Black Hills Corp. Reports 2018 Fourth Quarter and Full Year Results

• 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

RAPID CITY, S.D., Feb. 07, 2019 (GLOBE NEWSWIRE) — Black Hills Corp. (NYSE: BKH) today announced 2018 fourth quarter and full year financial results. Net income from continuing operations available for common stock for the fourth quarter and full year 2018 was $88 million and $265 million, or $1.51 and $4.78 per diluted share, respectively, compared to $64 million and $194 million, or $1.17 and $3.52 per diluted share, respectively, for the same periods in the prior year.  The three and 12 months ending Dec. 31, 2018 included net tax benefits of $27 million and $69 million, or $0.46 and $1.24 per diluted share, respectively, primarily related to legal entity restructuring at our gas utilities that resulted in the recognition of deferred tax benefits associated with amortizable goodwill for tax purposes.  The same periods in 2017 included a benefit from tax reform and other tax items of $12 million or $0.21 per diluted share.

Net income from continuing operations available for common stock, as adjusted, for the three and 12 months ending Dec. 31, 2018 increased over the same periods in 2017 by 13 percent and 6 percent, respectively.  Net income from continuing operations available for common stock, as adjusted, for the three and 12 months ending Dec. 31, 2018 was $61 million and $197 million, or $1.05 and $3.54 per diluted share, respectively, compared to $54 million and $185 million or $0.98 and $3.36 per share, respectively, for the same period in 2017 (this is a non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided).

Net income available for common stock for the fourth quarter and full year of 2018 was $87 million and $258 million, or $1.49 and $4.66 per diluted share, respectively, compared to $51 million and $177 million, or $0.92 and $3.21 per diluted share, respectively, for the same periods in 2017.  Net income available for common stock includes results from discontinued operations for all periods presented.

“I am pleased with the organization’s accomplishments in 2018 as we continued to execute our electric and natural gas utility strategy,” said Linn Evans, president and CEO of Black Hills Corp. “Black Hills achieved excellent operational performance and made progress on a number of important strategic initiatives. Adjusted earnings per share grew 5 percent year-over-year through ongoing strategic investments to better serve our customers and communities and from increased customer usage primarily due to weather. Earnings per share were impacted by the Nov. 1 conversion of our equity units and the resulting addition of 6.37 million new shares of common stock.

“We planned and managed through a comprehensive regulatory agenda in 2018, and I am proud of how the entire Black Hills team responded. We successfully completed three rate reviews, including our first at Arkansas Gas, provided tax reform benefits to customers in six states and prepared and filed an electric resource plan in Wyoming. We received regulatory approval for a major pipeline project and requested approval for a wind generation project. In addition, to simplify regulatory and legal processes, we commenced proceedings in Colorado and Wyoming to consolidate multiple gas utilities within those states. These accomplishments in 2018 continued to demonstrate our team’s core strength in advancing regulatory initiatives to achieve successful results for all stakeholders.

“We enhanced our customer-focused strategy in 2018 as Black Hills celebrated its 135th anniversary of delivering the essential energy customers need. We are optimistic about the future and the opportunities to modernize utility infrastructure and transform the customer experience to meet the ever changing expectations of customers. Our ongoing strong capital investment program will continue to benefit our customers, shareholders and the communities we serve.

“In closing, I want to recognize and congratulate David Emery on his retirement as CEO and his 29 years of service to Black Hills, its employees and customers. As CEO for the last 15 years, and as chairman of the board for the past 14 years, David has been instrumental in leading, creating and growing the company that we know today, and we look forward to his continued inspiration as our executive chairman through May 1, 2020,” concluded Evans.

(Minor differences may result due to rounding.)

Black Hills Corp. highlights for the fourth quarter and full year 2018, recent regulatory filings, updates and other events include:

• 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.

Electric Utilities

• 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.
• 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.
• 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 segment of the Wygen I Power Purchase Agreement with Wyoming Electric (an affiliate company) will escalate by 3 percent annually through 2022.
• 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.

Gas Utilities

• 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.
• 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.
• 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.

Power Generation

• 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.
• 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.

Corporate

• 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.
• 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.
• 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.
• 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.

Discontinued Operations

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

BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS (Unaudited)

(Minor differences may result due to rounding.)

^{(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.}

2019 EARNINGS GUIDANCE REAFFIRMED

Black Hills is reaffirming its guidance for 2019 earnings per share from continuing operations available for common stock, as adjusted, to be in the range of $3.35 to $3.55 per share (a non-GAAP measure*). The guidance range is based on the following assumptions:

• 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.

*  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.

2020 EARNINGS GUIDANCE REAFFIRMED

Black Hills is reaffirming its guidance for 2020 earnings per share available for common stock, as adjusted (a non-GAAP measure*), to be in the range of $3.50 to $3.80, based on the following assumptions:

• 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.

*The company is not able to provide a forward-looking quantitative GAAP to non-GAAP reconciliation of guidance for 2020 earnings, as adjusted, because unplanned or unique events that may occur are unknown at this time.

ANNUAL MEETING OF SHAREHOLDERS

The company’s annual meeting of shareholders will be held on Tuesday, April 30, 2019, at 9:30 a.m. local time, at Black Hills’ company headquarters located at 7001 Mt. Rushmore Road in Rapid City, South Dakota. The company plans to mail the Annual Report and Proxy Statement on or about March 15, 2019, to shareholders of record as of March 1, 2019.

CONFERENCE CALL AND WEBCAST

The company will host a live conference call and webcast at 11 a.m. EST on Friday, Feb. 8, 2019, to discuss the company’s financial and operating performance.

To access the live webcast and download a copy of the investor presentation, go to the Black Hills website at www.blackhillscorp.com, and click on “Events and Presentations” in the “Investor Relations” section. The presentation will be posted on the website before the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. Those interested in asking a question during the live broadcast or those without Internet access can call 866-544-7741 if calling within the United States. International callers can call 724-498-4407. All callers need to enter the passcode 3986835 when prompted.

For those unable to listen to the live broadcast, a replay will be available on the company’s website.

USE OF NON-GAAP FINANCIAL MEASURE

As noted in this news release, in addition to presenting its earnings information in conformity with Generally Accepted Accounting Principles (GAAP), the company has provided non-GAAP earnings data reflecting adjustments for special items as specified in the GAAP to non-GAAP adjustment reconciliation table below. Net income (loss), as adjusted, is defined as Net income (loss), adjusted for expenses and gains that the company believes do not reflect the company’s core operating performance. The company believes that non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. The company’s management uses these non-GAAP financial measures as an indicator for planning and forecasting future periods. These non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of the company’s results as reported under GAAP. The presentation of these non-GAAP financial measures should not be construed as an inference that future results will not be affected by unusual, non-routine, or non-recurring items.

Gross margin (revenue less cost of sales) is considered a non-GAAP financial measure due to the exclusion of deprecation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of operating performance. 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 revenue 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 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.

GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION

SEGMENT PERFORMANCE SUMMARY

Our segment highlights for the three months and 12 months ended Dec. 31, 2018, compared to the three months and 12 months ended Dec. 31, 2017, are discussed below. The following segment information does not include certain inter-company eliminations. Minor differences in comparative amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.

Electric Utilities

^{(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.}
           

Fourth Quarter 2018 Compared to Fourth Quarter 2017

Gross margin ^(a) increased as a result of:

________________
^{(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.}

Operations and maintenance increased primarily due to $1.3 million higher vegetation management expenses, $0.6 million higher facility costs, $0.6 million of higher employee costs driven primarily by labor and benefits, and $0.4 million of higher contractor and consulting expenses.

Depreciation and amortization increased primarily due to higher asset base driven by the prior year addition of Horizon Point and the completion of the first segment of the Rapid City-Stegall transmission line earlier in 2018.

Interest expense, net was comparable to the same period in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased in 2018 due to a prior year tax benefit of $23 million resulting from revaluation of net deferred tax liabilities in accordance with the ASC 740 and the enactment of the TCJA on Dec. 22, 2017.  In addition, current year expense increased due to $1.0 million of tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. This was partially offset by a reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.

Full Year 2018 Compared to Full Year 2017

Gross margin ^(a) decreased as a result of:

________________
^{(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.}

Operations and maintenance increased primarily due to higher facility costs of $4.5 million and higher employee costs of $3.6 million driven primarily by labor and benefits. Vegetation management expenses increased over the prior year by $2.9 million, contractor and consulting expenses increased by $1.2 million and property taxes increased by $1.0 million due to a higher asset base.

Depreciation and amortization increased primarily due to higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line as well as the current year completion of the first segment of the Rapid City-Stegall transmission line.

Interest expense, net was comparable to the same period in the prior year.

Other (expense) income, net decreased due to the presentation change of non-service pension costs to Other income (expense) in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.

Income tax benefit (expense): The effective tax rate increased in 2018 due to a prior year $23 million benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on Dec. 22, 2017. In addition, current year expense increased due to $4.2 million of tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. This was partially offset by the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.

Gas Utilities

^{(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.}

Fourth Quarter 2018 Compared to Fourth Quarter 2017

Gross margin ^(a) increased as a result of:

________________
^{(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.}

Operations and maintenance increased primarily due to $8.2 million of higher employee costs driven by labor, benefits and additional headcount and $2.9 million of higher outside services, contractor, and consulting expenses due primarily to expenses related to jurisdictional simplification.

Depreciation and amortization increased primarily due to higher asset base driven by previous and current year capital expenditures.

Interest expense, net increased due to higher corporate allocations from financing activities.

Other income (expense), net increased due to lower non-qualified deferred pension costs, previously reported in Operations and maintenance.

Income tax benefit (expense): The effective tax rate decreased due to legal restructuring to enable jurisdictional simplification that resulted in the recognition of a deferred tax benefit of approximately $23 million associated with amortizable goodwill for tax purposes. In addition, the 2018 benefit increased due to $3.0 million of tax benefit associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. The current year rate also reflects the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.  In the prior year, there was additional tax expense of $6.8 million as a result of the TCJA enacted on December 22, 2017, partially offset by $4.1 million tax benefit recognized in the prior year from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition.

Full Year 2018 Compared to Full Year 2017

Gross margin ^(a) increased as a result of:

________________
^{(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.}

Operations and maintenance increased primarily due to higher employee costs of $11.8 million driven by labor, benefits and additional headcount.  Outside services, consulting, and contractor expenses increased by $4.0 million due primarily to expenses related to jurisdictional simplification.  In addition, facility costs increased by $4.7 million and bad debt expense increased by $2.1 million driven by the current year increase in revenues.

Depreciation and amortization increased primarily due to higher asset base driven by previous and current year capital expenditures.

Interest expense, net increased due to higher corporate allocations from financing activities.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate decrease was due to legal restructuring to enable jurisdictional simplification that resulted in the recognition of a deferred tax benefit of approximately $73 million associated with amortizable goodwill for tax purposes. The current year rate also reflects the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.  In the prior year there was additional tax expense of $6.8 million as a result of the TCJA enacted on Dec. 22, 2017 partially offset by $4.1 million tax benefit recognized in the prior year from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition.

Power Generation

^{(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.}

Fourth Quarter 2018 Compared to Fourth Quarter 2017

Net income available for common stock for the Power Generation segment was $3.5 million for the three months ended Dec. 31, 2018, compared to Net income available for common stock of $28 million for the same period in 2017.  Revenue decreased in the current year due to lower volumes from a planned outage at Wygen I.  Depreciation expense decreased in the current year due primarily to a prior year increase in depreciation on non-leased assets. The variance in tax expense is primarily due to a prior year $24 million tax benefit recognized from the revaluation of deferred tax liabilities in accordance with the TCJA enacted on Dec. 22, 2017 partially offset by the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.

Full Year 2018 Compared to Full Year 2017

Net income available for common stock for the Power Generation segment was $21 million for the 12 months ended Dec. 31, 2018, compared to Net income available for common stock of $46 million for the same period in 2017.  Revenue decreased in the current year due a decrease in MWh sold, primarily due to a planned outage at Wygen I.  Operating expenses increased due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation. Interest expense increased from the same period in the prior year due to higher interest rates.  The variance in tax expense is primarily due to a prior year $24 million tax benefit recognized from the revaluation of deferred tax liabilities in accordance with the TCJA enacted on Dec. 22, 2017 partially offset by the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.

Mining

Fourth Quarter 2018 Compared to Fourth Quarter 2017

Net income available for common stock for the Mining segment was $3.3 million for the three months ended Dec. 31, 2018, compared to Net income available for common stock of $5.3 million for the same period in 2017.  Revenue decreased primarily due to lower tons of coal sold driven by an unplanned outage. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income (expense), net. During the current period, approximately 53% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operating expenses decreased primarily due to lower major maintenance expenses and lower overburden removal.  Other income (expense), net decreased from the prior year due to the presentation change of lease and rental revenue to Revenue in the current year, previously reported in Other income (expense), net.  The variance in tax expense is primarily due to a prior year $2.7 million benefit resulting from revaluation of net deferred tax liabilities in accordance with the enactment of the TCJA on Dec. 22, 2017, partially offset by the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.

Full Year 2018 Compared to Full Year 2017

Net income available for common stock for the Mining segment was $13 million for the year ended Dec. 31, 2018, compared to Net income available for common stock of $14 million for the same period in 2017. Revenue increased primarily due to a 1% increase in price per ton sold.  Current year revenue is also reflective of lease and rental revenue, previously reported in Other income (expense), net.  During the current period, approximately 50% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operating expenses decreased primarily due to lower major maintenance expenses and lower overburden removal.  Other income (expense), net decreased from the prior year due to the presentation change of lease and rental revenue to Revenue in the current year, previously reported in Other income (expense), net.  The variance in tax expense is primarily due to a prior year $2.7 million benefit resulting from revaluation of net deferred tax liabilities in accordance with the enactment of the TCJA on Dec 22, 2017, partially offset by the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.

Corporate and Other

Corporate and Other represents certain unallocated expenses for administrative activities and interest and taxes that support our reportable operating segments.  Corporate and Other also includes business development activities that do not fall under our operating segments.

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

Fourth Quarter 2018 Compared to Fourth Quarter 2017

Net loss available for common stock for the three months ended Dec. 31, 2018, was $(1.7) million compared to Net loss available for common stock of $(36) million for the same period in 2017. The variance from the prior year was driven primarily by a decrease in income tax expense, as well as lower operating expenses. The variance from the prior year was due to:

• 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. 

Full Year 2018 Compared to Full Year 2017

Net loss available for common stock was $(7.6) million for the 12 months ended Dec. 31, 2018, compared to Net loss available for common stock of $(43) million for the same period in 2017. The variance from the prior year was driven primarily by a decrease in income tax expense, as well as lower operating and interest expenses.  The variance from the prior year was due to:

• 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.

Discontinued Operations

Fourth Quarter 2018 Compared to Fourth Quarter 2017

Net loss from discontinued operations $(1.3) million for the three months ended Dec. 31, 2018, compared to Net loss from discontinued operations of $(14) million for the same period in 2017. The variance to the prior year is primarily driven by a prior year $20 million non-cash fair value impairment of assets held for sale and lower revenues due to property sales partially offset by lower oil and gas operating expenses and lower employee costs.

Full Year 2018 Compared to Full Year 2017

Net loss from discontinued operations was $(6.9) million for the 12 months ended Dec. 31, 2018, compared to Net loss from discontinued operations of $(17) million for the same period in 2017. The variance is driven by lower revenues due to property sales and higher losses on sales of operating assets, partially offset by lower oil and gas operating expenses and lower employee costs. Current year depreciation expense is representative of the amortization of the remaining book value of accounting software. Depreciation and depletion expense was recorded under full cost accounting, which ceased Nov. 1, 2017 due to reclassification to assets held for sale.  There were no impairments during 2018 compared to a $20 million non-cash fair value impairment of assets held for sale in 2017.

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE: BKH) is a customer-focused, growth-oriented utility company with a tradition of improving life with energy and a vision to be the energy partner of choice. Based in Rapid City, South Dakota, the company serves 1.25 million natural gas and electric utility customers in eight states: Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. More information is available at www.blackhillscorp.com, www.blackhillscorp.com/corporateresponsibility and www.blackhillsenergy.com.

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This news release includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. This includes, without limitations, our 2019 and 2020 earnings guidance. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2017 Annual Report on Form 10-K and other reports that we file with the SEC from time to time, and the following:

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

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

(Minor differences may result due to rounding.)

^{(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.}

^{(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.}

^{(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.}

^{(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.}