EDGAR 10-K Filing

Company CIK: 1130464
Filing Year: 2021
Filename: 1130464_10-K_2021_0001130464-21-000007.json

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ITEM 1. BUSINESS
ITEMS 1 AND 2.BUSINESS AND PROPERTIES
History and Organization
Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota (incorporated in South Dakota in 1941).
We operate our business in the United States, reporting our operating results through our regulated Electric Utilities, regulated Gas Utilities, Power Generation and Mining segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Our Electric Utilities segment generates, transmits and distributes electricity to approximately 216,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 992 MW of generation and 8,892 miles of electric transmission and distribution lines.
Our Gas Utilities segment serves approximately 1,083,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate 4,774 miles of intrastate gas transmission pipelines and 41,838 miles of gas distribution mains and service lines, seven natural gas storage sites, nearly 49,000 horsepower of compression and over 560 miles of gathering lines.
Our Power Generation segment produces electric power from its wind, natural gas and coal-fired generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Mining segment produces coal at our mine near Gillette, Wyoming, and sells and delivers primarily under long-term contracts to adjacent mine-mouth electric generation facilities owned by our Electric Utilities and Power Generation businesses.
Electric Utilities
We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our retail customers. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services under the Service Guard Comfort Plan and Tech Services.
As of December 31,
Customers at End of Year 2020 2019 2018
Residential 184,872 183,232 181,459
Commercial 30,225 29,921 29,299
Industrial 83 83 84
Other 1,017 1,024 1,030
Total Electric Customers at End of Year 216,197 214,260 211,872
As of December 31,
Customers at End of Year 2020 2019 2018
Colorado Electric 98,735 97,890 96,645
South Dakota Electric 73,700 73,052 72,533
Wyoming Electric 43,762 43,318 42,694
Total Electric Customers at End of Year 216,197 214,260 211,872
Capacity and Demand. System peak demand for the Electric Utilities’ retail customers for each of the last three years are listed below:
System Peak Demand (in MW)
2020 2019 2018
Summer Winter Summer Winter Summer Winter
Colorado Electric 401 297 422 297 413 313
South Dakota Electric 378 304 335 320 355 314
Wyoming Electric 271 246 265 247 254 238
Regulated Power Plants. As of December 31, 2020, our Electric Utilities’ ownership interests in electric generating plants were as follows:
Unit Fuel
Type Location Ownership
Interest % (d)
Owned Capacity (MW) In Service Date
Colorado Electric:
Busch Ranch I (a)
Wind Pueblo, Colorado 50% 14.5 2012
Peak View (b)
Wind Pueblo, Colorado 100% 60.0 2016
Pueblo Airport Generation Gas Pueblo, Colorado 100% 180.0 2011
Pueblo Airport Generation CT Gas Pueblo, Colorado 100% 40.0 2016
AIP Diesel Oil Pueblo, Colorado 100% 10.0 2001
Diesel #1 and #3-5 Oil Pueblo, Colorado 100% 8.0 1964
Diesel #1-5 Oil Rocky Ford, Colorado 100% 10.0 1964
South Dakota Electric:
Cheyenne Prairie Gas Cheyenne, Wyoming 58% 55.0 2014
Corriedale (c)
Wind Cheyenne, Wyoming 62% 32.5 2020
Wygen III Coal Gillette, Wyoming 52% 57.2 2010
Neil Simpson II Coal Gillette, Wyoming 100% 90.0 1995
Wyodak Plant Coal Gillette, Wyoming 20% 72.4 1978
Neil Simpson CT Gas Gillette, Wyoming 100% 40.0 2000
Lange CT Gas Rapid City, South Dakota 100% 40.0 2002
Ben French Diesel #1-5 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
Wyoming Electric:
Cheyenne Prairie Gas Cheyenne, Wyoming 42% 40.0 2014
Cheyenne Prairie CT Gas Cheyenne, Wyoming 100% 37.0 2014
Corriedale (c)
Wind Cheyenne, Wyoming 38% 20.0 2020
Wygen II Coal Gillette, Wyoming 100% 95.0 2008
Total MW Capacity 991.6
________________________
(a) In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act.
(b) The Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning November 2016. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins.
(c) Corriedale was completed and placed in service on November 30, 2020. This facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning November 2020.
(d) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows:
Power Supply 2020 2019 2018
Coal 32.7 % 30.1 % 32.1 %
Natural Gas and Diesel Oil (a)
8.4 8.2 6.1
Wind 3.8 3.2 3.4
Total Generated 44.9 41.5 41.6
Coal, Natural Gas, Oil and Other Market Purchases 43.3 52.5 52.4
Wind 11.8 6.0 6.0
Total Purchased 55.1 58.5 58.4
Total 100.0 % 100.0 % 100.0 %
____________________
(a) The diesel-fueled generating units are generally used as supplemental peaking units. Power generated from these units, as a percentage of total power supply, was 0.2%, 0.1% and 0.0% for the years ended December 31, 2020, 2019, and 2018, respectively.
Our Electric Utilities’ weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 were as follows:
Fuel and Purchased Power (dollars per MWh) 2020 2019 2018
Coal $ 11.00 $ 11.46 $ 11.10
Natural Gas and Diesel Oil 21.67 28.26 34.07
Total Generated Weighted Average Fuel Cost 12.07 13.86 13.53
Coal, Natural Gas, Oil and Other Market Purchases 44.61 43.73 45.62
Wind Purchases 32.01 48.61 54.31
Total Purchased Power Weighted Average Cost 41.91 44.23 46.51
Total Weighted Average Fuel and Purchased Power Cost $ 28.52 $ 31.62 $ 32.79
Power Purchase and Power Sales Agreements. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Our Electric Utilities also have various long-term PSAs. Key contracts are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly operate an electric transmission system, referred to as the Common Use System, with Basin Electric Power Cooperative and Powder River Energy Corporation. Each participant in the Common Use System individually owns assets that are operated together for a single system. The Common Use System also provides transmission service to our Transmission Tie. South Dakota Electric owns 35% of the Transmission Tie. The Transmission Tie is further discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2020, our Electric Utilities owned the electric transmission and distribution lines shown below:
Utility State Transmission (a)
(in Line Miles)
Distribution
(in Line Miles)
Colorado Electric Colorado 572 3,135
South Dakota Electric South Dakota, Wyoming 1,242 2,565
Wyoming Electric Wyoming 58 1,320
1,872 7,020
____________________
(a) Electric transmission line miles include voltages of 69 kV and above.
Material transmission services agreements are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, cooling demand is often greater in the summer and heating demand in often greater in the winter.
Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas. Various legislative or regulatory restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, these initiatives have not had a material impact on our utilities. In Colorado, our electric utility is subject to rules which may require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated IPPs for the right to supply electric energy and capacity for Colorado Electric when resource plans require additional resources. Additionally, electrification initiatives in our service territories could increase demand for electricity and increase customer growth.
Rates and Regulation. Our Electric Utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate and the FERC for certain assets. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities.
The following table provides regulatory information for each of our Electric Utilities:
Subsidiary Jurisdic-tion Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Tariffed Mechanisms Percentage of Power Marketing Profit Shared with Customers
Colorado Electric (a)
CO 9.37% 7.43% 48%/52% $539.6 1/2017 ECA, TCA, PCCA, EECR/DSM, RESA 90%
CO 9.37% 6.02% 67%/33% $57.9 1/2017 Clean Air Clean Jobs Act Adjustment Rider N/A
South Dakota Electric WY 9.90% 8.13% 47%/53% $46.8 10/2014 ECA 65%
SD Global Settlement 7.76% Global Settlement $543.9 10/2014 ECA, TFA, EIA 70%
FERC 10.80% 8.76% 43%/57% $154.0 (b)
2/2009 FERC Transmission Tariff N/A
Wyoming Electric (a)
WY 9.90% 7.98% 46%/54% $376.8 10/2014 PCA, EECR/DSM, Rate Base Recovery on Acquisition Adjustment N/A
__________
(a) For both Colorado Electric and Wyoming Electric, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs.
(b) Includes $136.9 million in 2020 rate base for the 2020 Projected Common Use System formula rate that is updated annually and $17.1 million in rate base for the Transmission Tie that is based on the approved stated rate from 2005.
The regulatory provisions for recovering the costs to supply electricity vary by state. We have cost adjustment mechanisms for our Electric Utilities, subject to thresholds noted above, that allow us to pass the prudently-incurred cost of fuel and purchased power to customers. These mechanisms allow the utility operating in that state to collect, or refund the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate review. In addition, some states allow for recovery of new capital investment placed in service between base rate reviews through approved rider tariffs. These tariffs allow the utility a return on the investment.
A summary of mechanisms we have in place are shown in the table below:
Electric Utility Jurisdiction Cost Recovery Mechanisms
Environmental Cost Energy Efficiency Transmission Expense Fuel Cost Transmission Capital Purchased Power RESA
Colorado Electric þ þ þ þ þ þ
South Dakota Electric (SD) (a)
þ þ þ þ þ
South Dakota Electric (WY) þ þ þ þ
South Dakota Electric (FERC) (b)
þ
Wyoming Electric þ þ þ þ
__________
(a) South Dakota Electric’s Environmental Cost (EIA) and Transmission Capital (TFA) tariffs were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, South Dakota Electric received approval from the SDPUC to extend the 6-year moratorium period by an additional 3 years whereby these recovery mechanisms will not be effective prior to July 1, 2026. For additional information, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. On December 1, 2020, South Dakota Electric (SD) terminated its Energy Efficiency program.
(b) South Dakota Electric has an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.
Tariff Filings. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information regarding current electric regulatory activity.
Operating Statistics. See a summary of key operating statistics in the Electric Utilities segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Gas Utilities
We conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities transport and distribute natural gas through our distribution network to approximately 1,083,000 customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.
We also provide non-regulated services to our regulated customers. Black Hills Energy Services provides natural gas supply to approximately 52,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan, Tech Services and HomeServe.
As of December 31,
Customers at End of Year 2020 2019 2018
Residential 844,999 831,351 821,624
Commercial 83,135 82,912 82,498
Industrial 2,235 2,208 2,221
Transportation 152,568 149,971 147,550
Total Natural Gas Customers at End of Year 1,082,937 1,066,442 1,053,893
As of December 31,
Customers at End of Year 2020 2019 2018
Arkansas 178,281 174,447 171,978
Colorado 197,817 191,950 186,759
Iowa 160,952 159,641 158,485
Kansas 116,973 115,846 114,840
Nebraska 296,778 293,576 291,723
Wyoming 132,136 130,982 130,108
Total Natural Gas Customers at End of Year 1,082,937 1,066,442 1,053,893
We procure natural gas for our distribution customers from a diverse mix of producers, processors and marketers and generally use hedging, physical fixed-price purchases and market-based price purchases to achieve dollar-cost averaging within our natural gas portfolio. The majority of our procured natural gas is transported in interstate pipelines under firm transportation service agreements.
In addition to company-owned natural gas storage assets in Arkansas, Colorado and Wyoming, we also contract with third-party transportation providers for natural gas storage service to provide gas supply during the winter heating season and to meet peak day customer demand for natural gas.
The following table summarizes certain information regarding our regulated underground gas storage facilities as of December 31, 2020:
State Working Capacity (Mcf) Cushion Gas (Mcf) Total Capacity (Mcf) Maximum Daily Withdrawal Capability (Mcfd)
Arkansas 8,442,700 13,149,040 21,591,740 196,000
Colorado 2,360,895 6,165,315 8,526,210 30,000
Wyoming 5,733,900 17,145,600 22,879,500 36,000
Total 16,537,495 36,459,955 52,997,450 262,000
The following table summarizes certain information regarding our system infrastructure as of December 31, 2020:
State Intrastate Gas
Transmission Pipelines
(in line miles) Gas Distribution
Mains
(in line miles) Gas Distribution
Service Lines
(in line miles)
Arkansas 935 5,090 1,223
Colorado 693 6,879 2,618
Iowa 165 2,839 2,151
Kansas 330 2,961 1,366
Nebraska 1,312 8,739 3,252
Wyoming 1,339 3,495 1,225
Total 4,774 30,003 11,835
Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as market price. In particular, demand is often greater in the winter months for heating. Natural gas is used primarily for residential and commercial heating, so the demand for this product depends heavily upon weather throughout our service territories. As a result, a significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters. Demand for natural gas can also be impacted by summer temperatures and precipitation, which can affect demand for irrigation.
Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives are aimed at increasing competition. Additionally, electrification initiatives in our service territories could negatively impact demand for natural gas and decrease customer growth. To date, these initiatives have not had a material impact on our utilities. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial customers, in instances where independent marketers displace us as the seller of natural gas, we still collect a charge for transporting the gas through our distribution network.
Rates and Regulation. Our Gas Utilities are subject to the jurisdiction of the public utility commissions in the states where they operate. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities.
Our Gas Utilities are authorized to use natural gas cost recovery mechanisms allowing rate adjustments reflecting changes in the wholesale cost of natural gas and recovery of all the costs prudently incurred in purchasing gas for customers. In addition to natural gas cost recovery mechanisms, other recovery mechanisms, which vary by utility, allow us to recover certain costs or earn a return on capital investments, such as energy efficiency plan costs and system safety and integrity investments.
The following table provides regulatory information for each of our natural gas utilities:
Subsidiary Jurisdic-tion Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Tariffed Mechanisms
Arkansas Gas AR 9.61% 6.82% (a)
51%/49% $451.5 (b)
10/2018 GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas CO 9.20% 6.76% 50%/50% $231.2 7/2020 GCA, EECR/DSM
RMNG CO 9.90% 6.71% 53%/ 47% $118.7 6/2018 System Safety Integrity Rider, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas IA Global Settlement Global Settlement Global Settlement $109.2 2/2011 GCA, EECR, Capital Infrastructure Automatic Adjustment Mechanism, Farm Tap Tracker Adjustment, Gas Supply Optimization revenue sharing
Kansas Gas KS Global Settlement Global Settlement Global Settlement $127.9 1/2015 GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Pension Levelized Adjustment
Nebraska Gas (c) (d)
NE 9.50% 6.71% 50%/50% $504.2 3/2021 GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge, Choice Gas Program, System Safety and Integrity Rider, Bad Debt expense recovered through Choice Supplier Fee
Wyoming Gas (d)
WY 9.40% 6.98% 50%/50% $354.4 3/2020 GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program
__________
(a) Arkansas Gas return on rate base is adjusted to remove current liabilities from rate review capital structure for comparison with other subsidiaries.
(b) Arkansas Gas rate base is adjusted to include current liabilities for comparison with other subsidiaries.
(c) Information above reflects the NPSC order received on January 26, 2021. For additional information, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
(d) The Choice Gas Program mechanisms are applicable to only a portion of Nebraska Gas and Wyoming Gas customers.
All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate reviews. Some of the mechanisms we have in place include the following:
Gas Utility Jurisdiction Cost Recovery Mechanisms
DSM/Energy Efficiency Integrity Additions Bad Debt Weather Normal Pension Recovery Gas Cost Revenue Decoupling
Arkansas Gas þ þ þ þ þ
Colorado Gas þ þ
RMNG(a)
þ
Iowa Gas þ þ þ
Kansas Gas þ þ þ þ þ
Nebraska Gas þ þ þ
Wyoming Gas þ þ þ
__________
(a) RMNG, which is an intrastate transmission pipeline that provides natural gas transmission and wholesale services in western Colorado, has an SSIR recovery mechanism. The other cost recovery mechanisms are not applicable to RMNG.
Tariff Filings. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current natural gas regulatory activity.
Operating statistics. See a summary of key operating statistics in the Gas Utilities segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Utility Regulation Characteristics
State Renewable Energy Standards
Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. As of December 31, 2020, we were subject to the following renewable energy portfolio standards or objectives:
•Colorado. Colorado adopted a renewable energy standard in 2004 that has two components: (i) electric resource standards and (ii) a 2% maximum annual retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The net annual incremental retail rate impact for these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We have been and currently remain in compliance with these standards.
In 2019, the State of Colorado approved Senate Bill 236, which required qualified retail electric utilities (more than 500,000 customers) to submit a Clean Energy Plan to meet an 80% carbon reduction goal by 2030 based upon 2005 baseline levels. While Colorado Electric is not required to submit a Clean Energy Plan, the state also passed House Bill 1261 which established state-wide emission goals for greenhouse gas emitting activities that apply to Colorado Electric. Both House Bill 1261 and Senate Bill 236 include provisions that allow Colorado Electric to submit a voluntary Clean Energy Plan with a goal of 80% reduction by 2030. On January 7, 2021, Colorado Electric announced it will file a Clean Energy Plan with the CPUC voluntarily in 2022.
On September 23, 2020, Colorado Electric received approval from the CPUC for its preferred solar bid request in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy in Colorado by the end of 2023, which will contribute towards the aforementioned 80% carbon reduction goal by 2030. When Renewable Advantage comes online in 2023, more than half of Colorado Electric’s generation mix will be renewable sources, leading to an approximate 70% reduction in GHG emissions by 2024.
•South Dakota. South Dakota adopted a renewable portfolio objective in 2008 that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015.
•Wyoming. Wyoming currently has not issued a renewable energy portfolio standard.
In November 2020, we announced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. See more information in the Key Elements of our Business Strategy within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Federal Regulation
Energy Policy Act. The Energy Policy Act of 2005 included provisions to create an Electric Reliability Organization, which is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must maintain tariffs and rate schedules on file with FERC that govern the rates, and terms and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates. Our public Electric Utilities’ subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.
Our Electric Utilities and Power Generation entities are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, each files Electric Quarterly Reports with FERC. Our Electric Utilities own and operate FERC-jurisdictional interstate transmission facilities and provide open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC’s regulations.
The Federal Power Act authorizes FERC to certify and oversee a national electric reliability organization with authority to promulgate and enforce mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified NERC as the electric reliability organization. NERC has promulgated mandatory reliability standards and NERC, in conjunction with regional reliability organizations that operate under FERC’s and NERC’s authority and oversight, enforces those mandatory reliability standards.
PUHCA 2005. PUHCA 2005 gives FERC authority with respect to the books and records of a utility holding company. As a utility holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and also a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.
Power Generation
Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops, constructs and operates our non-regulated power plants. As of December 31, 2020, we held varying interests in independent power plants with a total net ownership of 423 MW.
We produce electric power from our generating facilities and sell the electric capacity and energy, primarily to affiliates under a combination of mid- to long-term contracts, which mitigates the impacts of volatility in future power prices and fluctuations in demand.
As of December 31, 2020, the power plant ownership interests held by our Power Generation segment include:
Power Plants Fuel Type Location Ownership
Interest % (d)
Owned Capacity (MW) In Service Date
Wygen I Coal Gillette, Wyoming 76.5% 68.9 2003
Pueblo Airport Generation (a)
Gas Pueblo, Colorado 50.1% 200.0 2012
Busch Ranch I (b)
Wind Pueblo, Colorado 50.0% 14.5 2012
Busch Ranch II (c)
Wind Pueblo, Colorado 100.0% 60.0 2019
Top of Iowa (c)
Wind Joice, Iowa 100.0% 80.0 2019
423.4
_________________________
(a) In 2016, Black Hills Electric Generation sold a 49.9% noncontrolling interest in Black Hills Colorado IPP to a third party. See Note 14 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
(b) In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act.
(c) The Busch Ranch II and Top of Iowa facilities qualify for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date each facility was originally placed in service.
(d) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Power Sales Agreements and Operating Agreements. Our Power Generation facilities have various mid- to long-term power sales agreements and operating agreements. Key contracts are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess.
With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for IPPs in some regions. To date, these initiatives have not had a material impact on our Power Generation segment.
The Energy Policy Act of 1992 and Public Utility Holding Company Act of 2005 (PUHCA 2005). PUHCA 2005 reiterated the definition and benefits of Exempt Wholesale Generator (EWG) status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, operating or both owning and operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with three EWGs, Wygen I, Pueblo Airport Generating and Top of Iowa. Each of these three EWG’s have been granted market-based rate authority.
Operating statistics. See a summary of key operating statistics in the Power Generation segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Mining
Our Mining segment operates a single coal mine through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River Basin. We produced approximately 3.7 million tons of coal in 2020.
During our surface mining operations, we strip and store the topsoil. We then remove the overburden (earth and rock covering the coal) with heavy equipment. Removal of the overburden typically requires drilling and blasting. Once the coal is exposed, we drill, fracture and systematically remove it, using front-end loaders and conveyors to transport the coal to the mine-mouth generating facilities. We reclaim disturbed areas as part of our normal mining activities by back-filling the pit with overburden removed during the mining process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life in accordance with our approved post-mining topography plan.
In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, has trended upwards over the last fifteen years. However, the overburden ratio at December 31, 2020 was 2.17 which decreased from 2.30 in the prior year as we mined in areas with lower overburden. We expect our stripping ratio to increase to approximately 2.27 by the end of 2021 as we mine in areas with higher overburden.
Mining rights to the reserves are based on three federal leases and one state lease. The federal leases expire between March 31, 2021 and September 30, 2025 and the state lease expires on August 1, 2023. The duration of the leases varies; however, the lease terms generally are extended to the exhaustion of economically recoverable reserves, as long as active mining continues. The federal lease expiring March 31, 2021 relates to an area we are no longer mining and will not be renewed. The Biden Administration recently issued an executive order that suspends new oil and gas leases on federal lands and eliminates fossil fuel subsidies. However, this moratorium does not apply to federal mining leases and we have not received federal subsidies.
We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, 2020, we estimated our recoverable reserves to be approximately 182 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable reserve life is equal to approximately 49 years at the current production levels. Our recoverable reserve estimates are periodically updated to reflect past production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable reserves include reserves that can be economically and legally extracted at the time of their determination.
Substantially all of the mine’s production is currently sold under contracts to:
•South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons each year. This contract is for the life of the plant;
•Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons each year. This contract is for the life of the plant;
•The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons each year, subject to adjustments for planned outages and other contract terms. This contract expires December 31, 2022 and negotiations to extend the contract are ongoing. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages and other contract terms;
•The 110 MW Wygen III power plant jointly owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons each year;
•The 90 MW Wygen I power plant jointly owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons each year; and
•Certain regional industrial customers served by truck to which we sell a total of approximately 300,000 tons each year. These contracts have terms of one to five years.
Our Mining segment sells coal to South Dakota Electric and Wyoming Electric for all of their requirements under cost-based agreements that regulate earnings from these affiliate sales to a specified return on our mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above Moody’s A-Rated Utility Bond Index applied to our Mining investment base.
The price of unprocessed coal sold to PacifiCorp for the Wyodak Plant is determined by the supply agreement described above. The agreement included a price adjustment in 2019. The price adjustment essentially allowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment was based on market price plus considerations for the avoided costs of rail transportation and an unloading facility, which PacifiCorp would have to incur if it purchased from another mine. In addition, the agreement also provided for the monthly escalation of price based on an escalation factor.
In October 2019, negotiations were completed for the price re-opener in the contract with the Wyodak Plant. The new price was
reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton. The current contract price is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of an unloading facility (approximately 30% of current price); and 3) a rolling 12-month average of the Coal Daily spot market price of 8,400 Btu Powder River Basin coal (approximately 50% of current price).
WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement through June 30, 2038. Currently, this agreement uses a base price that includes price escalators and quality adjustments and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated Utility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. Effective January 1, 2022, in conjunction with the new Wygen I 60 MW PPA, WRDC’s current coal supply agreement will be revised using pricing that will be cost-based to regulate earnings to a specified return on the cost-depreciated investment base. For additional information regarding the new Wygen I 60 MW PPA, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Competition. Our strategy is to sell the majority of our production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, any off-site sales have been to consumers within close proximity to the WRDC mine. Rail transport market opportunities for WRDC are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC mine is served by only one railroad, resulting in less competitive transportation rates.
Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental and availability considerations affect the overall demand for coal as a fuel.
Environmental Matters. We are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. See Environmental Matters section for further information.
Mine Reclamation. Reclamation is completed during production and after mining has finished. Under applicable law, we must submit applications to, and receive approval from, the Wyoming Department of Environmental Quality for any mining and reclamation plans that provide for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC mine is permitted to operate under a five-year mining permit issued by the State of Wyoming. In 2016, that five-year permit was re-issued and we are currently in the process of renewing this permit. Based on extensive reclamation studies, we have accrued approximately $13 million for reclamation costs as of December 31, 2020. See additional information in Note 7 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Operating statistics. See a summary of key operating statistics in the Mining segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Environmental Matters
In November 2020, we announced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. See more information in Key Elements of our Business Strategy within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Environmental Management System (EMS). We operate an EMS that is composed of environmental policies and procedures, voluntary initiatives, objectives and annual targets, operational controls, training, a sophisticated task scheduling/tracking and document control system, and a continuous improvement process. The program attained Colorado’s highest level in their Environmental Leadership Program (Gold Level status in 2014) and has continued this status through 2020.
Methane Rules (Greenhouse Gas Emissions). The EPA and the State of Colorado have implemented strict regulatory requirements on hydrocarbon and methane emissions associated with natural gas gathering and transmission systems. Presently, we have facilities in our natural gas transmission operations affected by the methane reduction rules.
Our operations are in compliance with both EPA and State of Colorado rules. Future modifications to our gathering and transmissions systems are anticipated to trigger EPA methane rules that we will adhere to. We developed a corporate-wide methane control strategy to address GHG emissions. As a proactive measure in reducing methane emissions beyond current regulatory requirements, we have entered into the EPA’s Methane Challenge Program. This is a voluntary program founded by the EPA in collaboration with oil and natural gas companies that recognizes companies that make specific and transparent commitments to reduce methane emissions.
Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for SO2, NOx and opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.
We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut down the power plant if we anticipate the emission limit will be exceeded. There have been limited instances of the trip logic mechanism being used and we experienced zero exceedances during 2020.
Regional Haze (Impacts to the Wyodak Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas. The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed PacifiCorp to install low-NOx burners in the Wyodak Plant, of which South Dakota Electric owns 20%. The EPA did not agree with the State of Wyoming’s determination, overruled it in a Federal Implementation Plan (FIP) and proposed a Selective Catalytic Reactor to be installed to control NOx emissions. This would cost South Dakota Electric approximately $27 million due to its 20% ownership of the Wyodak Plant. PacifiCorp and the State of Wyoming challenged the EPA’s determination. Prior to proceeding to court, PacifiCorp and the EPA reached a verbal agreement on December 16, 2020, to limit operating hours and determined that low-NOx burners would be considered appropriate to control NOx emissions. This proposed agreement was published in the Federal Register, but remains in the public comment period until March 1, 2021. The final agreement must be published in the Federal Register and approved in Wyoming’s State Implementation Plan through the rule making process.
Mining. Operations at the WRDC mine must regularly address issues related to the proximity of the mine disturbance boundary to the City of Gillette and to residential properties. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential areas. Specific concerns could include damage to wells, fugitive dust emissions, vibration and an emissions cloud from blasting. The mine makes every effort to reduce these impacts by monitoring blasts, modifying blast techniques to reduce blast vibration, applying dust suppression controls on roads and reclaiming lands to reduce windblown dust.
Former Manufactured Gas Plants (FMGP). Federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. As of December 31, 2020, our Gas Utilities have two active FMGP sites, which are located in Council Bluffs, Iowa, and McCook, Nebraska. At the Council Bluffs site, the EPA issued an order for the responsible parties to proceed with an Engineering Evaluation and Cost Analysis (EECA) to clean up the site. Three viable Potential Responsible Parties (PRP) continue to deny their legal attachment to the site. The Company will continue conducting the EECA and anticipates pursuing the PRP’s through legal action. There is currently no action being taken at the McCook, Nebraska site. A third-party initially indicated they intend to manage and pay for the clean-up at this site. However, after further investigation, the third-party assessed they owned the property after the gas plant ceased operations. We expect to conduct an assessment to determine viable PRPs.
For additional information, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Affordable Clean Energy Rule. The EPA was directed to repeal, revise and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy (ACE) rule. This rule focused on heat-rate improvements on coal-fired boiler units and applied only to our coal-fired plants. The Company’s coal-fired plants subject to the rule had implemented or planned to implement a majority of the efficiency requirements listed in the rule. On January 19, 2021, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule. The court remanded the regulation regarding carbon dioxide emissions from existing power plants back to the EPA for reconsideration. Currently, there is no rule governing power plant GHG emissions and it is uncertain when a new rule will be promulgated.
OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because ash is used for backfill reclamation in areas previously mined. The Office of Surface Mining (OSM) was considering CCR rules that would apply to the mine, but these rules were not proposed during the Trump administration. We will continue to monitor to see if the Biden administration pursues these rules.
Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Other Properties
In addition to the properties previously disclosed in the sections above, we own or lease several facilities throughout our service territories including a corporate headquarters building and various office, service center, storage, shop and warehouse space. Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.
Human Capital Resources
Overview
Black Hills Corporation is committed to supporting operational excellence by attracting, motivating, retaining and encouraging the development of highly qualified employees. Our employees’ drive and dedication to their work, and their commitment to the safety of our customers and their fellow employees, allows Black Hills Corporation to successfully grow and manage our business year over year. The impacts of COVID-19 to our businesses and employees are discussed in the Company Highlights within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Our Team As of December 31, 2020
Total employees 3,011
Gender diversity (women as a % of total employees) 26%
Women in executive leadership positions (a)
31%
Ethnic diversity (non-white employees as a % of total) 11%
Military veterans 16%
Represented by a union 25%
For the year ended December 31, 2020
Number of external hires 299
External hires gender diversity (as a % of total external hires) 29%
External hires ethnic diversity (as a % of total external hires) 16%
Turnover rate (b)
8%
Retirement rate 3%
__________
(a) Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.
(b) Includes voluntary and involuntary separations, but excludes internships.
Total Employees
Number of Employees
At December 31, 2020
Electric Utilities 379
Gas Utilities 1,237
Power Generation and Mining 60
Corporate and Other 1,335
Total 3,011
At December 31, 2020, approximately 21% of our total employees and 23% of our Electric and Gas Utilities employees were eligible for regular (age 65 with at least 5 years of service) or early (ages 55 to 64 with at least 5 years of service) retirement.
Collective Bargaining Agreements
At December 31, 2020, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining agreements as shown in the table below. We have not experienced any labor stoppages in decades.
Utility Number of Employees Union Affiliation Expiration Date of Collective Bargaining Agreement
Colorado Electric 95 IBEW Local 667 April 15, 2023
South Dakota Electric 137 IBEW Local 1250 March 31, 2022
Wyoming Electric 26 IBEW Local 111 June 30, 2024
Total Electric Utilities 258
Iowa Gas 121 IBEW Local 204 January 31, 2026
Kansas Gas 17 Communications Workers of America, AFL-CIO Local 6407 December 31, 2024
Nebraska Gas 100 IBEW Local 244 March 13, 2022
Nebraska Gas 147 CWA Local 7476 October 30, 2023
Wyoming Gas 15 IBEW Local 111 June 30, 2024
Wyoming Gas 84 CWA Local 7476 October 30, 2023
Total Gas Utilities 484
Total 742
Attraction
Continuous attraction of qualified team members is critical to our ability to serve our 1.3 million customers safely and efficiently. We actively recruit diverse candidates and continuously evaluate our interviewing and hiring practices to ensure equitable pay and processes. Our attraction efforts include the use of multiple nation-wide job boards, local college and high school outreach programs, a strong college internship program and participation in national and local job fairs. Another key area of attraction is our commitment to our military personnel and veterans. We have targeted attraction efforts specific to military personnel transitioning into civilian life and for veterans of all types.
Diversity & Inclusion
At Black Hills Corporation, we believe in the benefits of diversity, equity and inclusion. We believe that a diverse workforce will assist us in achieving our goals of becoming the safest utility in the nation, providing exceptional customer service and achieving new levels of growth in a rapidly evolving industry. Workforce diversity trends, including diverse new hires, promotions and turnover, are monitored at regular intervals.
Development and Retention
Retaining and developing team members is critical to our continued success. Our retention efforts include competitive compensation programs, career development resources for all employees and internal training programs. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant. Our career development resources include management onboarding, leadership development programs, mentoring programs, individual development assessments and more. Internal training opportunities include corporate-wide trainings such as our code of conduct and specialized training opportunities for different job functions. Our Field Career Path Program (FCPP) promotes career growth through established standards of knowledge, skills, abilities and performance.

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ITEM 1A. RISK FACTORS
ITEM 1A.RISK FACTORS
The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business operations, financial condition, results of operations or cash flows are described below. These risk factors, along with other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.
STRATEGIC RISKS
Our continued success is dependent on execution of our strategic business plans including our growth strategy.
Our success depends, in significant part, on our ability to execute our strategic business plans, including our growth strategy. Our plans and strategy include reducing GHG emissions for our Electric Utilities and Gas Utilities, transforming the customer experience, growing our electric and natural gas customer load, pursuing operating efficiencies and modernizing our utility infrastructure. Our current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, changing political, business or regulatory conditions, and technology advancements.
In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business plans. The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that include, but are not limited to: weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, availability of materials, governmental approvals and permitting, regulatory cost recovery and return on investment.
An inability to successfully and timely adapt to changing conditions and execute our strategic plans, including our growth strategy could materially affect our financial operating results including earnings, cash flow and liquidity.
Customer growth and usage in our service territories may fluctuate with economic conditions, emerging technologies or responses to price increases.
Our financial operating results are impacted by energy demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.
REGULATORY, LEGISLATIVE AND LEGAL RISKS
We may be subject to future laws, regulations, or actions associated with climate change, including those relating to fossil-fuel generation and GHG emissions, which could increase our operating costs or restrict our market opportunities.
We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase, store and deliver natural gas to our customers. These business activities are subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.
There is uncertainty surrounding climate regulation due to legal challenges to some current regulations and anticipated new federal and/or state climate legislation and regulation. The Biden administration has issued executive orders aimed at reducing GHG emissions and declared climate change a national security policy for the first time. 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 capacity reductions of coal-fired power generation facilities and potential increased production from our combined cycle natural gas-fired generating units. Increased rules and regulations associated with fossil fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution, generation and natural gas storage facilities or our coal mine. Further, these rules could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial condition or cash flows.
Future GHG constraints designed to minimize emissions from natural gas could likewise result in increased costs and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas. Certain cities in our operational footprint are focused on electrification and have adopted initiatives to prohibit the construction of new natural gas distribution facilities. Any such initiatives and legislation could have a material impact on our results of operations, financial condition and cash flows.
We may be subject to unfavorable or untimely federal and state regulatory outcomes.
Our regulated Electric and Gas Utilities are subject to cost-of-service/rate-of-return regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our customer rates are regulated by either the FERC or the respective state utility regulatory authority based on an analysis of our costs and investments, as reviewed and approved in a regulatory proceeding. 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 our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full or timely recovery of our costs and the allowed return on invested capital. In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic, political, legislative, public perception and regulatory pressures and adversely impact results of operations, financial condition and cash flows.
Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs or integrity capital investments) outside of a base rate review in order to stabilize customer rates and reduce regulatory lag. If regulators decide to discontinue these tariff-based recovery mechanisms, it could negatively impact results of operations, financial condition and cash flows.
Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e. SO2, NOx, volatile organic compounds, particulate matter and GHG), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure or inability to comply with evolving environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.
Our business segments may not be successful in recovering increased capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on our business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.
Legislative and regulatory requirements may lead to increased costs and result in compliance penalties.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, SEC and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.
Municipal governments may seek to limit or deny our franchise privileges.
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. We regularly engage in negotiations on renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot initiatives on franchise renewals. To date, we have been successful in resolving or defending each of these challenges. 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. We also cannot quantify the impact that such action would have on the remainder of our business operations.
Changes in Federal tax law may significantly impact our business.
We are subject to taxation by the various taxing authorities at the federal, state and local levels where we do business. Similar to the TCJA, sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to U.S. corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which the effect of a change in corporate tax rate will impact our utility customers and the time period over which the impact will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.
OPERATING RISKS
Our financial performance depends on the successful operation of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities, and a coal mine.
The risks associated with management of these operations include:
•Inherent dangers. Electricity and natural gas can be dangerous to employees and the general public. Failures of or contact with power lines, natural gas pipelines or service facilities and equipment may result in fires, explosions, property damage and personal injuries, including death. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance;
•Weather, natural conditions and disasters. Severe weather events, such as snow and ice storms, fires, tornadoes, strong winds, significant thunderstorms, flooding and drought, could negatively impact operations, including our ability to provide energy safely, reliably and profitably and our ability to complete construction, expansion or refurbishment of facilities as planned;
•Acts of sabotage, terrorism or other malicious attacks. Damage to our facilities due to deliberate acts could lead to outages or other adverse effects;
•Operating hazards. Operating hazards such as leaks, mechanical problems and accidents, including fires or explosions could impact employee and public safety, reliability and customer confidence;
•Equipment and processes. Breakdown or failure of equipment or processes, unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations;
•Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver utility services and satisfy our contractual obligations may be hindered;
•Natural gas supply for generation and distribution. Our regulated utilities and non-regulated entities purchase natural gas from a number of suppliers for our generating facilities and for distribution to our customers. Our results of operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations;
•Replacement power. The cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities could negatively impact our results of operations;
•Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate
and our results of operations;
•Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and contractual agreements, including those that restrict the timing of generation plant scheduled outages, could negatively impact our results of operations;
•Increased costs. Increased capital and operating costs to comply with increasingly stringent laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;
•Labor and labor relations. The cost of recruiting and retaining skilled technical labor or the unavailability of such resources could have a negative impact on our operations. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2020, approximately 23% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk; approximately 25% of our employees are represented by unions;
•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses; and
The ongoing operation of our business involves the risks described above, in addition to risks associated with threats to our overall business model, such as electrification initiatives. Any of these risks could cause us to experience negative financial results and damage to our reputation and public confidence. These risks could cause us to incur significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance and obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.
Cyberattacks, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations, or lead to a loss or misuse of confidential and proprietary information.
To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cyberattacks, terrorism or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or gas operations. Attacks targeting other key technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and associated revenues, as well as significant expense to repair damages and remedy security breaches. In addition, any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.
We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. Despite our implementation of security measures and safeguards, all of our technology systems may still be vulnerable to disability, failures or unauthorized access.
Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.
Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. Unusually mild summers and winters, therefore, could have an adverse effect on our financial operating results, including earnings, cash flow and liquidity.
FINANCIAL RISKS
A sub-investment grade credit rating could impact our ability to access capital markets.
Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms, if at all. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through existing regulatory rate structures and contracts with customers.
Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result in material financial losses.
We use various financial and physical derivatives, including futures, forwards, options and swaps to manage commodity price and interest rate risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. For Black Hills Energy Services under the Choice Gas Program, and in certain instances within our regulated Utilities where unrealized and realized gains and losses from derivative instruments are not approved for regulatory accounting treatment, fluctuating commodity prices may cause fluctuations in reported financial results due to mark-to-market accounting treatment.
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.
Additionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are unable to meet these requirements, this could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. Further, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.
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 to the holding company because these subsidiaries depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 9 of our Notes to Consolidated Financial Statements 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, pay dividends 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.
A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, 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.
We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.
Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers. Additionally insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which the Company may be subject, including liability and losses associated with wildfire, natural gas and gas storage field explosions, cyber-security breaches, environmental hazards and natural disasters.
Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement benefit plans.
Assumptions related to interest rates, expected return on investments, mortality and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow and liquidity.
Costs associated with our healthcare plans and other benefits could increase significantly.
The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have required, and likely will continue to require, changes to our current employee benefit plans and supporting administrative processes. 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 is no assurance that the state utility commissions will allow recovery of these increased costs. The rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results including earnings, cash flow, or liquidity.
PANDEMIC RISK
Our business operations, results of operations, financial condition and cash flows could be adversely affected by the coronavirus (COVID-19) pandemic.
We have responded to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.
For the year ended December 31, 2020, the COVID-19 pandemic had a limited net financial impact on our business operations, financial condition and cash flows. In particular, we experienced:
•Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;
•Increased costs due to sequestration of mission-critical and essential employees;
•Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;
•Waived customer late payment fees;
•Reduced availability of our employees;
•Increased costs for personal protection equipment and cleaning supplies;
•Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;
•Minimal impacts to the availability of our contractors;
•Minimal decline in the funded status of our pension plan;
•Minimal interest expense increase due to disruptions in the Commercial Paper markets; and
•Reduced training, travel, and outside services related expenses.
Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business operations, financial condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:
•Adverse impacts on our strategic business plans, growth strategy and capital investments;
•Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;
•Further reduction in the availability of our employees and contractors;
•Increased costs as a result of our preventative measures, such as sequestration of essential employees and facility cleaning services;
•Increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;
•Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;
•Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;
•Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;
•Impairment of goodwill or long-lived assets;
•Adverse impacts on our ability to construct and operate facilities;
•Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;
•Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;
•Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;
•Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets; and
•Delays in our ability to change rates through regulatory proceedings.
To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our results of operations, financial condition and cash flows.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3.LEGAL PROCEEDINGS
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 3, “Commitments, Contingencies and Guarantees”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 of this Annual Report.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Linden R. Evans, age 58, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer - Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 19 years of experience with the Company.
Scott A. Buchholz, age 59, has been our Senior Vice President of Strategic Initiatives since July 2020. He served as Senior Vice President - Chief Information Officer from the closing of the Aquila Transaction in 2008 to 2020. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 40 years of experience with the Company, including 28 years with Aquila. Mr. Buchholz plans to retire on March 8, 2021.
Brian G. Iverson, age 58, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26, 2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February 1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 17 years of experience with the Company.
Richard W. Kinzley, age 55, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 21 years of experience with the Company.
Jennifer C. Landis, age 46, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 19 years of experience with the Company.
Stuart Wevik, age 59, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 35 years of experience with the Company.
Erik Keller, age 57, joined the Company as Senior Vice President and Chief Information Officer on July 27, 2020. Prior to joining the company, he was an Information Technology consultant to Ontic Inc., a global provider of parts and services for legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation support and aftermarket services provider, from February 2012 to January 2020.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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 January 31, 2021, we had 3,537 common shareholders of record and 46,737 beneficial owners, representing all 50 states, the District of Columbia and 6 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 27, 2021 meeting, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend rate of $2.26 per share. This equivalent rate, if declared and paid in 2021, will represent 51 consecutive years of annual dividend increases.
For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
UNREGISTERED SECURITIES ISSUED
There were no unregistered securities sold during 2020.
ISSUER PURCHASES OF EQUITY SECURITIES
The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2020:
Period Total Number of Shares Purchased (a)
Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2020 - October 31, 2020 1 $ 53.95 - -
November 1, 2020 - November 30, 2020 804 58.63 - -
December 1, 2020 - December 31, 2020 7,569 59.66 - -
Total 8,374 $ 59.56 - -
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(a) Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6.SELECTED FINANCIAL DATA
We have early adopted the new SEC amendments to modernize, simplify, and enhance certain financial disclosure requirements in Regulation S-K which, among other things, eliminates the requirement to present Selected Financial Data.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. We conduct our business operations through four reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company’s Electric Utilities are supported by our Power Generation and Mining segments, which are mostly contracted to company affiliates and subject to utility-like regulation and oversight. The Power Generation segment produces electric power from its five generating facilities and sells most of the electric capacity and energy to our Electric Utilities under mid- and long-term contracts. The Mining segment, consisting of a single coal mine near Gillette, Wyoming, sells nearly all production to fuel the five on-site, mine-mouth power generation facilities. With more than 90% of the Company’s assets directly invested in its regulated utility businesses and the Power Generation and Mining segments supporting its electric utilities mainly through long-term contracts, the Company considers itself a domestic, pure-play electric and natural gas utility company.
The Company has provided energy and served customers for 137 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe energy and being strong environmental stewards. Our strategy today continues that emphasis on serving customers and being responsive to the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. Customers and other stakeholders are demanding cleaner energy solutions to address concerns around carbon emissions. In this rapidly changing energy environment, we are Ready to serve.
Our strategy focuses on improving the way we serve customers with safe, reliable, affordable and cleaner energy while improving the lives of the customers and communities we serve. Our emphasis is on consistently outperforming utility industry averages in key safety metrics; transforming the customer experience; growing our electric and natural gas customer load; pursuing operating efficiencies; and modernizing utility infrastructure. These areas of focus will present the company with significant investment needs as we modernize our infrastructure systems, meet customer growth and fulfill customer expectations for cleaner energy services. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective interactions.
Key Elements of our Business Strategy
Modernize, replace and operate utility infrastructure to meet our customers’ energy needs while providing safe, reliable, affordable and cleaner energy. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that spans nearly 1,600 miles of the United States. Our Electric Utilities own and operate 992 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate 47,000 miles of natural gas transmission and distribution pipelines. A key strategic focus is to modernize this utility infrastructure to meet customers’ and communities’ varied energy needs, ensure the continued delivery of safe, reliable and affordable energy and reduce GHG emission intensity. In addition, we invest in the accessibility, capacity and integrity of our systems to meet customer growth.
We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas Utilities to systematically and proactively replace aging infrastructure on a system-wide basis. To meet our electric customers’ continued expectations of high levels of reliability, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and replacement of aging infrastructure. Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas. Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame. We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace aging infrastructure through programs that prioritize safety and reliability for our customers. All but one of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.
As of December 31, 2020, we estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual 2020 and forecasted capital expenditures and depreciation for the next five years from 2021 through 2025 are as follows (in millions):
Actual Forecasted
Capital Expenditures By Segment (a) :
2020 2021 2022 2023 2024 2025
(in millions)
Electric Utilities $ 271 $ 240 $ 180 $ 143 $ 156 $ 154
Gas Utilities 449 377 347 339 330 326
Power Generation 9 10 9 6 4 5
Mining 8 9 9 9 9 10
Corporate and Other 18 11 5 13 13 13
Total $ 755 $ 647 $ 550 $ 510 $ 512 $ 508
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(a) Includes accruals for property, plant and equipment as disclosed as supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K.
Efficiently plan, construct and operate rate base power generation facilities to serve our Electric Utilities. We believe that we best serve customers and communities with a vertically integrated business model for our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.
Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs, efficiency in converting fuel into energy, low per unit operating and maintenance costs and high levels of power plant availability. For our coal-fired power plants, we leverage our mine-mouth location advantage to eliminate coal transportation costs that often represent the largest component of the delivered cost of coal for many other utilities. Additionally, we operate our plants with high levels of availability as compared to industry benchmarks.
We continue to believe that ownership of power generation facilities by our Electric Utilities best serves customers. Rate-based generation assets offer several advantages for customers and shareholders, including:
•When 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; especially when compared to power otherwise purchased from the open market through wholesale contracts that are periodically re-priced to reflect current and varying market conditions;
•Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;
•The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital; and
•Investors are provided a long-term and stable return on their investment.
Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities of 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are based on existing technology and computed from 2005 baseline levels of GHG emissions intensity for our electric operations and natural gas distribution system. Since 2005, we have reduced GHG emissions intensity from our Gas Utilities by more than 33% and achieved a 25% reduction from our Electric Utilities. Colorado Electric has achieved an approximate 50% reduction in GHG emissions since 2005 and is on track to reach Colorado’s 80% carbon reduction goal by 2030. Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values.
More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest, we created the Renewable Ready program for South Dakota and Wyoming customers. In support of this program, we created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental agency customer requests for renewable energy resources. To meet the renewable energy commitments under the new tariffs, on November 30, 2020, we completed construction and placed into service the Corriedale wind project, a 52.5 MW wind energy project near Cheyenne, Wyoming. Supporting our renewable energy efforts in Colorado, in September 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program, which plans to add up to 200 MW of renewable energy by the end of 2023.
To date, many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emission reduction targets. Federal legislation for renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reliable and affordable sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and 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.
Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be an important provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy 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 for shareholders over the long-term than we would by selling energy into more volatile energy 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 minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.
Vertically integrate businesses that are supportive of our Electric and Gas Utility businesses. While our primary focus is serving customers and growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate power generation and mining assets that are vertically integrated into and support our Electric Utilities. These operations are located at our utility-generating complexes and are physically integrated into our Electric Utilities’ operations.
The Power Generation segment currently owns five power facilities, four of which are contracted with our affiliate Electric Utilities under mid- to long-term power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 22 generation projects since 1995 with an aggregate investment in excess of $2.5 billion. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. In certain states, our Electric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs.
Our small surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where all five of our remaining coal-fired power plants are located. We operate and own majority interests in four of the five power plants. We own 20% of the fifth power plant which is operated by a majority owner. The mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to other coal-fired and natural gas-fired generating facilities. Nearly all of the mine’s production is sold to the five on-site, mine-mouth generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.
Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. 2020 represented our 50th consecutive year of increasing dividends. In January 2021, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend of $2.26 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.
Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining 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 predominately on regulated utilities, provides growth opportunities, yet avoids concentrating business risk. We expect much of our earnings growth in the next few years will come from the need for capital deployment at our utilities and continued focus on improving efficiencies and controlling costs. 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. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our company highlights discussed below.
Company Highlights
February 2021 Weather Event
In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. Although this historic weather and energy demand event strained energy resources across the United States, our natural gas and electric systems performed as expected and demonstrated our Ready to Serve commitment to our customers. Our ongoing system investments in safety and reliability and our strong operational performance were essential in our ability to maintain service for our customers during this extraordinary event.
We responded to this event with requests for certain natural gas customer usage curtailments that began on February 12, 2021, and extended through February 19, 2021, to ensure the reliability of our system. We also communicated to all customers on how to conserve energy and stay safe during this event. Our customer service representatives worked extended hours to provide guidance and support to our customers.
Our Utilities have regulatory mechanisms to recover the increased energy costs from this record-breaking cold weather event. However, given the extraordinary impact of these higher costs to our customers, we expect our regulators to undertake a heightened review. We are engaged with our regulators to identify appropriate recovery periods over which to recover costs associated with this event as we continue to address the impacts to our customers’ bills.
As a result of this historic event, our natural gas purchases increased by approximately $600 million compared to forecasted base load for the month of February. This amount is a preliminary estimate through February 24, 2021, and does not include certain pipeline transportation charges that remain subject to settlement and are payable in late March 2021. To fund February natural gas purchases and pipeline transportation charges and provide additional liquidity, we entered into an $800 million term loan maturing on November 23, 2021. The nine-month term loan has no prepayment penalty and is subject to the same covenants as our Revolving Credit Facility. We expect to repay a portion of this term loan prior to maturity and refinance the remaining portion in longer-term debt.
As of February 24, 2021, the Company had $1.3 billion of liquidity consisting of approximately $800 million of cash and $500 million of available capacity on its Revolving Credit Facility.
COVID-19 Pandemic
One of the Company’s core values is safety. The COVID-19 pandemic has given us an opportunity to demonstrate our commitment to the health and safety of our customers, employees, business partners and the communities we serve. We have executed our business continuity plans across all of our jurisdictions with the goal of continuing to provide safe and reliable service during the COVID-19 pandemic.
For the year ended December 31, 2020, we have experienced limited impacts to our financial results and operational activities due to COVID-19. Negative impacts to gross margins were driven primarily by lower volumes in certain commercial and industrial customers and waived customer late payment fees which were partially offset by higher residential usage. Increased operations and maintenance expenses due to sequestration costs of mission critical and essential employees and increased bad debt expense were partially offset by decreased training, travel, and outside services related expenses.
We continue to closely monitor customer loads in our states as updated executive orders and recommendations associated with COVID-19 are provided. We have continued to proactively communicate with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We have increased our allowance for credit losses and bad debt expense by $3.3 million for the year ended December 31, 2020, after considering the potential economic impact of the COVID-19 pandemic in forward looking projections related to write-off and recovery rates. All of our jurisdictions temporarily suspended disconnections for a period of time. State orders lifting those restrictions have been issued in nearly all of our jurisdictions; however, we expect the status of restrictions will continue to fluctuate for the next several months. We continue to monitor customer loads, accounts receivable arrears balances, disconnects, cash flows and bad debt expense. We are proactively working with customers to establish payment plans and find available payment assistance resources.
Throughout 2020, we maintained adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in equity to support its 2020 capital investment program. In June 2020, the Company issued $400 million of long-term debt which was used to repay short-term debt and for working capital and general corporate purposes. For the year ended December 31, 2020, the Company also utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. As of December 31, 2020, the Company had $498 million of liquidity which included $6.4 million of cash and $491 million of available capacity on its Revolving Credit Facility. We continue to meet our debt covenant requirements. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the year ended December 31, 2020.
We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts from COVID-19 on supply chains including the availability of supplies, materials and lead times. Capital projects are ongoing without material disruption to schedules due to COVID-19. Our third party resources continue to support our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a significant impact from COVID-19 on our capital investment plan for 2021.
We continue to work closely with local health, public safety and government officials to minimize the spread of COVID-19 and its impact to our employees and the services we provide to our customers. Actions the Company took earlier in the year included implementing protocols for our field operations personnel to safely and effectively interact with our customers, asking certain employees to work from home, requiring employees to complete daily health assessments, covering 100% of COVID-19 testing costs for our active employee medical plans, limiting travel to only mission-critical purposes and temporarily sequestering essential employees.
During the third quarter of 2020, we suspended sequestration of essential employees but continued to monitor the impacts of COVID-19 in our service territories to ensure we provide reliable service to our customers. Additionally, we implemented our Ready2Return program, which includes a phased return of our employees to our work facilities while keeping our workforce healthy, safe and informed. Our Ready2Return program also focuses on enhancing our facility readiness to improve ventilation, ensure social distancing and establish cleaning services to reduce the spread of infection.
On January 13, 2021, the FERC sent a letter to the Centers for Disease Control and Prevention’s (CDC) Advisory Committee on Immunization Practices urging that essential employees of the energy workforce receive vaccines earlier than currently recommended. We continue to monitor guidance from the CDC to ensure our essential employees may receive the vaccine within a prioritized phase.
We provide periodic status updates and maintain ongoing dialogue with the regulatory commissions in our jurisdictions. We have worked with regulators in our service territories to preserve our right for deferred regulatory treatment for certain COVID-19 related costs and to seek recovery of these costs at a later date.
During these uncertain times, we remain highly focused on the safety and health of our customers, employees, business partners and communities. We continue to monitor load, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of resources to execute our plans and the capital markets to ensure we have the liquidity necessary to support our financial needs.
As we look forward to 2021 and beyond, our operating results could be further affected by COVID-19, as discussed in detail in our Risk Factors.
Business Segment Highlights and Corporate Activity
Electric Utilities
•On November 30, 2020, South Dakota Electric and Wyoming Electric completed and placed in service the Corriedale project. The 52.5 MW wind project is jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers under the Renewable Ready program.
•On October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years.
•On September 23, 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy in Colorado by the end of 2023.
•On July 10, 2020, Wyoming Electric set a new all-time peak load of 271 MW, surpassing the previous peak of 265 MW set in July 2019.
•On May 5, 2020, citizens in Pueblo, Colorado voted overwhelmingly to retain Colorado Electric as its electric utility provider by 75.6% of votes cast. The current franchise agreement continues through 2030.
Gas Utilities
•On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates will be enacted on March 1, 2021 and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism for consolidated utility alignment.
•On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On January 6, 2021 the CPUC issued an order dismissing the rate review. On January 26, 2021, Colorado Gas filed an application for rehearing, reargument or reconsideration in response to the Commission’s January 6 order.
On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety and integrity focused investments in its system over five years. A decision from the CPUC is expected by mid-2021.
•On December 27, 2020, gas service to approximately 3,500 Colorado Gas customers in Aspen, Colorado was disrupted due to vandalism. Gas services were restored to nearly all customers by December 30, 2020 with the remaining few restored by January 1, 2021. Colorado Gas employees were joined by Black Hills Energy technicians from other states, as well as contractors and other utilities, to successfully restore service despite challenging weather, temperatures, additional precautions due to COVID-19 and significant travel by many to reach Aspen.
•On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the new system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020.
•On March 1, 2020, Wyoming Gas enacted new rates and implemented a new rider to recover integrity investments. The new, single statewide rate structure successfully completed the consolidation process of four natural gas utilities in the state and is expected to generate $13 million in new annual revenues. Going forward, the new rate structure and consolidated tariffs will contribute to improvements in customer service and reduce the complexity and number of rate reviews and other regulatory filings.
Power Generation
•On October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Black Hills Wyoming and Wyoming Electric on August 2, 2019 for approval of a new 60 MW PPA. See additional information in the Electric Utilities Segment highlights above.
Corporate and Other
•On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date.
•On June 17, 2020, we completed a public debt offering of $400 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 2.50%, 10-year senior notes due June 15, 2030. The proceeds were used to repay short-term debt, as well as for working capital and general corporate purposes.
•On February 27, 2020, we issued 1.2 million shares of common stock at a price of $81.77 per share for net proceeds of $99 million.
Results of Operations
Our discussion and analysis for the year ended December 31, 2020 compared to 2019 is included herein. For discussion and analysis for the year ended December 31, 2019 compared to 2018, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on February 14, 2020.
Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.
Consolidated Summary and Overview
For the Years Ended December 31,
2020 2019 2018
(in thousands)
Adjusted operating income (a) :
Electric Utilities $ 156,055 $ 160,297 $ 155,869
Gas Utilities 215,889 189,971 185,239
Power Generation 42,112 44,779 42,614
Mining 12,807 12,627 16,340
Corporate and Other 1,440 (1,632) (3,025)
Operating Income 428,303 406,042 397,037
Interest expense, net (143,470) (137,659) (139,975)
Impairment of investment (6,859) (19,741) -
Other income (expense), net (2,293) (5,740) (1,180)
Income tax benefit (expense) (32,918) (29,580) 23,667
Income from continuing operations 242,763 213,322 279,549
(Loss) from discontinued operations, net of tax - - (6,887)
Net income 242,763 213,322 272,662
Net income attributable to noncontrolling interest (15,155) (14,012) (14,220)
Net income available for common stock $ 227,608 $ 199,310 $ 258,442
Earnings per share from continuing operations, Diluted $ 3.65 $ 3.28 $ 4.78
(Loss) per share from discontinued operations, Diluted - - (0.12)
Total earnings per share of common stock, Diluted $ 3.65 $ 3.28 $ 4.66
_____________
(a) Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.
2020 Compared to 2019
The variance to the prior year included the following:
•COVID-19 related impacts to consolidated results included $3.6 million of lower gross margin driven primarily by lower volumes and waived customer late payment fees, $2.6 million of costs due to sequestration of essential employees and $3.3 million of additional bad debt expense which were partially offset by $3.8 million of lower travel, training, and outside services related expenses;
•Electric Utilities’ adjusted operating income decreased $4.2 million due to higher depreciation and amortization expense as a result of additional plant placed in service, lower commercial and industrial demand and COVID-19 impacts partially offset by benefits from the release of TCJA revenue reserves and increased rider revenues;
•Gas Utilities’ adjusted operating income increased $26 million primarily due to new customer rates in Wyoming and Nebraska and increased rider revenues, customer growth, mark-to-market gains on non-utility natural gas commodity contracts and prior year amortization of excess deferred income taxes partially offset by higher depreciation and amortization expense as a result of additional plant placed in service, COVID-19 impacts and unfavorable weather;
•Power Generation’s adjusted operating income decreased $2.7 million primarily due to higher depreciation and maintenance expense from new wind assets and expense related to the early retirement of certain assets;
•Corporate and Other expenses decreased $3.1 million primarily due to lower unallocated employee costs;
•A $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a privately held oil and gas company compared to a similar $20 million impairment in 2019;
•Interest expense increased $5.8 million primarily due to higher debt balances partially offset by lower rates;
•Other expense decreased $3.4 million due to the prior year expensing of $5.4 million of development costs related to projects we no longer intend to construct partially offset by increased current year pension non-service costs; and
•Increased tax expense of $3.3 million primarily due to higher pre-tax income partially offset by a lower effective tax rate.
Segment Operating Results
A discussion of operating results from our business segments follows.
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 and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.
Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases 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 measures. 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):
2020 Variance 2019 Variance 2018
Revenue $ 714,044 $ 1,292 $ 712,752 $ 1,301 $ 711,451
Total fuel and purchased power 267,045 (1,252) 268,297 (15,543) 283,840
Gross margin (non-GAAP) 446,999 2,544 444,455 16,844 427,611
Operations and maintenance 196,794 1,213 195,581 9,406 186,175
Depreciation and amortization 94,150 5,573 88,577 3,010 85,567
Total operating expenses 290,944 6,786 284,158 12,416 271,742
Adjusted operating income $ 156,055 $ (4,242) $ 160,297 $ 4,428 $ 155,869
2020 Compared to 2019
Gross margin increased over the prior year as a result of:
(in millions)
Release of TCJA revenue reserves (a)
$ 2.7
Rider recovery and true-up (b)
2.3
Transmission services 1.4
Residential customer growth 0.9
Lower commercial and industrial demand (2.7)
COVID-19 impacts (c)
(1.8)
Weather (0.3)
Total increase in Gross margin (non-GAAP) $ 2.5
____________________
(a) In July 2020, regulatory proceedings resolved the last of the Company's open dockets seeking approval of its TCJA plans. As a result, the Company reversed certain TCJA-related liabilities, which resulted in an increase to Gross margin of $2.7 million. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
(b) Gross margin increased due to $3.5 million of rider revenues, which was partially offset by a $1.2 million rider true-up.
(c) The impacts to Electric Utilities’ gross margin from COVID-19 were primarily driven by reduced commercial volumes and waived customer late payment fees partially offset by higher residential usage.
Operations and maintenance expense increased primarily due to COVID-19 impacts which included $2.2 million of expenses related to the sequestration of essential employees and $0.8 million of additional bad debt expense which were partially offset by $1.2 million of lower travel, training and outside services related expenses. Additionally, lower employee costs of $1.9 million were partially offset by $1.0 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures.
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
Operating Statistics
Electric Revenue (in thousands) Quantities Sold (MWh)
For the year ended December 31, 2020 2019 2018 2020 2019 2018
Residential $ 221,530 $ 216,108 $ 218,558 1,477,514 1,440,551 1,450,585
Commercial 239,166 246,704 250,894 1,974,043 2,055,253 2,034,917
Industrial 131,154 131,831 124,668 1,794,795 1,787,412 1,682,074
Municipal 16,860 17,206 17,871 158,222 157,298 160,913
Subtotal Retail Revenue - Electric 608,710 611,849 611,991 5,404,574 5,440,514 5,328,489
Contract Wholesale (a)
17,847 19,078 33,688 492,637 368,360 900,854
Off-system/Power Marketing Wholesale 24,308 25,622 24,800 648,928 701,633 673,994
Other 63,179 56,203 40,972 - - -
Total Revenue and Energy Sold 714,044 712,752 711,451 6,546,139 6,510,507 6,903,337
Other Uses, Losses or Generation, net (b)
- - - 400,826 393,573 470,250
Total Revenue and Energy 714,044 712,752 711,451 6,946,965 6,904,080 7,373,587
Less cost of fuel and purchased power 267,045 268,297 283,840
Gross Margin (non-GAAP) $ 446,999 $ 444,455 $ 427,611
Electric Revenue (in thousands) Gross Margin (non-GAAP)
(in thousands)
Quantities Sold (MWh) (b)
For the year ended
December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018
Colorado Electric $ 253,229 $ 247,332 $ 251,218 $ 139,731 $ 137,323 $ 138,901 2,379,866 2,180,985 2,151,918
South Dakota Electric (a)
283,153 291,219 298,080 220,456 218,104 205,194 2,563,387 2,798,887 3,360,396
Wyoming Electric 177,662 174,201 162,153 86,812 89,028 83,516 2,003,712 1,924,208 1,861,273
Total Revenue, Gross Margin (non-GAAP), and Quantities Sold $ 714,044 $ 712,752 $ 711,451 $ 446,999 $ 444,455 $ 427,611 6,946,965 6,904,080 7,373,587
________________
(a) 2020 and 2019 revenue and purchased power, as well as associated quantities, for certain wholesale contracts have been presented on a net basis. 2018 amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.
(b) Includes company uses, line losses, and excess exchange production.
For the year ended December 31,
Quantities Generated and Purchased by Fuel Type (MWh) 2020 2019 2018
Generated:
Coal 2,273,635 2,226,028 2,368,506
Natural Gas and Oil 581,554 600,002 446,373
Wind 261,400 238,999 253,180
Total Generated 3,116,589 3,065,029 3,068,059
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases (a)
3,235,086 3,576,394 4,134,145
Wind 595,290 262,657 171,383
Total Purchased 3,830,376 3,839,051 4,305,528
Total Generated and Purchased 6,946,965 6,904,080 7,373,587
For the year ended December 31,
Quantities Generated and Purchased (MWh) 2020 2019 2018
Generated:
Colorado Electric 364,058 443,770 481,446
South Dakota Electric 1,901,009 1,768,456 1,734,222
Wyoming Electric 851,522 852,803 852,391
Total Generated 3,116,589 3,065,029 3,068,059
Purchased:
Colorado Electric 2,015,808 1,737,215 1,670,472
South Dakota Electric (a)
662,378 1,030,431 1,626,174
Wyoming Electric 1,152,190 1,071,405 1,008,882
Total Purchased 3,830,376 3,839,051 4,305,528
Total Generated and Purchased 6,946,965 6,904,080 7,373,587
____________________
(a) 2020 and 2019 purchased power quantities for a wholesale contract have been presented on a net basis. 2018 amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.
For the year ended December 31,
Degree Days 2020 2019 2018
Actual Variance from Normal Actual Variance from Normal Actual Variance from Normal
Heating Degree Days:
Colorado Electric 5,103 (9)% 5,453 (3)% 5,119 4%
South Dakota Electric 6,910 (3)% 8,284 16% 7,749 8%
Wyoming Electric 6,771 (5)% 7,406 1% 7,036 (7)%
Combined (a)
6,056 (6)% 6,813 5% 6,405 3%
Cooling Degree Days:
Colorado Electric 1,384 54% 1,226 37% 1,420 58%
South Dakota Electric 682 7% 404 (36)% 488 (23)%
Wyoming Electric 594 71% 462 33% 430 24%
Combined (a)
985 41% 791 14% 902 29%
________________
(a) The combined degree days are calculated based on a weighted average of total customers by state.
For the year ended December 31,
Contracted generating facilities availability by fuel type(a)
2020 2019 2018
Coal 94.1% 92.1% 93.9%
Natural gas and diesel oil (b)
80.6% 87.9% 96.4%
Wind 98.1% 95.6% 96.9%
Total availability 87.0% 89.9% 95.6%
Wind capacity factor 38.9% 38.7% 39.2%
____________________
(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2020 included a planned outage at Cheyenne Prairie and unplanned outages at Pueblo Airport Generation and Lange CT. 2019 included planned outages at Neil Simpson CT and Lange CT.
Gas Utilities
Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):
2020 Variance 2019 Variance 2018
Revenue:
Natural gas - regulated $ 900,637 $ (31,474) $ 932,111 $ (10,813) $ 942,924
Other - non-regulated services 74,033 (3,886) 77,919 (4,464) 82,383
Total revenue 974,670 (35,360) 1,010,030 (15,277) 1,025,307
Cost of natural gas sold:
Natural gas - regulated 347,611 (59,032) 406,643 (35,887) 442,530
Other - non-regulated services 7,034 (12,221) 19,255 (368) 19,623
Total cost of sales 354,645 (71,253) 425,898 (36,255) 462,153
Gross margin (non-GAAP) 620,025 35,893 584,132 20,978 563,154
Operations and maintenance 303,577 1,733 301,844 10,363 291,481
Depreciation and amortization 100,559 8,242 92,317 5,883 86,434
Total operating expenses 404,136 9,975 394,161 16,246 377,915
Adjusted operating income $ 215,889 $ 25,918 $ 189,971 $ 4,732 $ 185,239
2020 Compared to 2019
Gross margin increased over the prior year as a result of:
(in millions)
New rates $ 25.4
Customer growth - distribution 5.6
Mark-to-market on non-utility natural gas commodity contracts 3.3
Prior year amortization of excess deferred income taxes 2.6
Weather (1.8)
COVID-19 impacts (a)
(1.8)
Other 2.6
Total increase in Gross margin (non-GAAP) $ 35.9
____________________
(a) The impacts to Gas Utilities’ gross margin from COVID-19 were primarily driven by reduced volumes from certain transport customers and waived customer late payment fees.
Operations and maintenance expense increased primarily due to higher property taxes due to a higher asset base driven by prior and current year capital expenditures. Lower employee costs were mostly offset by various other current year expenses. COVID-19 impacts to operations and maintenance expense included $2.5 million of additional bad debt expense which was partially offset by $2.4 million of lower travel, training, and outside services related expenses.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.
Operating Statistics
Revenue (in thousands) Gross Margin (non-GAAP)
(in thousands)
Quantities Sold and Transported (Dth)
For the year ended December 31, For the year ended December 31, For the year ended December 31,
2020 2019 2018 2020 2019 2018 2020 2019 2018
Residential $ 527,518 $ 551,701 $ 567,785 $ 298,707 $ 285,802 $ 276,858 61,962,171 66,956,080 65,352,164
Commercial 193,017 212,229 214,718 89,590 88,264 82,529 28,784,319 32,241,441 30,753,361
Industrial 24,014 24,832 26,466 8,670 8,053 7,056 6,881,354 6,548,023 6,309,211
Other 582 (1,361) (7,899) 582 (1,361) (7,899) - - -
Total Distribution 745,131 787,401 801,070 397,549 380,758 358,544 97,627,844 105,745,544 102,414,736
Transportation and Transmission 155,506 144,710 141,854 155,477 144,710 141,850 149,062,476 153,101,264 148,299,003
Total Regulated 900,637 932,111 942,924 553,026 525,468 500,394 246,690,320 258,846,808 250,713,739
Non-regulated Services 74,033 77,919 82,383 66,999 58,664 62,760 - - -
Total Revenue, Gross Margin (non-GAAP) and Quantities Sold $ 974,670 $ 1,010,030 $ 1,025,307 $ 620,025 $ 584,132 $ 563,154 246,690,320 258,846,808 250,713,739
Revenue (in thousands) Gross Margin (non-GAAP)
(in thousands)
Quantities Sold and Transported (Dth)
For the year ended December 31, For the year ended December 31, For the year ended December 31,
2020 2019 2018 2020 2019 2018 2020 2019 2018
Arkansas $ 184,849 $ 185,201 $ 176,660 $ 127,720 $ 115,899 $ 100,917 28,572,621 30,496,243 30,931,390
Colorado 186,085 199,369 188,002 106,749 106,776 99,851 32,077,083 33,908,529 29,857,063
Iowa 137,982 151,619 161,843 69,528 70,290 68,384 36,824,548 41,795,729 40,668,682
Kansas 101,118 105,906 112,306 60,586 58,020 55,226 33,732,897 32,650,854 31,387,672
Nebraska 246,381 255,622 278,969 169,311 155,901 164,513 80,202,783 81,481,192 81,658,938
Wyoming 118,255 112,313 107,527 86,131 77,246 74,263 35,280,388 38,514,261 36,209,994
Total Revenue, Gross Margin (non-GAAP) and Quantities Sold $ 974,670 $ 1,010,030 $ 1,025,307 $ 620,025 $ 584,132 $ 563,154 246,690,320 258,846,808 250,713,739
For the year ended December 31,
2020 2019 2018
Heating Degree Days: Actual Variance From
Normal Actual Variance From Normal Actual Variance From Normal
Arkansas (a)
3,442 (15)% 3,897 (4)% 4,169 3%
Colorado 6,068 (8)% 6,672 1% 6,136 (7)%
Iowa 6,504 (4)% 7,200 6% 7,192 6%
Kansas (a)
4,648 (5)% 5,190 6% 5,242 7%
Nebraska 5,853 (5)% 6,578 7% 6,563 6%
Wyoming 7,289 (4)% 8,010 7% 7,425 (1)%
Combined (b)
6,038 (6)% 6,840 5% 6,628 2%
________________
(a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.
(b) The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.
Power Generation
Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):
2020 Variance 2019 Variance 2018
Revenue $ 105,047 $ 3,789 $ 101,258 $ 8,807 $ 92,451
Total fuel 8,993 (66) 9,059 467 8,592
Operations and maintenance 33,695 5,266 28,429 3,294 25,135
Depreciation and amortization 20,247 1,256 18,991 2,881 16,110
Total operating expenses 62,935 6,456 56,479 6,642 49,837
Adjusted operating income $ 42,112 $ (2,667) $ 44,779 $ 2,165 $ 42,614
2020 Compared to 2019
Revenue increased in the current year due to increased wind megawatt hours sold primarily driven by Busch Ranch II, additional Black Hills Colorado IPP fired-engine hours and higher power sales agreement prices and volumes. Operating expenses increased in the current year primarily due to a $3.1 million expense related to the early retirement of certain assets and higher depreciation and maintenance expense from new wind assets. COVID-19 impacts included $0.4 million of expenses related to the sequestration of essential employees which were mostly offset by lower travel and training expenses.
Operating Statistics
Revenue (in thousands) Quantities Sold (MWh) (a)
For the year ended December 31, 2020 2019 2018 2020 2019 2018
Black Hills Colorado IPP $ 57,057 $ 55,191 $ 55,331 1,076,819 935,997 1,000,577
Black Hills Wyoming 42,464 41,822 36,978 633,389 629,788 582,938
Black Hills Electric Generation 5,526 4,245 142 353,559 167,296 5,873
Total Revenue and Quantities Sold $ 105,047 $ 101,258 $ 92,451 2,063,767 1,733,081 1,589,388
____________________
(a) Company use and losses are not included in the quantities sold.
For the year ended December 31,
Quantities Generated and Purchased (MWh) (a)
Fuel Type 2020 2019 2018
Generated:
Black Hills Colorado IPP Natural Gas 1,076,819 935,997 1,000,577
Black Hills Wyoming Coal 551,136 557,119 501,945
Black Hills Electric Generation Wind 353,559 167,296 5,873
Total Generated 1,981,514 1,660,412 1,508,395
Purchased:
Black Hills Wyoming (b)
Various 82,525 74,199 83,213
Total Generated and Purchased 82,525 74,199 83,213
____________________
(a) Company use and losses are not included in the quantities generated and purchased.
(b) Under the 20-year economy energy PSA (discussed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K) with the City of Gillette, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.
For the year ended December 31,
Contracted generating facilities availability by fuel type (a)
2020 2019 2018
Coal 95.4% 94.5% 85.8%
Natural gas 99.5% 98.6% 99.4%
Wind 92.8% 90.6% N/A
Total availability 96.4% 95.0% 95.9%
Wind capacity factor 26.6% 23.5% N/A
___________
(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.
Mining
Mining operating results for the years ended December 31 were as follows (in thousands):
2020 Variance 2019 Variance 2018
Revenue $ 61,075 $ (554) $ 61,629 $ (6,404) $ 68,033
Operations and maintenance 39,033 (999) 40,032 (3,696) 43,728
Depreciation, depletion and amortization 9,235 265 8,970 1,005 7,965
Total operating expenses 48,268 (734) 49,002 (2,691) 51,693
Adjusted operating income $ 12,807 $ 180 $ 12,627 $ (3,713) $ 16,340
2020 Compared to 2019
Adjusted operating income was comparable to the prior year.
Operating Statistics
For the year ended December 31, 2020 2019 2018
Tons of coal sold 3,737 3,716 4,085
Cubic yards of overburden moved 8,120 8,534 8,970
Coal reserves at year-end (in tons) 181,711 185,448 189,164
Revenue per ton $ 15.67 $ 15.94 $ 16.11
Corporate and Other
Corporate and Other operating results for the years ended December 31 were as follows (in thousands):
(in thousands) 2020 Variance 2019 Variance 2018
Adjusted operating income (loss) $ 1,440 $ 3,072 $ (1,632) $ 1,393 $ (3,025)
2020 Compared to 2019
The variance in Adjusted operating income (loss) was primarily due to lower unallocated employee costs.
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
(in thousands) 2020 Variance 2019 Variance 2018
Interest expense, net $ (143,470) $ (5,811) $ (137,659) $ 2,316 $ (139,975)
Impairment of investment (6,859) 12,882 (19,741) (19,741) -
Other income (expense), net (2,293) 3,447 (5,740) (4,560) (1,180)
Income tax benefit (expense) (32,918) (3,338) (29,580) (53,247) 23,667
2020 Compared to 2019
Interest Expense
The increase in Interest expense, net was driven by higher debt balances partially offset by lower interest rates.
Impairment of Investment
In the current year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company, compared to a $20 million write-down in the prior year. The impairments in both years were triggered by continued adverse natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas exploration and production activities. See Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
Other Income (Expense)
The variance in Other income (expense), net was due to the prior year expensing of $5.4 million of development costs related to projects we no longer intend to construct which was partially offset by higher current year non-service defined benefit plan costs primarily driven by lower discount rates.
Income Tax Benefit (Expense)
For the year ended December 31, 2020, the effective tax rate was 11.9% compared to 12.2% in 2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and one-time research and development tax credits partially offset by a prior year tax benefit from a federal tax loss carry-back claim including interest. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
Liquidity and Capital Resources
OVERVIEW
Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, five-year Revolving Credit Facility, CP Program, ATM and ability to access the public and private capital markets through debt and equity securities offerings when necessary. 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.
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, as well as during the construction season which typically peaks in spring and summer.
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, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
In response to the February 2021 weather event and the COVID-19 pandemic, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Company Highlights above.
The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
Financial Position Summary 2020 2019
Cash and cash equivalents $ 6,356 $ 9,777
Restricted cash and equivalents $ 4,383 $ 3,881
Notes payable $ 234,040 $ 349,500
Current maturities of long-term debt $ 8,436 $ 5,743
Long-term debt (a)
$ 3,528,100 $ 3,140,096
Stockholders’ equity $ 2,561,385 $ 2,362,123
Ratios
Long-term debt ratio 58 % 57 %
Total debt ratio 60 % 60 %
______________
(a) Carrying amount of long-term debt is net of deferred financing costs.
CASH FLOW ACTIVITIES
The following table summarizes our cash flows for the years ended December 31 (in thousands):
2020 2019 2018
Cash provided by (used in)
Operating activities $ 541,863 $ 505,513 $ 488,811
Investing activities $ (761,664) $ (816,210) $ (465,849)
Financing activities $ 216,882 $ 300,210 $ (17,057)
2020 Compared to 2019
Operating Activities:
Net cash provided by operating activities was $36 million higher than in 2019. The variance to the prior year was primarily attributable to:
•Cash earnings (income from continuing operations plus non-cash adjustments) were $20 million higher than prior year driven primarily by higher operating income at our Gas Utilities;
•Net inflows from changes in certain operating assets and liabilities were $18 million higher than prior year, primarily attributable to:
•Cash inflows decreased by approximately $18 million primarily as a result of changes in accounts receivable and other current assets driven by warmer weather, lower commodity prices and COVID-19 related impacts;
•Cash outflows decreased by approximately $60 million as a result of changes in accounts payable and other current liabilities driven by the impact of lower commodity prices, deferral of payroll taxes under the CARES Act and other working capital requirements; and
•Cash outflows increased by approximately $24 million primarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery and returns for fuel costs adjustments partially offset by the TCJA tax rate change that was returned to customers in the prior year.
•Cash inflows decreased $1.3 million for other operating activities.
Investing Activities:
Net cash used in investing activities was $55 million lower than in 2019. This variance to the prior year was primarily attributable to:
•Capital expenditures of approximately $767 million in 2020 compared to $818 million in 2019. Higher prior year expenditures were driven by large projects such as the Natural Bridge pipeline project, the Busch Ranch II wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota to Stegall, Nebraska. The current year capital expenditures included the Corriedale wind project.
•Cash inflows increased $3.6 million for other investing activities.
Financing Activities:
Net cash provided by financing activities was $83 million lower than in 2019. This variance to the prior year was primarily attributable to:
•Cash inflows decreased $82 million due to maturities and repayments of long and short-term debt in excess of issuances;
•Cash outflows increased $11 million due to increased dividends paid on common stock; and
•Cash outflows decreased by $9.7 million for other financing activities primarily driven by lower current year financing costs incurred in the June 17, 2020 debt transaction compared to prior year financing costs incurred in the June 17, 2019 and October 3, 2019 debt transactions.
CAPITAL SOURCES
Revolving Credit Facility and CP Program
We have a $750 million Revolving Credit Facility that matures on July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. We also have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million.
The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
The Revolving Credit Facility contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to 1) make timely payments of debt obligations; or 2) triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permit the acceleration of debt maturities or mandatory debt prepayment.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
Current Short-term borrowings at Letters of Credit (a) at
Available Capacity at
Credit Facility Expiration Capacity December 31, 2020 December 31, 2020 December 31, 2020
Revolving Credit Facility and CP Program July 30, 2023 $ 750 $ 234 $ 25 $ 491
__________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit. For more information on these letters of credit, see Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
The weighted average interest rate on short-term borrowings at December 31, 2020 was 0.27%. Short-term borrowing activity for the year ended December 31, 2020 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances) $ 366
Average amount outstanding (based on daily outstanding balances) $ 193
Weighted average interest rate 0.90 %
See Note 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our Revolving Credit Facility and CP Program.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may, at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates. While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
Long-term Debt
Our Long-term debt and associated interest payments due by year are shown below (in thousands). For more information on our long-term debt, see Note 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Payments Due by Period
2021 2022 2023 2024 2025 Thereafter Total
Principal payments on Long-term debt including current maturities (a)
$ 8,436 $ - $ 525,000 $ - $ - $ 3,035,000 $ 3,568,436
Interest payments on Long-term debt (a)
141,561 141,547 141,547 119,235 119,235 1,209,188 1,872,313
__________
(a)Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2020.
Covenant Requirements
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of December 31, 2020. See additional information in Note 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K
Equity
Shelf Registration
We have a shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2023. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2020, we had approximately 63 million shares of common stock outstanding and no shares of preferred stock outstanding.
ATM
Our ATM allows us to sell shares of our common stock with an aggregate value of up to $400 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. In 2020, we did not issue any shares of common stock under the ATM.
For additional information regarding equity, see Note 10 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Future Financing Plans
We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2021, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of common stock under the ATM. As discussed in the Company Highlights above, on February 24, 2021, we entered into an $800 million term loan maturing on November 23, 2021. We expect to repay a portion of this term loan prior to maturity and refinance the remaining portion in longer-term debt.
CREDIT RATINGS
Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. We note that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2020:
Rating Agency Senior Unsecured Rating Outlook
S&P (a)
BBB+ Stable
Moody’s (b)
Baa2 Stable
Fitch (c)
BBB+ Stable
__________
(a) On April 10, 2020, S&P reported BBB+ rating and maintained a Stable outlook.
(b) On December 21, 2020, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c) On August 20, 2020, Fitch reported BBB+ rating and maintained a Stable outlook.
Certain fees and interest rates under our Revolving Credit Facility are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgrades our senior unsecured debt, we will be required to pay higher fees and interest rates under our Revolving Credit Facility.
The following table represents the credit ratings of South Dakota Electric at December 31, 2020:
Rating Agency Senior Secured Rating
S&P (a)
A
Moody’s (b)
A1
Fitch (c)
A
__________
(a) On April 16, 2020, S&P reported A rating.
(b) On December 21, 2020, Moody’s reported A1 rating.
(c) On August 20, 2020, Fitch reported A rating.
We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.
CAPITAL REQUIREMENTS
Capital Expenditures
Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity benefiting customers that may be included in utility rate base and eligible to be recovered from our utility customers with regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
As discussed in the Company Highlights above, there have been limited impacts from COVID-19 on our capital investment plan and we do not anticipate a significant impact in 2021.
Our capital expenditures for the three years ended December 31 were as follows (in thousands):
2020 2019 2018
Capital Expenditures By Segment (a) :
Electric Utilities $ 271,104 $ 222,911 $ 152,524
Gas Utilities 449,209 512,366 288,438
Power Generation 9,329 85,346 30,945
Mining 8,250 8,430 18,794
Corporate and Other 17,500 20,702 11,723
Capital expenditures before discontinued operations 755,392 849,755 502,424
Discontinued operations - - 2,402
Total capital expenditures $ 755,392 $ 849,755 $ 504,826
____________________________
(a) Includes accruals for property, plant and equipment as disclosed as supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K.
Unconditional Purchase Obligations
We have unconditional purchase obligations which include the energy and capacity costs associated with our PPAs, transmission services agreements, and natural gas capacity, transportation and storage agreements. Additionally, our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. For additional information. see Note 3 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Defined Benefit Pension Plan
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the plan is $40 million as of December 31, 2020 compared to $51 million as of December 31, 2019. We do not have required 2021 contributions and currently do not expect to contribute to our Pension Plan. See further information in Note 15 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-Ks.
Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.
Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
On January 27, 2021, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend rate of $2.26 per share. The table below provides our dividends paid (in thousands), dividend payout ratio and dividends paid per share for the three years ended December 31:
2020 2019 2018
Common Stock Dividends Paid $ 135,439 $ 124,647 $ 106,591
Dividend Payout Ratio 60 % 63% 40%
Dividends Per Share $ 2.17 $ 2.05 $ 1.93
Our three-year compound annualized dividend growth rate was 6.2% and all dividends were paid out of available operating cash flows.
Collateral Requirements
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 2020, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. The cash collateral we were required to post at December 31, 2020 was not material. For the year ended December 31, 2020, we did not experience any requests to post additional collateral, including for concerns over a potential deterioration of our financial condition due to COVID-19.
Guarantees
We provide various guarantees, which represent off-balance sheet commitments, supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Critical Accounting Policies Involving Significant 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. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities and contingent liabilities. 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.
Regulation
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions 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.
Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory 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.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state regulatory commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs.
As of December 31, 2020 and 2019, we had total regulatory assets of $278 million and $271 million, respectively, and total regulatory liabilities of $533 million and $537 million, respectively. See Note 2 of the Notes to Consolidated Financial Statements for further information.
Goodwill
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with our financial planning process.
Accounting standards for testing goodwill for impairment require the application of either a qualitative or quantitative assessment to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Under either the qualitative or quantitative assessment, the estimated fair value of a reporting unit is compared with its carrying amount, including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit.
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 the Chief Operating Decision Maker (CODM) 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; 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. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed as of October 1, 2020. 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 investments through rider mechanisms and rate reviews. 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 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 the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years ended December 31, 2020, 2019, and 2018, there were no impairment losses recorded. At December 31, 2020, the fair value substantially exceeded the carrying value at all reporting units.
As described in Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, prospectively on January 1, 2020.
Pension and Other Postretirement Benefits
As described in Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A VEBA trust for the funded portion of the post-retirement healthcare plan has also been established.
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and 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.
Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company uses a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.
The 2021 pension benefit cost for our non-contributory funded pension plan is expected to be $0.5 million compared to $4 million in 2020. The decrease in the expected 2021 pension benefit cost is driven primarily by favorable asset returns partially offset by a decrease in the discount rate.
The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
December 31,
Assumptions Percentage Change 2020
Increase/(Decrease)
PBO/APBO (a)
Increase/(Decrease) Expense - Pretax
Pension
Discount rate (b)
+/- 0.5 (30,334)/33,326 (3,162)/3,743
Expected return on assets +/- 0.5 N/A (2,367)/2,372
OPEB
Discount rate (b)
+/- 0.5 (3,139)/3,425 (100)/108
Expected return on assets +/- 0.5 N/A (38)/38
__________________________
(a) Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.
(b) Impact on service cost, interest cost and amortization of gains or losses.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
The Company uses 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.
As of December 31, 2020, we have a regulatory liability associated with TCJA related items of $285 million, completing our accounting for the revaluation of deferred taxes pursuant to the TCJA. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets.
As of December 31, 2020, the Company has amortized $13.3 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in 2020, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.
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.
See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
New Accounting Pronouncements
See Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2020 or pending adoption.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.
Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks:
•Commodity price risk associated with our retail natural gas services, wholesale electric power marketing activities and fuel procurement for several of our gas-fired generation assets. Market fluctuations may occur due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and
•Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit risk is associated with financial loss resulting from non-performance of contractual obligations by a counterparty.
To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.
Commodity Price Risk
Electric and Gas Utilities
Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to reflect billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state regulatory commissions.
The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state regulatory commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations.
For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. See additional information in Note 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Wholesale Power
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments and do not qualifying for the normal purchase and normal sales exception for derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income.
A potential risk related to wholesale power sales is the price risk arising from the sale of power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.
Black Hills Energy Services
We buy and sell natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with fixed price forward contracts to supply gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings.
See additional commodity risk and derivative information in Note 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Interest Rate Risk
Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. At December 31, 2020, we had no interest rate swaps in place. Further details of past swap agreements are set forth in Note 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2020, 93% of our debt is fixed rate debt, which limits our exposure to variable interest rate fluctuations. A hypothetical 100 basis point increase in the benchmark rate on our variable rate debt would have increased annual pretax interest expense by approximately $2.1 million and $4.6 million for the years ended December 31, 2020 and 2019, respectively. See Note 9 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.
We are subject to interest rate risk associated with our pension and post-retirement benefit obligations. Changes in interest rates impact the liabilities associated with these benefit plans as well as the amount of income or expense recognized for these plans. Declines in the value of the plan assets could diminish the funded status of the pension plans and potentially increase the requirements to make cash contributions to these plans. See additional information in Critical Accounting Estimates in Item 7 and Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Credit Risk
We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2020 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.
See more information in Notes 1 and 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Control over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2020.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of December 31, 2020. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.
Black Hills Corporation
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2021, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Notes 1 and 2 to the Financial Statements.
Critical Audit Matter Description
The Company is subject to cost-of-service regulation and earnings oversight by state and federal utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).
Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will not always result in rates that produce a full recovery of costs and the return on invested capital.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers. Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) refunds or future reductions in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.
•We obtained and evaluated an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or of a future reduction in rates.
•We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new regulatory assets or liabilities.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 26, 2021
We have served as the Company's auditor since 2002.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 26, 2021, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 26, 2021
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Year ended December 31, 2020 December 31, 2019 December 31, 2018
(in thousands, except per share amounts)
Revenue $ 1,696,941 $ 1,734,900 $ 1,754,268
Operating expenses:
Fuel, purchased power and cost of natural gas sold 492,404 570,829 625,610
Operations and maintenance 495,404 495,994 481,706
Depreciation, depletion and amortization 224,457 209,120 196,328
Taxes - property and production 56,373 52,915 51,746
Other operating expenses - - 1,841
Total operating expenses 1,268,638 1,328,858 1,357,231
Operating income 428,303 406,042 397,037
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) (144,931) (139,291) (141,616)
Interest income 1,461 1,632 1,641
Impairment of investment (6,859) (19,741) -
Other income (expense), net (2,293) (5,740) (1,180)
Total other income (expense) (152,622) (163,140) (141,155)
Income before income taxes 275,681 242,902 255,882
Income tax benefit (expense) (32,918) (29,580) 23,667
Income from continuing operations 242,763 213,322 279,549
Net (loss) from discontinued operations - - (6,887)
Net income 242,763 213,322 272,662
Net income attributable to noncontrolling interest (15,155) (14,012) (14,220)
Net income available for common stock $ 227,608 $ 199,310 $ 258,442
Amounts attributable to common shareholders:
Net income from continuing operations $ 227,608 $ 199,310 $ 265,329
Net (loss) from discontinued operations - - (6,887)
Net income available for common stock $ 227,608 $ 199,310 $ 258,442
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations $ 3.65 $ 3.29 $ 4.88
(Loss) from discontinued operations - - (0.13)
Total earnings per share of common stock, Basic $ 3.65 $ 3.29 $ 4.75
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations $ 3.65 $ 3.28 $ 4.78
(Loss) from discontinued operations - - (0.12)
Total earnings per share of common stock, Diluted $ 3.65 $ 3.28 $ 4.66
Weighted average common shares outstanding:
Basic 62,378 60,662 54,420
Diluted 62,439 60,798 55,486
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31, 2020 December 31, 2019 December 31, 2018
(in thousands)
Net income $ 242,763 $ 213,322 $ 272,662
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $191, $1,886 and $(660), respectively)
(1,062) (6,253) 2,155
Benefit plan liability adjustments - prior service costs (net of tax of $0, $2 and $0 respectively)
- (8) -
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(958), $434 and $(586), respectively)
1,429 1,179 1,901
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $23, $19 and $43, respectively)
(80) (58) (135)
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(287), $(666) and $(599), respectively)
2,564 2,185 2,252
Net unrealized gains (losses) on commodity derivatives (net of tax of $14, $126 and $(228), respectively)
(47) (422) 755
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(96), $55 and $(31), respectively)
505 (362) 99
Other comprehensive income (loss), net of tax 3,309 (3,739) 7,027
Comprehensive income 246,072 209,583 279,689
Less: comprehensive income attributable to non-controlling interest (15,155) (14,012) (14,220)
Comprehensive income available for common stock $ 230,917 $ 195,571 $ 265,469
See Note 13 for additional disclosures related to Comprehensive Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
As of
December 31, 2020 December 31, 2019
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 6,356 $ 9,777
Restricted cash and equivalents 4,383 3,881
Accounts receivable, net 265,961 255,805
Materials, supplies and fuel 117,400 117,172
Derivative assets, current 1,848 342
Income tax receivable, net 19,446 16,446
Regulatory assets, current 51,676 43,282
Other current assets 26,221 26,479
Total current assets 493,291 473,184
Property, plant and equipment 7,305,530 6,784,679
Less accumulated depreciation and depletion (1,285,816) (1,281,493)
Total property, plant and equipment, net 6,019,714 5,503,186
Other assets:
Goodwill 1,299,454 1,299,454
Intangible assets, net 11,944 13,266
Regulatory assets, non-current 226,582 228,062
Other assets, non-current 37,801 41,305
Total other assets, non-current 1,575,781 1,582,087
TOTAL ASSETS $ 8,088,786 $ 7,558,457
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)
As of
December 31, 2020 December 31, 2019
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 183,340 $ 193,523
Accrued liabilities 243,612 226,767
Derivative liabilities, current 2,044 2,254
Regulatory liabilities, current 25,061 33,507
Notes payable 234,040 349,500
Current maturities of long-term debt 8,436 5,743
Total current liabilities 696,533 811,294
Long-term debt, net of current maturities 3,528,100 3,140,096
Deferred credits and other liabilities:
Deferred income tax liabilities, net 408,624 360,719
Regulatory liabilities, non-current 507,659 503,145
Benefit plan liabilities 150,556 154,472
Other deferred credits and other liabilities 134,667 124,662
Total deferred credits and other liabilities 1,201,506 1,142,998
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholders’ equity -
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 62,827,179 and 61,480,658, respectively
62,827 61,481
Additional paid-in capital 1,657,285 1,552,788
Retained earnings 870,738 778,776
Treasury stock at cost - 32,492 and 3,956, respectively
(2,119) (267)
Accumulated other comprehensive income (loss) (27,346) (30,655)
Total stockholders’ equity 2,561,385 2,362,123
Noncontrolling interest 101,262 101,946
Total equity 2,662,647 2,464,069
TOTAL LIABILITIES AND TOTAL EQUITY $ 8,088,786 $ 7,558,457
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31, 2020 December 31, 2019 December 31, 2018
(in thousands)
Operating activities:
Net income $ 242,763 $ 213,322 $ 272,662
Loss from discontinued operations, net of tax - - 6,887
Income from continuing operations 242,763 213,322 279,549
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 224,457 209,120 196,328
Deferred financing cost amortization 7,883 7,838 7,845
Impairment of investment 6,859 19,741 -
Stock compensation 5,373 12,095 12,390
Deferred income taxes 38,091 38,020 (24,239)
Employee benefit plans 11,997 12,406 14,068
Other adjustments, net 11,669 16,485 5,836
Change in certain operating assets and liabilities:
Materials, supplies and fuel 2,755 2,052 (2,919)
Accounts receivable and other current assets (10,843) 7,578 (45,966)
Accounts payable and other current liabilities 24,659 (34,906) 5,305
Regulatory assets - current (5,047) 23,619 33,608
Regulatory liabilities - current (10,706) (15,158) 18,533
Contributions to defined benefit pension plans (12,700) (12,700) (12,700)
Other operating activities, net 4,653 6,001 6,689
Net cash provided by operating activities of continuing operations 541,863 505,513 494,327
Net cash provided by (used in) operating activities of discontinued operations - - (5,516)
Net cash provided by operating activities 541,863 505,513 488,811
Investing activities:
Property, plant and equipment additions (767,404) (818,376) (457,524)
Purchase of investment - - (24,429)
Other investing activities 5,740 2,166 (4,281)
Net cash (used in) investing activities of continuing operations (761,664) (816,210) (486,234)
Net cash provided by investing activities of discontinued operations - - 20,385
Net cash (used in) investing activities (761,664) (816,210) (465,849)
Financing activities:
Dividends paid on common stock (135,439) (124,647) (106,591)
Common stock issued 99,278 101,358 300,834
Net (payments) borrowings of short-term debt (115,460) 163,880 (25,680)
Long-term debt - issuance 400,000 1,100,000 700,000
Long-term debt - repayments (8,597) (905,743) (854,743)
Distributions to noncontrolling interests (15,839) (17,901) (19,617)
Other financing activities (7,061) (16,737) (11,260)
Net cash provided by (used in) financing activities 216,882 300,210 (17,057)
Net change in cash, restricted cash and cash equivalents (2,919) (10,487) 5,905
Cash, restricted cash and cash equivalents beginning of year 13,658 24,145 18,240
Cash, restricted cash and cash equivalents end of year $ 10,739 $ 13,658 $ 24,145
Supplemental cash flow information:
Cash (paid) refunded during the period for continuing operations:
Interest (net of amounts capitalized) $ (136,549) $ (131,774) $ (137,965)
Income taxes $ 2,172 $ 4,682 $ (14,730)
Non-cash investing and financing activities from continuing operations:
Accrued property, plant and equipment purchases at December 31 $ 72,215 $ 91,491 $ 69,017
Increase in capitalized assets associated with asset retirement obligations $ 4,774 $ 5,044 $ 2,625
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
Common Stock Treasury Stock
(in thousands except share amounts) Shares Value Shares Value Additional Paid in Capital Retained Earnings AOCI Non controlling Interest Total
Balance at December 31, 2017 53,579,986 $ 53,580 39,064 $ (2,306) $ 1,150,285 $ 548,617 $ (41,202) $ 111,232 $ 1,820,206
Net income available for common stock - - - - - 258,442 - 14,220 272,662
Other comprehensive income (loss), net of tax - - - - - - 7,027 - 7,027
Reclassification of certain tax effects from AOCI - - - - - - 740 - 740
Reclassification to regulatory asset - - - - - - 6,519 - 6,519
Dividends on common stock ($1.93 per share)
- - - - - (106,591) - - (106,591)
Share-based compensation 92,830 93 5,189 (204) 7,301 - - - 7,190
Issuance of common stock 6,371,690 6,372 - - 292,628 - - - 299,000
Issuance costs - - - - (15) - - - (15)
Dividend reinvestment and stock purchase plan 4,061 4 - - 216 - - - 220
Other stock transactions - - - - 154 (72) - - 82
Distributions to noncontrolling interest - - - - - - - (19,617) (19,617)
Balance at December 31, 2018 60,048,567 $ 60,049 44,253 $ (2,510) $ 1,450,569 $ 700,396 $ (26,916) $ 105,835 $ 2,287,423
Net income available for common stock - - - - - 199,310 - 14,012 213,322
Other comprehensive income (loss), net of tax - - - - - - (3,739) - (3,739)
Dividends on common stock ($2.05 per share)
- - - - - (124,647) - - (124,647)
Share-based compensation 103,759 104 (40,297) 2,243 4,729 - - - 7,076
Issuance of common stock 1,328,332 1,328 - - 98,672 - - - 100,000
Issuance costs - - - - (1,182) - - - (1,182)
Other - - - - - 327 - - 327
Implementation of ASU 2016-02 Leases - - - - - 3,390 - - 3,390
Distributions to noncontrolling interest - - - - - - - (17,901) (17,901)
Balance at December 31, 2019 61,480,658 $ 61,481 3,956 $ (267) $ 1,552,788 $ 778,776 $ (30,655) $ 101,946 $ 2,464,069
Net income available for common stock - - - - - 227,608 - 15,155 242,763
Other comprehensive income (loss), net of tax - - - - - - 3,309 - 3,309
Dividends on common stock ($2.17 per share)
- - - - - (135,439) - - (135,439)
Share-based compensation 123,578 123 28,536 (1,852) 6,923 - - - 5,194
Issuance of common stock 1,222,943 1,223 - - 98,777 - - - 100,000
Issuance costs - - - - (1,203) - - - (1,203)
Implementation of ASU 2016-13 Financial Instruments - - Credit Losses - - - - - (207) - - (207)
Distributions to noncontrolling interest - - - - - - - (15,839) (15,839)
Balance at December 31, 2020 62,827,179 $ 62,827 32,492 $ (2,119) $ 1,657,285 $ 870,738 $ (27,346) $ 101,262 $ 2,662,647
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
Notes to Consolidated Financial Statements
December 31, 2020, 2019 and 2018
(1) BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Segment Reporting
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming.
Both of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 18.
On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations. Unless otherwise noted, the amounts presented in the accompanying Notes to Consolidated Financial Statements relate to the Company’s continuing operations.
Use of Estimates and Basis of Presentation
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
COVID-19 Pandemic
In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations.
The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the year ended December 31, 2020, there were no material adverse impacts on the Company’s results of operations.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 18.
Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generation facility, wind farm or transmission tie. See Note 6 for additional information.
Variable Interest Entities
We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.
Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 14.
Cash and Cash Equivalents and Restricted Cash
We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities.
We maintain an allowance for credit losses which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.
In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Following is a summary of accounts receivable as of December 31 (in thousands):
2020 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net
Electric Utilities $ 45,841 $ 32,915 $ (1,269) $ 77,487
Gas Utilities 95,592 93,150 (5,734) 183,008
Power Generation 1,837 - - 1,837
Mining 2,511 - - 2,511
Corporate 1,118 - - 1,118
Total $ 146,899 $ 126,065 $ (7,003) $ 265,961
2019 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net
Electric Utilities $ 41,428 $ 33,886 $ (592) $ 74,722
Gas Utilities 97,607 79,616 (1,683) 175,540
Power Generation 2,164 - - 2,164
Mining 2,277 - - 2,277
Corporate 1,271 - (169) 1,102
Total $ 144,747 $ 113,502 $ (2,444) $ 255,805
Changes to allowance for credit losses for the years ended December 31, were as follows (in thousands):
Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year
2020 $ 2,444 $ 8,927 (a)
$ 4,728 $ (9,096) $ 7,003
2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502) $ 2,444
2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823) $ 3,209
_________________
(a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 11.
Materials, Supplies and Fuel
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
2020 2019
Materials and supplies $ 85,250 $ 82,809
Fuel 1,531 2,425
Natural gas in storage 30,619 31,938
Total materials, supplies and fuel $ 117,400 $ 117,172
Materials and supplies represent parts and supplies for all of our business segments. Fuel represents diesel oil and gas used by our Electric Utilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.
Investments
In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment.
During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million for the three months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment at that time.
During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time.
The following table presents the carrying value of our investments (in thousands), which are included in Other assets, non-current on the Consolidated Balance Sheets, as of December 31:
2020 2019
Investment in privately held oil and gas company $ 1,500 $ 8,359
Cash surrender value of life insurance contracts 13,628 13,056
Other investments 682 514
Total investments $ 15,810 $ 21,929
We changed the classification of our investments on the Consolidated Balance Sheets as of December 31, 2019 to conform with current year presentation. The prior year reclassification of $22 million from Investments to Other assets, non-current did not impact previously reported current or total assets.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our stored natural gas base or Cushion Gas as property, plant and equipment.
The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.
Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. The composite depreciation method is applied to regulated utility property. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.
See Note 5 for additional information.
Asset Retirement Obligations
Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability.
We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. Additional information is included in Note 7.
Goodwill and Intangible Assets
Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life are amortized over their estimated useful lives.
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process.
The Company has determined that the reporting units for its goodwill impairment test are its operating segments, which are also its reportable segments.
Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies.
We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill amounts have not changed since 2016. As of December 31, 2020 and 2019, Goodwill balances were as follows (in thousands):
Electric Utilities Gas Utilities Power Generation Total
Goodwill $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454
Our intangible assets represent contract intangibles, easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
2020 2019 2018
Intangible assets, net, beginning balance $ 13,266 $ 14,337 $ 7,559
Additions - - 7,602
Amortization expense (a)
(1,322) (1,071) (824)
Intangible assets, net, ending balance $ 11,944 $ 13,266 $ 14,337
_________________
(a) Amortization expense for existing intangible assets is expected to be $1.3 million for each year of the next five years.
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
2020 2019
Accrued employee compensation, benefits and withholdings $ 77,806 $ 62,837
Accrued property taxes 47,105 44,547
Customer deposits and prepayments 52,185 54,728
Accrued interest 31,520 31,868
Other (none of which is individually significant) 34,996 32,787
Total accrued liabilities $ 243,612 $ 226,767
Fair Value Measurements
Financial Instruments
We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:
Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.
Level 2 - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 - Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.
Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Valuation Methodologies for Derivatives
The wholesale electric energy and natural gas commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.
Additional information on fair value measurements is included in Notes 12 and 15.
Derivatives and Hedging Activities
All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting.
In addition, certain derivative contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980, Regulated Operations.
We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures.
See additional information in Notes 11, 12 and 13.
Deferred Financing Costs
Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities. See additional information in Note 9.
Regulatory Accounting
Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:
•Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
•Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
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.
If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.
As of December 31, 2020 and 2019, we had total regulatory assets of $278 million and $271 million respectively, and total regulatory liabilities of $533 million and $537 million respectively. See Note 2 for further information.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.
It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax benefit (expense) on the Consolidated Statements of Income.
We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 17 for additional information.
Earnings per Share of Common Stock
Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans.
A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands):
2020 2019 2018
Net income available for common stock $ 227,608 $ 199,310 $ 258,442
Weighted average shares - basic 62,378 60,662 54,420
Dilutive effect of:
Equity Units - - 898
Equity compensation 61 136 168
Weighted average shares - diluted 62,439 60,798 55,486
Net income available for common stock, per share - Diluted $ 3.65 $ 3.28 $ 4.66
The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands):
2020 2019 2018
Equity compensation 60 1 16
Anti-dilutive shares excluded from computation of earnings per share 60 1 16
Noncontrolling Interests
We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidation. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 14 for additional detail on noncontrolling interests.
Share-Based Compensation
We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. See additional information in Note 16.
Change in Accounting Principle - Pension Accounting Asset Method
Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will continue to use a calculated value for the return-seeking assets (equities) in the portfolio but was changed to fair value for the liability-hedging assets (fixed income). See Note 15 for additional information.
Recently Issued Accounting Standards
Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating if we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements and the potential impact on our financial position, results of operations and cash flows.
Simplifying the Accounting for Income Taxes, ASU 2019-12
In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. Adoption of this standard is not anticipated to have a material impact on our financial position, results of operations and cash flows.
Recently Adopted Accounting Standards
Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-13
In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses.
We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for credit losses, primarily associated with the inclusion of expected losses on unbilled revenue. The cumulative effect of the adoption, net of tax impact, was $0.2 million, which was recorded as an adjustment to retained earnings.
Simplifying the Test for Goodwill Impairment, ASU 2017-04
In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.
Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15
In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.
(2) REGULATORY MATTERS
We had the following regulatory assets and liabilities as of December 31 (in thousands):
2020 2019
Regulatory assets
Deferred energy and fuel cost adjustments (a)
$ 39,035 $ 34,088
Deferred gas cost adjustments (a)
3,200 1,540
Gas price derivatives (a)
2,226 3,328
Deferred taxes on AFUDC (b)
7,491 7,790
Employee benefit plans and related deferred taxes (c)
116,598 115,900
Environmental (a)
1,413 1,454
Loss on reacquired debt (a)
22,864 24,777
Renewable energy standard adjustment (a)
- 1,622
Deferred taxes on flow-through accounting (c)
47,515 41,220
Decommissioning costs (a)
8,988 10,670
Gas supply contract termination (a)
2,524 8,485
Other regulatory assets (a)
26,404 20,470
Total regulatory assets 278,258 271,344
Less current regulatory assets (51,676) (43,282)
Regulatory assets, non-current $ 226,582 $ 228,062
Regulatory liabilities
Deferred energy and gas costs (a)
$ 13,253 $ 17,278
Employee benefit plan costs and related deferred taxes (c)
40,256 43,349
Cost of removal (a)
172,902 166,727
Excess deferred income taxes (c)
285,259 285,438
Other regulatory liabilities (c)
21,050 23,860
Total regulatory liabilities 532,720 536,652
Less current regulatory liabilities (25,061) (33,507)
Regulatory liabilities, non-current $ 507,659 $ 503,145
__________
(a) Recovery of costs, but we are not allowed a rate of return.
(b) In addition to recovery of costs, we are allowed a rate of return.
(c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions. The recovery period for these costs is less than a year.
Deferred Gas Cost Adjustments - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state regulatory commissions. The recovery period for these costs is less than a year.
Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2020 are hedged over a maximum forward term of two years.
Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.
Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.
Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time.
Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.
Renewable Energy Standard Adjustment - The renewable energy standard adjustment provides funding for various renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard. These programs include incentives for our Colorado Electric customers to install renewable energy equipment at their location. These project costs and program incentives are recovered over time through the Renewable Energy Standard Adjustment charged on customers’ bills.
Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer and result in lower utility rates in the year in which the tax benefits are realized. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.
Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and received approval in 2020 to begin recovering those costs over three years.
Gas Supply Contract Termination - As part of our acquisition of SourceGas in 2016, we acquired agreements that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to certain customers in Colorado, Nebraska, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our SourceGas Transaction purchase price allocation. We were granted approval to terminate these agreements from the CPUC, NPSC and WPSC on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016.
Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.
Deferred Energy and Gas Costs - Deferred energy and gas costs that have been over-recovered through customer rates and will be returned to customers in future periods.
Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.
Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense.
Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See Note 17 for additional information.
Regulatory Activity
TCJA
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018 and 2019, the Company successfully delivered several of these tax benefits from the TCJA to its utility customers.
In 2020, regulatory proceedings resolved the last of the Company’s open dockets seeking approval of its TCJA plans. As a result, the Company relieved certain TCJA-related liabilities, which resulted in an increase to net income for the year ended December 31, 2020 of $4.0 million.
On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related customer billing credits to its customers. The billing credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, will be delivered to customers in February 2021. These billing credits will be offset by a reduction in income tax expense and will result in a minimal impact to Net income.
On Janaury 26, 2021, NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related customer billing credits to its customers. The billing credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, is expected to be delivered to customers in the second quarter of 2021. These billing credits will be offset by a reduction in income tax and and will result in a minimal impact to Net income.
Electric Utilities Regulatory Activity
South Dakota Electric
Settlement
On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the 6-year moratorium period by an additional 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $5.4 million of development costs in 2019 related to projects we no longer intend to construct. This settlement amends a previous agreement approved by the SDPUC on June 16, 2017, whereby South Dakota Electric would not increase base rates, absent an extraordinary event, for a 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA.
FERC Formula Rate
The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2020 the annual revenue requirement was $27 million and included estimated weighted average capital additions of $33 million for 2019 and 2020 combined. The annual transmission revenue requirement has a true-up mechanism that is recorded in June of each year.
Black Hills Wyoming and Wyoming Electric
Wygen 1 FERC Filing
On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years.
Gas Utilities Regulatory Activity
Colorado Gas
Jurisdictional Consolidation and Rate Reviews
On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On January 6, 2021 the CPUC issued an order dismissing the rate review. On January 26, 2021, Colorado Gas filed an application for rehearing, reargument or reconsideration in response to the Commission’s January 6 order.
On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety and integrity focused investments in its system over five years. A decision from the CPUC is expected by mid-2021.
On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020.
RMNG SSIR
On October 30, 2020, RMNG filed the tariff adjusting rates to include 2021 projects with an expected capital investment of $33 million under the current SSIR. The new tariff rates went into effect January 1, 2021 and the current approved SSIR expires December 31, 2021.
Nebraska Gas
Jurisdictional Consolidation and Rate Review
On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates will be enacted on March 1, 2021, to replace interim rates enacted September 1, 2020. The approval will shift $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism for consolidated utility alignment.
Wyoming Gas
Jurisdictional Consolidation and Rate Review
Wyoming Gas’s new single statewide rate structure became effective March 1, 2020. Wyoming Gas received approval from the WPSC on December 11, 2019, to consolidate the rates, tariffs and services of its four existing gas distribution territories. New rates are expected to generate $13 million in new annual revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.
(3) COMMITMENTS, CONTINGENCIES AND GUARANTEES
Power Purchase and Transmission Services Agreements
Through our subsidiaries, we have the following significant long-term power purchase contracts and transmission services agreement (TSA) with non-affiliated third-parties:
Subsidiary Contract Type Counterparty Fuel Type Quantity (MW) Expiration Date
Colorado Electric (a)
PPA PRPA Wind 60 May 31, 2030
Colorado Electric PPA PRPA Coal 25 June 30, 2024
South Dakota Electric PPA PacifiCorp Coal 50 December 31, 2023
South Dakota Electric (b)
TSA PacifiCorp N/A 50 December 31, 2023
South Dakota Electric PPA PRPA Wind 12 September 30, 2029
South Dakota Electric PPA Fall River Solar, LLC Solar 80 Pending Completion (c)
Wyoming Electric (d)
PPA Happy Jack Wind 30 September 3, 2028
Wyoming Electric (e)
PPA Silver Sage Wind 30 September 30, 2029
_____________
(a) Colorado Electric sells the wind energy purchased under this PPA to City of Colorado Springs as discussed below.
(b) This is a firm point-to-point transmission service agreement that provides 50 MW of capacity and energy to be transmitted annually.
(c) This agreement relates to a new solar facility currently being constructed and will expire 20 years after construction completion, which is expected by the end of 2022.
(d) Under a separate intercompany PSA, Wyoming Electric sells 50% of the facility output to South Dakota Electric.
(e) Under a separate intercompany PSA, Wyoming Electric sells 67% of the facility output to South Dakota Electric.
Costs under these agreements for the years ended December 31 were as follows (in thousands):
Subsidiary Contract Type Counterparty Fuel Type 2020 2019 2018
Colorado Electric PPA PRPA Wind $ 2,791 $ - $ -
Colorado Electric PPA PRPA Coal $ 4,524 $ 1,802 $ -
South Dakota Electric PPA PacifiCorp Coal $ 5,897 $ 7,477 $ 13,681
South Dakota Electric TSA PacifiCorp N/A $ 1,776 $ 1,741 $ 1,742
South Dakota Electric PPA PRPA Wind $ 715 $ 688 $ 223
Wyoming Electric PPA Happy Jack Wind $ 4,531 $ 3,936 $ 3,884
Wyoming Electric PPA Silver Sage Wind $ 6,203 $ 5,366 $ 5,376
Power Purchase Agreements - Related Parties
Wyoming Electric currently has a PPA with Black Hills Wyoming expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I facility. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years.
Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric through a PPA, which expires in November 2044.
Black Hills Electric Generation provides its 14.5 MW share of energy generated from Busch Ranch I to Colorado Electric through a PPA, which expires in October 2037.
Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. At the segment level, we recognize the associated revenues, costs and assets on an accrual basis, rather than as a finance lease. See Note 18 for additional information.
Purchase Commitments
We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.
Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2020, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):
Northern Natural Gas - Ventura Northwest Pipeline - Wyoming ONEOK - Oklahoma Southern Star Central Gas Pipeline Panhandle Eastern Pipe Line
2021 3,650,000 1,510,000 5,475,000 113,130 4,680
2022 1,810,000 1,510,000 5,475,000 - -
2023 1,840,000 1,510,000 5,475,000 - -
2024 1,820,000 910,000 5,490,000 - -
2025 - - 4,560,000 - -
Thereafter - - - - -
Purchases under these contracts totaled $25 million, $6.7 million and $27 million for 2020, 2019 and 2018, respectively.
Other Gas Supply Agreements
Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044.
The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in thousands):
Power purchase and transmission services agreements (a)
Natural gas transportation and storage agreements
2021 $ 24,452 $ 116,563
2022 $ 11,678 $ 121,819
2023 $ 11,678 $ 100,282
2024 $ 2,738 $ 67,089
2025 $ - $ 50,709
Thereafter $ - $ 167,100
_____________
(a) This schedule does not reflect renewable energy PPA obligations since these agreements vary based on weather conditions.
Power Sales Agreements
Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:
•On July 1, 2020, Colorado Electric entered into a PSA with the City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA discussed above. This PSA with the City of Colorado Springs expires June 30, 2025.
•During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.
•South Dakota Electric has an agreement to provide MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.
•During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from its other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which has an initial term through September 3, 2034 and would be renewed annually on September 3 thereafter, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.
•South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028. The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:
Contract Years Total Contract Capacity Contingent Capacity Amounts on Wygen III Contingent Capacity Amounts on Neil Simpson II
2020-2022 15 MW 7 MW 8 MW
2022-2023 15 MW 8 MW 7 MW
2023-2028 10 MW 5 MW 5 MW
•South Dakota Electric has an agreement that expires December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.
•Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PSA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.
Environmental Matters
We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.
Reclamation Liability
For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
Under our land leases for our wind generation facilities, we are required to reclaim land where we have placed wind turbines. The reclamation liabilities are recorded at the present value of the estimated future cost to reclaim the land.
Under its mining permit, WRDC is required to reclaim all land where it has mined reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
See Note 7 for additional information.
Manufactured Gas Processing
In 2008, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.2 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.4 million regulatory asset for manufactured gas processing sites; see Note 2 for additional information.
As of December 31, 2020, we had $2.6 million accrued for remediation of Iowa’s manufactured gas processing site as the landowner. As of December 31, 2020, we had $0.6 million accrued for remediation of Nebraska’s manufactured gas processing site as the land owner. These liabilities are included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.
Legal Proceedings
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.
In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.
Guarantees
We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements, which are off-balance sheet commitments, include indemnification for reclamation and surety bonds. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.
We had the following guarantees in place as of (in thousands):
Maximum Exposure at
Nature of Guarantee December 31, 2020 Expiration
Indemnification for subsidiary reclamation/surety bonds $ 53,769 Ongoing
(4) REVENUE
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are:
•Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, Regulated Operations, that provide services to regulated customers under tariff rates, charges, terms and conditions of service and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our Utilities’ regulated sales are subject to regulatory-approved tariffs.
•Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement.
•Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate Electric Utilities, and an affiliate non-regulated Power Generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered.
•Other non-regulated services - Our Electric and Gas Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.
The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments, for the years ended December 31, 2020, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.
Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 610,721 $ 765,922 $ - $ 58,567 $ (31,478) $ 1,403,732
Transportation - 154,581 - - (526) 154,055
Wholesale 17,848 - 103,258 - (97,169) 23,937
Market - off-system sales 24,309 260 - - (8,797) 15,772
Transmission/Other 58,965 43,658 - - (19,315) 83,308
Revenue from contracts with customers 711,843 964,421 103,258 58,567 (157,285) 1,680,804
Other revenues 2,201 10,249 1,789 2,508 (610) 16,137
Total revenues $ 714,044 $ 974,670 $ 105,047 $ 61,075 $ (157,895) $ 1,696,941
Timing of revenue recognition:
Services transferred at a point in time $ - $ - $ - $ 58,567 $ (31,478) $ 27,089
Services transferred over time 711,843 964,421 103,258 - (125,807) 1,653,715
Revenue from contracts with customers $ 711,843 $ 964,421 $ 103,258 $ 58,567 $ (157,285) $ 1,680,804
Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 605,756 $ 817,840 $ - $ 59,233 $ (32,053) $ 1,450,776
Transportation - 143,390 - - (1,042) 142,348
Wholesale 20,884 - 99,157 - (91,577) 28,464
Market - off-system sales 23,817 691 - - (7,736) 16,772
Transmission/Other 57,104 47,725 - - (16,797) 88,032
Revenue from contracts with customers 707,561 1,009,646 99,157 59,233 (149,205) 1,726,392
Other revenues 5,191 384 2,101 2,396 (1,564) 8,508
Total revenues $ 712,752 $ 1,010,030 $ 101,258 $ 61,629 $ (150,769) $ 1,734,900
Timing of revenue recognition:
Services transferred at a point in time $ - $ - $ - $ 59,233 $ (32,053) $ 27,180
Services transferred over time 707,561 1,009,646 99,157 - (117,152) 1,699,212
Revenue from contracts with customers $ 707,561 $ 1,009,646 $ 99,157 $ 59,233 $ (149,205) $ 1,726,392
Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total
Customer types: (in thousands)
Retail $ 594,329 $ 833,379 $ - $ 65,803 $ (32,194) $ 1,461,317
Transportation - 140,705 - - (1,348) 139,357
Wholesale 33,687 - 90,791 - (84,957) 39,521
Market - off-system sales 24,799 866 - - (8,102) 17,563
Transmission/Other 56,209 49,402 - - (14,827) 90,784
Revenue from contracts with customers 709,024 1,024,352 90,791 65,803 (141,428) 1,748,542
Other revenues 2,427 955 1,660 2,230 (1,546) 5,726
Total revenues $ 711,451 $ 1,025,307 $ 92,451 $ 68,033 $ (142,974) $ 1,754,268
Timing of revenue recognition:
Services transferred at a point in time $ - $ - $ - $ 65,803 $ (32,194) $ 33,609
Services transferred over time 709,024 1,024,352 90,791 - (109,234) 1,714,933
Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 90,791 $ 65,803 $ (141,428) $ 1,748,542
The majority of our revenue contracts are based on variable quantities delivered. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.
Revenue Not in Scope of ASC 606
Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations.
Significant Judgments and Estimates
Unbilled Revenue
To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month, the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 1.
(5) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
2020 2019 Lives (in years)
Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum
Electric plant:
Production $ 1,417,951 40 $ 1,348,049 41 32 46
Electric transmission 517,794 49 483,640 51 44 51
Electric distribution 959,453 46 861,042 47 46 48
Plant acquisition adjustment (a)
4,870 32 4,870 32 32 32
General 259,010 28 259,266 28 26 29
Total electric plant in service 3,159,078 2,956,867
Construction work in progress 89,402 102,268
Total electric plant 3,248,480 3,059,135
Less accumulated depreciation (666,669) (670,861)
Electric plant net of accumulated depreciation $ 2,581,811 $ 2,388,274
_____________
(a) The plant acquisition adjustment is included in rate base and is being recovered with 10 years remaining.
2020 2019 Lives (in years)
Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum
Gas plant:
Production $ 15,603 40 $ 13,000 35 24 46
Gas transmission 578,278 54 516,172 50 22 71
Gas distribution 2,115,082 53 1,857,233 43 45 59
Cushion gas - depreciable (a)
3,539 28 3,539 28 28 28
Cushion gas - not depreciable (a)
39,184 N/A 44,443 N/A N/A N/A
Storage 55,481 38 46,977 31 24 52
General 438,217 19 437,054 20 12 23
Total gas plant in service 3,245,384 2,918,418
Construction work in progress 67,229 63,080
Total gas plant 3,312,613 2,981,498
Less accumulated depreciation (323,679) (336,721)
Gas plant net of accumulated depreciation $ 2,988,934 $ 2,644,777
_____________
(a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides.
2020 Lives (in years)
Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum
Power Generation $ 529,927 $ 4,876 $ 534,803 $ (167,787) $ 367,016 31 2 40
Mining $ 186,552 $ 988 $ 187,540 $ (126,537) $ 61,003 14 2 59
2019 Lives (in years)
Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum
Power Generation $ 532,397 $ 2,121 $ 534,518 $ (154,362) $ 380,156 31 2 40
Mining $ 179,198 $ 1,275 $ 180,473 $ (118,585) $ 61,888 13 2 59
2020 Lives (in years)
Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum
Corporate $ 5,692 $ 16,402 $ 22,094 $ (1,144) $ 20,950 10 10 22
2019 Lives (in years)
Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum
Corporate $ 5,721 $ 23,334 $ 29,055 $ (964) $ 28,091 10 3 30
(6) JOINTLY OWNED FACILITIES
Our consolidated financial statements include our share of several jointly-owned utility and non-regulated facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.
Wyodak Plant
South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.
Transmission Tie
South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the Transmission Tie), an AC-DC-AC transmission tie. Basin Electric Power Cooperative owns the remaining ownership percentage. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.
Wygen III
South Dakota Electric owns 52% of the Wygen III generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies fuel to Wygen III for the life of the plant.
Wygen I
Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations.
At December 31, 2020, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation
Wyodak Plant $ 116,074 $ 2,249 $ (67,762) $ 50,561
Transmission Tie $ 26,176 $ 509 $ (7,103) $ 19,582
Wygen III $ 142,739 $ 582 $ (24,783) $ 118,538
Wygen I $ 114,975 $ 318 $ (49,459) $ 65,834
Jointly Owned Facilities - Related Party
Busch Ranch I
Colorado Electric owns 50% of Busch Ranch I while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. Colorado Electric retains responsibility for operations of the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.
Cheyenne Prairie
Cheyenne Prairie serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 100.4 MW unit that is jointly-owned by South Dakota Electric (58 MW) and Wyoming Electric (42.4 MW). BHSC is responsible for plant operations.
Corriedale
Corriedale serves as the dedicated wind energy supply for Renewable Ready customers in South Dakota and Wyoming. The 52.5 MW wind farm is jointly-owned by South Dakota Electric (32.5 MW) and Wyoming Electric (20 MW). BHSC is responsible for operations of the wind farm.
(7) ASSET RETIREMENT OBLIGATIONS
We have identified legal retirement obligations related to reclamation of mining sites in the Mining segment, removal of fuel tanks, transformers containing polychlorinated biphenyls, and an evaporation pond at our Electric Utilities, wind turbines at our Electric Utilities and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these AROs. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment.
The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
December 31, 2019 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2020
Electric Utilities (a)
$ 9,329 $ 1,217 $ - $ 407 $ - $ 10,953
Gas Utilities (b)
36,085 4,782 (132) 1,539 - 42,274
Power Generation 4,739 - - 206 - 4,945
Mining (c)
14,052 - (185) 617 (1,225) 13,259
Total 64,205 $ 5,999 $ (317) $ 2,769 $ (1,225) $ 71,431
December 31, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2019
Electric Utilities (d)
$ 6,258 $ - $ - $ 385 $ 2,686 $ 9,329
Gas Utilities 34,627 - - 1,458 - 36,085
Power Generation (a)
300 3,445 - 158 836 4,739
Mining (c)
15,615 - (380) 740 (1,923) 14,052
Total $ 56,800 $ 3,445 $ (380) $ 2,741 $ 1,599 $ 64,205
_____________________
(a) Liabilities incurred were related to new wind assets.
(b) Liabilities incurred were driven by an increase in gas pipeline miles; which increases our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.
(c) The Mining Revisions to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process.
(d) The Electric Utilities Revisions to Prior Estimates was primarily driven by an increase in the estimated cost to decommission certain regulated wind farm assets.
We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time.
(8) LEASES
Lessee
We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 35 years, including options to extend that are reasonably certain to be exercised. We have one immaterial finance lease for communication equipment at the WRDC mine.
Most of our leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using our applicable subsidiaries’ incremental borrowing rate (weighted-average of 4.24% as of December 31, 2020).
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the accompanying Consolidated Balance Sheets.
Lease expense for the year ended December 31 were as follows (in thousands):
Income Statement Location 2020 2019
Operating lease cost Operations and maintenance $ 978 $ 1,456
Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands):
Balance Sheet Location 2020 2019
Assets:
Operating lease assets Other assets, non-current $ 4,188 $ 4,629
Total lease assets $ 4,188 $ 4,629
Liabilities:
Current:
Operating leases Accrued liabilities $ 736 $ 1,179
Noncurrent:
Operating leases Other deferred credits and other liabilities 3,807 3,821
Total lease liabilities $ 4,543 $ 5,000
Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands):
2020 2019
Cash paid included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 1,023 $ 1,263
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 161 $ 2,801
Weighted average remaining terms and discount rates related to leases as of December 31 were as follows:
2020 2019
Weighted average remaining lease term:
Operating leases 8 years 8 years
Weighted average discount rate:
Operating leases 4.24 % 4.27 %
As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands):
Operating Leases
2021 $ 907
2022 804
2023 779
2024 776
2025 529
Thereafter 1,643
Total lease payments $ 5,438
Less imputed interest 895
Present value of lease liabilities $ 4,543
Lessor
We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 34 years.
Lease revenue for the year ended December 31 were as follows (in thousands):
Income Statement Location 2020 2019
Operating lease income Revenue $ 2,534 $ 2,306
As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands):
Operating Leases
2021 $ 2,383
2022 2,122
2023 2,130
2024 2,074
2025 2,090
Thereafter 58,829
Total lease receivables $ 69,628
(9) DEBT AND CREDIT FACILITIES
Short-term debt
We had the following Notes payable outstanding at the Consolidated Balance Sheets date (in thousands):
December 31, 2020 December 31, 2019
Balance Outstanding Letters of Credit (a)
Balance Outstanding Letters of Credit (a)
Revolving Credit Facility $ - $ 24,730 $ - $ 30,274
CP Program 234,040 - 349,500 -
Total $ 234,040 $ 24,730 $ 349,500 $ 30,274
_______________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.
Revolving Credit Facility and CP Program
On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, at December 31, 2020. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2020.
We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.
Our net short-term borrowings (payments) during 2020 were $(115) million. As of December 31, 2020, the weighted average interest rate on short-term borrowings was 0.27%.
Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See below for additional details.
Long-term debt
Long-term debt outstanding was as follows (dollars in thousands):
Interest Rate at Balance Outstanding
Due Date December 31, 2020 December 31, 2020 December 31, 2019
Corporate
Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000
Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000
Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000
Senior unsecured notes, due 2029 October 15, 2029 3.05% 400,000 400,000
Senior unsecured notes, due 2030 June 15, 2030 2.50% 400,000 -
Senior unsecured notes due 2033 May 1, 2033 4.35% 400,000 400,000
Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000
Senior unsecured notes, due 2049 October 15, 2049 3.88% 300,000 300,000
Corporate term loan due 2021 June 7, 2021 2.32% 1,436 7,178
Total Corporate debt 3,026,436 2,632,178
Less unamortized debt discount (7,013) (6,462)
Total Corporate debt, net 3,019,423 2,625,716
South Dakota Electric
Series 94A Debt, variable rate (a)
June 1, 2024 N/A - 2,855
First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000
First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000
First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000
Total South Dakota Electric debt 340,000 342,855
Less unamortized debt discount (78) (82)
Total South Dakota Electric debt, net 339,922 342,773
Wyoming Electric
Industrial development revenue bonds due 2021(a) (b)
September 1, 2021 0.12% 7,000 7,000
Industrial development revenue bonds due 2027(a) (b)
March 1, 2027 0.12% 10,000 10,000
First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000
First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000
Total Wyoming Electric debt 202,000 202,000
Less unamortized debt discount - -
Total Wyoming Electric debt, net 202,000 202,000
Total long-term debt 3,561,345 3,170,489
Less current maturities 8,436 5,743
Less unamortized deferred financing costs (c)
24,809 24,650
Long-term debt, net of current maturities and deferred financing costs $ 3,528,100 $ 3,140,096
_______________
(a) Variable interest rate.
(b) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due March 1, 2027 and the 2009B bonds of $7.0 million due September 1, 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.
(c) Includes deferred financing costs associated with our Revolving Credit Facility of $1.0 million and $1.7 million as of December 31, 2020 and December 31, 2019, respectively.
Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
2021 $ 8,436
2022 $ -
2023 $ 525,000
2024 $ -
2025 $ -
Thereafter $ 3,035,000
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2020. See below for additional information.
Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
Amortization of Deferred Financing Costs
Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31,
December 31, 2020 2020 2019 2018
$ 24,809 $ 3,272 $ 3,242 $ 2,829
Debt Transactions
On June 17, 2020, we completed a public debt offering which consisted of $400 million of 2.50% 10-year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes.
On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the sole investor on March 17, 2020.
On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:
• Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;
• Retire the $200 million 5.875% senior notes due July 15, 2020; and
• Repay a portion of short-term debt.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan.
Debt Covenants
Revolving Credit Facility
Under our Revolving Credit Facility and term loan agreements we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.
We were in compliance with our covenants at December 31, 2020 as shown below:
As of December 31, 2020 Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio 59.9% Less than 65%
Wyoming Electric
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2020, we were in compliance with these covenants.
Dividend Restrictions
Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs.
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2020:
•Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2020, the restricted net assets at our Electric and Gas Utilities were approximately $155 million.
•South Dakota Electric and Wyoming Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements.
(10) STOCKHOLDERS' EQUITY
February 2020 Equity Issuance
On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC.
At-the-Market Equity Offering Program
On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC.
We did not issue any common shares under the ATM during the twelve months ended December 31, 2020. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM for $99 million, net of $1.2 million in issuance costs. We did not issue any common shares under the ATM during the twelve months ended December 31, 2018.
Shareholder Dividend Reinvestment and Stock Purchase Plan
We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2020, there were 163,962 shares of unissued stock available for future offering under the DRSPP.
Preferred Stock
Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding.
(11) RISK MANAGEMENT AND DERIVATIVES
Market and Credit Risk Disclosures
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.
Market Risk
Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks:
•Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and
•Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2020 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.
We continue to monitor COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify estimated future financial impacts to the allowance for credit losses. During the year ended December 31, 2020, the potential economic impact of the COVID-19 pandemic was considered in forward looking projections related to write-off and recovery rates, and resulted in increases to the allowance for credit losses and bad debt expense of $3.3 million. See Note 1 for further information.
Derivatives and Hedging Activity
Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 12.
The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.
For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income.
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income.
We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from January 2021 through May 2022. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.
The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our utilities are comprised of both short and long positions. We had the following net long positions as of:
December 31, 2020 December 31, 2019
Notional (MMBtus) Maximum Term (months) (a)
Notional (MMBtus) Maximum Term (months) (a)
Natural gas futures purchased 620,000 3 1,450,000 12
Natural gas options purchased, net 3,160,000 3 3,240,000 3
Natural gas basis swaps purchased 900,000 3 1,290,000 12
Natural gas over-the-counter swaps, net (b)
3,850,000 17 4,600,000 24
Natural gas physical commitments, net (c)
17,513,061 22 13,548,235 12
Electric wholesale contracts (c)
219,000 12 - 0
__________
(a) Term reflects the maximum forward period hedged.
(b) As of December 31, 2020, 914,600 of natural gas over-the-counter swaps purchased were designated as cash flow hedges.
(c) Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP.
We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At December 31, 2020, the Company posted $1.5 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.
Derivatives by Balance Sheet Classification
As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements that allow us to settle positive and negative positions.
The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):
Balance Sheet Location 2020 2019
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives Derivative assets - current $ 181 $ 1
Noncurrent commodity derivatives Other assets, non-current 43 3
Liability derivative instruments:
Current commodity derivatives Derivative liabilities - current (108) (490)
Noncurrent commodity derivatives Other deferred credits and other liabilities - (29)
Total derivatives designated as hedges $ 116 $ (515)
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives Derivative assets - current $ 1,667 $ 341
Noncurrent commodity derivatives Other assets, non-current 151 2
Liability derivative instruments:
Current commodity derivatives Derivative liabilities - current (1,936) (1,764)
Noncurrent commodity derivatives Other deferred credits and other liabilities - (63)
Total derivatives not designated as hedges $ (118) $ (1,484)
Derivatives Designated as Hedge Instruments
The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
2020 2019 2018 2020 2019 2018
Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in OCI Income Statement Location Amount of Gain/(Loss) Reclassified from AOCI into Income
(in thousands) (in thousands)
Interest rate swaps $ 2,851 $ 2,851 $ 2,851 Interest expense $ (2,851) $ (2,851) $ (2,851)
Commodity derivatives 540 (965) 1,113 Fuel, purchased power and cost of natural gas sold (601) 417 (130)
Total $ 3,391 $ 1,886 $ 3,964 $ (3,452) $ (2,434) $ (2,981)
As of December 31, 2020, $2.8 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.
Derivatives Not Designated as Hedge Instruments
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
2020 2019 2018
Derivatives Not Designated as Hedging Instruments Income Statement Location Amount of Gain/(Loss) on Derivatives Recognized in Income
(in thousands)
Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold $ 144 $ - $ -
Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 1,640 (1,100) 1,101
$ 1,784 $ (1,100) $ 1,101
As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to these financial instruments in our Gas Utilities were $2.2 million and $3.3 million at December 31, 2020 and 2019, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income.
(12) FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements
Derivatives
The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.
As of December 31, 2020
Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a)
Total
(in thousands)
Assets:
Commodity derivatives - Gas Utilities $ - $ 2,504 $ - $ (1,527) $ 977
Commodity derivatives - Electric Utilities - 1,065 - - 1,065
Total $ - $ 3,569 $ - $ (1,527) $ 2,042
Liabilities:
Commodity derivatives - Gas Utilities $ - $ 2,675 $ - $ (1,552) $ 1,123
Commodity derivatives - Electric Utilities $ 921 $ - $ 921
Total $ - $ 3,596 $ - $ (1,552) $ 2,044
_______________
(a) As of December 31, 2020, $1.5 million of our commodity derivative gross assets and $1.6 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
As of December 31, 2019
Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a)
Total
Assets:
Commodity derivatives - Gas Utilities $ - 1,433 $ - $ (1,085) $ 348
Total $ - $ 1,433 $ - $ (1,085) $ 348
Liabilities:
Commodity derivatives - Gas Utilities $ - $ 5,254 $ - $ (2,909) $ 2,345
Total $ - $ 5,254 $ - $ (2,909) $ 2,345
_______________
(a) As of December 31, 2019, $1.1 million of our commodity derivative assets and $2.9 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
Pension and Postretirement Plan Assets
A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 15.
Nonrecurring Fair Value Measurement
A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 1.
Other Fair Value Measurements
The carrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in thousands):
2020 2019
Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current maturities (a)
$ 3,536,536 $ 4,208,167 $ 3,145,839 $ 3,479,367
_______________
(a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.
(13) OTHER COMPREHENSIVE INCOME
We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.
The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income for the period, net of tax (in thousands):
Location on the Consolidated Statements of Income Amount Reclassified from AOCI
December 31, 2020 December 31, 2019
Gains and (losses) on cash flow hedges:
Interest rate swaps Interest expense $ (2,851) $ (2,851)
Commodity contracts Fuel, purchased power and cost of natural gas sold (601) 417
(3,452) (2,434)
Income tax Income tax benefit (expense) 383 611
Total reclassification adjustments related to cash flow hedges, net of tax $ (3,069) $ (1,823)
Amortization of components of defined benefit plans:
Prior service cost Operations and maintenance $ 103 $ 77
Actuarial gain (loss) Operations and maintenance (2,387) (745)
(2,284) (668)
Income tax Income tax benefit (expense) 935 (453)
Total reclassification adjustments related to defined benefit plans, net of tax $ (1,349) $ (1,121)
Total reclassifications $ (4,418) $ (2,944)
Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):
Derivatives Designated as Cash Flow Hedges
Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total
As of December 31, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655)
Other comprehensive income (loss)
before reclassifications - (47) (1,062) (1,109)
Amounts reclassified from AOCI 2,564 505 1,349 4,418
As of December 31, 2020 $ (12,558) $ 2 $ (14,790) $ (27,346)
Derivatives Designated as Cash Flow Hedges
Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total
As of December 31, 2018 $ (17,307) $ 328 $ (9,937) $ (26,916)
Other comprehensive income (loss)
before reclassifications - (422) (6,261) (6,683)
Amounts reclassified from AOCI 2,185 (362) 1,121 2,944
As of December 31, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655)
(14) VARIABLE INTEREST ENTITY
Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric.
The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810, Consolidation. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet.
Net income available for common stock for the years ended December 31, 2020, 2019 and 2018 was reduced by $15 million, $14 million, and $14 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of net income attributable to this noncontrolling interest are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.
Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.
We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31 (in thousands):
2020 2019
Assets:
Current assets $ 13,604 $ 13,350
Property, plant and equipment of variable interest entities, net $ 190,637 $ 193,046
Liabilities:
Current liabilities $ 5,318 $ 6,013
(15) EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.
The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.
Defined Benefit Pension Plan
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria.
The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.
The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2020, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 28% to 36% return-seeking assets and 64% to 72% liability-hedging assets.
Our Pension Plan is funded in compliance with the federal government’s funding requirements.
Plan Assets
The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:
2020 2019
Equity 21% 20%
Real estate 3 3
Fixed income 69 71
Cash 3 1
Hedge funds 4 5
Total 100% 100%
Supplemental Non-qualified Defined Benefit Plans
We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are funded on a cash basis as benefits are paid.
Non-pension Defined Benefit Postretirement Healthcare Plan
BHC sponsors a retiree healthcare plan (Healthcare Plan) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for post-65 Medicare-eligible retirees is provided through an individual market healthcare exchange.
We fund the Healthcare Plan on a cash basis as benefits are paid. The Healthcare Plan provides for partial pre-funding via VEBA trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa and Kansas.
Plan Contributions
Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands):
2020 2019
Defined Contribution Plan
Company retirement contributions $ 10,455 $ 9,714
Company matching contributions $ 15,240 $ 14,558
2020 2019
Defined Benefit Plans
Defined Benefit Pension Plan $ 12,700 $ 12,700
Non-Pension Defined Benefit Postretirement Healthcare Plan $ 6,058 $ 7,033
Supplemental Non-Qualified Defined Benefit Plans $ 2,674 $ 2,344
We do not have required 2021 contributions and currently do not expect to contribute to our Pension Plan.
Fair Value Measurements
The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
Pension Plan December 31, 2020
Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a)
Total Investments
Common Collective Trust - Cash and Cash Equivalents $ - $ 16,810 $ - $ 16,810 $ - $ 16,810
Common Collective Trust - Equity - 100,311 - 100,311 - 100,311
Common Collective Trust - Fixed Income - 324,845 - 324,845 - 324,845
Common Collective Trust - Real Estate - - - - 14,301 14,301
Hedge Funds - - - - 17,454 17,454
Total investments measured at fair value $ - $ 441,966 $ - $ 441,966 $ 31,755 $ 473,721
Pension Plan December 31, 2019
Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a)
Total Investments
AXA Equitable General Fixed Income $ - $ 60 $ - $ 60 $ - $ 60
Common Collective Trust - Cash and Cash Equivalents - 7,054 - 7,054 - 7,054
Common Collective Trust - Equity - 87,106 - 87,106 - 87,106
Common Collective Trust - Fixed Income - 306,275 - 306,275 - 306,275
Common Collective Trust - Real Estate - - - - 14,239 14,239
Hedge Funds - - - - 19,550 19,550
Total investments measured at fair value $ - $ 400,495 $ - $ 400,495 $ 33,789 $ 434,284
_____________
(a) Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.
Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2020
Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments
Cash and Cash Equivalents $ 8,165 $ - $ - $ 8,165 $ 8,165
Total investments measured at fair value $ 8,165 $ - $ - $ 8,165 $ 8,165
Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2019
Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments
Cash and Cash Equivalents $ 8,305 $ - $ - $ 8,305 $ 8,305
Total investments measured at fair value $ 8,305 $ - $ - $ 8,305 $ 8,305
Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:
Pension Plan
Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.
Common Collective Trust-Real Estate Funds: These funds are valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. Some of the funds without participant withdrawal limitations are categorized as Level 2.
The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance:
Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.
Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 10% of the shares may be redeemed at the end of each month with a 15-day notice and full redemptions are available at the end of each quarter with 60-day notice and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.
Non-pension Defined Benefit Postretirement Healthcare Plan
Cash and Cash Equivalents: This represents an investment in Northern Institutional Government Assets Portfolio, which is a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.
Other Plan Information
The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands):
Employee Benefit Plan Obligations
Defined Benefit Pension Plan Supplemental Non-qualified Defined
Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31, 2020 2019 2020 2019 2020 2019
Change in benefit obligation:
Projected benefit obligation at beginning of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817
Service cost (a)
5,411 5,383 1,579 4,995 2,056 1,815
Interest cost 13,426 17,374 1,099 1,295 1,649 2,247
Actuarial (gain) loss 47,064 56,384 962 7,132 5,804 5,976
Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033)
Plan participants’ contributions - - - - 1,510 1,455
Projected benefit obligation at end of year $ 514,008 $ 485,376 $ 55,054 $ 54,088 $ 70,238 $ 65,277
____________________
(a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised.
Fair Value Employee Benefit Plan Assets
Defined Benefit
Pension Plan Supplemental Non-qualified Defined
Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan (a)
As of December 31, 2020 2019 2020 2019 2020 2019
Change in fair value of plan assets:
Beginning fair value of plan assets $ 434,284 $ 390,796 $ - $ - $ 8,305 $ 8,162
Investment income (loss) 64,006 69,934 - - 33 260
Employer contributions 12,700 12,700 2,674 2,344 4,374 5,461
Retiree contributions - - - - 1,511 1,455
Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033)
Ending fair value of plan assets $ 473,721 $ 434,284 $ - $ - $ 8,165 $ 8,305
____________________
(a) Assets of VEBA trusts.
In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, recent capital markets volatility driven by the COVID-19 pandemic did not materially affect our unfunded status.
Amounts Recognized in the Consolidated Balance Sheets
Defined Benefit
Pension Plan Supplemental
Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31, 2020 2019 2020 2019 2020 2019
Regulatory assets $ 86,677 $ 88,471 $ - $ - $ 16,102 $ 11,670
Current liabilities $ - $ - $ 1,927 $ 1,420 $ 4,931 $ 4,802
Non-current liabilities $ 40,287 $ 51,093 $ 53,127 $ 51,243 $ 57,142 $ 52,136
Regulatory liabilities $ 3,607 $ 3,524 $ - $ - $ 2,140 $ 4,088
Accumulated Benefit Obligation
Defined Benefit
Pension Plan Supplemental
Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31, 2020 2019 2020 2019 2020 2019
Accumulated Benefit Obligation $ 498,815 $ 470,615 $ 54,779 $ 49,241 $ 70,238 $ 65,277
Components of Net Periodic Expense
Defined Benefit
Pension Plan Supplemental
Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
For the years ended December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018
Service cost (a)
$ 5,411 $ 5,383 $ 6,834 $ 1,579 $ 4,995 $ 1,764 $ 2,056 $ 1,815 $ 2,291
Interest cost 13,426 17,374 15,470 1,099 1,295 1,170 1,649 2,247 2,085
Expected return on assets (22,591) (24,401) (24,741) - - - (182) (230) (315)
Net amortization of prior service cost - 26 58 2 2 2 (546) (398) (398)
Recognized net actuarial loss (gain) 8,372 3,763 8,632 1,702 535 1,000 20 - 216
Net periodic expense $ 4,618 $ 2,145 $ 6,253 $ 4,382 $ 6,827 $ 3,936 $ 2,997 $ 3,434 $ 3,879
____________________
(a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised.
For the years ended December 31, 2020, 2019 and 2018, Service costs were recorded in Operations and maintenance expense while non service costs were recorded in Other expense on the Consolidated Statements of Income.
Change in Accounting Principle - Pension Accounting Asset Method
Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company used a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.
We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Consolidated Statements of Income for the year ended December 31, 2020.
AOCI Amounts (After-Tax)
Defined Benefit
Pension Plan Supplemental
Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31, 2020 2019 2020 2019 2020 2019
Net (gain) loss $ 5,511 $ 5,322 $ 9,323 $ 9,893 $ 100 $ 90
Prior service cost (gain) - - - 2 (144) (230)
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense $ 5,511 $ 5,322 $ 9,323 $ 9,895 $ (44) $ (140)
Assumptions
Defined Benefit
Pension Plan Supplemental
Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine benefit obligations: 2020 2019 2018 2020 2019 2018 2020 2019 2018
Discount rate 2.56 % 3.27 % 4.40 % 2.41 % 3.14 % 4.34 % 2.41 % 3.15 % 4.28 %
Rate of increase in compensation levels 3.34 % 3.49 % 3.52 % 5.00 % 5.00 % 5.00 % N/A N/A N/A
Defined Benefit
Pension Plan Supplemental
Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2020 2019 2018 2020 2019 2018 2020 2019 2018
Discount rate (a)
3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.67 % 3.15 % 4.28 % 3.60 %
Expected long-term rate of return on assets (b)
5.25 % 6.00 % 6.25 % N/A N/A N/A 2.35 % 3.00 % 3.93 %
Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 5.00 % 5.00 % 5.00 % N/A N/A N/A
_____________________________
(a) The estimated discount rate for the Defined Benefit Pension Plan is 2.56% for the calculation of the 2021 net periodic pension costs.
(b) The expected rate of return on plan assets is 4.50% for the calculation of the 2021 net periodic pension cost.
The healthcare benefit obligation at December 31 was determined as follows:
2020 2019
Trend Rate - Medical
Pre-65 for next year - All Plans 6.10% 6.40%
Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50%
Trend Year 2027 2027
Post-65 for next year - All Plans 4.92% 4.92%
Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50%
Trend Year 2029 2028
The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands):
Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan
2021 $ 25,842 $ 1,927 $ 6,108
2022 $ 26,658 $ 1,968 $ 5,965
2023 $ 27,581 $ 2,033 $ 5,725
2024 $ 28,284 $ 2,231 $ 5,532
2025 $ 29,062 $ 2,690 $ 5,244
2026-2030 $ 144,273 $ 13,117 $ 22,872
(16) SHARE-BASED COMPENSATION PLANS
Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 561,073 shares available to grant at December 31, 2020.
Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2020, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 2 years. Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in thousands):
2020 2019 2018
Stock-based compensation expense $ 5,373 $ 12,095 $ 12,390
Stock Options
The Company has not issued any stock options since 2014 and has 5,000 stock options outstanding at December 31, 2020. The amount of stock options granted and related exercise activity are not material to the Company’s consolidated financial statements.
Restricted Stock
The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.
The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over three years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.
A summary of the status of the restricted stock and restricted stock units at December 31, 2020, was as follows:
Restricted Stock Weighted-Average Grant Date Fair Value
(in thousands)
Balance at January 1, 2020 192 $ 65.66
Granted 116 69.49
Vested (90) 63.30
Forfeited (22) 65.30
Balance at December 31, 2020 196 $ 69.05
The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, were as follows:
Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested
(in thousands)
2020 $ 69.49 $ 6,722
2019 $ 73.66 $ 8,438
2018 $ 57.31 $ 6,776
As of December 31, 2020, there was $10.3 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.2 years.
Performance Share Plan
Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.
The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.7 million at December 31, 2020 would be reclassified as a liability.
Outstanding performance periods at December 31, 2020 were as follows (shares in thousands):
Possible Payout Range of Target
Grant Date Performance Period Target Grant of Shares Minimum Maximum
January 1, 2020 January 1, 2020 - December 31, 2022 36 0% 200%
January 1, 2019 January 1, 2019 - December 31, 2021 36 0% 200%
January 1, 2018 January 1, 2018 - December 31, 2020 49 0% 200%
A summary of the status of the Performance Share Plan at December 31, 2020 was as follows:
Equity Portion Liability Portion
Weighted-Average Grant Date Fair Value (a)
Weighted-Average Fair Value at
Shares Shares December 31, 2020
(in thousands) (in thousands)
Performance Shares balance at beginning of period 67 $ 64.32 67
Granted 19 81.42 19
Forfeited (2) 73.89 (2)
Vested (23) 63.52 (23)
Performance Shares balance at end of period 61 $ 69.71 61 $ 52.42
_____________________
(a) The grant date fair values for the performance shares granted in 2020, 2019 and 2018 were determined by Monte Carlo simulation using a blended volatility of 18%, 21% and 21%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.
The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:
Weighted Average Grant Date Fair Value
December 31, 2020 $ 81.42
December 31, 2019 $ 68.72
December 31, 2018 $ 61.82
Performance plan payouts have been as follows (in thousands):
Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value
January 1, 2017 to December 31, 2019 2020 14 $ 1,100 $ 2,199
January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720
January 1, 2015 to December 31, 2017 2018 - - -
On January 27, 2021, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2018 through December 31, 2020 performance period was at the 55th percentile of its peer group and confirmed a payout equal to 112.35% of target shares, valued at $3.3 million. The payout was fully accrued at December 31, 2020.
As of December 31, 2020, there was $2.0 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.7 years.
(17) INCOME TAXES
CARES Act
On March 27, 2020, President Trump signed the CARES Act, which contained, in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a COVID-19 employee retention tax credit of up to $5,000 per eligible employee.
Eligible employers are taxpayers experiencing either: (1) a full or partial suspension of business operations stemming from a government COVID-19 related order or (2) a more than 50% drop in gross receipts compared to the corresponding calendar quarter in 2019. This 50% employee retention tax credit applies up to $10,000 in qualified wages paid between March 13, 2020 through December 31, 2020, and is refundable to the extent it exceeds the employer portion of payroll tax liability.
Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all services to the employer for the credit to potentially apply.
Additionally, the CARES Act accelerates the amount of alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns. In 2020, we filed for, and received, a refund of approximately $2.4 million of AMT credit carryforwards under this provision.
During the year ended December 31, 2020, we utilized the payroll tax deferral provision which allowed us to defer payment of approximately $10 million of Social Security employment tax liabilities. We are currently reviewing the potential future benefits of the CARES Act related to employee retention tax credits to assess the impact on our financial position, results of operations and cash flows.
TCJA
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the federal and state utility commissions, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018, we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2020, the Company has amortized $13.3 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2020, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.
Income Tax Expense (Benefit)
Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
2020 2019 2018
Current:
Federal $ (6,020) $ (8,578) $ 325
State 847 138 247
Current income tax expense (benefit) (5,173) (8,440) 572
Deferred:
Federal 35,672 34,551 (25,022)
State 2,419 3,469 783
Deferred income tax expense (benefit) 38,091 38,020 (24,239)
Income tax expense (benefit) $ 32,918 $ 29,580 $ (23,667)
Effective Tax Rates
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
2020 2019 2018
Federal statutory rate 21.0 % 21.0 % 21.0 %
State income tax (net of federal tax effect) 2.4 1.5 2.3
Non-controlling interest (a)
(1.2) (1.2) (1.3)
Tax credits(b) (c)
(9.2) (3.9) (2.0)
Flow-through adjustments (d)
(1.6) (2.4) (1.6)
Jurisdictional consolidation project (e)
- - (28.5)
Uncertain Tax Benefits 1.5 - -
Valuation Allowance 0.7 - -
Other tax differences 0.6 (1.6) (0.1)
TCJA corporate rate reduction (f)
- - 1.6
Amortization of excess deferred income tax expense (g)
(2.3) (1.2) (0.7)
Effective Tax Rate 11.9 % 12.2 % (9.3) %
_________________________
(a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded.
(b) The current year increase of PTCs reflect full year production of two wind facilities that were acquired/ placed into service during 2019; Top of Iowa purchased February 2019 and Busch Ranch II with an in-service date of November 2019. Additionally, in November 2020, the Corriedale qualifying wind facility was placed in service.
(c) In 2020, the Company completed a research and development study which encompassed tax years from 2013 to 2019.
(d) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.
(e) In 2018, the Company restructured certain legal entities from earlier acquisitions, which resulted in additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, and deferred tax benefits of $73 million.
(f) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items.
(g) Primarily TCJA - see above.
Deferred Tax Assets and Liabilities
The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
2020 2019
Deferred tax assets:
Regulatory liabilities $ 90,535 $ 89,754
State tax credits 23,339 23,261
Federal NOL 96,155 120,624
State NOL 9,914 13,537
Partnership 15,601 14,030
Credit Carryovers 51,445 27,139
Other deferred tax assets 40,143 33,395
Less: Valuation allowance (13,943) (12,063)
Total deferred tax assets 313,189 309,677
Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences (551,137) (533,292)
Regulatory assets (28,007) (23,586)
Goodwill (30,590) (15,875)
State deferred tax liability (73,910) (72,911)
Other deferred tax liabilities (38,169) (24,732)
Total deferred tax liabilities (721,813) (670,396)
Net deferred tax liability $ (408,624) $ (360,719)
Net Operating Loss Carryforwards
At December 31, 2020, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):
Amounts Expiration Dates
Federal NOL Carryforward $ 378,236 2022 to 2037
Federal NOL Carryforward $ 79,644 No expiration
State NOL Carryforward (a)
$ 173,867 2021 to 2040
_________________________
(a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.
As of December 31, 2020, we had a $1.1 million valuation allowance against the state NOL carryforwards. Our 2020 analysis of the ability to utilize such NOLs resulted in a $0.8 million increase in the valuation allowance reduced by previously reserved expiring NOL of $0.2 million, which results in an increase to tax expense of $0.8 million net of federal income tax and a decrease to the state NOL deferred tax asset of $0.2 million. The valuation allowance adjustment was primarily attributable to statutory rate reduction for years beyond 2020.
Unrecognized Tax Benefits
The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
Changes in Uncertain Tax Positions
Beginning balance at January 1, 2018 $ 3,263
Additions for prior year tax positions 251
Reductions for prior year tax positions (417)
Additions for current year tax positions 486
Settlements -
Ending balance at December 31, 2018 3,583
Additions for prior year tax positions 446
Reductions for prior year tax positions (862)
Additions for current year tax positions 998
Settlements -
Ending balance at December 31, 2019 4,165
Additions for prior year tax positions 3,788
Reductions for prior year tax positions (1,313)
Additions for current year tax positions 1,743
Settlements -
Ending balance at December 31, 2020 $ 8,383
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $4.3 million.
We recognized no interest expense associated with income taxes for the years ended December 31, 2020, December 31, 2019 and December 31, 2018. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2020 and December 31, 2019.
The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which filed a separate consolidated tax return from BHC and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. BHC is no longer subject to examination for tax years prior to 2017.
As of December 31, 2020, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2021.
State tax credits have been generated and are available to offset future state income taxes. At December 31, 2020, we had the following state tax credit carryforwards (in thousands):
State Tax Credit Carryforwards Expiration Year
ITC $ 23,060 2023 to 2041
Research and development $ 278 No expiration
As of December 31, 2020, we had a $12.8 million valuation allowance against the state ITC carryforwards. Our 2020 analysis of the ability to utilize such ITC resulted in a $1.3 million increase in the valuation allowance, which resulted in an increase to tax expense of $1.3 million. The valuation allowance adjustment was primarily attributable to changes in forecasted future state taxable income.
(18) BUSINESS SEGMENT INFORMATION
Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.
Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the Chief Operating Decision Maker (CODM) assesses performance. The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.
Segment information was as follows (in thousands):
Total Assets (net of intercompany eliminations) as of December 31, 2020 2019
Electric Utilities $ 3,120,928 $ 2,900,983
Gas Utilities 4,376,204 4,032,339
Power Generation 404,220 417,715
Mining 77,085 77,175
Corporate and Other 110,349 130,245
Total assets $ 8,088,786 $ 7,558,457
Capital Expenditures (a) for the years ended December 31,
2020 2019
Electric Utilities $ 271,104 $ 222,911
Gas Utilities 449,209 512,366
Power Generation 9,329 85,346
Mining 8,250 8,430
Corporate and Other 17,500 20,702
Total capital expenditures $ 755,392 $ 849,755
_________________
(a) Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows.
Property, Plant and Equipment as of December 31, 2020 2019
Electric Utilities $ 3,248,480 $ 3,059,135
Gas Utilities 3,312,613 2,981,498
Power Generation 534,803 534,518
Mining 187,540 180,473
Corporate and Other 22,094 29,055
Total property, plant and equipment $ 7,305,530 $ 6,784,679
Consolidating Income Statement
Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total
Revenue -
Contracts with customers $ 687,929 $ 959,696 $ 6,090 $ 27,089 $ - $ - $ 1,680,804
Other revenues 2,201 9,962 1,566 2,408 - - 16,137
690,130 969,658 7,656 29,497 - - 1,696,941
Inter-company operating revenue -
Contracts with customers 23,914 4,724 97,169 31,478 167 (157,452) -
Other revenues - 288 222 100 352,976 (353,586) -
23,914 5,012 97,391 31,578 353,143 (511,038) -
Total revenue 714,044 974,670 105,047 61,075 353,143 (511,038) 1,696,941
Fuel, purchased power and cost of natural gas sold 267,045 354,645 8,993 - 83 (138,362) 492,404
Operations and maintenance, including taxes 196,794 303,577 33,695 39,033 284,501 (305,823) 551,777
Depreciation, depletion and amortization 94,150 100,559 20,247 9,235 25,150 (24,884) 224,457
Adjusted operating income (loss) $ 156,055 $ 215,889 $ 42,112 $ 12,807 $ 43,409 $ (41,969) $ 428,303
Interest expense, net (143,470)
Impairment of investment (6,859)
Other income (expense), net (2,293)
Income tax benefit (expense) (32,918)
Income from continuing operations 242,763
(Loss) from discontinued operations, net of tax -
Net income 242,763
Net income attributable to noncontrolling interest (15,155)
Net income available for common stock $ 227,608
Consolidating Income Statement
Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total
Revenue -
Contracts with customers $ 684,445 $ 1,007,187 $ 7,580 $ 27,180 $ - $ - $ 1,726,392
Other revenues 5,191 384 1,859 1,074 - $ - 8,508
689,636 1,007,571 9,439 28,254 - - 1,734,900
Inter-company operating revenue -
Contracts with customers 23,116 2,459 91,577 32,053 230 (149,435) -
Other revenues - - 242 1,322 343,975 (345,539) -
23,116 2,459 91,819 33,375 344,205 (494,974) -
Total revenue 712,752 1,010,030 101,258 61,629 344,205 (494,974) 1,734,900
Fuel, purchased power and cost of natural gas sold 268,297 425,898 9,059 - 268 (132,693) 570,829
Operations and maintenance, including taxes 195,581 301,844 28,429 40,032 286,799 (303,776) 548,909
Depreciation, depletion and amortization 88,577 92,317 18,991 8,970 22,065 (21,800) 209,120
Adjusted operating income (loss) 160,297 189,971 44,779 12,627 35,073 (36,705) 406,042
Interest expense, net (137,659)
Impairment of investment (19,741)
Other income (expense), net (5,740)
Income tax benefit (expense) (29,580)
Income from continuing operations 213,322
(Loss) from discontinued operations, net of tax -
Net income 213,322
Net income attributable to noncontrolling interest (14,012)
Net income available for common stock $ 199,310
Consolidating Income Statement
Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total
Revenue -
Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ - $ - $ 1,748,542
Other revenues 2,427 955 1,413 931 - - 5,726
688,699 1,023,783 7,246 34,540 - - 1,754,268
Inter-company operating revenue -
Contracts with customers 22,752 1,524 84,959 32,194 148 (141,577) -
Other revenues - - 246 1,299 379,775 (381,320) -
22,752 1,524 85,205 33,493 379,923 (522,897) -
Total revenue 711,451 1,025,307 92,451 68,033 379,923 (522,897) 1,754,268
Fuel, purchased power and cost of natural gas sold 283,840 462,153 8,592 - 44 (129,019) 625,610
Operations and maintenance, including taxes 186,175 291,481 25,135 43,728 324,916 (336,142) 535,293
Depreciation, depletion and amortization 85,567 86,434 16,110 7,965 21,161 (20,909) 196,328
Adjusted operating income (loss) 155,869 185,239 42,614 16,340 33,802 (36,827) 397,037
Interest expense, net (139,975)
Other income (expense), net (1,180)
Income tax benefit (expense) 23,667
Income from continuing operations 279,549
(Loss) from discontinued operations, net of tax (6,887)
Net income 272,662
Net income attributable to noncontrolling interest (14,220)
Net income available for common stock $ 258,442
(19) SUBSEQUENT EVENT
In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity.
Our Utilities have regulatory mechanisms to recover the increased energy costs from this record-breaking cold weather event. However, given the extraordinary impact of these higher costs to our customers, we expect our regulators to undertake a heightened review. We are engaged with our regulators to identify appropriate recovery periods over which to recover costs associated with this event as we continue to address the impacts to our customers’ bills.
As a result of this historic event, our natural gas purchases increased by approximately $600 million compared to forecasted base load for the month of February. This amount is a preliminary estimate through February 24, 2021, and does not include certain pipeline transportation charges that remain subject to settlement and payable in late March 2021. To fund February natural gas purchases and pipeline transportation charges and provide additional liquidity, we entered into a nine-month Credit Agreement on February 24, 2021, that provides for an $800 million unsecured term loan facility. The term loan, which matures on November 23, 2021, has an interest rate based on LIBOR plus 75 basis points, carries no prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We expect to repay a portion of this term loan prior to maturity and refinance the remaining portion in longer-term debt. In the event we are unable to refinance the remaining obligation under the $800 million term loan, we believe it is probable that our current plans to manage liquidity would be sufficient to meet our obligations.
Except as described above and the Note 2 disclosures surrounding Colorado Gas’ and Nebraska Gas’ jurisdictional consolidation and rate reviews, there have been no events subsequent to December 31, 2020 which would require recognition in the consolidated financial statements or disclosures.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A.CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2020. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act, as amended, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2020, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting is presented on Page 62 of this Annual Report on Form 10-K.

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ITEM 9B. OTHER INFORMATION
ITEM 9B.OTHER INFORMATION
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2021 Annual Meeting of Shareholders, which is incorporated herein by reference. Information about our Executive Officers is reported in Part 1 of this Annual Report on Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11.EXECUTIVE COMPENSATION
Information required under this item is set forth in the Proxy Statement for our 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.
EQUITY COMPENSATION PLAN INFORMATION
The following table includes information as of December 31, 2020 with respect to our equity compensation plans. These plans include the 2005 Omnibus Incentive Plan and 2015 Omnibus Incentive Plan.
Equity Compensation Plan Information
Plan category Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted-average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(a) (b) (c)
Equity compensation plans approved by security holders 154,354 (1)
$ 54.29 (1)
561,073 (2)
Equity compensation plans not approved by security holders - $ - -
Total 154,354 $ 54.29 561,073
_________________________
(1) Includes 149,354 full value awards outstanding as of December 31, 2020, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 195,875 shares of unvested restricted stock were outstanding as of December 31, 2020, which are not included in the above table because they have already been issued.
(2) Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 2021 Annual Meeting of Shareholders, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 2021 Annual Meeting to Shareholders, which is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of this report
1. Consolidated Financial Statements
Financial statements required under this item are included in Item 8 of Part II
2. Schedules
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto. Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
3.Exhibits
Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting a board of director or management compensatory plan are designated by a cross (†).
Exhibit Number Description
2.1 Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on July 14, 2015).
2.2 First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).
2.3 Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed on July 14, 2015).
3.1 Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 5, 2018).
3.2 Amended and Restated Bylaws of the Registrant dated April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on April 28, 2017).
4.1 Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
4.1.1 First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003).
4.1.2 Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
4.1.3 Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).
4.1.4 Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on November 18, 2013).
4.1.5 Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016).
4.1.6 Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016).
4.1.7 Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-K filed on August 17, 2018).
4.1.8 Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on October 4, 2019).
4.1.9 Ninth Supplemental Indenture dated as of June 17, 2020 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on June 17, 2020).
4.2 Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
4.2.1 First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
4.2.2 Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
4.2.3 Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
4.3 Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014).
4.3.1 First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014).
4.3.2 Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014).
4.4 Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
4.5 Description of Securities (filed as Exhibit 4.5 to the Registrant's Form 10-K for 2019)
10.1† Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001).
10.1.1† First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002).
10.1.2† Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).
10.2† 2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant’s Form 10-K for 2008).
10.3† Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008).
10.3.1† First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).
10.4† Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).
10.4.1† First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2018).
10.5† Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan (filed as Exhibit 10.6 to the Registrant’s Form 10-K for 2018).
10.6† Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005).
10.6.1† First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008).
10.6.2† Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).
10.7*† Black Hills Corporation Amended and Restated 2015 Omnibus Incentive Plan effective January 26, 2021.
10.8† Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013).
10.9† Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to Registrant’s Form 10-K for 2015).
10.10† Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015).
10.11*† Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on or after January 26, 2021.
10.12† Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015).
10.13† Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.14† Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2017 (filed as Exhibit 10.12 to the Registrant's Form 10-K for 2019).
10.15† Form of Short-term Incentive Plan for Officers Award Agreement effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.16*† Form of Short-term Incentive Plan for Officers Award Agreement effective for awards granted on or after January 1, 2021.
10.17*† Form of Performance Unit Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on or after January 1, 2021.
10.18† Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004).
10.19† Change in Control Agreement dated November 15, 2019 between Black Hills Corporation and Linden R. Evans (filed as Exhibit 10.15 to the Registrant's Form 10-K for 2019).
10.20† Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.16 to the Registrant's Form 10-K for 2019).
10.21† Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008).
10.21.1† First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).
10.21.2† Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012).
10.21.3† Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2014).
10.21.4† Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017 (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016).
10.21.5† Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2017).
10.21.6† Sixth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2019 (filed as Exhibit 10.18 to the Registrant’s Form 10-K for 2018).
10.22† Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.23 Equity Distribution Sales Agreement dated August 4, 2020 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on August 4, 2020).
10.24 Third Amended and Restated Credit Agreement dated as of July 30, 2018 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 31, 2018).
10.25 Amended and Restated Credit Agreement dated as of July 30, 2018 (relating to $300 million, two-year term loan), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 31, 2018).
10.25.1 First Amendment dated as of June 17, 2019 to Amended and Restated Credit Agreement dated as of July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on June 17, 2019).
10.26 Coal Leases between WRDC and the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10-K for 1989).
10.27 Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).
21* List of Subsidiaries of Black Hills Corporation.
23.1* Consent of Independent Registered Public Accounting Firm.
31.1* Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2* Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1* Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95* Mine Safety and Health Administration Safety Data
101.INS* XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
104* Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)