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•	2018 EPS from continuing operations of $4.78 includes tax benefits of $1.24 per share

•	2018 EPS from continuing operations, as adjusted, of $3.54 is $0.04 above guidance range

•	Weather benefit of $0.09 per share for full year and $0.06 per share in fourth quarter

•	2019 and 2020 earnings guidance reaffirmed

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•	In 2018, Black Hills’ electric and natural gas utilities finalized agreements with state utility regulators to deliver federal corporate income tax reform benefits from the Tax Cuts and Jobs Act to utility customers in six states. We expect approval to deliver tax reform benefits to Wyoming customers in the first half of 2019.

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On Dec. 17, South Dakota Electric and Wyoming Electric filed for approval of new, voluntary tariffs, known as Renewable Ready Service Tariffs, with the South Dakota Public Utilities Commission and Wyoming Public Service Commission in response to governmental, commercial and industrial customer interest in purchasing renewable energy. Related to the proposed program, the utilities also filed an application with the WPSC for a certificate of public convenience and necessity to construct a new $57 million, 40-megawatt wind generation project near Cheyenne, Wyoming. If approved, the Corriedale Wind Energy Project will be constructed and placed in service during 2020 and jointly owned by South Dakota Electric and Wyoming Electric.

•	On Dec. 6, Wyoming Electric set a new all-time winter peak load of 238 megawatts, surpassing the previous all-time winter peak load of 230 megawatts set in December 2016.

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On Nov. 30, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC. The plan recommends that long-term electric capacity and energy needs be met utilizing a balanced mix of generation resources, including coal, natural gas and renewable resources, such as wind and solar. The plan also recommends that near-term needs be met through the purchase of the Wygen I power plant, located near Gillette, Wyoming, as the least cost resource. A future purchase of Wygen I, which is owned by Black Hills Wyoming, an affiliate company, by Wyoming Electric would require approval by the WPSC and the Federal Energy Regulatory Commission. This process is expected to be completed by year-end 2019.

•	On Nov. 20, South Dakota Electric placed in service a 33-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25. The remaining 94-mile segment is expected to be in service by the end of 2019.

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On Oct. 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year, multi-docket settlement regarding its Power Cost Adjustment Application filed earlier in 2018. Wyoming Electric agreed to provide a total of $7 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve several years of disputed issues related to PCA dockets before the commission. The settlement also stipulates that the adjustment for the variable cost

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•	On Oct. 3, Colorado Electric set a new all-time winter peak load of 313 megawatts, surpassing the previous all-time winter peak load of 310 megawatts set in February 2011.

•	On July 10, Wyoming Electric set a new all-time peak load of 254 megawatts, surpassing the previous all-time peak load of 249 megawatts set in July 2017.

•	On June 27, Colorado Electric set a new all-time peak load of 413 megawatts, surpassing the previous peak load of 412 megawatts set in July 2016.

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On Feb. 1, 2019, Colorado Gas filed a rate review proposal with the Colorado Public Utilities Commission to consolidate the rates, tariffs and services of its two existing gas distribution territories in Colorado. The rate review also requests $2.5 million in new revenue to recover investments in safety, reliability and system integrity for natural gas service to 187,000 customers in Colorado. Colorado Gas is also requesting a new rider mechanism to recover accelerated safety and integrity investments in its system.

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On Nov. 20, Wyoming Gas received approval from the WPSC for a CPCN to construct a new $54 million, 35-mile natural gas pipeline to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The pipeline will be constructed from an interconnection supply point near Douglas, Wyoming, to existing facilities near Casper, Wyoming. The pipeline, known as the Natural Bridge Pipeline, is planned to be in service in late 2019.

•	On Oct. 10, Colorado Gas and Colorado Gas Distribution received approval from the Colorado Public Utilities Commission for their Joint Application request to merge the two gas utility businesses into a single new company called Black Hills Colorado Gas.

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On Oct. 5, Arkansas Gas received approval from the Arkansas Public Service Commission for new rates to recover more than $160 million of investment to replace, upgrade and maintain more than 5,500 miles of natural gas pipelines in Arkansas. The approval includes an increase of $12 million in new annual revenue based on a return on equity of 9.61 percent and a capital structure of 49.1 percent equity and 50.9 percent debt. New customer rates were effective Oct. 15, 2018.

•	On Sept. 5, Nebraska Gas Distribution received approval from the Nebraska Public Service Commission to extend the recovery period of its system safety and integrity rider from Oct. 31, 2019, to Dec. 31, 2020. Nebraska Gas Distribution receives approximately $6 million of revenue annually through this rider mechanism.

•	On July 16, Wyoming Gas (Northwest Wyoming) received approval for new rates to recover approximately $6 million of system integrity investments. The approval included an increase of $1.0 million in annual revenue based on a return on equity of 9.6 percent and a capital structure of 54 percent equity and 46 percent debt. New customer rates were effective Sept. 1, 2018.

•	On June 19, Kansas Gas received approval from the Kansas Corporation Commission to double eligible system integrity and safety investments up to $8.0 million per year under the Gas System Reliability rider.

•	On June 1, Rocky Mountain Natural Gas, an intrastate pipeline company in Colorado, implemented new rates after approval of a settlement agreement of a rate review filed in October 2017. The settlement included an increase of $1.1 million in annual revenue and an extension of the system safety and integrity rider to recover investments from 2018 through 2021.

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On Dec. 11, Black Hills Electric Generation completed the purchase of a 50 percent ownership interest in the 29-megawatt Busch Ranch I wind farm located near Pueblo, Colorado, from a third party for $16 million. Colorado Electric, an affiliate utility company, owns the remaining 50 percent and operates the wind farm. The acquired 14.5 megawatts of energy from the purchased interest in the wind farm is contracted to Colorado Electric through a power purchase agreement expiring in 2037.

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•	On April 25, Black Hills Electric Generation was selected to provide 60 megawatts of renewable energy from a new wind project to Colorado Electric through a 25-year power purchase agreement. The $71 million Busch Ranch II wind project is expected to be constructed near the Busch Ranch I wind farm and placed in service during the fourth quarter of 2019.

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On Jan. 30, 2019, the board of directors declared a dividend of $0.505 per share, equivalent to an annual dividend rate of $2.02 per share. Common shareholders of record at the close of business on Feb. 15, 2019, will receive $0.505 per share, payable March 1, 2019. In November 2018, the board approved a 6.3 percent increase in the quarterly dividend rate, the third quarterly increase of 6 percent or more since 2016. The annual dividend rate of $2.02 for 2019 represents the 49th consecutive calendar year of dividend increases.

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Effective Dec. 31, David Emery retired as CEO after 29 years of service - 15 years as CEO, with 14 of those years as chairman of the board. Emery will continue to serve the company as executive chairman until May 1, 2020. Linn Evans, president and chief operating officer and 17-year veteran of the company, was appointed president and CEO, effective Jan. 1, 2019. Evans was also appointed to the board of directors effective Nov. 1, 2018. This leadership transition was the result of a comprehensive, multi-year, board-led succession planning process.

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On Nov. 1, Black Hills Corp. issued 6.37 million shares of new common stock related to the conversion of its 5.98 million equity units. Gross proceeds of approximately $299 million from the conversion of the equity units were used to repay the $250 million senior notes due in 2019 and pay down short-term debt. Black Hills had approximately 59.97 million shares of common stock outstanding after conversion.

•	On Aug. 17, Black Hills Corp. completed a public debt offering of $400 million of 4.35 percent senior unsecured notes due July 30, 2033. These notes replaced the $299 million of Remarketable Junior Subordinated Notes due 2028 (originally issued as part of the equity units) and paid down short-term debt.

•	On Aug. 9, S&P Global Ratings upgraded its corporate credit rating of Black Hills Corp. to BBB+ from BBB, maintaining a stable outlook.

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On July 30, Black Hills Corp. amended and restated its corporate revolving credit facility, maintaining total commitments of $750 million and extending the term through July 30, 2023, with two one-year extension options. The facility includes an accordion feature that allows the company, under certain conditions, to increase total commitments up to $1 billion. The terms are materially consistent with the previous agreement.

•	On July 30, Black Hills Corp. amended and restated its $300 million term loan due in August 2019 with a new maturity of July 30, 2020. The cost of borrowing is based on LIBOR plus a spread based on the company’s credit rating, which is currently 75 basis points per annum.

•	During 2018, Black Hills completed the exit of its oil and gas business.

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(a)	Net income from continuing operations for the three and 12 months ended Dec. 31, 2018 included a $23 million and $73 million tax benefit resulting from legal entity restructuring.

(b)

Net income (loss) from continuing operations for the three and 12 months ended Dec. 31, 2018 included approximately $3.5 million income tax benefit and ($4.0) million of income tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. The (expense) benefit impact to our operating segments and Corporate and Other for the three and 12 months ended Dec. 31, 2018 was: Electric Utilities $(1.0) million and ($4.2) million; Gas Utilities $3.1 million and $0.5 million; Power Generation $0.0 million and ($0.7) million; Mining $0.0 million and ($0.5) million; and Corporate and Other $1.5 million and $0.9 million, respectively.

(c)

Net Income from continuing operations for the three and 12 months ended Dec. 31, 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. The (expense) benefit impact to our operating segments and Corporate and Other for the three and 12 months ended Dec. 31, 2017 was: Electric Utilities $23 million; Gas Utilities ($6.8) million; Power Generation $24 million; Mining $2.7 million; and Corporate and Other ($35) million, respectively.

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•	Capital spending of $670 million;

•	Normal weather conditions within our utility service territories including temperatures, precipitation levels and wind conditions;

•	Normal operations and weather conditions for planned construction, maintenance and/or capital investment projects;

•	Completion of utility regulatory dockets;

•	Complete construction and place in service the Rapid City, South Dakota, to Stegall, Nebraska, electric transmission line , Busch Ranch II wind project and Natural Bridge Pipeline by year-end 2019;

•	No significant unplanned outages at any of our facilities;

•	Equity financing of $25 to $50 million during 2019 under our At-the-Market equity offering program; and

•	No significant acquisitions or divestitures.

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Earnings per share from continuing operations, as adjusted, is defined as GAAP Earnings per share from continuing operations, adjusted for expenses and gains that the company believes do not reflect the company’s core operating performance. Examples of these types of adjustments may include unique one-time non-budgeted events, impairing of assets, and acquisition and disposition costs. The company is not able to provide forward-looking quantitative GAAP to non-GAAP reconciliation for the 2019 earnings guidance, as adjusted, because we do not know the unplanned or unique events that may occur.

•	Capital spending of $670 million and $524 million in 2019 and 2020, respectively;

•	Normal weather conditions within our utility service territories including temperatures, precipitation levels and wind conditions;

•	Normal operations and weather conditions for planned construction, maintenance and/or capital investment projects;

•	Completion of utility regulatory dockets;

•	Complete construction and place in service by year-end 2019 of the Rapid City, South Dakota, to Stegall, Nebraska, electric transmission line, Busch Ranch II wind project and Natural Bridge Pipeline, and, if approved, the Corriedale Wind Energy Project by year-end 2020;

•	No significant unplanned outages at any of our facilities;

•	Equity financing of $25 to $50 million in 2019 and $25 to $50 million in 2020 under our At-the-Market equity offering program; and

•	No significant acquisitions or divestitures.

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(a)	Non-GAAP measure.

(b)	We estimated and recorded a reserve to revenue of approximately $5.1 million and $22.3 million during the three and 12 months ended Dec. 31, 2018, respectively, to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs. This reduction to revenues is offset by lower tax expense and has no impact on overall results.

(c)	The three and 12 months ended Dec. 31, 2018 include Horizon Point shared facility revenues of approximately $2.8 million and $11 million, respectively, which are allocated to all of our operating segments as facility expenses. This shared facility agreement has no impact on BHC’s consolidated operating results.

(d)	Gross margin was impacted for the three and 12 months ended Dec. 31, 2018 by ($0.6) million and ($4.3) million, respectively, as a result of the Wyoming Electric PCA settlement.

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(a)	Non-GAAP measure

(b)	Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.

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(a)	Non-GAAP measure

(b)	Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.

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(a)	Non-GAAP measure.

(b)	We estimated and recorded a reserve to revenue of approximately $7.0 million and $20.5 million during the three and 12 months ended Dec. 31, 2018, respectively, to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs. This reduction to revenues is offset by lower tax expense and has no impact on overall results.

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(a)	Non-GAAP measure

(b)	Heating degree days at the Gas Utilities for the three months ended December 31, 2018 were 5% higher than the 30-year average (normal) compared to 7% lower than normal for the same period in 2017.

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(a)	Non-GAAP measure

(b)	Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than the 30-year average (normal) compared to 10% lower than normal in 2017.

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(a)	The generating facility located in Pueblo, Colorado, is accounted for as a capital lease under GAAP; therefore, depreciation expense for the original cost of the facility is recorded at the Electric Utility segment.

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(a)	Includes certain general and administrative and interest expenses that are not reported as discontinued operations

•	Prior year tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of the TCJA;

•	Higher current year state income tax expense of $4.6 million; and

•	Lower interest costs due to interest expenses previously allocated to our Oil and Gas segment in 2017, which were not reclassified to discontinued operations in 2017, and were allocated to our operating segments in 2018.

•	Prior year tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of the TCJA;

•	Higher current year state income tax expense of $4.6 million;

•	A decrease in corporate expenses from prior year acquisition costs; and

•	Lower interest costs due to interest expenses originally charged to our Oil and Gas Segment in 2017 which were not reclassified to discontinued operations in 2017, and were allocated to our operating segments in 2018.

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•	The accuracy of our assumptions on which our earnings guidance is based;

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Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power and other operating costs, the timing in which new rates would go into effect and the results of regulatory proceedings regarding the effects of the TCJA;

•	Our ability to complete our capital program in a cost-effective and timely manner;

•	Our ability to execute on our strategy, including: achieving long-term EPS growth rate above the utility industry average, targeting a 50 to 60 percent dividend payout ratio and continuing our track record of continuous annual dividend increases;

•	Our ability to execute our jurisdiction simplification plan;

•	The impact of future governmental regulation; and

•	Other factors discussed from time to time in our filings with the SEC.

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(a)	The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.

(b)	Non-GAAP measure.

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(a)	The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.

(b)	Non-GAAP measure.

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(a)	The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.

(b)	Non-GAAP measure.

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(a)	The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.

(b)	Non-GAAP measure.