for natural gas ~~is primarily used for residential and commercial heating, the demand for this product~~ depends heavily upon ~~winter weather~~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 seasons. 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. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial condition and ~~results of operations.~~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 factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these storms. 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 condition and cash flows.

Our ~~coal mining~~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. Additionally, weather patterns can also affect electricity demand. Extreme temperatures, both hot and cold, cause increased power usage, and therefore, increased generating requirements and the use of coal. Conversely, mild temperatures could result in lower electrical demand.

~~Weather~~While our planned activity related to our Oil and Gas segment is limited, weather conditions can also limit or temporarily halt our drilling, completion and producing activities ~~and other~~at our crude oil and natural gas operations. Primarily in the winter and spring, our operations can be curtailed because of cold, snow and wet ~~conditions. Severe~~conditions, and severe weather could ~~further curtail~~exacerbate these ~~operations, including drilling, and completion of new wells or production from existing wells.~~operational issues. In addition, weather conditions and other events could temporarily impair our ability to transport our crude oil and natural gas production.

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 contract and off-system wholesale 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. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets may be subject to significant, unpredictable price fluctuations over relatively short periods of time.

The success of our crude oil and natural gas operations is affected by the prevailing market prices of crude oil and natural gas. Crude oil and natural gas prices and markets historically have been, and are likely to continue to be, unpredictable. A decrease in crude oil or natural gas prices ~~would~~ not only ~~reduce~~reduces revenues and profits, but ~~would~~ also ~~reduce~~reduces the ~~quantities~~quantity and value of reserves that are commercially recoverable and may result in charges to earnings for impairment of the net capitalized cost of these assets. Crude oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control.

The proliferation of domestic crude oil and natural gas shale plays in recent years has provided the market with an abundant new supply of crude oil and natural ~~gas. The increase in domestic natural~~ gas, ~~supply~~which has driven prices down in recent years. ~~The ratio of crude oil to natural gas prices remains at high levels, far in excess of the six to one heating value equivalent ratio.~~ There is also risk that ~~the~~ increased domestic ~~crude oil~~ resources could drive both crude oil and natural gas prices lower.

Our mining operation requires reliable supplies 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. ~~In recent years, industry-wide~~

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 ~~exceeded~~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 ~~growth for certain surface mining equipment~~ and ~~off-the-road tires. As a result, lead times for procuring some items generally increased~~transmission and/or distribution facilities obsolete prior to ~~several months~~the end of their useful lives. Each of these factors could materially affect our results of operations, financial position and ~~prices for these items increased significantly.~~cash flows.

Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations. ~~If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered.~~

Our Electric Utilities, ~~Group~~Gas Utilities and Power Generation segment rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to ratepayers, 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 in rates. Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers in rates and could result in a material impact on our financial results.

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 production, transportation and storage of crude oil and 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 and could adversely affect our results of operations, financial position and liquidity.~~ways.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power 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 disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation) within our system or within a neighboring system. Any such disruption could have a material impact on our financial results.

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 ~~operate in a highly regulated industry that requires the continuous~~ use and ~~operation of~~operate sophisticated 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 could further add to a full or partial disruption to 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. FERC, through the North American Electric Reliability Corporation, requires~~assets, including certain safeguards ~~be implemented to deter cyber attacks.~~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 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. In addition, FERC delegated certain aspects of authority for enforcement of electric system reliability standards to the NERC, with similar penalty authority for violations. If a serious regulatory violation occurred and penalties were imposed by FERC or another federal agency, this actionbusiness, 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, pipeline or drilling projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events could disrupt or impair our operations, create additional costs and cause substantial loss to us.

Inherent in our natural gas and electricity transmission and distribution activities, as well as our production, transportation and storage of crude oil and natural gas and our coal mining operations, are a variety of hazards and operating risks, such as leaks, blow-outs, fires, releases of hazardous materials, explosions and mechanical problems that could cause substantial adverse financial impacts. These events could result in injury or loss of human life, significant damage to property or natural resources (including public parks), environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. 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 significant.

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, which could adversely affect our results of operations, financial position or liquidity.~~recoverable.

Our regulated electric and gas utility operations 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 gas and electric utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate case. 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 flow.

If regulatory commissions refuse to approve the implementation of a cost of service gas program to serve our natural gas utilities and the fuel needs of our electric utilities, it could adversely affect future operations or require us to make changes to our business strategy.

We are evaluating the implementation of a program supporting our natural gas and electric utilities that can provide longer-term price stability for our regulated customers by enhancing our current utility gas supply portfolio, through the addition of utility or affiliate owned natural gas production and reserves. In addition to providing our customers the benefits associated with more predictable long-term commodity prices, it also provides additional opportunities for increased earnings. We will require regulatory approval from our state commissions to implement this program. If regulatory commissions refuse to approve the program, we may have to reconsider our long-term strategy, including the potential for vertical integration of our oil and gas operations in support of this program.

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 $~~353 million~~1.3 billion of goodwill on our consolidated balance sheets as of December 31, ~~2014~~2016. 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 condition.

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.

Oil and Gas

Our inability to successfully include our Oil and Gas segment core assets in utility Cost of Service Gas Programs may result in additional material impairments of our Oil and Gas assets.

In our oil and gas business, we are actively divesting non-core assets while retaining those assets best suited for a Cost of Service Gas Program for our utilities and third-party utilities, and have refocused our professional staff on assisting with the implementation of a Cost of Service Gas Program. The implementation of Cost of Service Gas Programs will provide a long-term physical hedge for a portion of a utility’s gas supply, enhancing the quality of the overall gas supply portfolio. In addition to providing utility customers the potential benefits associated with more predictable and lower long-term natural gas prices, it also provides utilities an opportunity to increase earnings through investment in gas reserves. Cost of Service Gas Programs require regulatory approval from state commissions that regulate utility participants in these programs. Failure to obtain these approvals may result in additional impairments of our Oil and Gas assets, and could adversely affect the market perception of our business, operating results and stock price.

Estimates of the quantity and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

The process of estimating crude oil and natural gas reserves requires interpretation of available technical data and various assumptions, including assumptions relating to economic factors. Significant variances in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. Actual prices, production, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves may vary significantly from those assumed in our estimates. Any significant variance from the assumptions used could cause the actual quantity of our reserves and future net cash flow to be materially different from our estimates. In addition, results of drilling, testing and production, changes in future capital expenditures and fluctuations in crude oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions that could adversely affect our results of operations.

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in restrictions which could increase costs and cause delays to the completion of certain oil and gas wells and potentially preclude the economic drilling and completion of wells in certain reservoirs.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used extensively for decades to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Hydraulic fracturing involves using mostly water, sand and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. The process is typically regulated by state crude oil and natural gas commissions. However, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition several agencies of the federal government including the EPA and the BLM are conducting studies of the fracturing stimulation process which may result in additional regulations. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide the federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

In the event federal, state, local or municipal legal restrictions on the hydraulic fracturing are adopted in areas where we are conducting or in the future plan to conduct operations, we may incur additional costs to comply with such regulations that may be significant, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from utilizing fracture stimulation and effectively preclude the drilling of wells.

Exploratory and development drilling are speculative activities that may not result in commercially productive reserves. Lack of drilling success could result in uneconomical investments.

While our planned activity related to our Oil and Gas segment is limited, drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental rules and regulations and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays are caused by the high demand for rigs and other needed equipment by a large number of companies in active drilling basins. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.

We could incur additional write-downs of the carrying value of our natural gas and oil properties, which would cause a decrease in our assets and stockholders' equity and could adversely impact our results of operations.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, which is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Two primary factors in the ceiling test are natural gas and crude oil reserve quantities, which are impacted by current commodity prices, and SEC-defined crude oil and gas prices, both of which impact the present value of estimated future net revenues. We recorded non-cash impairment charges in 2016 and 2015 due to the full cost ceiling limitations. See Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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, our cost of capital and our other operating costs.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB (Stable outlook) by S&P; and BBB+ (Negative 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 included in current financial reform legislation 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 crude oil and natural gas derivative instruments for our hedging activities for our oil and gas production activities and our gas utility operations. We 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 to clearing entities 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 and interest rate 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 or assets being hedged. The difference in accounting can 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 liquidity.

As discussed in Note 18 of the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan 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 conditions 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 and liquidity.

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 affected 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, risks associated with our oil and gas exploration and production activities, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation of gas in pipelines.

While we maintain insurance coverage for our operated wells and we participate in insurance coverage maintained by the operators of our wells, there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.

Increasing costs associated with our health care plans and other benefits may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care 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 health care plans may adversely affect our results of operations, financial position or liquidity.

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.

Prior to the Acquisition, SourceGas was a private company, exempt from reporting and control requirements under Section 404 of the Sarbanes-Oxley Act of 2002. As permitted by the guidance set forth by the Securities and Exchange Commission, the acquired SourceGas businesses are not included in management’s assessment of internal control over financial reporting for the year ended December 31, 2016. 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. While we expect our control system to adequately integrate the SourceGas processes, we cannot be certain that our current design for internal control over financial reporting, or any additional changes to be made, will be sufficient to enable management to determine that our internal controls are effective for any period, or on an ongoing basis. 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

Federal and state laws concerning greenhouse gas regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming and Colorado. Recent 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 caption “Environmental Matters.”

The GHG Tailoring Rule, effective June 2010, will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities, monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units, published October 2015, effectively prohibits new coal-fired units until carbon capture and sequestration becomes technically and economically feasible.

On October 23, 2015, the EPA finalized the CPP to cut carbon emissions from existing electric generating units. The design of the CPP is to decrease existing coal-fired generation, increase the utilization of existing gas generation, increase renewable energy and demand side management. The rule, which does not propose to regulate individual emission sources, calls for each state to develop plans to meet the EPA-assigned statewide average emission rate target for that state by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. The U.S. Supreme Court entered an order staying the CPP in February 2016, pending appeal. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. In 2015 and again in 2016, we met with the staff of state air programs and public utility commissions on several occasions. We will continue to work closely with state regulatory staff as these plans develop.

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 generating facilities and potential increased load of our combined cycle natural gas fired 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 is subject to extensive energy, environmental and other laws and regulations of federal, state, tribal and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which can require significant capital expenditure and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of penalties, liens or fines, claims for property damage or personal injury, or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures or cause us to reevaluate the feasibility of continued operations at certain sites and have a detrimental effect on our business.

In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain properties, regardless of when such liabilities arose, whether known or unknown, and in some cases agreed to indemnify the former owners of those properties for environmental liabilities. Future steps to bring our facilities into compliance or to address contamination from legacy operations, if necessary, could be expensive and could adversely affect our results of operations and financial condition. Environmental compliance expenditures could be substantial in the future if the trend towards stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate continues.

Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. The CPP regulation is expected to have an adverse effect 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 operations and financial results could be adversely impacted.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


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. 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.	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, 2016, we had 3,860 common shareholders of record and approximately 28,000 beneficial owners, representing all 50 states, the District of Columbia and 8 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 25, 2017 meeting, our Board of Directors declared a quarterly dividend of $0.445 per share, equivalent to an annual dividend of $1.78 per share, marking 2017 as the 47^th 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.

Quarterly dividends paid and the high and low prices for our common stock, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:



Year ended December 31, 2016	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.420	$	0.420	$	0.420	$	0.420
Common stock prices
High	$	61.13	$	63.53	$	64.58	$	62.83
Low	$	44.65	$	56.16	$	56.86	$	54.76



Year ended December 31, 2015	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.405	$	0.405	$	0.405	$	0.405
Common stock prices
High	$	53.37	$	52.96	$	47.27	$	47.51
Low	$	47.88	$	43.48	$	36.81	$	40.00

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during 2016.

ISSUER PURCHASES OF EQUITY SECURITIES



There were no equity securities acquired for the three months ended December 31, 2016.


ITEM 6.	SELECTED FINANCIAL DATA

(Minor differences may result due to rounding)



Years Ended December 31,	2016				2015				2014				2013				2012
(dollars in thousands, except per share amounts)

Total Assets	$	6,515,444			$	4,626,643			$	4,222,301			$	3,820,877			$	3,677,019

Property, Plant and Equipment
Total property, plant and equipment	$	6,412,223			$	4,976,778			$	4,563,400			$	4,259,445			$	3,930,772
Accumulated depreciation and depletion	(1,943,234		)		(1,717,684		)		(1,357,929		)		(1,306,390		)		(1,229,159		)
Total property, plant and equipment, net	$	4,468,989			$	3,259,094			$	3,205,471			$	2,953,055			$	2,701,613

Capital Expenditures	$	467,119			$	458,821			$	391,267			$	379,534			$	347,980

Capitalization (excluding noncontrolling interests)
Current maturities of long-term debt	$	5,743			$	—			$	275,000			$	—			$	103,973
Notes payable	96,600				76,800				75,000				82,500				277,000
Long-term debt, net of current maturities and deferred financing costs	3,211,189			(a)	1,853,682			(a)	1,255,953				1,383,714				927,561
Common stock equity	1,614,639			(b)	1,465,867			(b)	1,353,884				1,283,500				1,205,800
Total capitalization	$	4,928,171			$	3,396,349			$	2,959,837			$	2,749,714			$	2,514,334

Capitalization Ratios
Short-term debt, including current maturities	2		%		2		%		12		%		3		%		15		%
Long-term debt, net of current maturities	65		%	(a)	55		%		42		%		50		%		37		%
Common stock equity	33		%		43		%		46		%		47		%		48		%
Total	100		%		100		%		100		%		100		%		100		%

Total Operating Revenues	$	1,572,974			$	1,304,605			$	1,393,570			$	1,275,852			$	1,173,884

Net Income Available for Common Stock
Electric Utilities	$	85,827			$	77,579		(g)	$	57,270		(g)	$	49,003		(g)	$	52,123		(g)
Gas Utilities	59,624				39,306			(g)	44,151			(g)	35,838			(g)	27,465			(g)
Power Generation	25,930			(c)	32,650				28,516				16,288			(c)	21,328
Mining	10,053				11,870				10,452				6,327				5,626
Oil and Gas	(71,054		)	(b)	(179,958		)	(b)	(8,525		)		(1,751		)		18,683			(b)
Corporate and intersegment eliminations	(37,410		)	(d)	(13,558		)	(d, g)	(975		)		12,602			(d)	(15,808		)	(d)
Net Income (loss) available for common stock before discontinued operations	72,970				(32,111		)		130,889				118,307				109,417
Income (loss) from discontinued operations, net of tax ^(e)	—				—				—				(884		)		(6,977		)
Net income (loss) available for common stock	$	72,970			$	(32,111	)		$	130,889			$	117,423			$	102,440

SELECTED FINANCIAL DATA continued



Years Ended December 31,	2016			2015			2014			2013			2012
(dollars in thousands, except per share amounts)

Dividends Paid on Common Stock	$	87,570		$	72,604		$	69,636		$	67,587		$	65,262

Common Stock Data^(f) (in thousands)
Shares outstanding, average basic	51,922			45,288			44,394			44,163			43,820
Shares outstanding, average diluted	53,271			45,288			44,598			44,419			44,073
Shares outstanding, end of year	53,382			51,192			44,672			44,499			44,206

Earnings (Loss) Per Share of Common Stock (in dollars)
Basic earnings (loss) per average share -
Continuing operations	$	1.59		$	(0.71	)	$	2.95		$	2.68		$	2.50
Discontinued operations ^(e)	—			—			—			(0.02		)	(0.16		)
Non-controlling interest	(0.19		)	—			—			—			—
Total	$	1.41		$	(0.71	)	$	2.95		$	2.66		$	2.34
Diluted earnings (loss) per average share -
Continuing operations	$	1.55		$	(0.71	)	$	2.93		$	2.66		$	2.48
Discontinued operations	—			—			—			(0.02		)	(0.16		)
Non-controlling interest	(0.18		)	—			—			—			—
Total	$	1.37		$	(0.71	)	$	2.93		$	2.64		$	2.32

Dividends Declared per Share	$	1.68		$	1.62		$	1.56		$	1.52		$	1.48

Book Value Per Share, End of Year	$	30.25		$	28.63		$	30.31		$	28.84		$	27.28

Return on Average Common Stock Equity (full year)	4.7		%	(2.3		)%	9.9		%	9.4		%	8.7		%

SELECTED FINANCIAL DATA continued



Years ended December 31,	2016	2015	2014	2013	2012
Operating Statistics:
Generating capacity (MW):
Electric Utilities (owned generation)	941	841	841	790	859
Electric Utilities (purchased capacity)	110	210	210	150	150
Power Generation (owned generation)	269	269	269	309	309
Total generating capacity	1,320	1,320	1,320	1,249	1,318

Electric Utilities:
MWh sold:
Retail electric	5,140,519	4,990,594	4,775,808	4,642,254	4,598,080
Contracted wholesale	246,630	260,893	340,871	357,193	340,036
Wholesale off-system	769,843	1,000,085	1,118,641	1,456,762	1,652,949
Total MWh sold	6,156,992	6,251,572	6,235,320	6,456,209	6,591,065

Gas Utilities:
Gas sold (Dth)	79,165,742	56,638,299	64,861,411	64,131,850	51,620,293
Transport volumes (Dth)	126,927,565	77,393,775	77,433,266	73,730,017	71,092,286

Power Generation Segment:
MWh Sold	1,868,513	1,796,242	1,760,160	1,564,789	1,304,637
MWh Purchased	85,993	68,744	38,237	5,481	8,011

Oil and Gas Segment:
Oil and gas production sold (MMcfe)	12,142	12,896	9,986	9,529	12,544
Oil and gas reserves (MMcfe)^(b)	78,294	104,624	101,416	86,713	80,683

Mining Segment:
Tons of coal sold (thousands of tons)	3,817	4,140	4,317	4,285	4,246
Coal reserves (thousands of tons)	199,905	203,849	208,231	212,595	232,265


(a)	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)

2016 includes non-cash after-tax impairment charges to our crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax ceiling test impairment charges to our 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 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K). 2012 includes a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $32 million offset by an after-tax gain on sale of $49 million related to our Williston Basin assets.

(c)

On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest. 2013 includes $6.6 million after-tax expense relating to the settlement of interest rate swaps and write-off of deferred financing costs in conjunction with the prepayment of Black Hills Wyoming’s project financing.

(d)

2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $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. 2013 and 2012 include $20 million and $1.2 million non-cash after-tax unrealized mark-to-market gains, respectively, related to certain interest rate swaps; 2013 also includes $7.6 million after-tax expense for a make-whole premium, write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt, while 2012 includes an after-tax make-whole provision of $4.6 million for early redemption of our $225 million notes.


(e)	Discontinued operations in 2013 and 2012 include post-closing adjustments and operations relating to Enserco, sold in 2012.


(f)	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.

(g)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility results have been reclassified from the Electric Utilities segment to the Gas Utilities segment in the amounts of $1.7 million, $2.3 million, $3.1 million and $0.5 million for the years ending December 31, 2015, 2014, 2013 and 2012 respectively. Due to this reclassification, there also exists an intersegment elimination of $0.2 million that has been moved to “Corporate and intersegment eliminations” for the period ended December 31, 2015.

For additional information on our business segments see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note 5 of the Consolidated Financial Statements in this Annual Report on Form 10-K.


ITEMS 7 &	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS


and 7A.	OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET

RISK

We are a customer-focused, growth-oriented, vertically-integrated utility company operating in the United States. We report our operations and results in the following financial segments.

Electric Utilities: Our Electric Utilities segment generates, transmits and distributes electricity to approximately 208,500 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates.

Gas Utilities: Our Gas Utilities conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska subsidiaries. Our Gas Utilities distribute and transport natural gas through our network to approximately 1,030,800 natural gas customers. Additionally, we sell temporarily-available, contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates.

We also provide non-regulated services through Black Hills Energy Services. Black Hills Energy Services provides approximately 55,000 retail distribution customers in Nebraska and Wyoming with unbundled natural gas commodity offerings under the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and protection plans under various trade names. Service Guard and CAPP primarily provide appliance repair services to approximately 61,000 and 33,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services primarily serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.

Power Generation: Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts.

Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

Oil and Gas: Our Oil and Gas segment engages in the production of crude oil and natural gas, primarily in the Rocky Mountain region. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program, and we have refocused our professional staff on assisting utilities with the implementation of cost of service gas programs.

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. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our utilities, with the exception of our Oil and Gas segment.

Segment reporting transition of Cheyenne Light’s Natural Gas distribution

Effective January 1, 2016, the natural gas operations of Cheyenne Light are reported in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations including Cheyenne Light’s electric utility operations are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. The reclassifications moving Cheyenne Light’s natural gas results from the Electric Utilities segment to the Gas Utilities segment consisted of increasing Gas Utilities and decreasing Electric Utilities Revenue, Gross Margin and Net Income (loss) by $44 million, $22 million and $1.7 million, and $40 million, $17 million and $2.3 million for the Years ended December 31, 2015 and December 31, 2014, respectively.

Overview: Our customer focus provides opportunities to expand our business by constructing additional rate base assets to serve our utility customers and expanding our non-regulated energy products and services to our wholesale customers.

The diversity of our energy operations reduces reliance on any single business segment to achieve our strategic objectives. Our emphasis on our utility business with diverse geography and fuel mix, combined with a conservative approach to our non-regulated energy operations, mitigates our overall corporate risk and enhances our ability to earn stronger returns for shareholders over the long-term. Our long-term strategy focuses on growing both our utility and utility supporting non-regulated energy businesses, primarily by increasing our customer base and providing superior service.

SourceGas Acquisition

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co., pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. The acquisition is in alignment with our strategy to invest in utilities and to expand utility operations consistent with our regional focus and strategic advantages as further discussed below in our business strategies. See additional information below under Prospective Information and in Note 2 of the Notes to Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K.

Our Objective

Our objective is to be best-in-class relative to certain operational performance metrics, such as safety, power plant availability, electric and gas system reliability, efficiency, customer service and cost management. Our notable operational performance metrics for 2016 include:


•	Our three electric utilities achieved 1^st quartile reliability ranking with 64 customer minutes of outage time (SAIDI) in 2016 compared to industry averages (IEEE 2016 1^st quartile is less than 81 minutes);

Our JD Power Customer Satisfaction Survey indicated our Electric and Gas Utilities were favorable to our peers in the Midwest;


•	Our power generation fleet achieved a forced outage factor of 3.27% for coal fired plants, 0.76% for natural gas plants, and 0.00% for diesel plants in 2016, compared to an industry average^* of 4.61%, 4.41%, and 2.18%, respectively (^*NERC GADS 2015 Data);


•	Our power generation fleet availability was 94.41% for coal fired plants, 96.56% for natural gas fired plants, 98.92% for diesel fired plants, and 99.20% for wind generation in 2016 while the industry averages^ were 85.29%, 89.65%, 94.59% respectively (^NERC GADS 2015 data was used for coal, natural gas and diesel; data is not currently kept for wind);


•	Our safety TCIR of 1.7 compares well to an industry average of 2.2⁺ and our DART rate of 0.6 compares to an industry average of 1.2⁺ (⁺Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2015);

Our OSHA TCIR rate during construction of our generating facilities is also significantly better than industry average with a TCIR rate of 3.1 during the 2016 construction of the Pueblo LM 6000 compared to an industry average of 4.4 for natural-gas fired plants.

Our mine completed five years with favorable MSHA safety results compared to other mines located in the Powder River Basin and received an award from the State of Wyoming for seven years without a lost time accident. The mine also received the State Mine Inspector’s Award for the third year in a row for operating as the safest small mine and received the Mine Safety and Health Administration’s Certificate of Achievement for No Lost Time Incidents.

The electric utility industry is facing requirements to upgrade aging infrastructure, deploy smart grid technology and comply with new state and federal environmental regulations and renewable portfolio standards. Increased energy efficiency and smart grid technologies suppress demand in many areas of the United States. These competing considerations present challenges to energy companies’ approach to balancing capital spending and obtaining satisfactory rate recovery on investments.

State regulatory commissions have lowered authorized returns and implemented other regulatory mechanisms for cost recovery due to the slow-growing economy and concerns that utility rate increases may further harm local economies. The average awarded return on equity for investor-owned utilities over the past year has just under 10%. The average regulatory lag is less than 12 months, according to the Edison Electric Institute. Sustained low interest rates heavily influence the lower rates of return, along with actions by state commissions to moderate rate increases during a period of economic recovery.

In our gas and electric utilities’ service territories, we will continue to work with regulators to ensure we meet our obligations to serve projected customer demand and to comply with environmental mandates by constructing the infrastructure necessary to provide safe, reliable energy. By maintaining our high customer service and reliability standards in a cost-efficient manner, our goal is to secure appropriate rate recovery that provides fair economic returns on our utility investments.

The proliferation of domestic crude oil and natural gas production from shale plays in recent years has provided the domestic market an abundant new supply of both commodities, which has decreased the dependence on foreign resources for these commodities. The increased worldwide supply of crude oil and natural gas caused prices to continue to decline throughout 2016, making drilling and exploration activities uneconomical in many producing basins. We continued to focus our oil and gas expertise to support cost of service gas programs for our own utilities and third-party utilities.

Currently, approximately 30% of electricity generated in the United States is from coal-fired power plants. It will take significant time and expense before this generation can be replaced with alternative technologies. As a result, coal-fired resources will remain a necessary component of the nation’s electric supply for the foreseeable future. The regulatory climate in recent years, combined with the EPA’s proposed and expected GHG regulations, have limited construction of new conventional coal-fired power plants, but, if technologies such as carbon capture and sequestration become more proven and less expensive, they could provide for the long-term economic use of coal. We have investigated and will continue to investigate the possible deployment of these technologies at our mine site in Wyoming.

We have expertise in permitting, constructing and operating power generation facilities. These skills, combined with our understanding of electric resource planning and regulatory procedures, provide a significant opportunity for us to add long-term shareholder value. We intend to grow our non-regulated power generation business by continuing to focus on long-term contractual relationships with our affiliates and other load-serving utilities.

Key Elements of our Business Strategy

Provide stable long-term rates for customers and increase earnings by efficiently planning, constructing and operating rate-base power generation facilities needed to serve our electric utilities. Our Company began as a vertically-integrated electric utility. This business model remains a core strength and strategy today, as we invest in and operate efficient power generation resources to cost effectively transmit and distribute electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.

We believe we have a competitive power production strategy focused on low cost construction and operation of our generating facilities. Access to our own coal and third-party natural gas reserves allows us to be competitive as a power generator. Low production costs can result from a variety of factors including low fuel costs, efficiency in converting fuel into energy, low per unit operation and maintenance costs and high levels of plant availability. We leverage our mine-mouth coal-fired generating capacity which strengthens our position as a low-cost producer by eliminating fuel transportation costs which often represent the largest component of the delivered cost of coal for many other utilities. In addition, we typically operate our plants with high levels of availability, compared to industry benchmarks. We aggressively manage each of these factors with the goal of achieving low production costs.

Rate-base generation assets offer several advantages including:

Since the generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run, than if the power was purchased from the open market through wholesale contracts that are re-priced over time;

Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;

Investors are provided a long-term, reasonable, stable return on their investment; and

The lower risk profile of rate based generation assets may enhance credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

Our actions to provide power at reasonable rates to our customers were exemplified in our successful requests to secure the construction financing riders in both Wyoming and South Dakota during the 2013-2014 construction of Cheyenne Prairie, and in Colorado with the 2016 completion of a 40 MW natural gas-fired combustion turbine and Peak View Wind Project. These riders reduce the total cost of the plant ultimately passed along to our customers while we construct these plants to accommodate growth and replace plants that were closed prematurely due to environmental regulations.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating and remaining mindful of customer rate impacts. The energy and utility industries face uncertainty, and also potential investment opportunities, related to the potential impact of legislation and regulation intended to reduce GHG emissions and increase the use of renewable and other alternative energy sources. To date, many states have enacted, and others are considering, some form of mandatory renewable energy standard, requiring utilities to meet certain thresholds of renewable energy generation. Some states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both renewable energy standards and GHG emission reductions is also under consideration.

Mandates for the use of renewable energy or the reduction of GHG emissions will likely produce investment opportunities, either for our electric utilities or for our power generation business. These mandates will also most likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reasonably priced and reliable sources of energy to our customers. As a result, we employ a customer‑centered strategy for complying with renewable energy standards and GHG emission regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.

Colorado legislative mandates apply to our electric utilities segment regarding the use of renewable energy. Therefore, we pursue cost‑effective initiatives that allow us to meet our renewable energy requirements. Where permitted, we seek to construct renewable generation resources as rate base assets, which helps mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the Busch Ranch Wind Farm, a 29 MW wind farm project, was completed in the fourth quarter of 2012, as part of our plan to meet Colorado’s Renewable Energy Standard. We had also previously submitted requests for additional renewable energy supplies in 2014 for our Colorado Electric utility to help meet the renewable mandate. On October 21, 2015, we received approval from the Colorado Public Utilities Commission to purchase the $109 million, 60 MW Peak View Wind Project, under the terms of a build/transfer agreement with a third party developer. This wind project commenced commercial operation in November 2016;

In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future or other standards, such as those established by the CPP. For example, under two 20-year power purchase agreements, we purchase a total of 60 MW of energy from wind farms located near Cheyenne, Wyoming, for use at our South Dakota Electric and Wyoming Electric subsidiaries; and

In all states in which we conduct electric utility operations, we are exploring other cost-effective potential biomass, solar and wind energy projects, particularly wind generation sites located near our utility service territories.

Maintain a safe and reliable gas distribution system.We are in compliance with all applicable federal, state and local regulations as well as many industry best practices. Any leaks discovered, whatever the cause, are repaired as soon as possible while ensuring the safety of the public and our employees. We construct and renew our piping systems with state of the art materials and products to safely and efficiently deliver natural gas to our customers. Maintaining our product within our piping systems is of utmost importance to ensure the safety of the public and our employees and to protect the environment. To that end, we monitor the integrity of our piping systems and renew as appropriate to accomplish the stated goals of safe, efficient energy delivery. We have removed all cast and wrought iron from our system. With respect to unprotected steel, our distribution system contains less than 2.57% bare steel and 0.07% coated steel, while our transmission system consists of less than 0.63% bare steel. Many of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that allow them to adjust their rates to reflect all the costs prudently incurred in replacing piping systems.

Expand utility operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages. For more than 130 years, we have provided reliable utility services, delivering quality and value to our customers. Utility operations contribute substantially to the stability of our long-term cash flows, earnings and dividend policy. Our tradition of accomplishment supports efforts to expand our utility operations into other markets, most likely in areas that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system reliability, superior customer service, community involvement and a relationship-based approach to regulatory matters. Utility operations also enhance other important business development opportunities, including gas transmission pipelines and storage infrastructure, which could promote other non-regulated energy operations.

We have and will continue to pursue the purchase of not only large utility properties, such as SourceGas, but also smaller, private or municipal utility systems, which can be easily integrated into our operations. We purchased several small natural gas distribution systems in Kansas, Iowa and Wyoming in the past several years. We have a scalable platform of systems and processes, which simplifies the integration of our utility acquisitions. Merger and acquisition activity has continued in the utility industry and we will consider such opportunities if they advance our long-term strategy and add shareholder value.

Provide stable long-term gas costs for customers and increase earnings by efficiently planning and implementing a Cost of Service Gas Program to serve our electric and natural gas utilities. To further enhance our vertically-integrated utility business model, we are considering implementing a Cost of Service Gas Program. The Cost of Service Gas Program is designed to provide utility customers with long-term natural gas price stability, along with a reasonable expectation of savings over the life of the program, while providing increased earnings opportunities for our shareholders. We will need to apply for and receive regulatory approval from our state utility commissions for the program. Several utilities have cost of service gas programs in place in various states, including in both Wyoming and Montana.

We believe we have a competitive advantage related to a Cost of Service Gas Program in that our existing non-regulated oil and gas subsidiary could assist in drilling/acquiring and operating the gas reserves required to meet the needs of our electric and gas utilities. We could also provide this service to other utilities.

Focus our oil and gas business to support cost of service gas initiatives. Our oil and gas business is focused on supporting the implementation of a planned utility Cost of Service Gas Program in partnership with our own and other utilities, while maintaining the upside value of our Piceance Basin and other assets. We are divesting non-core assets while retaining those assets best suited for a Cost of Service Gas Program. In previous years, we successfully focused our efforts on proving up the large shale gas resource potential of our southern Piceance Basin asset, while improving our drilling and completion practices for the Mancos. We drilled 17 wells and completed 13, with production meeting or exceeding our expectations on the completed wells. We are currently assessing the Piceance Basin assets to determine their potential fit for a Cost of Service Gas Program.

Oil and Gas will rationalize its asset base. In the current price environment, we have reduced future capital expenditures and staffing to improve financial performance.

Build and maintain strong relationships with wholesale power customers of our utilities and non-regulated power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be a primary provider of electricity to wholesale utility customers, who will continue to need products, such as capacity, in order to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns over the long term than we could by selling energy into more volatile spot markets. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint owners in two of our power plants, Wygen I and Wygen III.

Selectively grow our non-regulated power generation business in targeted regional markets by developing assets and selling most of the capacity and energy production through mid- and long-term contracts primarily to load-serving utilities. While much of our recent power plant development has been for our regulated utilities, we seek to expand our non-regulated power generation business by developing and operating power plants in regional markets based on prevailing supply and demand fundamentals, in a manner that complements our existing fuel assets and marketing capabilities. We seek to grow this business through the development of new power generation facilities and disciplined acquisitions primarily in the western region, where we believe our detailed knowledge of market and electric transmission fundamentals provides us a competitive advantage and, consequently, increases our ability to earn attractive returns. We prioritize small-scale facilities that serve incremental growth or provide critical back up to renewable resources and are typically easier to permit and construct than large-scale generation projects.

Most of the energy and capacity from our non-regulated power facilities is sold under mid- and long-term contracts. When possible, we structure long-term contracts as tolling arrangements, whereby the contract counterparty assumes the fuel risk. Going forward, we will continue to focus on selling a majority of our non-regulated capacity and energy primarily to load-serving utilities under long-term agreements that have been reviewed or approved by state utility commissions. An example of this strategy is the 200 MW of combined-cycle gas-fired generation constructed by our non-regulated power generation subsidiary to serve our Colorado Electric utility subsidiary. The plant commenced operations on January 1, 2012, under a 20-year tolling agreement.

Diligently manage the credit, price and operational risks inherent in buying and selling energy commodities. Over the last decade or so, Black Hills has strategically refocused itself as a utility-centered energy company. Most of our buying and selling activities are directly related to maintaining utilities operations, mainly by purchasing fuel for our power generating units and purchasing natural gas for distribution to our natural gas utility customers. Our oil and gas business has a natural long position created by its natural gas and crude oil production. We sell this production into the open market and hedge some of the price risk for future production using financial derivatives.

All of our buying and selling activities to support operations require effective management of counterparty credit risk. We mitigate this risk by conducting business with a diverse group of creditworthy counterparties. In certain cases where creditworthiness merits security, we require prepayment, secured letters of credit or other forms of financial collateral. We establish counterparty credit limits and employ continuous credit monitoring, with regular review of compliance under our credit policy by our Executive Risk Committee. Our oil and gas and power generation operations require effective management of price and operational risks related to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we implemented risk management policies and procedures. Our oversight committee monitors compliance with these policies.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. Access to capital has been and will continue to be critical to our success. We have demonstrated our ability to access the debt and equity markets, resulting in sufficient liquidity. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent business growth. Our access to adequate and cost-effective financing depends upon our ability to maintain our investment-grade issuer credit rating.

Prospective Information

We expect to generate long-term growth through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused primarily on regulated utilities provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from our acquisition of SourceGas, continued focus on improving efficiencies and reducing costs, implementation of a Cost of Service Gas Program and focused capital investments at our utilities. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan.

Electric Utilities

Colorado Electric received a settlement agreement of its electric resource plan filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. The settlement, effective February 6, 2017, includes the addition of 60 megawatts of renewable energy to be in service by 2019 and provides for additional small solar and community solar gardens as part of the compliance plan. Colorado Electric plans to issue a request for proposal in the first half of 2017.

In December 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air Clean Jobs Act construction financing rider. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.61% debt and 52.39% equity. On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 rate decision.

In November 2016, Colorado Electric completed the purchase of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased through progress payments throughout 2016 under a commission approved third-party build transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric’s all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments, Renewable Energy Standard Surcharge and Transmission Cost Adjustment for 10 years, after which Colorado Electric can propose base rate recovery. Colorado Electric is required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility.

Retail MWhs sold increased in 2016 primarily due to increased industrial loads driven by customer load growth. The increase in industrial loads is primarily driven by Wyoming Electric and Colorado Electric, both of which set new all-time peak loads in 2016. Wyoming Electric recorded an all-time summer peak load of 236 MW in July 2016, and an all-time winter peak of 230 MW in December 2016. Colorado Electric recorded an all-time summer peak load of 412 MW in July 2016.

During the first quarter of 2016, South Dakota Electric commenced construction of the $54 million, 230-kV, 144 mile-long transmission line that will connect the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. Recovery is concurrent through the FERC transmission tariff. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange is expected to be placed in service in the first half of 2017.

Gas Utilities

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments of which $11 million was agreed to and received in June 2016.

SourceGas, which was renamed Black Hills Gas Holdings, LLC, primarily operates four regulated natural gas utilities serving approximately 431,000 customers in Arkansas, Colorado, Nebraska and Wyoming and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado.

We completed substantially all integration activities in 2016. All significant operations, customer, accounting, human resources and rebranding activities were successfully completed and implemented.

Our Gas Utilities invested in our gas distribution network and related technology such as advanced metering infrastructure and mobile data terminals. We continually monitor our investments and costs of operations in all states to determine the appropriateness of additional rate reviews or other rate filings. As part of our growth strategy, we continue to look for opportunities to purchase municipal and privately-owned gas infrastructure and distribution systems.

Cost of Service Gas Program Filings

During the third quarter of 2016, the Company withdrew its Cost of Service Gas applications in Wyoming, Iowa, Kansas and South Dakota. In consideration of the July 2016 denial of the application from the NPSC and the April 2016 dismissal of its application from the CPUC, the Company is re-evaluating its Cost of Service Gas regulatory approval strategy.

The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. The Company is currently considering filing new applications for approval of specific gas reserve properties.

The Cost of Service Gas Program is designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.

Mining

Production from the Mining segment primarily serves mine-mouth generation plants and select regional customers with long-term fuel needs. Total annual production was approximately 3.8 million tons for 2016, which was 8% less than 2015. Mining operations moved to an area with higher overburden ratios in 2016, which increased mining costs. However, lower fuel costs, and efficiencies in executing our mine plan offset these costs. Our stripping ratio at December 31, 2016 was 2.07 and we expect stripping ratios to decrease in 2017 to approximately 1.9 as the areas planned for mining contain lower overburden.

Our strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically our limited off-site sales have been to consumers within a close proximity to our mine, including off-site sales contracts served by truck. We continue to pursue new opportunities to market our coal despite limitations inherent to transporting our lower-heat content coal.

Oil and Gas

Our strategy is to focus our Oil and Gas business toward supporting our Cost of Service Gas Program and similar programs in partnership with other utilities, while maintaining the upside value optionality of our Piceance Basin and other assets. We can best utilize our oil and gas expertise to develop and operate the Cost of Service Gas Program on behalf of our utility businesses and similar programs in partnership with third-party utilities. We are divesting non-core assets while retaining those best suited for a Cost of Service Gas Program. Our oil and gas strategy through 2015 had been to prove up the potential of the Mancos formation for our southern Piceance Basin asset, while improving our drilling and completion practices for the Mancos. We drilled 17 wells and completed 13, with production meeting or exceeding our expectations on the completed wells. Due to the sustained low oil and natural gas prices, production in 2016 was limited to meeting contractual agreements we have in the Piceance, and we have limited our planned future capital based on our Cost of Service Gas strategy. We are currently assessing the Piceance wells and acreage holdings to determine their potential fit for a Cost of Service Gas Program.

Corporate

We took advantage of historically low interest rates to complete several financing transactions, including permanent financing of the SourceGas Acquisition, refinancing on favorable terms the debt acquired in the Acquisition, amending and extending our Revolving Credit Facility and executing a new three-year term loan. In addition to our debt issuances and refinancings, we implemented an ATM equity offering program, executed a declining balance term loan, closed on a CP Program and settled $400 million of interest rate swaps. See additional detail in the 2016 Corporate highlights.

Results of Operations

Executive Summary and Overview



	For the Years Ended December 31,
	2016			Variance			2015			Variance			2014
	(in thousands)
Revenue
Revenue	$	1,701,093		$	270,811		$	1,430,282		$	(90,827	)	$	1,521,109
Inter-company eliminations	(128,119		)	(2,442		)	(125,677		)	1,862			(127,539		)
	$	1,572,974		$	268,369		$	1,304,605		$	(88,965	)	$	1,393,570

Net income (loss) available for common stock
Electric Utilities^(a)	$	85,827		$	8,248		$	77,579		$	20,309		$	57,270
Gas Utilities^(a)	59,624			20,318			39,306			(4,845		)	44,151
Power Generation^(b)	25,930			(6,720		)	32,650			4,134			28,516
Mining	10,053			(1,817		)	11,870			1,418			10,452
Oil and Gas ^{(c) (d)}	(71,054		)	108,904			(179,958		)	(171,433		)	(8,525		)
	110,380			128,933			(18,553		)	(150,417		)	131,864

Corporate and Eliminations ^{(a) (e) (f)}	(37,410		)	(23,852		)	(13,558		)	(12,583		)	(975		)

Net income (loss) available for common stock	$	72,970		$	105,081		$	(32,111	)	$	(163,000	)	$	130,889

______________

(a)

Net income available for common stock for 2016 included a net tax benefit of approximately $3.1 million for the following items: at the Electric Utilities, a $2.1 million benefit related to production tax credits associated with the Peak View Wind Project being placed into service and flow through treatment of a treasury grant related to the Busch Ranch Wind Project; at the Gas Utilities, a tax benefit of approximately $2.2 million related to favorable flow through adjustments; and, various other items netting to $1.2 million of tax expense that predominantly affected Corporate.


(b)	On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest.


(c)	Net income (loss) available for common stock for 2016 and 2015 included non-cash after-tax impairments of our crude oil and natural gas properties of $67 million and $160 million. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


(d)	Net income (loss) available for common stock for 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.


(e)	Net income (loss) available for common stock for 2016 and 2015include incremental SourceGas Acquisition costs, after-tax of $30 million and $6.7 million and 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 business segments.


(f)	Net income (loss) available for common stock for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

The following business group and segment information does not include inter-company eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.

2016 Compared to 2015

Net income (loss) available for common stock was $73 million, or $1.37 per diluted share in 2016, compared to $(32) million, or $(0.71) per share in 2015. Net income available for common stock in 2016 increased over the same period in the prior year due primarily to: lower Oil and Gas property impairment charges; higher earnings at our Electric Utilities and Gas Utilities, which include earnings of $15 million from our acquired SourceGas utilities since the acquisition date of February 12, 2016; tax benefits of approximately $11 million from additional Oil and Gas properties’ percentage depletion deductions, and the re-measurement of uncertain tax positions’ liability predicated on an agreement reached with IRS Appeals. These increases were partially offset by $9.6 million of net income attributable to noncontrolling interests. Non-cash after-tax oil and gas property impairment charges were $67 million and after-tax SourceGas incremental acquisition and transition costs were $30 million in the year ended December 31, 2016. The Net income (loss) available for common stock for the year ended 2015 included non-cash after-tax ceiling test impairments of our oil and gas properties of $158 million, after-tax SourceGas incremental acquisition and transition costs of $6.7 million, and a non-cash after-tax impairment loss on an oil and gas equity investment of $2.9 million.

2016 Overview of Business Segments and Corporate Activity

Electric Utilities

In our Electric Utilities service territories, mild winter weather in 2016 partially offset a hotter than normal summer. Heating degree days were 2% lower than the prior year and 13% lower than normal. Offsetting this decrease was weather related demand during the peak summer months. Cooling degree days for the full year of 2016 were 9% higher than the same period in the prior year and 26% higher than normal.

On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

Construction riders related to the project increased gross margins by approximately $5.1 million for the year ended December 31, 2016.

On November 8, 2016, Colorado Electric completed the purchase of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased through progress payments throughout 2016 under a commission approved third-party build- transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments, Renewable Energy Standard Surcharge and Transmission Cost Adjustment for 10 years, after which Colorado Electric can propose base rate recovery.

Gas Utilities

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing. See additional information below under Corporate activities.

Gas Utilities were unfavorably impacted by milder weather in 2016 compared to 2015. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2015. Heating degree days for the full year in 2016 were 10% less than normal and 1% less than the same period in 2015.

The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on pre-hearing discovery and commission orders, the Company is considering filing new applications for approval of specific gas reserve properties.

~~Power Generation~~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, our cost of capital and our other operating costs.

Our use of derivative financial instruments could result in material financial losses.

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.

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 ~~purchase option for~~capital markets and the ~~sale~~costs and terms of ~~Wygen I~~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 ~~Cheyenne Light Fuel & Power~~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 Power Generation segment.~~

Black Hills Wyoming has a power sales agreement with Cheyenne Light which expires in December 2022. This power sales agreement includes an option for Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility until 2019. This purchase by Cheyenne Light, estimated to be approximately $154 million at December 31, 2014, would be subject to WPSC approval in order to obtain regulatory treatment. The inability to obtain power sales contracts at reasonable rates to fully utilize these assets subsequent to the expiration of long-term contracts could affect our results of operations, financial position and liquidity.

~~Coal Mining~~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.

~~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.~~

Our ~~mining consists~~ability to obtain insurance and the terms of ~~surface mining operations.~~ 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.

Increasing costs associated with our health care plans and other benefits may adversely affect our results of operations, financial position or liquidity.

The ~~Surface Mining Control~~costs of providing health care benefits to our employees and ~~Reclamation Act~~retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and ~~similar~~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 health care plans may adversely affect our results of operations, financial position or liquidity.

Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state ~~laws and regulation establish operations, reclamation and closure standards for all aspects of surface mining. We estimate our total reclamation liabilities~~regulatory authorities based on ~~permit~~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.

Prior to the Acquisition, SourceGas was a private company, exempt from reporting and control 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 valueunder Section 404 of the ~~estimated future cash flows. In estimating future cash flows, we consider~~Sarbanes-Oxley Act of 2002. As permitted by the ~~estimated current cost~~guidance set forth by the Securities and Exchange Commission, the acquired SourceGas businesses are not included in management’s assessment of ~~reclamation~~internal control over financial reporting for the year ended December 31, 2016. Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and ~~apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or~~effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the ~~timing~~effectiveness of these ~~expenses change significantly from~~controls. During their assessment of these controls, management or our ~~assumptions,~~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.

ENVIRONMENTAL RISKS

~~Estimates of the quality~~The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and ~~quantity of our coal reserves may change materially due~~any failure to numerous uncertainties inherent in three dimensional structural modeling. Significant inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserve whichdo so, could adversely affect our results of ~~operations.~~operations, financial position or liquidity.

~~There are many uncertainties inherent~~Our business is subject to extensive energy, environmental and other laws and regulations of federal, state, tribal and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in ~~estimating quantities~~order to operate, which can require significant capital expenditure and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of coal reserves. The process of coal volume estimation requires interpretations of drill hole log data and subsequent computer modeling of the intersected deposit. Significant inaccuracies in interpretationpenalties, liens 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 additionsfines, claims for property damage or ~~deletions from our volume estimates.~~personal injury, or environmental clean-up costs. In addition, ~~future environmental, economic~~existing regulations may be revised or ~~geologic changes~~reinterpreted and new laws and regulations may ~~occur~~be adopted or become ~~known that~~applicable to us or our facilities, which could require ~~reserve revisions either upward~~additional unexpected expenditures or ~~downward from prior reserve estimates.~~cause us to reevaluate the feasibility of continued operations at certain sites and have a detrimental effect on our business.

~~Oil and Gas~~

~~Estimates~~In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain properties, regardless of when such liabilities arose, whether known or unknown, and in some cases agreed to indemnify the ~~quantity~~former owners of those properties for environmental liabilities. Future steps to bring our facilities into compliance or to address contamination from legacy operations, if necessary, could be expensive and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves which could adversely affect our results of ~~operations.~~operations and financial condition. Environmental compliance expenditures could be substantial in the future if the trend towards stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate continues.

~~There~~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, NO_x, volatile organic compounds, particulate matter and GHG, which are ~~many uncertainties inherent~~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. Reductions in ~~estimating quantities~~mercury emissions required by EPA’s MATS rule described earlier, will likely require some power plants to install new equipment, at substantial cost, or discourage the use of ~~proved reserves~~certain coals containing higher levels of mercury. The EPA’s October 23, 2015 CPP described earlier, which has been stayed pending appeal, is designed to reduce carbon emissions from existing electric generating units. The basis of the CPP is to decrease existing coal-fired generation, increase the utilization of existing gas fired combined cycle generation, increase renewable energy and ~~their associated value. The process of estimating crude oil~~demand side management. This rule could have a significant impact on our coal and natural gas ~~reserves requires interpretation of available technical data~~generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and ~~various assumptions, including assumptions relating to economic factors. Significant inaccuracies in interpretations or assumptions could materially affect~~be assigned a new single target for the estimated quantities and present value of our reserves. The accuracy of reserve estimates is a function of the quality of available data, engineering and geological interpretations and judgment and the assumptions used regarding quantities of recoverable oil and gas reserves, future capital expenditures and prices for crude oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable crude oil andgroup.

Coal competes with other energy sources, such as natural gas, ~~reserves may vary from those assumed in our estimates. These variances may be significant. Any significant variance from the assumptions used could cause the actual quantity of our reserves~~wind, solar and ~~future net cash flow~~hydropower. The CPP regulation is expected to be materially different from our estimates. In addition, results of drilling, testing and production, changes in future capital expenditures and fluctuations in crude oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.

Hydraulic fracturing is an essential and common practice in the oil and gas industry used extensively for decades to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on our crude oil and natural gas properties. Hydraulic fracturing involves using mostly water, sand and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to enhance flow of hydrocarbons into the well-bore. The process is typically regulated by state crude oil and natural gas commissions; however, the EPA does assert federal regulatory authority over certain hydraulic fracturing activities when diesel comprises part of the fracturing fluid. In addition several agencies of the federal government including the EPA and the BLM are conducting studies of the fracturing stimulation process which may result in additional regulations. In May 2013, the U.S. Department of the Interior re-proposed rules regulating the use of hydraulic fracturing on Federal and Indian Lands, with final action expected in 2015. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide the federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Certain states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In the event federal, state, local or municipal legal restrictions on the hydraulic fracturing are adopted in areas where we are conducting or in the future plan to conduct operations, we may incur additional costs to comply with such regulations that may be significant, experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from utilizing fracture stimulation and effectively preclude the drilling of wells.

~~Exploratory and development drilling are speculative activities that may not result in commercially productive reserves. Lack of drilling success could result in uneconomical investments and could~~ have an adverse effect on coal as a domestic energy source, and could have a significant impact on our ~~financial condition and results of~~mining operations.

~~Drilling activities are subject to many risks, including~~Existing or proposed legislation focusing on emissions enacted by the ~~risk that no commercially productive oil~~United States or ~~gas reservoirs will be encountered. There can be no assurance that new wells drilled by~~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 in which we have an interest will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenuesswitch to ~~return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled~~alternative fuels as a result of ~~a variety of factors, many of which are beyond~~existing or future environmental regulations aimed at reducing emissions, our ~~control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental rules~~operations and regulations and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays are caused by the high demand for rigs and other needed equipment by a large number of companies in active drilling basins. High activity in some basins may cause shortages of rigs and equipment in other basins. Our future drilling activities may notfinancial results could be ~~successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.~~adversely impacted.

We could incur additional and substantial write-downs of the carrying value of our natural gas and oil properties, which would cause a decrease in our assets and stockholders' equity and could adversely impact our results of operations.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.

~~We review the carrying value of~~


ITEM 3.	LEGAL PROCEEDINGS

Information regarding our ~~natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis. This quarterly review~~legal proceedings is ~~referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal~~incorporated herein by reference to the ~~sum~~“Legal Proceedings” sub-caption within Item 8, Note 19, “Commitments and Contingencies”, of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, SEC-defined commodity prices and recent costs are utilized. Such prices and costs are utilized except when different prices and costs are fixed and determinable from applicable contracts for the remaining term of those contracts. Two primary factors in the ceiling test are natural gas and crude oil reserve quantities and SEC-defined crude oil and gas prices, both of which impact the present value of estimated future net revenues. Revisions to estimates of natural gas and crude oil reserves, or an increase or decrease in prices, can have a material impact on the present value of estimated future net revenues. The amount by which net book value, less deferred income tax, exceeds the tax adjusted net present value of reserves is written off as an expense.

~~We recorded a non-cash impairment charge in the second quarter of 2012 due to the full cost ceiling limitations. Using~~ our year-end reserve information and holding all other variables constant, a price sensitivity analysis indicates it is probable a ceiling impairment charge will occur in 2015 if crude oil and natural gas prices remain at or near the low levels experienced in late 2014 and early 2015. See Note 12 to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly dividends paid and the high and low prices for our common stock, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:



Year ended December 31, 2016	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.420	$	0.420	$	0.420	$	0.420
Common stock prices
High	$	61.13	$	63.53	$	64.58	$	62.83
Low	$	44.65	$	56.16	$	56.86	$	54.76



Year ended December 31, 2015	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.405	$	0.405	$	0.405	$	0.405
Common stock prices
High	$	53.37	$	52.96	$	47.27	$	47.51
Low	$	47.88	$	43.48	$	36.81	$	40.00

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during 2016.

ISSUER PURCHASES OF EQUITY SECURITIES



There were no equity securities acquired for the three months ended December 31, 2016.


ITEM 6.	SELECTED FINANCIAL DATA

(Minor differences may result due to rounding)



Years Ended December 31,	2016				2015				2014				2013				2012
(dollars in thousands, except per share amounts)

Total Assets	$	6,515,444			$	4,626,643			$	4,222,301			$	3,820,877			$	3,677,019

Property, Plant and Equipment
Total property, plant and equipment	$	6,412,223			$	4,976,778			$	4,563,400			$	4,259,445			$	3,930,772
Accumulated depreciation and depletion	(1,943,234		)		(1,717,684		)		(1,357,929		)		(1,306,390		)		(1,229,159		)
Total property, plant and equipment, net	$	4,468,989			$	3,259,094			$	3,205,471			$	2,953,055			$	2,701,613

Capital Expenditures	$	467,119			$	458,821			$	391,267			$	379,534			$	347,980

Capitalization (excluding noncontrolling interests)
Current maturities of long-term debt	$	5,743			$	—			$	275,000			$	—			$	103,973
Notes payable	96,600				76,800				75,000				82,500				277,000
Long-term debt, net of current maturities and deferred financing costs	3,211,189			(a)	1,853,682			(a)	1,255,953				1,383,714				927,561
Common stock equity	1,614,639			(b)	1,465,867			(b)	1,353,884				1,283,500				1,205,800
Total capitalization	$	4,928,171			$	3,396,349			$	2,959,837			$	2,749,714			$	2,514,334

Capitalization Ratios
Short-term debt, including current maturities	2		%		2		%		12		%		3		%		15		%
Long-term debt, net of current maturities	65		%	(a)	55		%		42		%		50		%		37		%
Common stock equity	33		%		43		%		46		%		47		%		48		%
Total	100		%		100		%		100		%		100		%		100		%

Total Operating Revenues	$	1,572,974			$	1,304,605			$	1,393,570			$	1,275,852			$	1,173,884

Net Income Available for Common Stock
Electric Utilities	$	85,827			$	77,579		(g)	$	57,270		(g)	$	49,003		(g)	$	52,123		(g)
Gas Utilities	59,624				39,306			(g)	44,151			(g)	35,838			(g)	27,465			(g)
Power Generation	25,930			(c)	32,650				28,516				16,288			(c)	21,328
Mining	10,053				11,870				10,452				6,327				5,626
Oil and Gas	(71,054		)	(b)	(179,958		)	(b)	(8,525		)		(1,751		)		18,683			(b)
Corporate and intersegment eliminations	(37,410		)	(d)	(13,558		)	(d, g)	(975		)		12,602			(d)	(15,808		)	(d)
Net Income (loss) available for common stock before discontinued operations	72,970				(32,111		)		130,889				118,307				109,417
Income (loss) from discontinued operations, net of tax ^(e)	—				—				—				(884		)		(6,977		)
Net income (loss) available for common stock	$	72,970			$	(32,111	)		$	130,889			$	117,423			$	102,440

SELECTED FINANCIAL DATA continued



Years Ended December 31,	2016			2015			2014			2013			2012
(dollars in thousands, except per share amounts)

Dividends Paid on Common Stock	$	87,570		$	72,604		$	69,636		$	67,587		$	65,262

Common Stock Data^(f) (in thousands)
Shares outstanding, average basic	51,922			45,288			44,394			44,163			43,820
Shares outstanding, average diluted	53,271			45,288			44,598			44,419			44,073
Shares outstanding, end of year	53,382			51,192			44,672			44,499			44,206

Earnings (Loss) Per Share of Common Stock (in dollars)
Basic earnings (loss) per average share -
Continuing operations	$	1.59		$	(0.71	)	$	2.95		$	2.68		$	2.50
Discontinued operations ^(e)	—			—			—			(0.02		)	(0.16		)
Non-controlling interest	(0.19		)	—			—			—			—
Total	$	1.41		$	(0.71	)	$	2.95		$	2.66		$	2.34
Diluted earnings (loss) per average share -
Continuing operations	$	1.55		$	(0.71	)	$	2.93		$	2.66		$	2.48
Discontinued operations	—			—			—			(0.02		)	(0.16		)
Non-controlling interest	(0.18		)	—			—			—			—
Total	$	1.37		$	(0.71	)	$	2.93		$	2.64		$	2.32

Dividends Declared per Share	$	1.68		$	1.62		$	1.56		$	1.52		$	1.48

Book Value Per Share, End of Year	$	30.25		$	28.63		$	30.31		$	28.84		$	27.28

Return on Average Common Stock Equity (full year)	4.7		%	(2.3		)%	9.9		%	9.4		%	8.7		%

SELECTED FINANCIAL DATA continued



Years ended December 31,	2016	2015	2014	2013	2012
Operating Statistics:
Generating capacity (MW):
Electric Utilities (owned generation)	941	841	841	790	859
Electric Utilities (purchased capacity)	110	210	210	150	150
Power Generation (owned generation)	269	269	269	309	309
Total generating capacity	1,320	1,320	1,320	1,249	1,318

Electric Utilities:
MWh sold:
Retail electric	5,140,519	4,990,594	4,775,808	4,642,254	4,598,080
Contracted wholesale	246,630	260,893	340,871	357,193	340,036
Wholesale off-system	769,843	1,000,085	1,118,641	1,456,762	1,652,949
Total MWh sold	6,156,992	6,251,572	6,235,320	6,456,209	6,591,065

Gas Utilities:
Gas sold (Dth)	79,165,742	56,638,299	64,861,411	64,131,850	51,620,293
Transport volumes (Dth)	126,927,565	77,393,775	77,433,266	73,730,017	71,092,286

Power Generation Segment:
MWh Sold	1,868,513	1,796,242	1,760,160	1,564,789	1,304,637
MWh Purchased	85,993	68,744	38,237	5,481	8,011

Oil and Gas Segment:
Oil and gas production sold (MMcfe)	12,142	12,896	9,986	9,529	12,544
Oil and gas reserves (MMcfe)^(b)	78,294	104,624	101,416	86,713	80,683

Mining Segment:
Tons of coal sold (thousands of tons)	3,817	4,140	4,317	4,285	4,246
Coal reserves (thousands of tons)	199,905	203,849	208,231	212,595	232,265


(a)	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)

(c)

(d)


(e)	Discontinued operations in 2013 and 2012 include post-closing adjustments and operations relating to Enserco, sold in 2012.


(f)	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.

(g)


ITEMS 7 &	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS


and 7A.	OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET

RISK

We are a customer-focused, growth-oriented, vertically-integrated utility company operating in the United States. We report our operations and results in the following financial segments.

Power Generation: Our Power Generation segment produces electric power from its generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts.

Mining: Our Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

Segment reporting transition of Cheyenne Light’s Natural Gas distribution

SourceGas Acquisition

Our Objective


•	Our three electric utilities achieved 1^st quartile reliability ranking with 64 customer minutes of outage time (SAIDI) in 2016 compared to industry averages (IEEE 2016 1^st quartile is less than 81 minutes);

Our JD Power Customer Satisfaction Survey indicated our Electric and Gas Utilities were favorable to our peers in the Midwest;


•	Our power generation fleet achieved a forced outage factor of 3.27% for coal fired plants, 0.76% for natural gas plants, and 0.00% for diesel plants in 2016, compared to an industry average^* of 4.61%, 4.41%, and 2.18%, respectively (^*NERC GADS 2015 Data);


•	Our power generation fleet availability was 94.41% for coal fired plants, 96.56% for natural gas fired plants, 98.92% for diesel fired plants, and 99.20% for wind generation in 2016 while the industry averages^ were 85.29%, 89.65%, 94.59% respectively (^NERC GADS 2015 data was used for coal, natural gas and diesel; data is not currently kept for wind);


•	Our safety TCIR of 1.7 compares well to an industry average of 2.2⁺ and our DART rate of 0.6 compares to an industry average of 1.2⁺ (⁺Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2015);

Key Elements of our Business Strategy

Rate-base generation assets offer several advantages including:

Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;

Investors are provided a long-term, reasonable, stable return on their investment; and

The lower risk profile of rate based generation assets may enhance credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

Oil and Gas will rationalize its asset base. In the current price environment, we have reduced future capital expenditures and staffing to improve financial performance.

Prospective Information

Electric Utilities

Gas Utilities

We completed substantially all integration activities in 2016. All significant operations, customer, accounting, human resources and rebranding activities were successfully completed and implemented.

Cost of Service Gas Program Filings

Mining

Oil and Gas

Corporate

Results of Operations

Executive Summary and Overview



	For the Years Ended December 31,
	2016			Variance			2015			Variance			2014
	(in thousands)
Revenue
Revenue	$	1,701,093		$	270,811		$	1,430,282		$	(90,827	)	$	1,521,109
Inter-company eliminations	(128,119		)	(2,442		)	(125,677		)	1,862			(127,539		)
	$	1,572,974		$	268,369		$	1,304,605		$	(88,965	)	$	1,393,570

Net income (loss) available for common stock
Electric Utilities^(a)	$	85,827		$	8,248		$	77,579		$	20,309		$	57,270
Gas Utilities^(a)	59,624			20,318			39,306			(4,845		)	44,151
Power Generation^(b)	25,930			(6,720		)	32,650			4,134			28,516
Mining	10,053			(1,817		)	11,870			1,418			10,452
Oil and Gas ^{(c) (d)}	(71,054		)	108,904			(179,958		)	(171,433		)	(8,525		)
	110,380			128,933			(18,553		)	(150,417		)	131,864

Corporate and Eliminations ^{(a) (e) (f)}	(37,410		)	(23,852		)	(13,558		)	(12,583		)	(975		)

Net income (loss) available for common stock	$	72,970		$	105,081		$	(32,111	)	$	(163,000	)	$	130,889

______________

(a)


(b)	On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest.


(c)	Net income (loss) available for common stock for 2016 and 2015 included non-cash after-tax impairments of our crude oil and natural gas properties of $67 million and $160 million. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


(d)	Net income (loss) available for common stock for 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.


(e)	Net income (loss) available for common stock for 2016 and 2015include incremental SourceGas Acquisition costs, after-tax of $30 million and $6.7 million and 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 business segments.


(f)	Net income (loss) available for common stock for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

2016 Compared to 2015

2016 Overview of Business Segments and Corporate Activity

Electric Utilities

Construction riders related to the project increased gross margins by approximately $5.1 million for the year ended December 31, 2016.

Gas Utilities

The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on pre-hearing discovery and commission orders, the Company is considering filing new applications for approval of specific gas reserve properties.

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, our cost of capital and our other operating costs.

Our issuer credit rating is ~~Baa1~~Baa2 (Stable outlook) by Moody’s; BBB (Stable outlook) by S&P; and BBB+ ~~(Stable~~(Negative 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.

~~In July 2010, Dodd-Frank was passed by Congress and signed into law.~~ 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 crude oil and natural gas derivative instruments for our hedging activities for our oil and gas production activities and our gas utility operations. We 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 to clearing entities for certain swap transactions we enter into. In addition ~~many of the transactions which were previously classified as swaps have been converted to~~our exchange-traded futures contracts ~~which~~ are subject to futures margin posting ~~requirements. Such a requirement~~requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price and interest rate 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 use of derivative financial instruments could result in material financial losses.

WeAs discussed in Note 18 of the Consolidated Financial Statements in this Annual Report on Form 10-K, we have ~~two~~one defined benefit pension plan and several defined post-retirement healthcare plans and ~~three non-pension postretirement~~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. ~~The subsidiaries may not be allowed or may be unable to make dividend payments or loan funds to the~~

As a holding company, ~~which could adversely affect~~ our ~~ability to meet our financial obligations or pay dividends to our shareholders.~~

~~We are 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.

~~We expect to continue our policy of paying regular cash dividends. However, there~~There is no assurance as to the amount, if any, of future dividends because they depend on our future earnings, capital requirements and financial conditions 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 ~~the~~ financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy. ~~Lack of credit at reasonable rates would have an adverse effect on our results of operations, financial position and liquidity.~~

Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, gas or well fluids, pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. WeWhile we maintain insurance coverage for our operated wells and we participate in insurance coverage maintained by the operators of our wells, ~~although~~ there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.

Increasing costs associated with our health care plans and other benefits may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. ~~The increasing costs~~Significant regulatory developments have, and ~~funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.~~

~~In March 2010, the President of the United States signed PPACA as amended by the Health Care and Education Reconciliation Act of 2010 (collectively, the “2010 Acts”). The 2010 Acts~~likely will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts are effective while other provisions of the 2010 Acts will be effective in future years. The 2010 Acts couldcontinue to, require ~~among other things,~~ changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our ~~plans. The ultimate extent~~plans, and ~~cost~~the increasing costs and funding requirements associated with our health care plans may adversely affect our results of ~~these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.~~operations, financial position or liquidity.

We have deferred a substantial amount of income tax related to various tax planning strategies, including the deferral of a gain associated with the assets sold in the IPP Transaction. If the Internal Revenue Service successfully challenges these tax positions, our results of operations, financial position or liquidity could be adversely affected.

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes associated with a like-kind exchange related to the IPP Transaction and the Aquila Transaction.

The IRS has challenged our position with respect to the like-kind exchange. As stated in a revised Notice of Proposed Adjustment received from the IRS in April 2013, their position is to disallow a significant portion of the gain deferred as reported on our originally filed 2008 tax return. A 30 Day Letter along with a Revenue Agent's Report were received on July 30, 2014, indicating no change in the IRS' position. We disagree with such a position and will pursue all available IRS and/or legal channels to challenge the proposed adjustment. A protest was timely filed with IRS Appeals in August 2014. In the event we are unsuccessful in our challenge, the amount of deferred income tax on a worst case basis that could be accelerated into a current taxes payable based on the revised NOPA would be approximately $88 million. However, we would be entitled to a cash tax benefit associated with the additional tax depreciation that would result from increasing the depreciable cost for tax purposes in the assets acquired. This net current tax liability would accrue interest, which is estimated to be approximately $19 million before income tax effect.

In certain circumstances, the IRS may assess penalties when challenging our tax positions. If we were unsuccessful in defending against these penalties, it may have a material impact on our results of operations. No penalties have been assessed by the IRS in connection with the like-kind exchange transaction.

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

Prior to the Acquisition, SourceGas was a private company, exempt from reporting and control requirements under Section 404 of the Sarbanes-Oxley Act of 2002. As permitted by the guidance set forth by the Securities and Exchange Commission, the acquired SourceGas businesses are not included in management’s assessment of internal control over financial reporting for the year ended December 31, 2016.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.

ENVIRONMENTAL RISKS

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming and Colorado. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants ~~will likely~~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 caption “Environmental Matters.”

On May 20, 2011, with amendments on December 21, 2012, the EPA’s Industrial and Commercial Boiler regulations became effective, which provide for hazardous air pollutant-related emission limits and monitoring requirements. The compliance deadline for this rule was March 21, 2014. Engineering evaluations were completed and confirmed the significant impact on our Neil Simpson I, Osage and Ben French facilities. These units were permanently retired on March 21, 2014. We have requested recovery for the remaining net book values of these plants and prudent decommissioning costs of these units. The WPSC granted approval to our request in the Wyoming rate case approved in August 2014, and our request with the SDPUC is pending with a decision expected in March 2015.

On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), with an effective date of April 16, 2012. Affected units have a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain circumstances. It is expected that all of our plants will be in compliance by the initial 2015 deadline, with the primary impacts to Neil Simpson II, Wygen I, Wygen II, Wygen III and the Wyodak Plant including installation of mercury sorbent injection systems, along with additional monitoring and testing requirements.

The GHG Tailoring Rule, ~~implementing regulations of GHG for permitting purposes, became~~ effective in June ~~2010. This rule~~2010, will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities, monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units, ~~was expected to be final by the end of 2014. As proposed, it~~published October 2015, effectively prohibits new ~~coal fired~~coal-fired units until carbon capture and sequestration becomes technically and economically feasible. It also effectively prohibits simple cycle natural gas combustion turbines from generating more than one-third of their capacity, averaged over a three year period. The rule was not finalized in 2014 and may be delayed to June 2015 to coincide with issuance of the Clean Power Plan regulations.

On ~~June 2, 2014,~~October 23, 2015, the EPA ~~proposed~~finalized the ~~Clean Power Plan~~CPP to cut carbon emissions from existing electric generating units. The design of the ~~Clean Power Plan~~CPP is to decrease existing coal-fired generation, increase the utilization of existing gas generation, increase renewable energy and demand side management. ~~This rule could have a significant impact on our coal and natural gas generating fleet.~~ The rule, which does not propose to regulate individual emission sources, calls for ~~states~~each state to develop plans to meet ~~their assigned~~the EPA-assigned statewide average emission rate ~~targets~~target for that state by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. The U.S. Supreme Court entered an order staying the CPP in February 2016, pending appeal. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. In 2015 and again in 2016, we met with the staff of state air programs and public utility commissions on several occasions. We ~~are currently evaluating this proposal, but cannot predict the impact on operations~~will continue to work closely with state regulatory staff as ~~this rule is expected to be final in June 2015. State~~these plans ~~are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018.~~develop.

Due to uncertainty as to the final outcome of federal climate change legislation, legal challenges, state clean power plan 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, cash flows or financial position. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to, the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level and the availability of technologies to control or reduce GHG emissions. If a “cap and trade” structure is implemented, the impact will depend on the degree to which offsets are allowed, the allocation of emission allowances to specific sources and the effect of carbon regulation on natural gas and coal prices.

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, ~~and~~ the closure or reduction of ~~certain~~load of coal generating ~~facilities.~~facilities and potential increased load of our combined cycle natural gas fired 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 ~~failure~~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. Additionally, the potentially high cost of complying with such requirements or addressing environmental liabilities could also adversely affect our results of operations, financial position or liquidity.

In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain properties, regardless of when such liabilities arose, whether known or unknown, and in some cases agreed to indemnify the former owners of those properties for environmental liabilities. Future steps to bring our facilities into compliance or to address contamination from legacy operations, if necessary, could be expensive and could adversely affect our results of ~~operation~~operations and financial condition. ~~We expect our environmental~~Environmental compliance expenditures tocould be substantial in the future ~~due to~~if the ~~continuing trends toward~~trend towards stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we ~~operate.~~operate continues.

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. ~~As a result, coal users may switch to other fuels, which would affect the volume of our sales and the price of our products.~~

~~Coal contains impurities, including but not limited to sulfur,~~Future regulations may require further reductions in emissions of mercury, ~~chlorine, carbon~~hazardous pollutants, SO₂, NO_x, volatile organic compounds, particulate matter and ~~other elements or compounds, many of~~GHG, which are released into the air when coal is burned. ~~More stringent environmental regulations of emissions from coal-fueled power plants~~These requirements could increase the costs of using coal, thereby reducing demand for coal as a fuel source and the volume and price of our coal sales. Renewable energy requirements and changes to regulations could make coal a less attractive fuel alternative in the planning and building of power plants in the future.

~~Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter, or greenhouse gases may~~ require the installation of costly emission control technology or the implementation of other measures. ~~For example, in order to meet the federal Clean Air Act limits for SO~~₂ ~~emission from power plants, coal users may need to install scrubbers, use SO~~₂ ~~emission allowances (some of which they may purchase), blend high-sulfur coal with low-sulfur coal or switch to other fuels.~~ Reductions in mercury ~~emission~~emissions required by ~~certain states and the EPA~~EPA’s MATS rule described earlier, will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. ~~On June 2, 2014, the EPA proposed the Clean Power Plan~~The EPA’s October 23, 2015 CPP described earlier, which has been stayed pending appeal, is designed to ~~cut~~reduce carbon emissions from existing electric generating units. The ~~design~~basis of the ~~Clean Power Plan~~CPP is to decrease existing coal-fired generation, increase the utilization of existing gas fired combined cycle generation, increase renewable energy and demand side management. This rule could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. We are currently evaluating this proposal, but cannot predict the impact on operations as this rule is expected to be final in June 2015. State plans are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018.

Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. ~~If the Clean Power Plan Rule regulations were~~The CPP regulation is expected to have an adverse effect on coal as a domestic energy source, ~~this rule~~and could have a significant impact on our ~~coal~~ mining operations.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 1819, “Commitments and Contingencies”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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.	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, ~~2014~~2016, we had ~~4,155~~3,860 common shareholders of record and approximately ~~26,000~~28,000 beneficial owners, representing all 50 states, the District of Columbia and 108 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 ~~28, 2015~~25, 2017 meeting, our Board of Directors declared a quarterly dividend of ~~$0.405~~$0.445 per share, equivalent to an annual dividend of ~~$1.62~~$1.78 per share, marking ~~2015~~2017 as the 4547^th consecutive annual dividend increase for the Company.

Quarterly dividends paid and the high and low prices for our common stock, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:


Year ended December 31, 2014	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year ended December 31, 2016									First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.390	$	0.390	$	0.390	$	0.390	$	0.420	$	0.420	$	0.420	$	0.420
Common stock prices
High	$	59.05	$	61.41	$	62.13	$	57.17	$	61.13	$	63.53	$	64.58	$	62.83
Low	$	51.09	$	55.23	$	47.87	$	47.11	$	44.65	$	56.16	$	56.86	$	54.76


Year ended December 31, 2013	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year ended December 31, 2015									First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Dividends paid per share	$	0.380	$	0.380	$	0.380	$	0.380	$	0.405	$	0.405	$	0.405	$	0.405
Common stock prices
High	$	44.32	$	50.53	$	55.09	$	54.83	$	53.37	$	52.96	$	47.27	$	47.51
Low	$	36.89	$	43.19	$	46.62	$	47.00	$	47.88	$	43.48	$	36.81	$	40.00

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during ~~2014~~.2016.

ISSUER PURCHASES OF EQUITY SECURITIES



There were no equity securities acquired for the three months ended December 31, ~~2014.~~2016.


ITEM 6.	SELECTED FINANCIAL DATA

(Minor differences may result due to rounding)


Years Ended December 31,	2014			2013				2012				2011				2010				2016				2015				2014				2013				2012
(dollars in thousands, except per share amounts)	(dollars in thousands, except per share amounts)																			(dollars in thousands, except per share amounts)

Total Assets	$	4,279,806		$	3,875,178			$	3,729,471			$	4,127,083			$	3,711,509			$	6,515,444			$	4,626,643			$	4,222,301			$	3,820,877			$	3,677,019

Property, Plant and Equipment
Total property, plant and equipment	$	4,563,400		$	4,259,445			$	3,930,772			$	3,724,016			$	3,353,509			$	6,412,223			$	4,976,778			$	4,563,400			$	4,259,445			$	3,930,772
Accumulated depreciation and depletion	$	(1,324,025	)	$	(1,269,148	)		$	(1,188,023	)		$	(934,441	)		$	(861,775	)		(1,943,234		)		(1,717,684		)		(1,357,929		)		(1,306,390		)		(1,229,159		)
Total property, plant and equipment, net																				$	4,468,989			$	3,259,094			$	3,205,471			$	2,953,055			$	2,701,613

Capital Expenditures	$	391,267		$	379,534			$	347,980			$	431,707			$	496,990			$	467,119			$	458,821			$	391,267			$	379,534			$	347,980

Capitalization
Capitalization (excluding noncontrolling interests)
Current maturities of long-term debt	$	275,000		$	—			$	103,973			$	2,473			$	5,181			$	5,743			$	—			$	275,000			$	—			$	103,973
Notes payable	75,000			82,500				277,000				345,000				249,000				96,600				76,800				75,000				82,500				277,000
Long-term debt, net of current maturities	1,267,589			1,396,948				938,877				1,280,409				1,186,050
Long-term debt, net of current maturities and deferred financing costs																				3,211,189			(a)	1,853,682			(a)	1,255,953				1,383,714				927,561
Common stock equity	1,376,024			1,307,748				1,232,509				1,209,336				1,100,270				1,614,639			(b)	1,465,867			(b)	1,353,884				1,283,500				1,205,800
Total capitalization	$	2,993,613		$	2,787,196			$	2,552,359			$	2,837,218			$	2,540,501			$	4,928,171			$	3,396,349			$	2,959,837			$	2,749,714			$	2,514,334

Capitalization Ratios
Short-term debt, including current maturities	12		%	3		%		15		%		12		%		10		%		2		%		2		%		12		%		3		%		15		%
Long-term debt, net of current maturities	42		%	50		%		37		%		45		%		47		%		65		%	(a)	55		%		42		%		50		%		37		%
Common stock equity	46		%	47		%		48		%		43		%		43		%		33		%		43		%		46		%		47		%		48		%
Total	100		%	100		%		100		%		100		%		100		%		100		%		100		%		100		%		100		%		100		%

Total Operating Revenues	$	1,393,570		$	1,275,852			$	1,173,884			$	1,272,188			$	1,219,691			$	1,572,974			$	1,304,605			$	1,393,570			$	1,275,852			$	1,173,884

Net Income Available for Common Stock	Net Income Available for Common Stock																			Net Income Available for Common Stock
Utilities	$	101,421		$	84,841			$	79,588			$	81,860			$	74,563
Non-regulated Energy	28,335			18,403			(1)	24,725			(1)	866				10,189
Electric Utilities																				$	85,827			$	77,579		(g)	$	57,270		(g)	$	49,003		(g)	$	52,123		(g)
Gas Utilities																				59,624				39,306			(g)	44,151			(g)	35,838			(g)	27,465			(g)
Power Generation																				25,930			(c)	32,650				28,516				16,288			(c)	21,328
Mining																				10,053				11,870				10,452				6,327				5,626
Oil and Gas																				(71,054		)	(b)	(179,958		)	(b)	(8,525		)		(1,751		)		18,683			(b)
Corporate and intersegment eliminations	(975		)	12,602			(2)	(15,808		)	(2)	(42,361		)	(2)	(21,611		)	(2)	(37,410		)	(d)	(13,558		)	(d, g)	(975		)		12,602			(d)	(15,808		)	(d)
Income (loss) from continuing operations	128,781			115,846				88,505				40,365				63,141
Income (loss) from discontinued operations, net of tax ⁽³⁾	—			(884		)		(6,977		)		9,365				5,544
Net income available for common stock	$	128,781		$	114,962			$	81,528			$	49,730			$	68,685
Net Income (loss) available for common stock before discontinued operations																				72,970				(32,111		)		130,889				118,307				109,417
Income (loss) from discontinued operations, net of tax ^(e)																				—				—				—				(884		)		(6,977		)
Net income (loss) available for common stock																				$	72,970			$	(32,111	)		$	130,889			$	117,423			$	102,440

~~2014~~2016 Compared to ~~2013~~2015

~~Income from continuing operations~~Net income (loss) available for common stock was ~~$129~~$73 million, or ~~$2.89~~$1.37 per diluted share in 2016, compared to $(32) million, or $(0.71) per share in ~~2014~~2015. Net income available for common stock in 2016 increased over the same period in the prior year due primarily to: lower Oil and Gas property impairment charges; higher earnings at our Electric Utilities and Gas Utilities, which include earnings of $15 million from our acquired SourceGas utilities since the acquisition date of February 12, 2016; tax benefits of approximately $11 million from additional Oil and Gas properties’ percentage depletion deductions, and the re-measurement of uncertain tax positions’ liability predicated on an agreement reached with IRS Appeals. These increases were partially offset by $9.6 million of net income attributable to noncontrolling interests. Non-cash after-tax oil and gas property impairment charges were $67 million and after-tax SourceGas incremental acquisition and transition costs were $30 million in the year ended December 31, 2016. The Net income (loss) available for common stock for the year ended 2015 included non-cash after-tax ceiling test impairments of our oil and gas properties of $158 million, after-tax SourceGas incremental acquisition and transition costs of $6.7 million, and a non-cash after-tax impairment loss on an oil and gas equity investment of $2.9 million.

2016 Overview of Business Segments and Corporate Activity

Electric Utilities

Construction riders related to the project increased gross margins by approximately $5.1 million for the year ended December 31, 2016.

Gas Utilities

Gas Utilities were unfavorably impacted by milder weather in 2016 compared to ~~$116~~2015. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2015. Heating degree days for the full year in 2016 were 10% less than normal and 1% less than the same period in 2015.

The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on pre-hearing discovery and commission orders, the Company is considering filing new applications for approval of specific gas reserve properties.

Power Generation

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. FERC approval of the sale was received on March 29, 2016. Proceeds from the sale were used to pay down short-term debt. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric.

Oil and Gas

Our Oil and Gas segment was impacted by lower net hedged prices received for crude oil and natural gas for the year ended December 31, 2016 compared to the same period in 2015. The average hedged price received for natural gas decreased by 24% for the year ended December 31, 2016 compared to the same period in 2015. The average hedged price received for oil decreased by 6% for the year ended December 31, 2016 compared to the same period in 2015. Oil and Gas production volumes decreased 6% for the year ended December 31, 2016 compared to the same period in 2015 as production was limited to meeting minimum daily quantity contractual gas processing requirements in the Piceance.

We review the carrying value of our natural gas and crude oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling test impairment charge in each quarter of 2016 totaling $92 million for the year ended December 31, 2016. We also recorded a $14 million impairment of other Oil and Gas depreciable properties not included in our full cost pool during the second quarter of 2016 as we advanced our strategy to divest non-core oil and gas assets. In 2016, we sold non-core assets for total proceeds of $11 million.

Corporate Activities

On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. Through December 31, 2016, we have sold and 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.

On December 22, 2016, we implemented 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. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as of December 31, 2016.

On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.

On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% 10-year senior notes due January 15, 2027 and $300 million of 4.20% 30-year senior notes due September 15, 2046. The proceeds of the notes were used for the following:


◦	Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;


◦	Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;


◦	Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;


◦	Pay down $100 million of the $500 million three-year unsecured term loan discussed below;


◦	Payment of $29 million for the settlement of $400 million notional interest rate swaps; and


◦	Remainder was used for general corporate purposes.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017.

On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021, with two, one-year extension options (subject to consent from the lenders). The facility includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility up to $1 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options, which are substantially the same as the former agreement.

On June 7, 2016, we issued a $29 million, declining balance five-year term loan maturing June 7, 2021, to finance the early termination of a gas supply agreement.

During the first quarter of 2016, we reached an agreement in principle with IRS Appeals with respect to our liability for unrecognized tax benefits attributable to the like-kind exchange effectuated in connection with the 2008 IPP Transaction and the 2008 Aquila Transaction. This agreement resulted in a tax benefit of approximately $5.1 million in the first quarter of 2016. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional details on this agreement.

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing. We funded the majority of the SourceGas Transaction with the following financings:

On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300 million of 3.95%, 10-year senior notes due 2026, and $250 million of 2.50%, 3-year senior notes due 2019. Net proceeds after discounts and fees were approximately $546 million; and

On November 23, 2015, we completed the offerings of common stock and equity units. We issued 6.325 million shares of common stock for net proceeds of $246 million and 5.98 million equity units for net proceeds of approximately $290 million.

On February 12, 2016, S&P affirmed the BHC credit rating of BBB and maintained a stable outlook after our acquisition of SourceGas, reflecting their expectation that management will continue to focus on the core utility operations while maintaining an excellent business risk profile following the acquisition.

On February 12, 2016, Fitch affirmed the BHC credit rating of BBB+ and maintained a negative outlook after our acquisition of SourceGas, which reflects the initial increased leverage associated with the SourceGas Acquisition.

On January 20, 2016, we executed a 10-year, $150 million notional, forward starting pay fixed interest rate swap at an all-in interest rate of 2.09%, and on October 2, 2015, we executed a 10-year, $250 million notional forward starting pay fixed interest rate swap at an all-in rate of 2.29%, to hedge the risks of interest rate movement between the hedge dates and pricing date for long-term debt refinancings occurring in August 2016. On August 19, 2016, we settled and terminated these interest rate swaps for a loss of $29 million. The loss recorded in AOCI is being amortized over the 10-year life of the associated debt.

2015 Compared to 2014

Net income (loss) was $(32) million, or ~~$2.61~~$(0.71) per share, in ~~2013.~~2015 compared to $131 million, or $2.93 per share, in 2014. 2015 Net income (loss) included a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million. 2015 Net income (loss) also included after-tax, external third-party costs of $6.7 million, primarily attributable to the SourceGas Acquisition. The 2014 ~~Income from continuing operations~~Net income (loss) did not include any expenses, gains, or losses that we believe are not representative of our core operating performance. The 2013 Income from continuing operations includes a $20 million non-cash after-tax mark-to-market gain on certain interest rate swaps, $6.6 million after-tax interest expense related to the early settlement of interest rate swaps and write-off of deferred financing costs associated with the prepayment of Black Hills Wyoming’s project financing and $7.6 million after-tax expense for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes.

~~Net income was $129 million, or $2.89 per share, in 2014 compared to $115 million, or $2.59 per share, in 2013~~2015 Overview of Business Segments and ~~includes the same items described above and losses from our Energy Marketing segment sold in February 2012.~~Corporate Activity

~~Business Group highlights for 2014 include:~~Electric Utilities

In our Electric Utilities ~~Group~~

~~Highlights of the Utilities Group include the following:~~

~~Gas Utilities were favorably impacted by colder~~service territories, mild winter weather in 2015 offset a hotter than normal weather during the first quarter of 2014, which was 14% colder than normal and 7% colder than the first quarter of 2013. This led to an increase in retail natural gas sold and offset unfavorable weather experienced through the remainder of 2014 when compared to 2013. Our service territories reported colder than normal winter weather as measured by heating degree days, compared to the 30-year average, but not as cold as 2013.summer. Heating degree days ~~for the full year in 2014~~ were ~~7% colder than normal but 2% less~~11% lower than the ~~same period in 2013.~~

~~Mild~~prior year and 10% lower than normal. Offsetting this was weather ~~was a contributing factor for our Electric Utilities during the year. Weather~~ related demand during the peak summer ~~months was tempered by significantly cooler temperatures within our service territories.~~months. Cooling degree days for the full year of ~~2014~~2015 were ~~29%~~ ~~lower~~32% higher than the same period in the prior year and ~~12%~~ ~~lower~~16% higher than normal.

Construction commenced in the second quarter of 2015 on Colorado Electric’s $63 million 40 MW natural gas-fired combustion turbine. As of December 31, 2015, approximately $35 million was expended Construction riders related to the project increased gross margins by approximately $1.9 million for the year ended December 31, 2015. This turbine was completed in and placed into service in December 2016.

On ~~December 19, 2014, Colorado~~July 23, 2015, South Dakota Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt. The CPUC also authorized the implementation of a riderWPSC for a ~~return on capital expenditures for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.~~

~~On December 16, Kansas Gas received approval from the Kansas Corporation Commission to increase annual base revenue by an estimated $5.2 million, effective Jan. 1, 2015.~~

On October 1, 2014, Black Hills Power and Cheyenne Light placed into commercial service their jointly-owned Cheyenne Prairie generating station. Cheyenne Prairie is a 132 MW, $222 million natural gas-fired generating facility built to serve Black Hills Power and Cheyenne Light customers. Cheyenne Prairie was constructed on time and on budget. Construction financing costs were recovered through construction financing riders.

◦

On October 1, 2014, Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie. Black Hills Power issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 and Cheyenne Light issued $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. Proceeds from Black Hills Power’s bond sale also funded the early redemption of its 5.35%, $12 million pollution control revenue bonds, originally due October 1, 2024.

◦

Black Hills Power and Cheyenne Light each received approval from the WPSC on rate cases associated with Cheyenne Prairie. On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt.

◦

On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Interim rates were implemented on October 1, 2014 when Cheyenne Prairie commenced commercial operations. A final ruling from the SDPUC is expected in the first quarter of 2015.

~~On July 22, 2014, Black Hills Power filed a~~ CPCN ~~with the WPSC~~ to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. ~~Approval by the WPSC is anticipated in the second quarter of 2015.~~

~~On June 30,~~South Dakota Electric received approval on November 6, 2014 ~~Black Hills Power filed an application with~~from the SDPUC for a permit to construct the South Dakota ~~portion~~portion. Construction commenced in the first quarter of ~~this line,~~2016, and ~~received approval on November 6, 2014.~~the project is expected to be placed in service in the first half of 2017.

On ~~May 5, 2014,~~June 23, 2015, Colorado Electric ~~issued an~~filed for a CPCN with the CPUC to acquire the planned 60 MW Peak View Wind Project, to be located near Colorado Electric's Busch Ranch Wind Farm. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request ~~including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request.~~on May 5, 2014. On December 23, 2014 the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that our standalone bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in FebruaryOctober 21, 2015, the Commission ~~determined none~~approved a build transfer proposal and settlement agreement. The settlement provides for recovery of the ~~alternatives was acceptable, because~~costs of ~~potential short-term rate impacts. The Commission discussed~~ the ~~possibility that~~project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which Colorado Electric ~~could more economically comply with~~can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy ~~standard~~generated by ~~purchasing renewable energy credits. The purchase~~the facility against the bid cost of ~~renewable energy credits will be considered in~~ a ~~separate proceeding. After review of~~PPA from the ~~Commission’s decision regarding the all source solicitation (which has not yet been issued),~~same facility. Colorado Electric ~~will determine whether to seek reconsideration.~~purchased the project from a third-party for approximately $109 million through progress payments throughout 2016, with ownership transfer occurring on November 7, 2016.

On ~~April 25, 2014, Cheyenne Light received FERC approval~~March 16, 2015, we announced plans to ~~establish rates~~build a new corporate headquarters in Rapid City, South Dakota that will consolidate our approximately 500 employees in Rapid City from five locations into one. The investment in the new corporate headquarters will be approximately $70 million and will support all our businesses. The cost of the facility will replace existing expenses associated with our current facilities throughout Rapid City. Construction began in September 2015 with completion expected in the fall of 2017.

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for ~~transmission services under their Open Access Transmission Tariff, effective May 3, 2014.~~South Dakota Electric of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The ~~approval includes~~SDPUC’s decision provides South Dakota Electric a return on ~~equity~~its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of ~~10.6%~~its share of operating expenses for this natural gas-fired facility. South Dakota Electric implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of ~~54%~~49.83% equity and ~~46% debt.~~50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $63 million natural gas-fired combustion turbine that was constructed in 2015 and 2016 to replace the retired W.N. Clark power plant.

On March 21, 2014, Black Hills Power retired the Ben French, Neil Simpson I and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. These plants were largely replaced by Black Hills Power’s share of Cheyenne Prairie.Gas Utilities

~~On February 25, 2014,~~Gas Utilities were unfavorably impacted by milder weather in 2015 compared to 2014. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the ~~CPUC issued a final order after rehearing, approving a CPCN~~30-year average, and compared to 2014. Heating degree days for the ~~retirement of Pueblo Unit #5~~full year in 2015 were 8% less than normal and ~~#6, effective December 31, 2013.~~

~~BHC continued its efforts to acquire smaller public and municipal gas distribution systems adjacent to our existing service territories.~~


◦	On January 1, 2015, we closed a $6 million transaction to acquire the natural gas utility assets of MGTC, Inc., a northeast Wyoming system serving more than 400 customers. This system will be operated by and consolidated into the results of Cheyenne Light.

◦

On October 14, 2014, we announced an agreement to acquire Energy West Wyoming, Inc., a Wyoming gas utility, and pipeline assets of Gas Natural, Inc. for $17 million. The gas utility serves approximately 6,700 customers, including service to Cody, Ralston and Meeteetse, Wyoming. The pipeline assets include a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory.


◦	~~During the first quarter of 2014, we acquired an additional gas system~~13% less than the same period in ~~Kansas, adding approximately 70 customers.~~

~~Non-regulated Energy Group~~

Coal Mining completed negotiations on the coal contract price increase with the third-party operator of the Wyodak plant. The new coal price of $18.25 per ton, an increase of approximately $4.75, was effective July 1, 2014.

On ~~September 3, 2014, Black Hills~~July 1, 2015, we completed the acquisition of Wyoming ~~closed the sale of its 40 MW CTII natural-gas fired generating unit to the City of Gillette,~~natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. The utility and pipeline assets were acquired for approximately ~~$22~~$17 million, ~~upon expiration~~and operate as subsidiaries of Wyoming Electric. The acquired system serves approximately 6,700 customers, in Cody, Ralston, and Meeteetse, Wyoming. The pipeline acquisition includes a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory.

In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on ~~August 31,~~December 16, 2014 offrom the ~~PPA with Cheyenne Light. As part of the sale, Black Hills Wyoming will provide services~~KCC to ~~the City of Gillette through ancillary agreements, including an~~increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating ~~agreement~~costs. The approval was a Global Settlement and ~~an economy energy PPA. The sale resulted in a deferred gain of $4.9 million which Black Hills Wyoming will recognize equally over the twenty-year term of the operating agreement.~~did not stipulate return on equity and capital structure.

Oil and Gas

Our ~~southern Piceance Basin drilling program continued~~Oil and Gas segment was impacted by lower commodity prices for crude oil and natural gas for the year ended December 31, 2015 compared to the same period in 2014. ~~During~~The average hedged price received for natural gas decreased by 39% for the ~~third~~year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for oil decreased by 24% for the year ended December 31, 2015 compared to the same period in 2014. Oil and Gas production volumes increased 29% for the year ended December 31, 2015 compared to the same period in 2014.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling impairment charge in each quarter ~~three~~of 2015, totaling $250 million for the year ended December 31, 2015.

We finished drilling the last of 13 Mancos Shale wells ~~were drilled, cased and cemented. On March 6, 2014, the Summit Midstream cryogenic gas processing plant with a capacity of 20,000 Mcf per day started serving the company’s gas production~~for our 2014/2015 drilling program in the ~~southern~~ Piceance ~~Basin, including two Mancos Shale~~Basin. Nine wells were placed on production ~~during~~in 2015, all with favorable production results to date, exceeding our expectations. We deferred the ~~first quarter.~~completion of our four remaining wells due to insufficient gas processing capacity and our expectation of continued low commodity prices. During the second quarter of 2015, we also reduced our planned 2016 and 2017 capital expenditures due to our strategic decision to focus our oil and gas expertise on being a cost of service gas provider for our electric and natural gas utilities.

Corporate Activities

The company recently announced that Anthony Cleberg, executive vice president and chief financial officer, will retire at the end of March 2015. Richard Kinzley, previously vice president and controller andOn July 12, 2015 we entered into a 15-year veteran of the company, was appointed senior vice president and chief financial officer, effective January 1, 2015. In addition, the senior leadership team was expanded when Brian Iverson, previously vice president and treasurer and 11-year veteran of the company, was appointed senior vice president regulatory and government affairs and assistant general counsel.

~~Consolidated interest expense decreased by~~definitive agreement to acquire SourceGas for approximately ~~$41~~$1.89 billion, which included an estimated $200 million in ~~2014, compared to 2013, due primarily to the refinancing activities occurring during the fourth quarter of 2013~~capital expenditures through closing and the ~~extension~~assumption of ~~our Revolving Credit Facility under favorable terms~~$760 million in long-term debt at closing. This acquisition closed on ~~May 29, 2014.~~February 12, 2016. Financing activities related to this acquisition are detailed above in the 2016 Corporate activities.

On June ~~13, 2014, Fitch upgraded the BHC credit rating to BBB+ with a stable outlook.~~

~~On May 29, 2014,~~26, 2015, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term one year, through ~~May 29, 2019.~~June 26, 2020. This facility is ~~substantially~~ similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate ~~options for which the borrowing rates were reduced under the amended agreement.~~

~~On January 30, 2014, Moody’s upgraded the BHC credit rating to Baa1 from Baa2 with a stable outlook.~~

~~2013 Compared to 2012~~

Income from continuing operations was $116 million, or $2.61 per share, in 2013 compared to $89 million, or $2.01 per share, in 2012. The 2013 Income from continuing operations includes a $20 million non-cash after-tax mark-to-market gain on certain interest rate swaps, ~~$6.6 million~~ after-tax interest expense related to the early settlement of interest rate swaps and write-off of deferred financing costs associated with the prepayment of Black Hills Wyoming’s project financing and $7.6 million after-tax expense for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt. The 2012 Income from continuing operations includes a $19 million after-tax gain on sale related to the Williston Basin asset sale, a $17 million non-cash after-tax ceiling test impairment, a $1.0 million non-cash after-tax write-off of deferred financing costs related to our previous Revolving Credit Facility, a $4.6 million after-tax make-whole premium for the early redemption of our $225 million corporate notes and a $1.2 million non-cash after-tax mark-to-market gain on certain interest rate swaps.

Net income was $115 million, or $2.59 per share, in 2013 compared to $82 million, or $1.85 per share, in 2012 and includes the same items described above and losses from our Energy Marketing segment sold in February 2012.

~~Business Group highlights for 2013 included:~~

~~Utilities Group~~

~~Highlights of the Utilities Group include the following:~~

On September 17, 2013, the South Dakota Public Utilities Commission approved a general rate case settlement agreement authorizing an increase for Black Hills Power of $8.8 million, or 6.4%, in annual electric revenues effective June 16, 2013. The settlement agreement was confidential and certain terms were not disclosed.

~~On September 17, 2013, the SDPUC approved~~ ~~the construction financing rider~~ in lieu of traditional AFUDC with an effective date of April 1, 2013. The rider allowed Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40% share of the total Cheyenne Prairie project cost that relates to South Dakota customers, while also saving customers money over the long-term. Cheyenne Light and Black Hills Power received approval from the WPSC for a similar construction financing rider in 2012 which allowed Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60% share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers.

Utility results for 2013 were favorably impacted by cold weather while 2012 utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported colder winter weather, as measured by heating degree days, compared to the 30-year average and the prior year. Heating degree days for the full year in 2013 were~~9% higher than weighted average norms for our Gas Utilities and 25% higher than the same period in 2012.~~

During 2013, Cheyenne Light and Black Hills Power commenced construction on Cheyenne Prairie. Project costs for plant construction and associated transmission were estimated at $222 million, of which approximately $156 million was spent as of December 31, 2013.

In April 2013, Colorado Electric filed an Energy Resource Plan with the CPUC addressing its projected resource requirements through 2019. The resource plan identified a 40 MW, simple-cycle, natural gas-fired turbine as the replacement of W.N. Clark. On January 6, 2014, the CPUC issued its initial written decision approving construction of the turbine.options.

On April ~~15, 2013, the IUB approved~~13, 2015, we entered into a Capital Infrastructure Automatic Adjustment Mechanism effective April 25, 2013, for $0.2 million. This adjustment mechanism requires an annual filing, therefore, subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings.

~~On November 25, 2013, the NPSC approved an Infrastructure System Replacement Cost Recovery Charge that provided for an annual revenue increase of $1.4 million.~~

On December 31, 2013, Colorado Electric retired W.N. Clark and Pueblo Units #5 and #6. These facilities, and certain Black Hills Power generating facilities, are being permanently retired primarily due to state and federal environmental regulations.new $300 million unsecured term loan. The ~~affected plants are listed in the table below with their operations suspension date and their ultimate retirement date:~~

Plant Company MW Type of Plant Date Suspended Actual Retirement Date Age of Plant (in years)
Osage Black Hills Power 34.5
Coal October 1, 2010 March 21, 2014 64
Ben French Black Hills Power 25.0
Coal August 31, 2012 March 21, 2014 52
Neil Simpson I Black Hills Power 21.8
Coal NA March 21, 2014 43
W.N. Clark Colorado Electric 42.0
Coal December 31, 2012 December 31, 2013 57
Pueblo Unit #5 Colorado Electric 9.0
Gas December 31, 2012 December 31, 2013 71
Pueblo Unit #6 Colorado Electric 20.0
Gas December 31, 2012 December 31, 2013 63
Total MW 152.3

~~Gas Utilities continued efforts to acquire small gas distribution systems adjacent to their existing gas utility service territories. During 2013, five small gas systems~~loan has a two-year term with a ~~total~~maturity date of ~~approximately 900 customers were acquired.~~

~~Non-regulated Energy Group~~

~~Highlights~~April 12, 2017. Proceeds of the ~~Non-regulated Energy Group include the following:~~

In 2013, our Oil and Gas segment drilled and completed two horizontal wells in the Mancos Shale formation in the Piceance Basin. These wells are part of a transaction in which we earned approximately 20,000 net acres of Mancos Shale leasehold in the Piceance Basin in exchange for drilling and completing the two wells.

Black Hills Wyoming entered into an agreement to sell its 40 MW CTII natural-gas fired generating unit to the City of Gillette for approximately $22 million upon expiration on August 31, 2014 of the PPA with Cheyenne Light. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through ancillary agreements, including a 20-year operating agreement and a 20 year economy energy PPA. The sale closed in September 2014.

On September 27, 2012, our Oil and Gas segment sold approximately 85% of its Williston Basin assets, including approximately 73 gross wells and 28,000 net leasehold acres, for net cash proceeds of approximately $228 million. We recognized a gain of $29 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and had the effect of reducing the depreciation, depletion and amortization rate after the sale.

~~Coal Mining continued operations under its revised mine plan. Mining operations moved in August 2012, to an area with lower overburden ratios, which reduced mining costs in 2013.~~

~~In the second quarter of 2012, our Oil and Gas segment recorded a $27 million non-cash ceiling test impairment loss as a result of continued low natural gas prices.~~

~~Corporate~~

~~Activities at Corporate include the following:~~

~~On November 19, 2013, we completed a public debt offering of $525 million in senior unsecured debt at 4.25% due November 30, 2023. Proceeds~~term note were used to ~~redeem our $250~~repay the existing $275 million 9% senior unsecured notes, pay off the Black Hills Wyoming project financing and related interest rate swaps, settle the de-designated interest rate swaps, partially pay down our Revolving Credit Facility and the remainder was used for other corporate purposes.term note due June 19, 2015.

On September 25, 2013, Moody’s raised our corporate credit rating to Baa2 from Baa3 with continued positive outlook. On July 24, 2013, S&P raised our corporate credit rating to BBB from BBB- with a stable outlook. They also raised our senior unsecured rating to BBB from BBB-. On May 10, 2013, Fitch Ratings raised our Issuer Default Rating to BBB from BBB- with a positive outlook. Subsequently on January 30, 2014, Moody’s upgraded our corporate credit rating to Baa1 and changed their outlook to stable.

~~On June 21, 2013, we replaced our $150 million and $100 million term loans with a two-year term loan for $275 million at an interest rate of 1.125% over LIBOR.~~

We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $30 million in 2013 compared to a $1.9 million unrealized mark-to-market loss on these swaps in 2012. These swaps were settled in November 2013.

~~Operating Results~~Gas Utilities

~~A discussion~~On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of ~~operating results from our business segments follows.~~$760 million in debt at closing. The purchase price was subject to post-closing adjustments of which $11 million was agreed to and received in June 2016.

We completed substantially all integration activities in 2016. All significant operations, customer, accounting, human resources and rebranding activities were successfully completed and implemented.

Cost of Service Gas Program Filings

Mining

Oil and Gas

Corporate

Results of Operations

Executive Summary and Overview



	For the Years Ended December 31,
	2016			Variance			2015			Variance			2014
	(in thousands)
Revenue
Revenue	$	1,701,093		$	270,811		$	1,430,282		$	(90,827	)	$	1,521,109
Inter-company eliminations	(128,119		)	(2,442		)	(125,677		)	1,862			(127,539		)
	$	1,572,974		$	268,369		$	1,304,605		$	(88,965	)	$	1,393,570

Net income (loss) available for common stock
Electric Utilities^(a)	$	85,827		$	8,248		$	77,579		$	20,309		$	57,270
Gas Utilities^(a)	59,624			20,318			39,306			(4,845		)	44,151
Power Generation^(b)	25,930			(6,720		)	32,650			4,134			28,516
Mining	10,053			(1,817		)	11,870			1,418			10,452
Oil and Gas ^{(c) (d)}	(71,054		)	108,904			(179,958		)	(171,433		)	(8,525		)
	110,380			128,933			(18,553		)	(150,417		)	131,864

Corporate and Eliminations ^{(a) (e) (f)}	(37,410		)	(23,852		)	(13,558		)	(12,583		)	(975		)

Net income (loss) available for common stock	$	72,970		$	105,081		$	(32,111	)	$	(163,000	)	$	130,889

______________

(a)


(b)	On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest.


(c)	Net income (loss) available for common stock for 2016 and 2015 included non-cash after-tax impairments of our crude oil and natural gas properties of $67 million and $160 million. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


(d)	Net income (loss) available for common stock for 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.


(e)	Net income (loss) available for common stock for 2016 and 2015include incremental SourceGas Acquisition costs, after-tax of $30 million and $6.7 million and 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 business segments.


(f)	Net income (loss) available for common stock for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

The following business group and segment information does not include inter-company eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated.

~~Utilities Group~~ Per share information references diluted shares unless otherwise noted.

~~Non-GAAP Financial Measure~~

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

In our Management Discussion and Analysis of Results of Operations, gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Gross margin for our Gas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

~~Electric Utilities~~

~~Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):~~

2014 Variance 2013 Variance 2012
Revenue - electric $ 657,556
$ 29,511
$ 628,045
$ 32,503
$ 595,542
Revenue - Cheyenne Light gas 39,754
2,491
37,263
5,839
31,424
Total revenue 697,310
32,002
665,308
38,342
626,966

Fuel and purchased power - electric 291,645
16,682
274,963
17,921
257,042
Purchased gas - Cheyenne Light 22,928
3,843
19,085
2,653
16,432
Total fuel and purchased power 314,573
20,525
294,048
20,574
273,474

Gross margin - electric 365,911
12,829
353,082
14,582
338,500
Gross margin - Cheyenne Light gas 16,826
(1,352 ) 18,178
3,186
14,992
Total gross margin 382,737
11,477
371,260
17,768
353,492

Operations and maintenance 165,640
5,679
159,961
13,434
146,527
Depreciation and amortization 79,424
1,720
77,704
2,460
75,244
Total operating expenses 245,064
7,399
237,665
15,894
221,771

Operating income 137,673
4,078
133,595
1,874
131,721

Interest expense, net (48,787 ) 7,473
(56,260 ) (5,219 ) (51,041 )
Other income, net 1,164
531
633
(549 ) 1,182
Income tax expense (30,498 ) (4,664 ) (25,834 ) 4,430
(30,264 )

Income from continuing operations $ 59,552
$ 7,418
$ 52,134
$ 536
$ 51,598

2014 2013 2012
Regulated power plant fleet availability:
Coal-fired plants^(a)
93.8% 96.7% 90.8%
Other plants^(b)
90.2% 96.5% 96.9%
Total availability 91.5% 96.6% 93.9%

~~____________________~~


~~(a)~~	~~2014 reflects a planned overhaul on Neil Simpson II for emissions controls upgrades.~~


~~(b)~~	~~2014 reflects planned overhauls for control system upgrades to meet NERC cyber security regulations on the Ben French CT's 1-4.~~

~~2014~~2016 Compared to ~~2013~~2015

~~Gross margin~~Net income (loss) available for common stock was $73 million, or $1.37 per diluted share in 2016, compared to $(32) million, or $(0.71) per share in 2015. Net income available for common stock in 2016 increased primarily due to a return on additional investments which increased base electric margins by $9.0 million, and increased rider margins from Cheyenne Prairie by $5.5 million. Industrial megawatt hours sold increased by approximately 15%, primarily due to load growth at Cheyenne Light resulting in increased margins of $1.7 million. Facility improvements at one of our large industrial customers drove a $1.8 million increase in technical service revenues. These increases were partially offset by a $3.5 million decrease from lower demand and residential megawatt hours sold driven by a 29% decrease in cooling degree days compared toover the same period in the prior year ~~a $1.6~~due primarily to: lower Oil and Gas property impairment charges; higher earnings at our Electric Utilities and Gas Utilities, which include earnings of $15 million ~~decrease~~ from our acquired SourceGas utilities since the ~~TCA,~~acquisition date of February 12, 2016; tax benefits of approximately $11 million from additional Oil and Gas properties’ percentage depletion deductions, and the re-measurement of uncertain tax positions’ liability predicated on an agreement reached with IRS Appeals. These increases were partially offset by $9.6 million of net income attributable to noncontrolling interests. Non-cash after-tax oil and gas property impairment charges were $67 million and after-tax SourceGas incremental acquisition and transition costs were $30 million in the year ended December 31, 2016. The Net income (loss) available for common stock for the year ended 2015 included non-cash after-tax ceiling test impairments of our oil and gas properties of $158 million, after-tax SourceGas incremental acquisition and transition costs of $6.7 million, and a ~~$0.8 million decrease from~~non-cash after-tax impairment loss on an oil and gas equity investment of $2.9 million.

2016 Overview of Business Segments and Corporate Activity

Electric Utilities

In our Electric Utilities service territories, mild winter weather in 2016 partially offset a ~~construction savings incentive recognized in~~hotter than normal summer. Heating degree days were 2% lower than the prior ~~year. Our Cheyenne Light gas utility experienced a~~year and 13% lower than normal. Offsetting this decrease ~~in heating~~was weather related demand during the peak summer months. Cooling degree days ~~resulting in a $1.4 million decrease in retail natural gas sales.~~

~~Operations and maintenance~~ ~~increased primarily due to property taxes, regulatory support and legal fees, generation maintenance, and employee costs.~~

~~Depreciation and amortization~~ ~~increased primarily due to a~~for the full year of 2016 were 9% higher ~~asset base driven by the addition of Cheyenne Prairie.~~

~~Interest expense, net~~ decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013, and extending our revolving credit facility under favorable terms during the second quarter of 2014.

~~Income tax benefit (expense): The effective tax rate was comparable to~~than the same period in the prior ~~year.~~year and 26% higher than normal.

~~2013 Compared~~On December 19, 2016, Colorado Electric received approval from the CPUC to ~~2012~~

~~Gross margin~~ ~~increased primarily due~~increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on ~~additional~~rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, ~~which~~with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

Construction riders related to the project increased ~~base electric~~gross margins by ~~$5.9~~approximately $5.1 million for the year ended December 31, 2016.

Gas Utilities

The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on pre-hearing discovery and commission orders, the Company is considering filing new applications for approval of specific gas reserve properties.

Power Generation

Oil and Gas

Corporate Activities

On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.


◦	Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;


◦	Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;


◦	Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;


◦	Pay down $100 million of the $500 million three-year unsecured term loan discussed below;


◦	Payment of $29 million for the settlement of $400 million notional interest rate swaps; and


◦	Remainder was used for general corporate purposes.

On June 7, 2016, we issued a $29 million, declining balance five-year term loan maturing June 7, 2021, to finance the early termination of a gas supply agreement.

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing. We funded the majority of the SourceGas Transaction with the following financings:

On February 12, 2016, Fitch affirmed the BHC credit rating of BBB+ and maintained a negative outlook after our acquisition of SourceGas, which reflects the initial increased ~~rider margins by $9.4~~leverage associated with the SourceGas Acquisition.

2015 Compared to 2014

Net income (loss) was $(32) million, or $(0.71) per share, in 2015 compared to $131 million, or $2.93 per share, in 2014. 2015 Net income (loss) included a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $158 million and a ~~$2.2~~non-cash after-tax equity investment impairment charge of $2.9 million. 2015 Net income (loss) also included after-tax, external third-party costs of $6.7 million, ~~increase at~~primarily attributable to the SourceGas Acquisition. The 2014 Net income (loss) did not include any expenses, gains, or losses that we believe are not representative of our ~~gas utility due~~core operating performance.

2015 Overview of Business Segments and Corporate Activity

Electric Utilities

In our Electric Utilities service territories, mild winter weather in 2015 offset a hotter than normal summer. Heating degree days were 11% lower than the prior year and 10% lower than normal. Offsetting this was weather related demand during the peak summer months. Cooling degree days for the full year of 2015 were 32% higher than the same period in the prior year and 16% higher than normal.

Construction commenced in the second quarter of 2015 on Colorado Electric’s $63 million 40 MW natural gas-fired combustion turbine. As of December 31, 2015, approximately $35 million was expended Construction riders related to ~~an increase~~the project increased gross margins by approximately $1.9 million for the year ended December 31, 2015. This turbine was completed in ~~volumes driven by~~and placed into service in December 2016.

On July 23, 2015, South Dakota Electric received approval from the WPSC for a ~~17% increase~~CPCN to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in ~~heating degree days. These are partially offset by~~northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. South Dakota Electric received approval on November 6, 2014 from the SDPUC for a ~~$2.1 million construction savings incentive received by~~permit to construct the South Dakota portion. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in the first half of 2017.

On June 23, 2015, Colorado Electric filed for a CPCN with the CPUC to acquire the planned 60 MW Peak View Wind Project, to be located near Colorado Electric's Busch Ranch Wind Farm. This renewable energy project was originally submitted in ~~2012 compared~~response to ~~$0.7~~Colorado Electric's all-source generation request on May 5, 2014. On October 21, 2015, the Commission approved a build transfer proposal and settlement agreement. The settlement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility. Colorado Electric purchased the project from a third-party for approximately $109 million ~~received in 2013.~~

~~Operations and maintenance~~ increased primarily due to property taxes, vegetation management and employee costs. Prior year included a $2.1 million reduction of major maintenance accruals related to plant suspensions and retirements.

~~Depreciation and amortization~~ ~~increased primarily due to a higher asset base.~~

~~Interest expense, net~~ ~~increased primarily due to lower AFUDC.~~

~~Income tax benefit (expense): The effective tax rate decreased primarily due to an unfavorable income tax true-up adjustment that impacted 2012.~~through progress payments throughout 2016, with ownership transfer occurring on November 7, 2016.

On March 16, 2015, we announced plans to build a new corporate headquarters in Rapid City, South Dakota that will consolidate our approximately 500 employees in Rapid City from five locations into one. The investment in the new corporate headquarters will be approximately $70 million and will support all our businesses. The cost of the facility will replace existing expenses associated with our current facilities throughout Rapid City. Construction began in September 2015 with completion expected in the fall of 2017.

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for South Dakota Electric of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides South Dakota Electric a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas-fired facility. South Dakota Electric implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $63 million natural gas-fired combustion turbine that was constructed in 2015 and 2016 to replace the retired W.N. Clark power plant.

Gas Utilities

Gas Utilities were unfavorably impacted by milder weather in 2015 compared to 2014. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2014. Heating degree days for the full year in 2015 were 8% less than normal and 13% less than the same period in 2014.

On July 1, 2015, we completed the acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. The utility and pipeline assets were acquired for approximately $17 million, and operate as subsidiaries of Wyoming Electric. The acquired system serves approximately 6,700 customers, in Cody, Ralston, and Meeteetse, Wyoming. The pipeline acquisition includes a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory.

In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on December 16, 2014 from the KCC to increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating costs. The approval was a Global Settlement and did not stipulate return on equity and capital structure.

Oil and Gas

Our Oil and Gas segment was impacted by lower commodity prices for crude oil and natural gas for the year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for natural gas decreased by 39% for the year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for oil decreased by 24% for the year ended December 31, 2015 compared to the same period in 2014. Oil and Gas production volumes increased 29% for the year ended December 31, 2015 compared to the same period in 2014.

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling impairment charge in each quarter of 2015, totaling $250 million for the year ended December 31, 2015.

We finished drilling the last of 13 Mancos Shale wells for our 2014/2015 drilling program in the Piceance Basin. Nine wells were placed on production in 2015, all with favorable production results to date, exceeding our expectations. We deferred the completion of our four remaining wells due to insufficient gas processing capacity and our expectation of continued low commodity prices. During the second quarter of 2015, we also reduced our planned 2016 and 2017 capital expenditures due to our strategic decision to focus our oil and gas expertise on being a cost of service gas provider for our electric and natural gas utilities.

Corporate Activities

On July 12, 2015 we entered into a definitive agreement to acquire SourceGas for approximately $1.89 billion, which included an estimated $200 million in capital expenditures through closing and the assumption of $760 million in long-term debt at closing. This acquisition closed on February 12, 2016. Financing activities related to this acquisition are detailed above in the 2016 Corporate activities.

On June 26, 2015, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term one year, through June 26, 2020. This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options.

On April 13, 2015, we entered into a new $300 million unsecured term loan. The loan has a two-year term with a maturity date of April 12, 2017. Proceeds of the term note were used to repay the existing $275 million term note due June 19, 2015.

Gas Utilities

~~Operating results~~On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments of which $11 million was agreed to and received in June 2016.

We completed substantially all integration activities in 2016. All significant operations, customer, accounting, human resources and rebranding activities were successfully completed and implemented.

Cost of Service Gas Program Filings

The Cost of Service Gas Program is designed to provide long-term natural gas price stability for the ~~years~~Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.

Mining

Oil and Gas

Corporate

Results of Operations

Executive Summary and Overview



	For the Years Ended December 31,
	2016			Variance			2015			Variance			2014
	(in thousands)
Revenue
Revenue	$	1,701,093		$	270,811		$	1,430,282		$	(90,827	)	$	1,521,109
Inter-company eliminations	(128,119		)	(2,442		)	(125,677		)	1,862			(127,539		)
	$	1,572,974		$	268,369		$	1,304,605		$	(88,965	)	$	1,393,570

Net income (loss) available for common stock
Electric Utilities^(a)	$	85,827		$	8,248		$	77,579		$	20,309		$	57,270
Gas Utilities^(a)	59,624			20,318			39,306			(4,845		)	44,151
Power Generation^(b)	25,930			(6,720		)	32,650			4,134			28,516
Mining	10,053			(1,817		)	11,870			1,418			10,452
Oil and Gas ^{(c) (d)}	(71,054		)	108,904			(179,958		)	(171,433		)	(8,525		)
	110,380			128,933			(18,553		)	(150,417		)	131,864

Corporate and Eliminations ^{(a) (e) (f)}	(37,410		)	(23,852		)	(13,558		)	(12,583		)	(975		)

Net income (loss) available for common stock	$	72,970		$	105,081		$	(32,111	)	$	(163,000	)	$	130,889

______________

(a)


(b)	On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest.


(c)	Net income (loss) available for common stock for 2016 and 2015 included non-cash after-tax impairments of our crude oil and natural gas properties of $67 million and $160 million. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.


(d)	Net income (loss) available for common stock for 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.


(e)	Net income (loss) available for common stock for 2016 and 2015include incremental SourceGas Acquisition costs, after-tax of $30 million and $6.7 million and 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 business segments.


(f)	Net income (loss) available for common stock for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

2016 Compared to 2015

2014 Variance 2013 Variance 2012
Revenue:
Natural gas - regulated $ 587,378
$ 77,123
$ 510,255
$ 84,987
$ 425,268
Other - non-regulated 30,390
956
29,434
621
28,813
Total revenue 617,768
78,079
539,689
85,608
454,081

Cost of natural gas sold:
Natural gas - regulated 365,034
69,609
295,425
64,163
231,262
Other - non-regulated 15,818
780
15,038
951
14,087
Total cost of natural gas sold 380,852
70,389
310,463
65,114
245,349

Gross margin:
Natural gas - regulated 222,344
7,514
214,830
20,824
194,006
Other - non-regulated 14,572
176
14,396
(330 ) 14,726
Total gross margin 236,916
7,690
229,226
20,494
208,732

Operations and maintenance 132,635
6,562
126,073
8,683
117,390
Depreciation and amortization 26,499
118
26,381
1,218
25,163
Total operating expenses 159,134
6,680
152,454
9,901
142,553

Operating income 77,782
1,010
76,772
10,593
66,179

Interest expense, net (15,284 ) 8,974
(24,258 ) (277 ) (23,981 )
Other expense (income), net 34
94
(60 ) (165 ) 105
Income tax expense (20,663 ) (916 ) (19,747 ) (5,434 ) (14,313 )

Income from continuing operations $ 41,869
$ 9,162
$ 32,707
$ 4,717
$ 27,990
year ended 2015 included non-cash after-tax ceiling test impairments of our oil and gas properties of $158 million, after-tax SourceGas incremental acquisition and transition costs of $6.7 million, and a non-cash after-tax impairment loss on an oil and gas equity investment of $2.9 million.

~~2014 Compared to 2013~~2016 Overview of Business Segments and Corporate Activity

~~Gross margin~~ increased primarily due to higher transport volumes which increased transport margins by $1.7 million. Rider margins increased $2.9 million primarily due to additional capital investments, and $1.6 million of additional margin was attributed to year over year customer growth. Higher retail volumes sold, driven mostly byElectric Utilities

In our Electric Utilities service territories, mild winter weather in 2016 partially offset a ~~7 percent increase in heating~~hotter than normal summer. Heating degree days ~~realized in~~were 2% lower than the ~~first quarter of 2014 resulted in a $1.2 million increase. Heating~~prior year and 13% lower than normal. Offsetting this decrease was weather related demand during the peak summer months. Cooling degree days for the ~~twelve months ended December 31, 2014,~~full year of 2016 were ~~2% lower~~9% higher than the same period in the prior year and 7%26% higher than normal.

~~Operations and maintenance~~ ~~increased primarily due~~On December 19, 2016, Colorado Electric received approval from the CPUC to ~~employee costs, property taxes, outside services, and uncollectible accounts attributed~~increase its annual revenues by $1.2 million to ~~increased revenue.~~

~~Depreciation and amortization~~recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This turbine was ~~comparable to the same period in the prior year.~~

~~Interest expense, net~~ ~~decreased primarily due to lower interest rates from refinancing higher cost debt~~completed in the fourth quarter of ~~2013.~~2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

Construction riders related to the project increased gross margins by approximately $5.1 million for the year ended December 31, 2016.

~~Income tax~~:On November 8, 2016, Colorado Electric completed the purchase of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased through progress payments throughout 2016 under a commission approved third-party build- transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. The ~~effective tax~~Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments, Renewable Energy Standard Surcharge and Transmission Cost Adjustment for 10 years, after which Colorado Electric can propose base rate ~~for 2014 was lower primarily due to a favorable true-up adjustment~~recovery.

During the first quarter of 2016, South Dakota Electric commenced construction of the $54 million, 230-kV, 144 mile-long transmission line that will connect the Teckla Substation in northeast Wyoming to the ~~filed 2013 income tax return,~~Lange Substation near Rapid City, South Dakota. Recovery is concurrent through the FERC transmission tariff. The first segment of this project connecting Teckla to Osage, WY was placed in ~~addition~~service on August 31, 2016. The second segment connecting Osage to ~~an increase~~Lange is expected to be placed in ~~flow-through tax adjustments.~~service in the first half of 2017.

~~2013 Compared to 2012~~

Gas Utilities

~~Gross margin~~ ~~increased primarily due~~On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to ~~a $12~~the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million ~~increase resulting from higher retail volumes driven~~in long-term debt at closing. See additional information below under Corporate activities.

Gas Utilities were unfavorably impacted by ~~a 25% increase~~milder weather in 2016 compared to 2015. Our service territories reported warmer than normal winter weather as measured by heating degree ~~days. Transport margins increased $2.9 million, surcharge revenue increased $1.9 million primarily due~~days, compared to ~~additional capital investments~~the 30-year average, and ~~$1.3 million of additional margin was attributed~~compared to 2015. Heating degree days for the full year ~~over year customer growth.~~

~~Operations~~in 2016 were 10% less than normal and ~~maintenance~~ ~~increased primarily due to employee costs, property taxes and uncollectible accounts attributed to increased revenue.~~

~~Depreciation and amortization~~ ~~increased primarily due to a higher asset base.~~

~~Interest expense, net~~ ~~was comparable to~~1% less than the same period in ~~the prior year.~~2015.

~~Income tax: The effective tax rate for 2013 increased primarily as a result~~During the third quarter of ~~favorable flow-through tax adjustment that benefited 2012.~~2016, the Company withdrew its Cost of Service Gas applications in Wyoming, Iowa, Kansas and South Dakota. In consideration of the July 2016 denial of the application from the NPSC and the April 2016 dismissal of its application from the CPUC, the Company is re-evaluating its Cost of Service Gas regulatory approval strategy.

~~Non-regulated Energy Group~~The Company’s initial applications submitted in late 2015 were based on a two-phase approach, the first of which would establish the criteria for how the program would work, and the second would seek approval for a specific gas reserves property. The orders in Colorado and Nebraska indicated the initial phase filings contained insufficient information and data to support customer benefits. Based on pre-hearing discovery and commission orders, the Company is considering filing new applications for approval of specific gas reserve properties.

Power Generation

Oil and Gas

Corporate Activities

On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.


◦	Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;


◦	Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;


◦	Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;


◦	Pay down $100 million of the $500 million three-year unsecured term loan discussed below;


◦	Payment of $29 million for the settlement of $400 million notional interest rate swaps; and


◦	Remainder was used for general corporate purposes.

On June 7, 2016, we issued a $29 million, declining balance five-year term loan maturing June 7, 2021, to finance the early termination of a gas supply agreement.

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing. We funded the majority of the SourceGas Transaction with the following financings:

2015 Compared to 2014

Net income (loss) was $(32) million, or $(0.71) per share, in 2015 compared to $131 million, or $2.93 per share, in 2014. 2015 Net income (loss) included a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million. 2015 Net income (loss) also included after-tax, external third-party costs of $6.7 million, primarily attributable to the SourceGas Acquisition. The 2014 Net income (loss) did not include any expenses, gains, or losses that we believe are not representative of our core operating performance.

2015 Overview of Business Segments and Corporate Activity

Electric Utilities

On July 23, 2015, South Dakota Electric received approval from the WPSC for a CPCN to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. South Dakota Electric received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in the first half of 2017.

On June 23, 2015, Colorado Electric filed for a CPCN with the CPUC to acquire the planned 60 MW Peak View Wind Project, to be located near Colorado Electric's Busch Ranch Wind Farm. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. On October 21, 2015, the Commission approved a build transfer proposal and settlement agreement. The settlement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility. Colorado Electric purchased the project from a third-party for approximately $109 million through progress payments throughout 2016, with ownership transfer occurring on November 7, 2016.

In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $63 million natural gas-fired combustion turbine that was constructed in 2015 and 2016 to replace the retired W.N. Clark power plant.

Gas Utilities

Oil and Gas

We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling impairment charge in each quarter of 2015, totaling $250 million for the year ended December 31, 2015.

Corporate Activities

Operating Results

A discussion of operating results from our business segments follows.

All amounts are presented on a pre-tax basis unless otherwise indicated.

Non-GAAP Financial Measure

Electric Utilities

Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):



	2016			Variance			2015			Variance			2014

Revenue	$	677,281		$	(2,562	)	$	679,843		$	22,287		$	657,556

Total fuel and purchased power	261,349			(8,060		)	269,409			(22,235		)	291,644

Gross margin	415,932			5,498			410,434			44,522			365,912

Operations and maintenance	158,134			(2,790		)	160,924			4,672			156,252
Depreciation and amortization	84,645			3,716			80,929			3,918			77,011
Total operating expenses	242,779			926			241,853			8,590			233,263

Operating income	173,153			4,572			168,581			35,932			132,649

Interest expense, net	(50,291		)	754			(51,045		)	(3,995		)	(47,050		)
Other income, net	3,193			1,977			1,216			142			1,074
Income tax expense	(40,228		)	945			(41,173		)	(11,770		)	(29,403		)

Net income (loss) available for common stock	$	85,827		$	8,248		$	77,579		$	20,309		$	57,270



	2016	2015	2014
Regulated power plant fleet availability:
Coal-fired plants^{(a) (b)}	90.2%	91.5%	93.8%
Other plants^(c)	95.1%	95.4%	90.2%
Total availability	93.5%	94.0%	91.5%

____________________


(a)	2016 reflects a planned outage at Wygen III and unplanned outages at Wyodak and Neil Simpson II.


(b)	2015 reflects planned outages at Neil Simpson II, Wygen II and Wygen III.


(c)	2014 reflects planned overhauls for control system upgrades to meet NERC cyber security regulations on the Ben French CTs 1-4.

2016 Compared to 2015

Gross margin increased over the prior year reflecting increased rider margins of $4.9 million driven primarily by our construction and TCA riders, an increase of $2.4 million in commercial and industrial margins driven by increased demand, a $1.5 million return on investment from the Peak View Wind Project, and a $1.4 million increase in residential margins driven by favorable weather. Offsetting these increases was a $2.1 million prior-year benefit as a result of a one-time settlement with the Colorado Public Utilities Commission on our renewable energy standard adjustment related to the Busch Ranch wind farm, a prior-year increase in return on invested capital of $1.2 million from South Dakota Electric’s rate case, and a $1.3 million decrease due to third-party billing true-ups relating to the current and prior years.

Operations and maintenance decreased primarily as a result of approximately $5.8 million lower employee costs primarily driven by a change in expense allocations impacting the electric utilities as a result of integrating the acquired SourceGas utilities. This decrease is partially offset by higher operating costs from the Peak View Wind Project, which commenced commercial operation in November 2016, and increased vegetation management costs.

Depreciation and amortization increased primarily due to a higher asset base driven partially by the addition of Peak View Wind Project.

Interest expense, net decreased primarily due to higher AFUDC interest income driven by construction in process as compared to prior year.

Other (expense) income, net increased primarily due to higher AFUDC equity in the current period compared to prior year.

Income tax benefit (expense): The effective tax rate was lower than prior year primarily due to the accelerated recognition of benefits associated with certain tax incentives.

2015 Compared to 2014

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $29.8 million, and increased electric cost recoveries by $4.8 million. Higher industrial and commercial megawatt hours sold driven by customer load growth increased margins by $5.9 million. Colorado Electric received approval of a one-time settlement agreement from the CPUC on our renewable energy standard adjustment related to Busch Ranch, which increased margins by $2.1 million. An increase in residential customer growth and usage per customer increased margins by $2.4 million. These increases are partially offset by a $1.7 million decrease from lower demand and residential megawatt hours sold primarily driven by an 11% decrease in heating degree days compared to the same period in the prior year, and facility improvements at one of our large industrial customers which resulted in a $1.8 million decrease in technical service revenues in the prior year.

Operations and maintenance increased primarily due to costs related to Cheyenne Prairie, which was placed into commercial service on October 1, 2014.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie.

Interest expense, net increased primarily due to interest costs from the $160 million of permanent financing placed during the fourth quarter of 2014 for Cheyenne Prairie.

Income tax benefit (expense): The effective tax rate was comparable to the prior year.

Gas Utilities

Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):



	2016			Variance			2015			Variance			2014
Revenue:
Natural gas - regulated	$	769,082		$	249,084		$	519,998		$	(107,135	)	$	627,133
Other - non-regulated	69,261			37,959			31,302			912			30,390
Total revenue	838,343			287,043			551,300			(106,223		)	657,523

Cost of natural gas sold:
Natural gas - regulated	315,618			31,985			283,633			(104,330		)	387,963
Other - non-regulated	36,547			20,535			16,012			194			15,818
Total cost of natural gas sold	352,165			52,520			299,645			(104,136		)	403,781

Gross margin:
Natural gas - regulated	453,464			217,099			236,365			(2,805		)	239,170
Other - non-regulated	32,714			17,424			15,290			718			14,572
Total gross margin	486,178			234,523			251,655			(2,087		)	253,742

Operations and maintenance	245,826			105,103			140,723			(1,301		)	142,024
Depreciation and amortization	78,335			46,009			32,326			3,414			28,912
Total operating expenses	324,161			151,112			173,049			2,113			170,936

Operating income	162,017			83,411			78,606			(4,200		)	82,806

Interest expense, net	(75,013		)	(57,702		)	(17,311		)	(290		)	(17,021		)
Other expense (income), net	184			(131		)	315			191			124
Income tax expense	(27,462		)	(5,158		)	(22,304		)	(546		)	(21,758		)

Net income (loss)	59,726			20,420			39,306			(4,845		)	44,151
Net income attributable to noncontrolling interest	(102		)	(102		)	—			—			—
Net income (loss) available for common stock	$	59,624		$	20,318		$	39,306		$	(4,845	)	$	44,151

2016 Compared to 2015

Gross margin increased primarily due to margins of approximately $236 million contributed by the SourceGas utilities acquired on Feb. 12, 2016 and Energy West Wyoming utility acquired on July 1, 2015. Partially offsetting this increase is a $ 2.0 million decrease due to weather. Heating degree days were 1% lower than the prior year and 10% lower than normal.

Operations and maintenance increased primarily due to additional operating costs of approximately $111 million for the acquired SourceGas utilities and Energy West Wyoming utility. Partially offsetting this increase were approximately $7.4 million lower employee costs primarily driven by a change in expense allocations impacting the gas utilities as a result of integrating the acquired SourceGas utilities.

Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas and Energy West Wyoming utilities of approximately $45 million, and due to a higher asset base at our other gas utilities over the same period in the prior year.

Interest expense, net increased primarily due to additional interest expense of approximately $58 million from the debt associated with the acquired SourceGas utilities.

Income tax: The effective tax rate for 2016, including the impact of the acquired SourceGas and Energy West Wyoming utilities, reflects additional tax benefits related primarily to a favorable flow through adjustment. Such adjustments are related to certain tax benefits that are recognized currently in accordance with prescribed regulatory treatment.

2015 Compared to 2014

Gross margin decreased primarily due to a $10.8 million impact from milder weather compared to the same period in the prior year and a $2.3 million decrease in retail volumes sold. Heating degree days in 2015 were 14% lower than the prior year and 8% lower than normal. Partially offsetting these decreases was $3.6 million of increased margins from the 2015 MCTC and Energy West Wyoming acquisitions, the impact from base rate increases from Kansas Gas, and an increase of $1.5 million from year over year customer growth.

Operations and maintenance decreased primarily due to lower operating expenses, partially offset by an increase in property taxes.

Depreciation and amortization increased primarily due to a higher asset base than the prior year.

Interest expense, net is comparable to the prior year.

Income tax: The effective tax rate for 2015 is higher primarily due to a less favorable return to accrual adjustment related to flow-through items when compared to the prior year.

Power Generation

Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):


	2014			Variance			2013			Variance			2012			2016			Variance			2015			Variance			2014

Revenue	$	87,558		$	4,521		$	83,037		$	3,648		$	79,389		$	91,131		$	341		$	90,790		$	3,232		$	87,558

Operations and maintenance	33,126			2,940			30,186			195			29,991			32,636			496			32,140			(986		)	33,126
Depreciation and amortization	4,540			(551		)	5,091			492			4,599			4,104			(225		)	4,329			(211		)	4,540
Total operating expenses	37,666			2,389			35,277			687			34,590			36,740			271			36,469			(1,197		)	37,666

Operating income	49,892			2,132			47,760			2,961			44,799			54,391			70			54,321			4,429			49,892

Interest expense, net	(3,669		)	16,724			(20,393		)	(5,636		)	(14,757		)	(1,775		)	1,428			(3,203		)	466			(3,669		)
Other income (expense), net	(6		)	(7		)	1			(6		)	7			2			(69		)	71			77			(6		)
Income tax expense	(17,701		)	(6,621		)	(11,080		)	(2,359		)	(8,721		)	(17,129		)	1,410			(18,539		)	(838		)	(17,701		)

Income from continuing operations	$	28,516		$	12,228		$	16,288		$	(5,040	)	$	21,328
Net income (loss)																35,489			2,839			32,650			4,134			28,516
Net income attributable to noncontrolling interest																(9,559		)	(9,559		)	—			—			—
Net income (loss) available for common stock																$	25,930		$	(6,720	)	$	32,650		4,134			$	28,516

On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Net income available for common stock for the year ended December 31, 2016, was reduced by $9.6 million 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.


	2014	2013	2012	2016	2015	2014
Contracted fleet plant availability:
Gas-fired plants	99.0%		99.4%	99.2%	99.1%	99.0%
Coal-fired plants ^(a)	94.7%	94.5%	99.6%	95.5%	98.4%	94.7%
Total	97.8%	97.9%	99.4%	98.3%	98.9%	97.8%

~~__________________________~~___________


(a)	Wygen I experienced an unplanned outage in 2016 and a planned ~~outages~~outage in ~~2014 and 2013.~~2014.

~~2014~~2016 Compared to ~~2013~~2015

Revenueincreased primarily due to increased PPA prices, partially offset by a decrease in contracted revenue driven by the Wygen I plant outage in the second quarter of 2016.

Operations and maintenance increased primarily due to fan upgrades to the Colorado IPP generator and increased Wygen I chemical and major maintenance costs as compared to the same period in the prior year.

Depreciation and amortization decreased primarily due to lower depreciation at Wygen I. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased due to higher interest income driven by the proceeds from the noncontrolling interest sale in April 2016.

Income tax expense: Black Hills Colorado IPP went from a single member LLC, wholly owned by Black Hills Generation, to a partnership as a result of the sale of 49.9 percent of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision was not recorded.

Net income attributable to noncontrolling interest: Net income attributable to the noncontrolling interest increased by $9.6 million as a result of the noncontrolling interest sale in April 2016.

2015 Compared to 2014

Revenue increased primarily due to an increase in megawatt hours delivered at higher prices and an increase in fired hours, ~~and an increase from the new economy energy PPA with the City of Gillette,~~ partially offset by the net effect of the expiration of the Gillette CTII ~~capacity contract with Cheyenne Light.~~PPA and subsequent economy energy PPA, which was impacted by lower natural gas prices in 2015.

Operations and maintenance~~increased~~ decreased primarily due to ~~increased~~lower outside services and materials, and ~~additional~~ maintenance costs onfrom the Wygen I outage ~~partially offset by decreased employee costs.~~in the prior year.

Depreciation and amortization decreased primarily due to lower depreciation at Black Hills Wyoming. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased primarily due to ~~refinancing~~favorable interest income driven by a higher ~~cost project debt and settling associated interest rate swaps~~allocated note receivable compared to the same period in the fourth quarter of 2013. The fourth quarter of 2013 included $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs.prior year.

Income tax expense: The effective tax rate was lower in 2015 primarily due to an unfavorable return to accrual adjustment recorded in 2014. Such adjustment was related to the filed 2013 income tax return.

Mining

Mining operating results for the years ended December 31 were as follows (in thousands):



	2016			Variance			2015			Variance			2014

Revenue	$	60,280		$	(4,786	)	$	65,066		$	1,708		$	63,358

Operations and maintenance	39,576			(2,054		)	41,630			458			41,172
Depreciation, depletion and amortization	9,346			(460		)	9,806			(470		)	10,276
Total operating expenses	48,922			(2,514		)	51,436			(12		)	51,448

Operating income (loss)	11,358			(2,272		)	13,630			1,720			11,910

Interest (expense) income, net	(377		)	22			(399		)	35			(434		)
Other income, net	2,209			(38		)	2,247			(28		)	2,275
Income tax benefit (expense)	(3,137		)	471			(3,608		)	(309		)	(3,299		)

Net income (loss) available for common stock	$	10,053		$	(1,817	)	$	11,870		$	1,418		$	10,452

The following table provides certain operating statistics for the Mining segment (in thousands):



	2016	2015	2014
Tons of coal sold	3,817	4,140	4,317

Cubic yards of overburden moved ^(a)	7,916	6,088	4,646

Coal reserves at year-end	199,905	203,849	208,231

____________


(a)	Increase in overburden was due to relocating mining operations to areas of the mine with higher overburden.

2016 Compared to 2015

Revenue decreased primarily due to an 8 percent decrease in tons sold resulting from a planned five-week outage in the second quarter of 2016, which was extended by an additional six weeks at Wyodak plant due to an unplanned major repair of a turbine rotor. Pricing was comparable to the same period in the prior year. Approximately 50 percent of our coal production was sold under contracts that are priced based on actual mining costs, including income taxes, as compared to 46 percent for the same period in the prior year.

Operations and maintenance decreased due to lower major maintenance requirements, fuel costs, and employee costs, as well as decreased royalties and revenue-related taxes driven by decreased revenue compared to the same period in the prior year.

Depreciation, depletion and amortization decreased primarily due to revised cost estimates for our asset retirement obligation driving lower accretion and depreciation.

Interest (expense) income, net is comparable to the same period in the prior year.

Income tax: The effective tax rate was comparable to the same period in the prior year.

~~2013~~2015 Compared to ~~2012~~

~~Revenue~~ ~~increased primarily due to $2.1 million relating to increased MWh delivered at higher prices and $2.3 million related to increased volumes and pricing for off-system sales at Black Hills Wyoming.~~

~~Operations and maintenance~~ ~~increased primarily due to two Wygen I outages, partially offset by decreased property taxes at Black Hills Colorado IPP.~~

~~Depreciation and amortization~~ were comparable to the same period in the prior year. The generating facility located in Pueblo, Colorado is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

~~Interest expense, net~~ increased primarily due to $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs, partially offset by lower inter-company debt.

~~Income tax expense: The effective tax rate in 2013 increased as a result of an unfavorable tax true-up adjustment.~~

~~Coal Mining~~

~~Coal Mining operating results for the years ended December 31 were as follows (in thousands):~~

2014 Variance 2013 Variance 2012

Revenue $ 63,358
$ 6,730
$ 56,628
$ (1,150 ) $ 57,778

Operations and maintenance 41,172
1,653
39,519
(3,034 ) 42,553
Depreciation, depletion and amortization 10,276
(1,247 ) 11,523
(1,537 ) 13,060
Total operating expenses 51,448
406
51,042
(4,571 ) 55,613

Operating income (loss) 11,910
6,324
5,586
3,421
2,165

Interest (expense) income, net (434 ) 197
(631 ) (1,561 ) 930
Other income, net 2,275
(29 ) 2,304
(312 ) 2,616
Income tax benefit (expense) (3,299 ) (2,367 ) (932 ) (847 ) (85 )
Income (loss) from continuing operations $ 10,452
$ 4,125
$ 6,327
$ 701
$ 5,626

~~The following table provides certain operating statistics for the Coal Mining segment (in thousands):~~

2014 2013 2012
Tons of coal sold 4,317
4,285
4,246

Cubic yards of overburden moved 4,646
3,192
^(a)
8,329

Coal reserves at year-end 208,231
212,595
^(b)
232,265

~~____________~~


~~(a)~~	~~Reduction in overburden was due to relocating mining operations in the second half of 2012 to an area of the mine with lower overburden.~~


~~(b)~~	~~Reduction in coal reserves was due to revisions in coal modeling based upon engineering data, changes in coal limit boundaries and current coal production.~~

2014 ~~Compared to~~ ~~2013~~

Revenue increased primarily due to ~~an 11%~~a 7% increase in the price per ton sold driven primarily by a coal price increase with the third-party operator of the Wyodak plant. ~~Price per ton also increased as~~Partially offsetting this was a ~~result~~4% decrease in tons of ~~an increase~~coal sold primarily driven by a forced outage at Neil Simpson II, and the decommissioning of Neil Simpson I in ~~pricing on contracts containing price adjustments based on actual mining costs.~~March of the prior year. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have increased due to higher operations and maintenance costs driven by mining in areas with a higher stripping ratio than the prior year, thereby increasing our price per ton for these customers.

Operations and maintenance increased primarily due to mining in areas with higher overburden, ~~materials and outside services on major maintenance projects,~~ and an increase in royalties and revenue related taxes driven by increased revenue, partially offset by lower fuel costs and lower employee costs.

Depreciation, depletion and amortization decreased primarily due to lower ~~depreciation on mine assets driven by a reduction in equipment run hours from changes in the mine plan design, and lower depreciation of mine reclamation costs.~~

~~Interest (expense) income, net~~ ~~is comparable to the same period in the prior year.~~

~~Income tax:~~ ~~The effective tax rate in 2014 is higher due to the reduced impact of the tax benefit of percentage depletion.~~

~~2013~~ ~~Compared to~~ ~~2012~~

~~Revenuedecreased~~ primarily due to a 9% decrease in the average price per ton charged on coal sold under contracts containing price adjustments, partially offset by a 1% increase in tons sold. Approximately 50% of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have trended down due to lower operations and maintenance costs, thereby decreasing our price per ton for these customers.

~~Operations and maintenancedecreased~~ primarily due to mining in areas with lower overburden, resulting in decreased fuel costs and reduced employee costs, partially offset by materials and outside services related to major maintenance projects.

~~Depreciation,~~ depletion, ~~and amortizationdecreased~~ ~~primarily due to~~ lower depreciation on mine assets and lower depreciation of mine reclamation costs.

~~Interest (expense) income, net~~ ~~reflects decreased interest income primarily due to a decrease in the inter-company notes receivable, reduced by payment of a dividend to our parent.~~

Income tax ~~benefit (expense)~~: The effective tax rate ~~increased~~was comparable to the same period in ~~2013 as a result of lower percentage depletion. In addition,~~ the ~~effective tax rate in 2012 was impacted by a favorable true-up adjustment that was primarily driven by an increased percentage depletion deduction reported on the 2011 tax return.~~prior year.

Oil and Gas

Oil and Gas operating results for the years ended December 31 were as follows (in thousands):


	2014			Variance			2013			Variance			2012			2016			Variance			2015			Variance			2014

Revenue	$	55,114		$	230		$	54,884		$	(24,188	)	$	79,072		$	34,058		$	(9,225	)	$	43,283		$	(11,831	)	$	55,114

Operations and maintenance	42,659			2,294			40,365			(2,902		)	43,267			32,158			(9,435		)	41,593			(1,066		)	42,659
Gain on sale of assets	—			—			—			29,129			(29,129		)
Depreciation, depletion and amortization	27,584			5,814			21,770			(16,724		)	38,494			13,902			(15,385		)	29,287			5,041			24,246
Impairment of long-lived assets	—			—			—			(26,868		)	26,868			106,957			(142,651		)	249,608			249,608			—
Total operating expenses	70,243			8,108			62,135			(17,365		)	79,500			153,017			(167,471		)	320,488			253,583			66,905

Operating income (loss)	(15,129		)	(7,878		)	(7,251		)	(6,823		)	(428		)	(118,959		)	158,246			(277,205		)	(265,414		)	(11,791		)

Interest expense, net	(1,685		)	(1,071		)	(614		)	3,321			(3,935		)	(4,864		)	(2,355		)	(2,509		)	(824		)	(1,685		)
Other income (expense), net	183			75			108			(99		)	207			110			447			(337		)	(520		)	183
Impairment of equity investments																—			4,405			(4,405		)	(4,405		)	—
Income tax benefit (expense)	5,998			2,453			3,545			1,618			1,927			52,659			(51,839		)	104,498			99,730			4,768

Income (loss) from continuing operations	$	(10,633	)	$	(6,421	)	$	(4,212	)	$	(1,983	)	$	(2,229	)
Net income (loss) available for common stock																$	(71,054	)	$	108,904		$	(179,958	)	$	(171,433	)	$	(8,525	)

~~2014~~2016 Compared to ~~2013~~2015

Revenue ~~increased~~decreased primarily due to ~~a 5% increase in volumes sold~~lower commodity prices for both crude oil and ~~an 8% increase in average price received for~~ natural gas, ~~sold, partially offset by an 11%~~resulting in a 24 percent decrease in the average price received, including hedges, for natural gas sold and a 6 percent decrease in the average price received, including hedges, for crude oil sold. In addition, production decreased by 6 percent as compared to prior year as we limited natural gas production to meet minimum daily quantity contractual gas processing commitments in the Piceance. Crude oil production also decreased due to non-core property sales in the fourth quarter of 2016.

Operations and maintenance decreased primarily due to lower employee costs as a result of the reduction in staffing in the prior year, and lower production taxes and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to a reduction of our full cost pool resulting from the ceiling test impairments incurred in current and prior years.

Impairment of long-lived assets represents a non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices and movement of certain unevaluated assets into the full-cost pool. The write-down of $107 million included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $93 million. The ceiling test write-down for the 12 months ended December 31, 2016 used an average NYMEX natural gas price of $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead, and $42.75 per barrel for crude oil, adjusted to $37.35 per barrel at the wellhead, compared to the $250 million ceiling test write-down in the same period of the prior year which used an average NYMEX natural gas price of $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead, and $50.82 per barrel for crude oil, adjusted to $44.72 per barrel at the wellhead.

Interest expense, net increased primarily due to higher interest expense driven by an increase in intercompany notes payable.

Impairment of equity investments represents a prior year non-cash write-down in equity investments related to interests in a pipeline and gathering system. The impairment resulted from continued declining performance, market conditions, and a change in view of the economics of the facilities that we considered to be other than temporary.

Income tax (expense) benefit: Each period reflects a tax benefit. The effective tax rate for 2016 was impacted by a benefit of approximately $5.8 million from additional percentage depletion deductions being claimed with respect to a change in estimate for tax purposes. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.

2015 Compared to 2014

Revenue decreased primarily due to lower commodity prices for both crude oil and natural gas, resulting in a 24 percent decrease in the average price received, including hedges, for crude oil sold and a 39 percent decrease in the average price received, including hedges, for natural gas sold. A 29 percent production increase driven by the nine Piceance Mancos shale wells placed on production in 2015 partially offset the decrease in commodity prices.

Operations and maintenance ~~increased~~decreased primarily due to ~~increased employee costs, higher lease operating and field operation expense, and higher~~lower production taxes and ad valorem taxes on ~~higher revenue.~~lower revenue, partially offset by severance costs.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate applied to increased ~~production.~~

~~Interest expense, net~~ ~~increased primarily due to third-party interest received on non-operated well revenue~~production, partially offset by the reduction in ~~the prior year that offset 2013 expense.~~

~~Income tax (expense) benefit: Each period presented reflects a tax benefit. The tax benefit for 2014 was impacted by an unfavorable true-up adjustment to the filed 2013 income tax return.~~

~~2013~~ ~~Compared to~~ ~~2012~~

~~Revenue~~ ~~decreased primarily due to a 24% decrease in volumes sold~~our full cost pool as a result of the ~~sale of our Williston Basin assets in 2012, a natural production decline in our gas wells and a 19% decrease in average price received for natural gas sold, partially offset by a 7% increase~~impact from the ceiling test impairments in the ~~average price received for crude oil sold.~~

~~Operations and maintenancedecreased~~ ~~primarily due to lower non-operated well costs and lower production taxes and ad valorem taxes on reduced revenue.~~

~~Gain on sale of operating assets~~ represents the gain on the sale of our Williston Basin assets in 2012. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The remainder of the sale amount not recognized as gain reduced the full-cost pool and had the effect of reducing the depreciation, depletion and amortization rate.

~~Depreciation, depletion and amortizationdecreased~~ ~~primarily due to a lower proportion of our total reserves being from crude oil in 2013, resulting from the sale of our Williston Basin assets in 2012.~~current year.

Impairment of long-lived assets represents a non-cash write-down in the value of our natural gas and crude oil properties driven by low natural gas ~~prices in the second quarter of 2012.~~and crude oil prices. The write-down reflected a ~~12-month~~trailing 12 month average NYMEX price of ~~$3.15~~$2.59 per Mcf, adjusted to ~~$2.66~~$1.27 per Mcf at the wellhead, for natural gas, and ~~$95.67~~$50.28 per barrel, adjusted to ~~$85.36~~$44.72 per barrel at the wellhead, for crude oil.

Interest expense, net ~~reflects lower interest expense~~increased primarily due to third-party interest received on non-operated well revenue in the prior year that offset 2014 expense.

~~decreased~~Impairment of equity investments ~~debt as~~represents a ~~result~~non-cash write-down in equity investments related to interests in a pipeline gathering system. The impairment resulted from continued declining performance, market conditions, and a change in the view of ~~proceeds from~~ the ~~sale~~economics of ~~our Williston Basin assets in 2012.~~the facilities that we considered to be other than temporary.

Income tax ~~(benefit) expense~~(expense) benefit: ~~Each period presented produced a pre-tax net loss that resulted in an income tax benefit.~~ The effective tax rate ~~in 2013 reflects lower percentage depletion.~~was comparable to the prior year.

Corporate

Corporate results represent certain unallocated costs for administrative activities that support the business segments. Corporate also includes business development activities that do not fall under the two business ~~groups as well as allocated costs associated with discontinued operations that could not be included in discontinued operations.~~groups.

~~2014~~2016 Compared to ~~2013~~2015

~~Loss from continuing operations~~Net income (loss) available for common stock for the twelve months ended December 31, ~~2014,~~2016, was $1$(37) million compared to ~~income from continuing operations~~net (loss) available for common stock of ~~$13~~$(14) million for the same period in the prior year. ~~Results for~~The variance from the prior year was due to higher corporate expenses, primarily driven by costs related to the SourceGas Acquisition including approximately $30 million of after-tax acquisition and transition costs compared to $6.7 million of after-tax acquisition costs in the prior year, and approximately $9.1 million of after-tax internal labor that otherwise would have been charged to other business segments during the year ended December 31, ~~2014 increased primarily due~~2016, compared to ~~refinancing activity~~$3.0 million of after-tax internal labor that ~~took place~~otherwise would have been charged to other business segments during the year ended December 31, 2015. These costs were partially offset by a tax benefit of approximately $4.4 million recognized during the year ended December 31, 2016 as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.

~~fourth~~2015 ~~quarter of~~Compared to ~~2013~~2014~~. Results~~

Net income (loss) available for common stock for the twelve months ended December 31, ~~2013 reflect a~~ ~~$30~~2015, was $(14) million ~~non-cash unrealized mark-to-market gain related~~ compared to ~~certain interest rate swaps. Corporate results~~net income (loss) available for ~~2013~~ ~~also include $10~~common stock of $(1) million offor the same period in the prior year. The variance from the prior year was due to higher corporate expenses, primarily driven by costs related to ~~early retirement~~the SourceGas Acquisition including approximately $4.3 million of ~~$250 million senior unsecured notes including a make-whole premium, write-off of deferred~~after-tax bridge financing costs ~~and~~recognized in interest expense, ~~on new debt.~~

~~2013~~ ~~Compared~~approximately $3.0 million of after-tax internal labor that otherwise would have been charged to ~~2012~~

~~Corporate results for 2013 include costs of $10~~other business segments, and approximately $2.3 million ~~for a make-whole premium and write-off of deferred financing costs related to early retirement of our $250 million senior unsecured notes and interest~~in after-tax other expenses ~~on new debt, compared to~~ ~~$7.1 million~~ ~~for a make-whole premium related~~attributable to the ~~early retirement of our $225 million senior unsecured notes in 2012. We also had an unrealized, non-cash mark-to-market gain on certain interest rate swaps of approximately~~ ~~$30 million~~ ~~in 2013, compared to an unrealized, non-cash mark-to-market gain of~~ ~~$1.9 million~~ ~~on these interest rate swaps for~~acquisition during the year ended December 31, ~~2012~~.2015, compared to the same period in the prior year.

~~2012 includes costs of $0.9 million previously allocated to our Energy Marketing segment were reclassified to the Corporate activities consistent with accounting for discontinued operations.~~

~~Discontinued Operations~~

On February 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. Net cash proceeds at date of sale were approximately $165 million, subject to final post-closing adjustments.

The buyer asserted certain purchase price adjustments, some that we accepted, and several that we disputed. The disputed claims were substantially resolved through a binding arbitration decision dated January 17, 2014. We expensed an additional $1.1 million in 2013 related to the claims assigned to arbitration from purchase price adjustments we accepted through a partial settlement agreement with the buyer. Loss from discontinued operations was $0.9 million for the twelve months ended December 31, 2013. Results for 2013 include the resolution of all previously unresolved purchase price adjustments.

Critical Accounting Policies Involving Significant Accounting Estimates

We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments, or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.

The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Goodwill

We perform ~~our~~a goodwill impairment test ~~as of November 30 each year~~on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements.

Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit ~~level. Our reporting units have been determined to be at the subsidiary~~ level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.

Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our 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. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation, ~~and adjusted as appropriate for our view of market participant assumptions,~~ 2) estimates of long-term growth rates for our businesses, 3) the determination of an appropriate weighted-average cost of capital or discount rate, and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries.

We have $353 million in goodwill as of December 31, 2014. The results of our November 30, 2014, annual impairment test indicated that our goodwill was not impaired, since the estimated fair value of all reporting units exceeded their carrying value.

~~Although an impairment did not exist as of November 30, 2014, we determined that one~~ Varying by reporting unit, Colorado Electric with goodwill of $245 million, had an estimated fair value that exceeded its carrying value by 24%, which we do not consider a substantial excess. The result of our valuation analysis estimates Colorado Electric's fair value at $860 million, compared to a carrying value of $694 million as of November 30, 2014. The result of the ~~income approach was sensitive to the 2% long-term cash flow growth rate applicable to periods beyond our internal five-year business plan financial forecast and the 5.04% weighted-average~~weighted average cost of capital ~~assumptions. As an illustration of this sensitivity, an increase of 0.25%~~ in the ~~cost~~range of 5% to 8% and the long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2016. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital ~~combined with~~investments through rider mechanisms and rate cases, as well as other improved efficiency and cost reduction initiatives. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition we add a ~~growth rate reduction~~reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.

The estimates and assumptions used in the impairment assessments are based on available market information, and we believe they are reasonable. However, variations in any of ~~0.25% would~~the assumptions could result in ~~an estimated~~materially different calculations of fair value ~~in excess~~and determinations of whether or not an impairment is indicated. For the years ended December 31, 2016, 2015, and 2014, there were no significant impairment losses recorded. At December 31, 2016, the fair value substantially exceeded the carrying value ~~of $99 million, or 14%, as of November 30, 2014.~~at all reporting units.

Full Cost Method of Accounting for Oil and Gas Activities

Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available - successful efforts and full cost. We account for our oil and gas activities under the full cost method, whereby all productive and nonproductive costs related to acquisition, exploration, development, abandonment and reclamation activities 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 abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon SEC-defined prices for oil and gas as of the end of each reporting period adjusted for contracted price changes. The prices, as well as costs and development capital, are assumed to remain constant for the remaining life of the properties. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Under these SEC-defined product prices, our net capitalized costs were more than the full cost ceiling ~~at June 30, 2012,~~throughout 2016, which required aan after-tax write-down of ~~$17~~$58 million ~~after-tax. We’ve taken no further write-downs related to our oil and gas full-cost pool since then and under~~for the ~~SEC-defined product prices at~~year ended December 31, ~~2014, no write-down was required.~~2016. Reserves in ~~2014~~2016 and ~~2013~~2015 were determined consistent with SEC requirements using a 12-month average 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.~~properties adjusted for contracted price changes. Because of the fluctuations in natural gas and oil prices, we can provide no assurance that future write-downs will not occur. ~~However, if the current low price environment continues, it is probable that we will have an impairment in 2015.~~

As noted, we utilize the full-cost method of accounting for our oil and gas activities in accordance with SEC Rule 4-10 of Regulation S-X (Rule 4-10). Under the full-cost method, sales of oil and gas properties generally are recorded as an adjustment to capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved oil and gas reserves. The Company’s sale of oil and gas properties in the Williston Basin of North Dakota in 2012 was significant as defined by Rule 4-10 and, accordingly, a $19 million after-tax gain on sale was recorded. Total net cash proceeds from the sale were approximately $228 million.

Under the guidance of Rule 4-10, if a gain or loss is recognized on such a sale, total capitalized costs shall be allocated between the reserves sold and the reserves retained on the same basis used to compute amortization, unless there are substantial economic differences between the properties sold and those retained, in which case capitalized costs shall be allocated on the basis of the relative fair value of the properties in the cost center. Because of the substantial differences between the Williston Basin crude oil properties we sold and those properties retained, which were predominantly natural gas, we allocated based on relative fair values.

If a different method of allocating the capitalized costs was chosen, the gain recorded on our transaction could vary substantially. For example, if the allocation was made on the same basis used to compute amortization as noted within Rule 4-10 and we utilized the ratio of proven reserve quantities from the properties sold compared to total proven reserve quantities in our cost center, we would have recorded a gain on sale of approximately $160 million. Because of the value associated with the undeveloped acreage sold, we did not believe this was an appropriate methodology for allocation. If the amount of gain were recorded differently, it would impact the amount of adjustment to our capitalized costs therefore impacting future depletion expense recorded within our consolidated financial statements.

Oil, Natural Gas, and Natural Gas Liquids Reserve Estimates

Estimates of our proved crude oil, natural gas and NGL reserves are based on the quantities of each that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. An independent petroleum engineering company prepares reports that estimate our proved oil, natural gas and NGL reserves annually. The accuracy of any crude oil, natural gas and NGL reserve estimate is a function of the quality of available data, engineering judgment and geological interpretation. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and work over costs, all of which may in fact vary considerably from actual results. In addition, as crude oil, natural gas and NGL prices and cost levels change from year to year, the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.

Despite the inherent imprecision in estimating our crude oil, natural gas and NGL reserves, the estimates are used throughout our financial statements. For example, since we use the unit-of-production method of calculating depletion expense, the amortization rate of our capitalized oil and gas properties incorporates the estimated unit-of-production attributable to the estimates of proved reserves. The net book value of our crude oil and gas properties is also subject to a “ceiling” limitation based in large part on the value of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Risk Management Activities

In addition to the information provided below, see Note 89, “Risk Management Activities” and Note 910, “Fair Value ~~Measurement~~Measurements,” of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Derivatives

We currently use derivative instruments, including options, swaps, and futures, to mitigate commodity purchase price risk and manage interest rate risk. Our typical hedging transactions fix the price received for anticipated future production at our Oil and Gas segment, or to fulfill the natural gas hedging plans for our Gas and Electric utilities. We also enter into interest rate swaps to convert a portion of our variable rate debt, or associated variable rate interest payments, to a fixed rate.

Accounting standards for derivatives require the recognition of all derivative instruments ~~as either assets or liabilities on the balance sheet and their measurement~~ at fair ~~value.~~value with changes in fair value ultimately recorded in the income statement. Our policy for recognizing the changes in fair value of these derivatives ~~varies based on~~in earnings is contingent upon whether the ~~designation~~derivative has been designated and qualified as part of ~~the derivative. The~~a hedging relationship or if regulatory accounting requirements require a different accounting treatment. For gas derivatives in our regulated utility business, changes in fair value ofand settled gains and losses are recorded to regulatory assets or liabilities, and recognized subsequently as gas or fuel costs under regulatory-approved cost recovery mechanisms. For our other derivatives, ~~that~~if they are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or fair values. The effective portion of changes in fair values of derivatives designated as cash flow hedges, the effective portion is recorded as a component of other comprehensive income (loss) until it is reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion ~~of changes in fair value of derivatives designated as cash flow hedges~~ is recorded in current earnings. ~~Changes in fair value of derivatives designated as fair value hedges are recognized in current earnings along with fair value changes of the underlying hedged item.~~

We currently use derivative instruments, including options, swaps, and futures, for non-trading (hedging) purposes. Our typical hedging transactions relate to contracts we enter into to fix the price received for anticipated future production at our Oil and Gas segment, or to fulfill the natural gas hedging plans for gas and electric utilities and for interest rate swaps we enter into to convert a portion of our variable rate debt, or associated variable rate interest payments, to a fixed rate.

Fair values of derivative instruments contracts are based on actively quoted market prices or other external source pricing information, where possible. If external market prices are not available, fair value is determined based on other relevant factors and pricing models that consider current market and contractual prices for the underlying financial instruments or commodities, as well as time value and yield curve or volatility factors underlying the positions.

Pricing models and their underlying assumptions impact the amount and timing of unrealized gains and losses recorded, and the use of different pricing models or assumptions could produce different financial results.

Pension and Other Postretirement Benefits

As described in Note 1718 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have ~~two defined~~one benefit pension ~~plans, three~~plan, and several defined post-retirement healthcare plans and ~~several~~ non-qualified retirement plans. A Master Trust holds the assets for the Pension Plans. ~~Each Pension Plan has an undivided interest in the Master Trust.~~ Trusts for the funded portion of the post-retirement healthcare plans have also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount ~~rate for measuring the present value of future plan obligations;~~rates, health care cost trend rates, expected ~~long-term rates of~~ return on plan ~~assets; rate of future~~assets, compensation increases, ~~in compensation levels;~~retirement rates and ~~healthcare cost projections.~~mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

The pension benefit cost for ~~2015~~2017 for our non-contributory funded pension plan is expected to be ~~$13.2~~$2.1 million compared to ~~$8.1~~$7.5 million in ~~2014.~~2016. The ~~estimated~~decrease in pension benefit cost is driven by the merging of the three benefit pension plans into one, improved mortality rates and better than expected return on plan assets, partially offset by a decrease in the discount ~~rate~~rate.

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. The new method used the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine ~~annual~~the benefit ~~cost accruals will be 4.20% in 2015;~~obligations to relevant projected cash outflows. Prior to 2016, the service and interest costs were determined using a single weighted-average discount rate ~~used in 2014 was 5.05%. In selecting the discount rate, we consider cash flow durations for each plan’s liabilities and returns~~based on ~~high credit quality fixed income~~hypothetical AA Above Median yield curves ~~for comparable durations.~~used to measure the benefit obligation at the beginning of the period. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income.

~~We do not pre-fund our non-qualified~~The Company changed to the new method to provide a more precise measure of service and interest costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in 2016.

The effect of hypothetical changes to selected assumptions on the pension ~~plans. One of the three~~and other postretirement benefit plans ~~is partially funded. The table below shows the expected impacts~~would be as follows in thousands of ~~an increase or decrease to our healthcare trend rate for our three Retiree Healthcare Plans (in thousands):~~dollars:

Change in Assumed Trend Rate
Impact on December 31, 2014 Accumulated Postretirement
Benefit Obligation

Impact on 2014 Service
and Interest Cost
Increase 1% $ 2,635
$ 168
Decrease 1% $ (2,166 ) $ (136 )



		December 31,
Assumptions	Percentage Change	2016 Increase/(Decrease) PBO/APBO ^(a)	2017 Increase/(Decrease) Expense - Pretax

Pension
Discount rate ^(b)	+/- 0.5	(25,788)/28,367	(2,835)/3,080
Expected return on assets	+/- 0.5	N/A	(1,816)/1,817

OPEB
Discount rate ^(b)	+/- 0.5	(2,813)/3,051	(29)/59
Expected return on assets	+/- 0.5	N/A	(40)/40
Health care cost trend rate ^(b)	+/- 1.0	2,569/(2,191)	374/(312)

__________________________


(a)	Projected benefit obligation (PBO) for pension plans and accumulated postretirement benefit obligation (APBO) for OPEB plans.


(b)	Impact on service cost, interest cost and amortization of gains or losses.

Regulation

~~Contingencies~~Our utility operations are subject to regulation with respect to rates, service area, accounting, and various other matters by state and federal regulatory authorities. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effects of the manner in which independent third-party regulators establish rates. Regulatory assets generally represent incurred or accrued costs that have been deferred when future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

~~When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of~~Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

Unbilled Revenue

Revenues attributable to gas and energy delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the ~~amount~~related costs are charged to expense. Factors influencing the determination of ~~loss are made~~unbilled revenues may include estimates of delivered sales volumes based on ~~currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities~~weather information and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position, results of operations and cash flows.customer consumption trends.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain acquired subsidiaries file as a separate consolidated group. Each ~~tax paying~~tax-paying entity records income taxes as if it were a separate taxpayer and consolidating 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. ~~We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.~~

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. With respect to changes in tax law, the TIPA, which was enacted December 19, 2014, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Certain provisions of the TIPA involving primarily the extension of 50% bonus depreciation resulted in the generation of a NOL for federal and state income tax purposes in 2014. In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations had the effect of a change in law and as a result the impact was taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We implemented all of the provisions of the final regulations with the filing of the 2013 federal income tax return in September 2014. The adoption of the final regulations did not have a material impact on our consolidated financial statements.

See Note 1415 in our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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. Pertaining to our current year acquisition of SourceGas, 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.

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 in our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Liquidity and Capital Resources

OVERVIEW

BHC and its subsidiaries require significant cash to support and grow ~~our business.~~their businesses. Our predominant source of cash is supplied by our operations and supplemented with corporate borrowings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.

The most significant uses of cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, and anticipated dividends and ~~anticipated~~ capital ~~expenditures discussed in this section.~~expenditures.

The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):


Financial Position Summary	2014			2013			2016			2015
Cash and cash equivalents(a)	$	21,218		$	7,841		$	13,580		$	440,861
Restricted cash and equivalents	$	2,056		$	2		$	2,274		$	1,697
Short-term debt, including current maturities of long-term debt	$	350,000		$	82,500		$	102,343		$	76,800
Long-term debt	$	1,267,589		$	1,396,948		$	3,211,189		$	1,853,682
Stockholders’ equity	$	1,376,024		$	1,307,748		$	1,614,639		$	1,465,867

Ratios
Long-term debt ratio	48		%	52		%	67		%	56		%
Total debt ratio	54		%	53		%	67		%	57		%



Incorporated in South Dakota	625 Ninth Street	IRS Identification Number
	Rapid City, South Dakota 57701	46-0458824
Registrant’s telephone number, including area code (605) 721-1700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common stock of $1.00 par value		New York Stock Exchange



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o



Class	Outstanding at January 31, ~~2015~~2017
Common stock, $1.00 par value	~~44,676,072~~53,384,259	shares



			Page
		GLOSSARY OF TERMS AND ABBREVIATIONS	3

		WEBSITE ACCESS TO REPORTS	78

		FORWARD-LOOKING INFORMATION	78
Part I
	ITEMS 1. and 2.	BUSINESS AND PROPERTIES	8

	ITEM 1A.	RISK FACTORS	5357

	ITEM 1B.	UNRESOLVED STAFF COMMENTS	6769

	ITEM 3.	LEGAL PROCEEDINGS	6769

	ITEM 4.	MINE SAFETY DISCLOSURES	6769
Part II
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	6770

	ITEM 6.	SELECTED FINANCIAL DATA	6871

	ITEMS 7. and 7A.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	7174

	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	~~116~~122

	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	~~188~~204

	ITEM 9A.	CONTROLS AND PROCEDURES	~~188~~204

	ITEM 9B.	OTHER INFORMATION	~~188~~204
Part III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	~~189~~205

	ITEM 11.	EXECUTIVE COMPENSATION	~~190~~205

	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	~~190~~206

	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	~~190~~206

	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	~~190~~206

Part IV

	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	~~191~~207

	ITEM 16.	FORM 10-K SUMMARY	212

		SIGNATURES	~~195~~213

		INDEX TO EXHIBITS	~~196~~214



AC	Alternating ~~current~~Current
AFUDC	Allowance for Funds Used During Construction
AltaGas	AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd.
AOCI	Accumulated Other Comprehensive Income
APSC	Arkansas Public Service Commission
Aquila Transaction	Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
ARO	Asset Retirement Obligations
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by the FASB
ATM	At-the-market equity offering program
Baseload plant	A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
Basin Electric	Basin Electric Power Cooperative
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation; the Company
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, includes Black Hills Gas Resources, Inc. and Black Hills Plateau Production LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.
~~BHSC~~	~~Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation~~
Black Hills Colorado IPP	Black Hills Colorado IPP, LLC a ~~direct wholly-owned~~50.1% owned subsidiary of Black Hills Electric Generation
Black Hills ~~Energy~~Gas	~~The name used to conduct the business~~Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC.
Black Hills Gas Holdings	Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, ~~Inc., and its subsidiaries~~which was previously named SourceGas Holdings LLC
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility companies
Black Hills Energy Arkansas Gas	Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations
Black Hills Energy Colorado Electric	Includes Colorado Electric’s utility operations
Black Hills Energy Colorado Gas	Includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado gas operations and RMNG
Black Hills Energy Iowa Gas	Includes Black Hills Energy Iowa gas utility operations
Black Hills Energy Kansas Gas	Includes Black Hills Energy Kansas gas utility operations
Black Hills Energy Nebraska Gas	Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations
Black Hills Energy Services	A Choice Gas supplier acquired in the SourceGas Acquisition
Black Hills Energy South Dakota Electric	Includes Black Hills Power’s operations in South Dakota, Wyoming and Montana
Black Hills Energy Wyoming Electric	Includes Cheyenne Light’s electric utility operations
Black Hills Energy Wyoming Gas	Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Black Hills Gas Distribution	Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Colorado, Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC.
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
BHSC	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLM	United States Bureau of Land Management
Btu	British thermal unit
Busch Ranch	Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has a 50% ownership interest in the wind farm.
Ceiling Test	Related to our Oil and Gas subsidiary, 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.
CAPP	Customer Appliance Protection Plan - acquired in the SourceGas Acquisition
CFTC	United States Commodity Futures Trading Commission
CG&A	Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
~~Cheyenne Light Pension Plan~~	~~The Cheyenne Light, Fuel and Power Company Pension Plan~~ (doing business as Black Hills Energy)
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural-gas fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
Choice Gas Program	The unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributes the gas and Black Hills Energy Service is one of the Choice Gas suppliers.
City of Gillette	~~The City of~~ Gillette, Wyoming ~~affiliate of the JPB. The JPB financed the purchase of 23% of Wygen III power plant for the City of Gillette.~~
CO₂	Carbon dioxide



Colorado Electric	Black Hills Colorado Electric Utility Company, LP, ~~(doing business as Black Hills Energy),~~ an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Gas	Black Hills Colorado Gas Utility Company, LP, ~~(doing business as Black Hills Energy),~~ an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
Colorado Interstate Gas (CIG)	Colorado Interstate Natural Gas Pricing Index
Colorado IPP	Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Consolidated Indebtedness to Capitalization Ratio	Any Indebtedness outstanding at such time, divided by Capital at such time. Capital being Consolidated Net-Worth (excluding noncontrolling interest and including the aggregate outstanding amount of RSNs) plus Consolidated Indebtedness (including letters of credit, certain guarantees issued and excluding RSNs) as defined within the current Credit Agreement.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a ~~30 year~~30-year average.
Cost of Service Gas Program (COSG)	Proposed Cost of Service Gas Program designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program.
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
CP Program	Commercial Paper Program
CPUC	Colorado Public Utilities Commission
CT	Combustion turbine
CTII	The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.



CVA	Credit Valuation Adjustment
DART	Days Away Restricted Transferred (number of cases with days away from work or job transfer or restrictions multiplied by 200,000 then divided by total hours worked for all employees during the year covered)
DC	Direct current
~~De-designated interest rate swaps~~	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under the accounting for derivatives and hedges but subsequently de-designated in December 2008. These swaps were settled in November 2013.
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DSM	Demand Side Management
DRSPP	Dividend Reinvestment and Stock Purchase Plan
Dth	~~Dekatherms~~Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
EBITDA	Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement
ECA	Energy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
Economy Energy	Electricity purchased by one utility from another utility to take the place of electricity that would have cost more to produce on the utility’s own system
Energy West	Energy West Wyoming, Inc., a subsidiary of Gas Natural, Inc. Energy West is an acquisition we closed on July 1, 2015.
Enserco	Enserco Energy Inc., a ~~formerly~~former wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations ~~throughout~~in this Annual Report filed on Form 10-K
EPA	United States Environmental Protection Agency
EPA Region VIII	EPA Region VIII (Mountains and Plains) located in Denver serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations
Equity Unit	Each Equity Unit has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs due 2028.
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FDIC	Federal Depository Insurance Corporation
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GADS	Generation Availability Data System
GCA	Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.
GHG	Greenhouse gases
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services



Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
IEEE	Institute of Electrical and Electronics Engineers
~~IFRS~~	~~International Financial Reporting Standards~~
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, ~~(doing business as Black Hills Energy),~~ a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
IPP	Independent power producer
IPP Transaction	The July 11, 2008 sale of seven of our IPP plants
IRS	United States Internal Revenue Service
~~IUB~~	~~Iowa Utilities Board~~
~~JPB~~	~~Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette.~~
KCC	Kansas Corporation Commission
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, ~~(doing business as Black Hills Energy),~~ a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
kV	Kilovolt



LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Loveland Area Project	Part of the Western Area Power Association transmission system
MACT	Maximum Achievable Control Technology
MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
Mbbl	Thousand barrels of oil
Mcf	Thousand cubic feet
Mcfd	Thousand cubic feet per day
Mcfe	Thousand cubic feet equivalent
MDU	Montana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MGP	Manufactured Gas ~~Plants~~Plant
MMBtu	Million British thermal units
MMcf	Million cubic feet
MMcfe	Million cubic feet equivalent
Moody’s	Moody’s Investors Service, Inc.
MSHA	Mine Safety and Health Administration
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
N/A	Not Applicable
Native load	Energy required to serve customers within our service territory
NAV	Net Asset Value
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC, ~~(doing business as Black Hills Energy),~~ a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy)
NERC	North American Electric Reliability Corporation
NGL	Natural Gas Liquids (1 barrel equals 6 Mcfe)
NOAA	National Oceanic and Atmospheric Administration



NOAA Climate Normals	This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NO_x	Nitrogen oxide
NOL	Net operating loss
~~NOPA~~	~~Notice of Proposed Adjustment~~
NPDES	National Pollutant Discharge Elimination System
NPSC	Nebraska Public Service Commission
NWPL	Northwest Interstate Natural Gas Pricing Index
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSHA	Occupational Safety & Health Administration
OSM	U.S. Department of the Interior’s Office of Surface Mining
OTC	Over-the-counter
PCA	Power Cost Adjustment
PCCA	Power Capacity Cost Adjustment
Peak View	$109 million 60 MW wind generating project owned by Colorado Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch Wind Farm
PPA	Power Purchase Agreement



PPACA	Patient Protection and Affordable Care Act of 2010
~~PSCo~~PPB	~~Public Service Company of Colorado~~Parts per billion
PUD	Proved undeveloped reserves
PUHCA 2005	Public Utility Holding Company Act of 2005
Quad O Regulation	40 CFR 60 Subpart OOOO - Standards of performance for crude oil and natural gas production, transmission and distribution
RCRA	Resource Conservation and Recovery Act
RICE	Reciprocating Internal Combustion Engines
REPA	Renewable Energy Purchase Agreement
Revolving Credit Facility	Our ~~$500~~$750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in ~~2019~~2021
~~RMSA~~RMNG	~~Retirement Medical Savings Account~~Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas Distribution in western Colorado (doing business as Black Hills Energy)
RSNs	Remarketable junior subordinated notes, issued on November 23, 2015
SAIDI	System Average Interruption Duration Index
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Service Guard	Home appliance repair product offering for both natural gas and electric.
Silver Sage	Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO₂	Sulfur dioxide
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
~~S&S~~SourceGas	~~Significant~~SourceGas Holdings LLC and ~~substantial~~its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
SourceGas Acquisition	The acquisition of SourceGas Holdings, LLC by Black Hills Utility Holdings
SourceGas Transaction	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
Spinning Reserve	Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission ~~outages.~~outages
SSIR	System Safety and Integrity Rider
SSTAR-TEXOK	Natural gas price index tied to the Southern Star Central gas pipeline
System Peak Demand	Represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
TCA	Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
TCIR	Total Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period)
~~TIPA~~	~~Tax Increase Prevention Act of 2014~~
VEBA	Voluntary Employee Benefit Association
VIE	Variable Interest Entity
VOC	Volatile Organic Compound
WDEQ	Wyoming Department of Environmental Quality
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
WTI	West Texas Intermediate ~~Crude~~crude oil, an oil index benchmark price as quoted by NYMEX
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.



~~Business Group~~	~~Financial Segment~~
~~Utilities~~	~~Electric Utilities~~
	~~Gas Utilities~~

~~Non-regulated Energy~~	~~Power Generation~~
	~~Coal Mining~~
	~~Oil and Gas~~


	System Peak Demand (in MW)						System Peak Demand (in MW)
	2014		2013		2012		2016		2015		2014
	Summer	Winter	Summer	Winter	Summer	Winter	Summer	Winter	Summer	Winter	Summer	Winter
Black Hills Power	410	389	422	403	449	362
Cheyenne Light	198	197	185	192	187	174
South Dakota Electric							438	389	424	369	410	389
Wyoming Electric ^(a)							236	230	212	202	198	197
Colorado Electric(b)	384	298	381	280	400	284	412	302	392	303	384	298
Total Electric Utilities Peak Demands	992	884	988	875	1,036	820	1,086	921	1,028	874	992	884


Fuel Source (dollars per megawatt-hour)	2014		2013		2012
Fuel Source (dollars per MWh)							2016		2015		2014
Coal	$	10.92	$	10.89	$	14.42	$	11.27	$	10.89	$	10.92

Natural Gas(a)	$	77.31	$	53.53	$	52.08	$	30.59	$	51.14	$	77.31

Diesel Oil(b)	$	174.04	$	233.47	$	280.29	$	149.13	$	303.16	$	174.04

Total Average Fuel Cost	$	14.82	$	14.65	$	16.05	$	12.99	$	14.62	$	14.82

Purchased Power - Coal, Gas and Oil	$	35.21	$	29.95	$	26.70	$	48.36	$	47.81	$	35.21

Purchased Power - Renewable Sources	$	50.27	$	49.20	$	47.45	$	51.95	$	50.92	$	50.27



	Net income (loss) available for common stock for the year ended December 31, 2016	Total Assets as of December 31, 2016
	(in thousands)
Electric Utilities	$85,827	$2,859,559
Gas Utilities	$59,624	$3,307,967
Power Generation	$25,930	$73,445
Mining	$10,053	$67,347
Oil and Gas	($71,054)	$96,435


(a)	Both 2016 summer and winter peaks are records set in July and December, respectively, replacing summer and winter record peaks set in July and December of 2015.


(b)	New summer peak load for Colorado Electric achieved in July 2016, replacing the previous all-time summer peak of 406 set in June 2016, and of 400 set in June 2012.


Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Black Hills Power ⁽¹⁾:
South Dakota Electric:
Cheyenne Prairie ^(2)(a)	Gas	Cheyenne, Wyoming	58%	55.0	2014	Gas	Cheyenne, Wyoming	58%	55.0	2014
Wygen III^(3)(b)	Coal	Gillette, Wyoming	52%	57.2	2010	Coal	Gillette, Wyoming	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995	Coal	Gillette, Wyoming	100%	90.0	1995
Wyodak ^(4)(c)	Coal	Gillette, Wyoming	20%	72.4	1978	Coal	Gillette, Wyoming	20%	72.4	1978
Neil Simpson CT	Gas	Gillette, Wyoming	100%	40.0	2000	Gas	Gillette, Wyoming	100%	40.0	2000
Lange CT	Gas	Rapid City, South Dakota	100%	40.0	2002	Gas	Rapid City, South Dakota	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, South Dakota	100%	10.0	1965	Oil	Rapid City, South Dakota	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, South Dakota	100%	80.0	1977-1979	Gas/Oil	Rapid City, South Dakota	100%	80.0	1977-1979
Cheyenne Light:
Wyoming Electric:
Cheyenne Prairie ^(2)(a)	Gas	Cheyenne, Wyoming	42%	40.0	2014	Gas	Cheyenne, Wyoming	42%	40.0	2014
Cheyenne Prairie CT ^(2)(a)	Gas	Cheyenne, Wyoming	100%	37.0	2014	Gas	Cheyenne, Wyoming	100%	37.0	2014
Wygen II	Coal	Gillette, Wyoming	100%	95.0	2008	Coal	Gillette, Wyoming	100%	95.0	2008
Colorado Electric:
Busch Ranch Wind Farm^(5)(d)	Wind	Pueblo, Colorado	50%	14.5	2012	Wind	Pueblo, Colorado	50%	14.5	2012
Peak View Wind Farm ^(e)						Wind	Pueblo, Colorado	100%	60.0	2016
Pueblo Airport Generation	Gas	Pueblo, Colorado	100%	180.0	2011	Gas	Pueblo, Colorado	100%	180.0	2011
Pueblo Airport Generation CT ^(f)						Gas	Pueblo, Colorado	100%	40.0	2016
AIP Diesel	Oil	Pueblo, Colorado	100%	10.0	2001	Oil	Pueblo, Colorado	100%	10.0	2001
Diesel #1-5	Oil	Pueblo, Colorado	100%	10.0	1964	Oil	Pueblo, Colorado	100%	10.0	1964
Diesel #1-5	Oil	Rocky Ford, Colorado	100%	10.0	1964	Oil	Rocky Ford, Colorado	100%	10.0	1964
Total MW Capacity				841.1					941.1


~~(3)~~(b)	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by ~~Black Hills Power. Black Hills Power~~South Dakota Electric. South Dakota Electric has a 52% ownership interest, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine supplies all of the fuel for the plant.


~~(4)~~(c)	Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by ~~Black Hills Power.~~South Dakota Electric. This baseload plant is operated by PacifiCorp and our WRDC coal mine supplies all of the fuel for the plant.


~~(5)~~(d)	Busch Ranch Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm. ~~The wind farm became operational October 16, 2012.~~


(e)	Peak View Wind Farm achieved commercial operation on November 7, 2016.


(f)	Colorado Electric’s newly constructed LM 6000, which achieved commercial operation on December 29, 2016.


(a)	Decrease is driven by lower 2016 natural gas costs than the prior year.


(b)	Decrease is due to combination of lower fuel costs in 2016 and the efficiencies at which the diesel units performed compared to the prior year.


Power Supply	2014		2013		2012		2016		2015		2014
Coal	34	%	36	%	37	%	33	%	33	%	34	%
Gas, Oil and Wind	4		4		2		7		4		4
Total Generated	38		40		39		40		37		38
Purchased(a)	62		60		61		60		63		62
Total	100	%	100	%	100	%	100	%	100	%	100	%


(a)	Wind represents approximately 7% of our purchased power in 2016, and approximately 5% of our purchased power in 2015 and 2014.



~~2015-2017~~2017	20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson ~~II; and~~II



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Black Hills Power	South Dakota, Wyoming	1,182	2,474
Black Hills Power - Jointly Owned ⁽¹⁾	South Dakota, Wyoming	44	—
Cheyenne Light	South Dakota, Wyoming	48	1,257
Colorado Electric	Colorado	585	3,070


◦	~~Black Hills Power, Cheyenne Light,~~South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets by the affiliate entity.


◦	Black Hills Colorado IPP and Colorado Electric are also parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets.


◦	~~Black Hills Power~~South Dakota Electric and ~~Cheyenne Light also~~Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.


◦	~~Black Hills Power,~~South Dakota Electric, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby ~~Black Hills Power~~South Dakota Electric charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.


◦	Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm.