SEC Info - Black Hills Power Inc - ‘10-K’ for 12/31/19

Black Hills Power Inc – ‘10-K’ for 12/31/19

Black Hills Power Inc – ‘10-K’ for 12/31/19

On: Tuesday, 2/18/20, at 2:33pm ET · For: 12/31/19 · Accession #: 12400-20-2 · File #: 1-07978

Previous ‘10-K’: ‘10-K’ on 2/21/19 for 12/31/18 · Latest ‘10-K’: This Filing

Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-K’ — Annual Report
Document Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

On: Tuesday, 2/18/20, at 2:33pm ET · For: 12/31/19 · Accession #: 12400-20-2 · File #: 1-07978

Previous ‘10-K’: ‘10-K’ on 2/21/19 for 12/31/18 · Latest ‘10-K’: This Filing

Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34Filing Table of Contents

‘10-K’ — Annual ReportDocument Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

Annual Report — Form 10-K — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-K’ — Annual Report
Document Table of Contents

Page	(sequential)		(alphabetic)	↑Top
		Alternative Formats (Word, et al.) Balance Sheets Business and Properties Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Controls and Procedures Exhibits, Financial Statement Schedules Financial Statements and Supplementary Data Form 10-K Summary Glossary of Terms and Abbreviations Item 14 Item 15 Item 16 Item 1A Item 1B Item 3 Item 5 Item 7 Item 8 Item 9 Item 9A Item 9B ITEMS 1. and 2 Legal Proceedings Management's Discussion & Analysis of Financial Condition and Results of Operations Management's Discussion and Analysis of Results of Operations Management's Report on Internal Controls Over Financial Reporting Market for Registrant's Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities Note 1 Note 10 Note 10. Comprehensive Income Note 11 Note 11. Supplemental Cash Flow Information Note 12 Note 12. Employee Benefit Plans Note 13 Note 13. Commitments and Contingencies Note 14 Note 14. Related-Party Transactions Note 15. Quarterly Historical Data (unaudited) Note 1. Business Description and Summary of Significant Accounting Policies Note 2. Revenue Note 3. Property, Plant and Equipment Note 4 Note 4. Jointly Owned Facilities Note 5 Note 5. Long-term Debt Note 6. Fair Value of Financial Instruments Note 7 Note 7. Regulatory Matters Note 8 Note 8. Leases Note 9 Note 9. Income Taxes Notes to the Financial Statements Other Information Principal Accounting Fees and Services Report of Independent Registered Public Accounting Firm Risk Factors Signatures Statements of Cash Flows Statements of Common Stockholder's Equity Statements of Comprehensive Income Statements of Income Table of Contents Unresolved Staff Comments
1	1st Page – Filing Submission
"	Table of Contents
"	Glossary of Terms and Abbreviations
"	ITEMS 1. and 2
"	Business and Properties
"	Item 1A -- Risk Factors
"	Item 1A
"	Item 1B
"	Unresolved Staff Comments
"	Item 3
"	Legal Proceedings
"	Item 5
"	Market for Registrant's Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities
"	Management's Discussion and Analysis of Results of Operations
"	Item 7 -- Management's Discussion & Analysis of Financial Condition and Results of Operations
"	Item 7
"	Financial Statements and Supplementary Data
"	Item 8
"	Management's Report on Internal Controls Over Financial Reporting
"	Report of Independent Registered Public Accounting Firm
"	Statements of Income
"	Statements of Comprehensive Income
"	Balance Sheets
"	Statements of Cash Flows
"	Statements of Common Stockholder's Equity
"	Notes to the Financial Statements
"	Note 1
"	Note 1. Business Description and Summary of Significant Accounting Policies
"	Note 2. Revenue
"	Note 3. Property, Plant and Equipment
"	Note 4
"	Note 4. Jointly Owned Facilities
"	Note 5. Long-term Debt
"	Note 5
"	Note 6. Fair Value of Financial Instruments
"	Note 7
"	Note 7. Regulatory Matters
"	Note 8. Leases
"	Note 8
"	Note 9
"	Note 9. Income Taxes
"	Note 10. Comprehensive Income
"	Note 10
"	Note 11. Supplemental Cash Flow Information
"	Note 11
"	Note 12
"	Note 12. Employee Benefit Plans
"	Note 13
"	Note 13. Commitments and Contingencies
"	Note 14
"	Note 14. Related-Party Transactions
"	Note 15. Quarterly Historical Data (unaudited)
"	Item 9
"	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
"	Item 9A
"	Controls and Procedures
"	Item 9B
"	Other Information
"	Item 14
"	Principal Accounting Fees and Services
"	Exhibits, Financial Statement Schedules
"	Item 15
"	Item 16
"	Form 10-K Summary
"	Signatures

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form i 10-K



i ☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended		i December 31, 2019
i ☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ___________________ to __________________
	Commission File Number	i 1-07978



i BLACK HILLS POWER, INC.
Incorporated in	i South Dakota		IRS Identification Number		i 46-0111677

i 7001 Mount Rushmore Road	i Rapid City		i South Dakota	i 57702

Registrant’s telephone number, including area code:		i (605)	i 721-1700

Securities registered pursuant to Section 12(b) of the Act:		None

Securities registered pursuant to Section 12(g) of the Act:		i None



Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
	Yes	☐	i No	☒

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
	i Yes	☒	No	☐

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
	i Yes	☒	No	☐

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).
	i Yes	☒	No	☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

This paragraph is not applicable to the Registrant. x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	☐	Accelerated filer	☐

i Non-accelerated filer	☒	Smaller reporting company	i ☐

		Emerging growth company	i ☐

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

All outstanding shares are held by the Registrant’s parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $ i 0.



Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
Class	Outstanding at January 31, 2020
Common stock, $1.00 par value	i 23,416,396	shares

Reduced Disclosure

The Registrant meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

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GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:



AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by FASB
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Energy	The name used to conduct the business of our utility company as well as our affiliates.
BHSC	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC (doing business as Black Hills Energy)
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC (doing business as Black Hills Energy)
CFTC	United States Commodity Futures Trading Commission
Cheyenne Prairie	132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Wyoming Electric and South Dakota Electric. Cheyenne Prairie was placed into commercial service on October 1, 2014.
City of Gillette	Gillette, Wyoming
Common Use System (CUS)	The Common Use System is a joint transmission system we participate in with Basin Electric and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming.
Cooling degree day (CDD)	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
Corriedale	Wind project near Cheyenne, Wyoming, that will be 52.5 MW wind farm jointly owned by South Dakota Electric and Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program.
CPCN	Certificate of Public Convenience and Necessity
CT	Combustion turbine
DC	Direct current
DSM	Demand Side Management
ECA	Energy Cost Adjustment -- adjustment that allows us to pass the prudently-incurred cost of fuel, purchased energy and transmission related expenses through to customers.
EIA	Environmental Improvement Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible investments in and expense related to new environmental measures.
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings Inc.
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gases
Global Settlement	Settlement with a utilities commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Happy Jack	Happy Jack Wind Farm, LLC, a subsidiary of Duke Energy Generation Services

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Heating degree day (HDD)	A heating degree day is equivalent to each degree that the average of the high and the low temperature for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
Horizon Point	BHC Corporate headquarters building in Rapid City, South Dakota, which was completed in 2017.
IRS	Internal Revenue Service
kV	Kilovolt
LIBOR	London Interbank Offered Rate
MAPP	Mid-Continent Area Power Pool
MDU	Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
Moody’s	Moody’s Investor Services, Inc.
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
N/A	Not Applicable
Native load	Energy required to serve customers within our service territory
NAV	Net Asset Value
NERC	North American Electric Reliability Corporation
NOAA	National Oceanic and Atmospheric Administration
NO_x	Nitrogen Oxide
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSHA	Occupational Safety and Health Organization
PacifiCorp	PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway
Parent	Black Hills Corporation
System Peak Demand	Represents the highest point of retail usage for a single hour.
PPA	Power Purchase Agreement
PRPA	Platte River Power Authority
PSA	Power Sales Agreement
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
SO₂	Sulfur Dioxide
South Dakota Electric	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
SPP	Southwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
TFA	Transmission Facility Adjustment -- annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers.
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings (doing business as Black Hills Energy)

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Wygen III	110 MW mine-mouth coal-fired power plant in which South Dakota Electric owns a 52% interest, MDU owns a 25% interest and the City of Gillette owns the remaining 23% interest. BHP operates the plant.
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by South Dakota Electric. The WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	Cheyenne Light, Fuel and Power Company, a direct, wholly owned subsidiary of Black Hills Corporations, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).

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Forward-Looking Information

This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, we may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. Our expectations, beliefs and projections are expressed in good faith and we believe we have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in our records and other data available from third parties. Nonetheless, our expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of us are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

History and Organization

Black Hills Power (“South Dakota Electric,” the “Company,” “we,” “us” and “our”) is a South Dakota corporation doing business as Black Hills Energy. We are a regulated electric utility company headquartered in Rapid City, South Dakota. We began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation (“Parent” or “BHC”).

Business

We generate, transmit and distribute electricity to approximately 73,000 customers in Montana, South Dakota and Wyoming. We own 445 MW of generation and 3,819 miles of electric transmission and distribution lines. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems.

Capacity and Demand. System peak demands for our retail customers for each of the last three years are listed below:



	System Peak Demand (in MW)
	2019		2018		2017
	Summer	Winter	Summer	Winter	Summer	Winter
South Dakota Electric	335	320	355	314	370	310

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Regulated Power Plants. As of December 31, 2019, our ownership interests in electric generation plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Cheyenne Prairie ^(a)	Gas	Cheyenne, Wyoming	58%	55.0	2014
Wygen III^(b)	Coal	Gillette, Wyoming	52%	57.2	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995
Wyodak Plant ^(c)	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
				444.6

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(a)	Cheyenne Prairie supports the utility customers of Wyoming Electric and us. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).


(b)	We operate Wygen III, a 110 MW mine-mouth coal-fired power plant and own a 52% interest in the facility. MDU owns a 25% interest and the City of Gillette owns the remaining 23% interest. The adjacent WRDC mine furnishes all of the fuel for the plant.


(c)	Wyodak Plant, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by us. This baseload plant is operated by PacifiCorp and WRDC mine supplies all of the fuel for the plant.

Our annual 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 Source (dollars per MWh)	2019		2018		2017
Coal	$	11.48	$	11.13	$	10.96

Natural Gas	$	17.24	$	29.98	$	28.46

Diesel Oil ^(a)	$	202.08	$	268.27	$	208.86

Total Weighted Average Fuel Cost	$	13.17	$	12.74	$	12.41

Purchased Power - Coal, Gas and Oil	$	24.53	$	29.01	$	28.10

Purchased Power - Renewable Sources	$	46.69	$	54.31	$	53.08

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(a)	Included in the Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the cost per MWh is reflective of how often the units are started and how long the units run.

Our 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	2019		2018		2017
Coal	46	%	48	%	47	%
Gas and Oil	8		4		3
Total Generated	54		52		50
Purchased ^(a)	46		48		50
Total	100	%	100	%	100	%

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(a)	Wind represents approximately 13%, 7% and 6% of our purchased power in 2019, 2018, and 2017, respectively.

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Power Purchase and Power Sales Agreements. We have executed various PPAs to support our capacity and energy needs beyond our regulated power plants’ generation. We also have various long-term PSAs. Key contracts are disclosed in Note 13 and Note 14 of the Notes to the Financial Statements in this Annual Report on Form 10-K.

Transmission and Distribution. 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 own an electric transmission system, referred to as the Common Use System, with Basin Electric and Powder River Energy Corporation.

At December 31, 2019, we owned the electric transmission and distribution lines shown below:



	State	Transmission (in Line Miles)	Distribution (in Line Miles)
South Dakota Electric	South Dakota, Wyoming	1,219	2,557
South Dakota Electric - Jointly Owned ^(a)	South Dakota, Wyoming	43	—
		1,262	2,557

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(a)

We own 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western and eastern United States, respectively. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. See Note 4 of the Notes to the Financial Statements in this Annual Report on Form 10-K for additional information.

Material contracts are disclosed in Note 13 and Note 14 of the Notes to the Financial Statements in this Annual Report on Form 10-K.

Operating Agreements. Material operating agreements are disclosed in Note 14 of the Notes to the Financial Statements in this Annual Report on Form 10-K. Additional agreements shown below are also key to our operations:


•	Shared Services Agreements -


•	South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets located at the Gillette, Wyoming energy complex by the affiliate entity.


•	South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.


•	South Dakota Electric and BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility.


•	Jointly owned facilities agreements are discussed in Note 4 of the Notes to the Financial Statements in this Annual Report on Form 10-K.

Seasonal Variations of Business. We are a seasonal business and weather patterns may impact our operating performance. Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, demand is often greater in the summer and winter months for cooling and heating, respectively.

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 the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, these initiative have not had a material impact on our business.

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Rates and Regulation. We are subject to the jurisdiction of the public utilities commissions in the states where we 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 illustrates certain enacted regulatory information with respect to the states in which we operate:



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 Off-System Sale Profits Shared with Customers
SD	Global Settlement	7.76%	Global Settlement	$543.9	10/2014	ECA, Energy Efficiency Cost Recovery/DSM, TFA, EIA	70%
WY	9.9%	8.13%	46.7%/53.3%	$46.8	10/2014	ECA	65%
FERC	10.8%	8.76%	43%/57%	$138.4 ^(a)	2/2009	FERC Transmission Tariff	N/A

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(a)	Includes $121.3 million in 2019 rate base for the Common Use System formula rate that is updated annually and $17.1 million in rate base for the DC transmission tie that is based on the approved stated rate from 2005.

Rates for our retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. We have rate adjustment mechanisms in South Dakota and Wyoming which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. We are also subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. We have been granted market-based rate authority by FERC and are not required to file cost-based tariffs for wholesale electric rates. Rates charged by us for use of our transmission system are subject to regulation by FERC.

A summary of mechanisms we have in place are shown in the table below:



Electric Utility Jurisdiction	Cost Recovery Mechanisms
Electric Utility Jurisdiction	Environmental Cost	Energy Efficiency	Transmission Expense	Fuel Cost	Transmission Capital	Purchased Power
South Dakota Electric (SD)	þ	þ	þ	þ	þ	þ
South Dakota Electric (WY)		þ	þ	þ		þ
South Dakota Electric (FERC)					þ

See Note 7 of the Notes to the Financial Statements in this Annual Report on Form 10-K for information regarding current electric rate activity.

Some of the mechanisms we have in place include:

•

An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. We also have a TFA tariff which recovers the costs associated with transmission facility improvements. The EIA and TFA were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, we received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to extend the six-year moratorium period by an additional three years whereby rate increases for these recovery mechanisms will not go into effect prior to July 1, 2026. See Note 7 of the Notes to the Financial Statements in this Annual Report on Form 10-K for further information.

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•

An annual ECA which provides for the over or under recovery of fuel, transmission and purchased power cost incurred to serve South Dakota customers. Additionally, this ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $1.0 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $1.0 million. We retain the remaining 30%. For the period of July 1, 2017 through March 31, 2023, the 100% credit of power marketing margin increased from $1.0 million to $2.0 million. The ECA methodology allows us to directly assign renewable resources and firm purchases to the customer load. In Wyoming, a similar fuel and purchased power cost adjustment is also in place.


•	The Common Use System (CUS) has an annual rate determination process that is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. See Note 7 of the Notes to the Financial Statements in this Annual Report on Form 10-K for further information.

Tariff Filings. See Note 7 of the Notes to the Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information.

Operating Statistics. The following tables provide certain electric utility operating statistics for the years ended December 31:



Heating and Cooling Degree Days
	2019		2018		2017
Actual
Heating degree days	8,284		7,749		6,870
Cooling degree days	404		488		709

Variance from normal
Heating degree days	16	%	8	%	(4	)%
Cooling degree days	(36	)%	(23	)%	11	%



	Electric Revenue (in thousands)						Quantities Sold (MWh)
	2019		2018		2017		2019	2018	2017
Residential	$	72,950	$	75,319	$	72,764	555,519	546,825	526,730
Commercial	92,457		95,509		96,531		766,057	751,479	769,463
Industrial	34,893		32,748		33,464		457,413	407,683	430,300
Municipal	3,248		3,571		3,707		30,415	31,636	33,272
Subtotal Retail Revenue - Electric	203,548		207,147		206,466		1,809,404	1,737,623	1,759,765
Contract Wholesale ^(a)	19,079		33,687		30,435		368,360	900,854	722,659
Off-system/Power Marketing Wholesale	16,475		17,692		14,271		472,276	518,725	509,963
Other	52,117		39,554		37,261		—	—	—
Total Revenue and Energy Sold	291,219		298,080		288,433		2,650,040	3,157,202	2,992,387
Other Uses, Losses or Generation, net^(b)	—		—		—		148,847	203,194	195,005
Total Revenue and Energy	291,219		298,080		288,433		2,798,887	3,360,396	3,187,392
Less cost of fuel and purchased power	73,115		92,886		87,638
Gross Margin (non-GAAP) ^(c)	$	218,104	$	205,194	$	200,795


(a)	2019 revenue and purchased power, as well as associated quantities, for a certain wholesale contract have been presented on a net basis, which resulted in a decrease of $12 million, or 480,400 MWh, in 2019. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin.


(b)	Total MWh includes Other Uses, Losses or Generation, net, which is approximately 6%.


(c)	For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

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	For the year ended December 31,
Quantities Generated and Purchased (MWh)	2019	2018	2017
Coal-fired	1,495,309	1,598,957	1,485,254
Natural Gas and Oil	273,147	135,265	96,661
Total Generated	1,768,456	1,734,222	1,581,915

Purchased ^(a)	1,030,431	1,626,174	1,605,477
Total Generated and Purchased	2,798,887	3,360,396	3,187,392

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(a)	2019 purchased power quantities for a certain wholesale contract have been presented on a net basis, which resulted in a decrease of 480,400 MWh in 2019. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin.

Utility Regulation Characteristics

State Regulation

Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage us to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At December 31, 2019, we were subject to the following renewable energy portfolio standards or objectives:

•

Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, South Dakota Electric filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding South Dakota Electric from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers South Dakota Electric has in Montana and the relatively high cost of meeting the renewable requirements.


•	South Dakota. South Dakota has adopted a renewable portfolio objective 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 no renewable energy portfolio standard.

Absent a specific renewable energy mandate in the territories we serve, our current strategy is to proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. Mandatory portfolio standards have increased, and will likely continue to increase the power supply costs of our electric utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.

Federal Regulation

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. We provide FERC-jurisdictional services subject to FERC’s oversight.

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We 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 our market-based rate authority, we file Electric Quarterly Reports with FERC. We own and operate FERC-jurisdictional interstate transmission facilities and provide open access transmission service under tariffs on file with FERC. We are subject to routine audit by FERC with respect to our 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.

Environmental Matters

Water Issues. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013, and published the final rule on November 3, 2015. In 2017, the EPA postponed the implementation of the rule and set a timeline in 2018 to revise the rule. To date, the rule is being reviewed by the Office of Management and Budget. This rule will have an impact on the Wyodak Plant. Until the EPA issues the rule for publication, we cannot quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation may impact the next permit renewal which will be in 2020.

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 Sulfur Dioxide (SO2), Nitrogen Oxide (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 the power plant down if a predicted emission limit is to be exceeded. Similar efforts have been taken and similar results achieved with our natural gas fired combustion turbine sites as well.

Regional Haze (Impacts to the Wyodak Power 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-NO_x burners in the Wyodak Plant, of which we own 20%. The EPA did not agree with the State of Wyoming’s determination and overruled it in a Federal Implementation Plan (FIP). The State of Wyoming and other interested parties are challenging the EPA’s determination. If the challenge is unsuccessful, additional capital investment would be necessary to bring the Wyodak Plant into compliance. Our 20% share of this capital investment for the facility would be approximately $27 million if PacifiCorp is required to install a Selective Catalytic Reactor for NO_xcontrol. The case is currently held in abeyance in the 10th Circuit Court as the parties work on a settlement. Basin Electric, who is part of the legal action, settled with the EPA. In lieu of going to court, PacifiCorp entered into mediation with the EPA and conservation groups. PacifiCorp submitted a “Request for Reconsideration” on October 24, 2019 to the EPA and provided a copy to the court. The purpose of the submittal is to revisit the emission impacts and cost of additional investment.

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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 rule. The rule focuses on heat rate improvements on coal-fired boiler units. In July 2019, the rule was finalized and applies only to our coal-fired plants. These plants have implemented, or plan to implement, a majority of the efficiency requirements listed in the rule.

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 13 of the Notes to the Financial Statements in this Annual Report on Form 10-K.

Other Properties

In addition to the facilities previously disclosed in Items 1 and 2, we own several facilities throughout our service territories. Our owned facilities are as follows:


•	In Rapid City, South Dakota, we have a 220,000 square foot corporate headquarters building, Horizon Point, which was completed in 2017.


•	In South Dakota and Wyoming, we own various office, service center, storage, shop and warehouse space totaling approximately 103,000 square feet.

Substantially all of our tangible utility properties are subject to liens securing first mortgage bonds.

Employees

At December 31, 2019, we had 217 employees. Approximately 62% of our employees are represented by a union. We have not experienced any labor stoppages in recent years. At December 31, 2019, approximately 30% of our 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.

At December 31, 2019, certain employees were covered by the following collective bargaining agreement:



Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
South Dakota Electric	135	IBEW Local 1250	March 31, 2024

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ITEM 1A. RISK FACTORS

OPERATING RISKS

The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.

Our continued success is dependent on execution of our strategic business plans and growth strategy.

Our results of operations depend, in significant part, on our ability to execute our strategic business plans and growth strategy. Technology advancements, disruptive forces and innovations in the marketplace and changing business or regulatory conditions may negatively impact our current plans and strategies. An inability to successfully and timely adapt to changing conditions could materially affect our financial operating results including earnings, cash flow and liquidity.

We may be subject to unfavorable federal and state regulatory outcomes.

Our regulated Electric Utility is subject to cost-of-service regulation and earnings oversight from federal and three state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that each state public utility commission 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 recovery of our costs and the allowed return on invested capital. In addition, rate decisions could be influenced by many factors, including general economic conditions and the political environment.

Our Electric Utility is 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 the state utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect financial operating results including earnings, cash flow and liquidity.

We may be subject to future laws, regulations, or actions associated with fossil-fuel generation and GHG emissions.

We own and operate regulated electric power plants that burn fossil fuels (natural gas and coal). This business activity is subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.

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 and generation facilities. 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.

Our financial performance depends on the successful management of our facilities operations, including ongoing operation, construction, expansion, and refurbishment.

Operation, construction, expansion and refurbishment of electric generating facilities and electric transmission and distribution systems involve risks that could result in fires, explosions, property damage and personal injury, including death. These risks include:


•	Inherent dangers. Electricity is dangerous for employees and the general public; contact with power lines and electrical facilities and equipment can result in fires and explosions, causing significant property damage and personal injuries, including death;

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•

Weather, natural conditions and disasters. Severe weather events could negatively impact operations, including our ability to provide energy safely and reliably and our ability to complete construction, expansion or refurbishment of facilities as planned. Extreme natural conditions and other disasters such as wind, lightning, flooding and winter storms, can cause wildfires, electric transmission or distribution pole failures, outages, property damage and personal injury;


•	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;

•

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, 2019, approximately 30% of our 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 62% of our employees are represented by a collective bargaining agreement;


•	Equipment and processes. Breakdown or failure of equipment or processes, the unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology;


•	Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;

•

Interruptions to supply of fuel and other commodities used in generation and distribution. We purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit our utility’s ability to operate facilities;


•	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 environmental laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;


•	Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses; and


•	Disruption in the functioning of our information technology and network infrastructure which is vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions.

The ongoing operation of our business involves the risks described above. 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, 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 we 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.

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Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events.

Inherent in our business is a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. Many of our transmission and distribution assets are located near populated residential areas, commercial business centers and industrial sites.

These hazards could result in injury or loss of human life, cause environmental pollution, significantly damage property or natural resources and impair our ability to operate our facilities. 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 and could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.

Customer growth and usage in our service territories may fluctuate with current economic conditions, emerging technologies or responses to price increases.

Our financial operating results are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity by our customers in response to increases in prices and energy efficiency programs, economic conditions impacting decreases in customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.

Cyberattacks, terrorism, or other malicious acts 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, SCADA, information technology systems and network infrastructure to 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 operations. Attacks targeting other key information technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective. Despite our implementation of security measures and safeguards, all of our information technology systems may be vulnerable to disability, failures or unauthorized access.

Risks associated with deployment of capital may impact our ability to execute our business plans and growth strategy.

We have significant capital investment programs planned for the next five years. The successful execution of our capital investment strategy depends on, or could be affected by, a variety of factors that include, but are not limited to: extreme weather conditions, effective management of projects, availability of qualified construction personnel, including contractors, changes in commodity and other prices, governmental approvals and permitting and regulatory cost recovery.

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Weather conditions may cause fluctuation in customer usage as well as service disruptions.

Our utility business is seasonal and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Unusually mild summers and winters, therefore, could have an adverse effect on our results of operations, financial position or cash flows.

Our business is located in areas that could be subject to severe weather events such as snow and ice storms, tornadoes, strong winds, significant thunderstorms, flooding and drought. These events could result in lost operating revenues due to outages, property damage, including inoperable generation facilities and downed transmission and distribution lines, and storm restoration activities. We may not be able to recover the costs incurred following these weather events resulting in a negative impact on our financial operating results including earnings, cash flow and liquidity.

We may be subject to increased risks of regulatory 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 and SEC 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.

Certain Federal laws provide special protection to certain designated animal species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation and wind projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

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. 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.

FINANCING RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our issuer credit rating is A1 by Moody’s, A by S&P and A by Fitch. Reduction of our 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.

Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plans 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.

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We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in electricity prices and general economic and market conditions.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession, if one occurs, may lead to an increase in late payments from retail, commercial and industrial utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting insurance businesses, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited to environmental hazards, fire-related liability from natural events or inadequate facility maintenance, distribution property losses and cyber-security risks.

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, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes. Our electric utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery. The increasing cost, or inadequate recovery of, rising employee benefit costs may adversely affect our financial operating results including earnings, cash flow or liquidity.

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

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.

A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perception of our business, operating results and stock price could be adversely affected.

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ENVIRONMENTAL RISKS

Developments in federal and state laws concerning GHG regulations and air emissions relating to climate could materially increase our generation costs and render some of our generating units uneconomical to operate and maintain.

To the extent climate change occurs, our businesses could be adversely impacted. Warmer temperatures during the heating season or cooler temperatures during the cooling season in our service territories could adversely affect financial results through lower MWh sold and associated lower revenues.

We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the section “Environmental Matters”.

There is uncertainty surrounding current climate regulation due to legal challenges, new federal climate legislation anticipated in the future, or state climate legislation and regulation. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial position or cash flows.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or reduction of load of coal-fired power generation facilities and potential increased load of our combined cycle natural gas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain; this could cause those generating units to be de-commissioned, potentially resulting in impairment costs. We will attempt to recover any remaining asset value; however, any unrecovered costs could have a material impact on our results of operations and financial condition.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, or failure to comply, could increase significantly.

We are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.

We may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on our financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub caption within Item 8, Note 13, “Commitments and Contingencies,” of our Notes to the Financial Statements in this Annual Report on Form 10-K.

PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER

MATTERS

All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Our discussion and analysis for the year ended December 31, 2019 compared to 2018 is included herein. For discussion and analysis for the year ended December 31, 2018 compared to 2017, 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, 2018, which was filed with the SEC on February 20, 2019.

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

Significant Events

2019 Overview


•	On September 17, 2019, South Dakota Electric completed construction on the final 94-mile segment of a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.

•

In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and jointly-filed CPCN to construct Corriedale. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from SDPUC to increase the offering under the program by 12.5 MW to 32.5 MW. The two electric utilities also received a determination from the WPSC to increase the project to 52.5 MW. The $79 million project is expected to be in service by year-end 2020.

Non-GAAP Financial Measure

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

Gross margin is calculated as operating revenue less cost of fuel and purchased power. Our gross margin is impacted by the fluctuations in power 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 measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

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Results of Operations

Operating results were as follows (in thousands):



For the years ended December 31,	2019			Variance			2018			Variance			2017

Revenue ^(a)	$	291,219		$	(6,861	)	$	298,080		$	9,647		$	288,433
Fuel and purchased power ^(a)	73,115			(19,771		)	92,886			5,248			87,638
Gross margin (non-GAAP)	218,104			12,910			205,194			4,399			200,795
				—						—
Operations and maintenance	134,167			7,308			126,859			9,890			116,969
Operating income	83,937			5,602			$	78,335		(5,491		)	83,826
				—						—
Interest expense, net	(21,718		)	(370		)	(21,348		)	(968		)	(20,380		)
Other income (expense), net	(5,816		)	(5,146		)	(670		)	(2,650		)	1,980
Income tax expense	(9,501		)	1,171			(10,672		)	3,456			(14,128		)
Net income	$	46,902		$	1,257		$	45,645		$	(5,653	)	$	51,298


(a)	2019 revenue and purchased power, as well as associated quantities, for a certain wholesale contract have been presented on a net basis. This resulted in a decrease of $12 million to both 2019 revenue and fuel and purchased power. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin.

2019 Compared to 2018

Gross margin increased primarily due to $6.5 million of reduced purchased power capacity charges, $3.4 million of increased rider revenues from new investments and $3.1 million of increased commercial and industrial demand.

Operations and maintenance expense increased primarily due to higher employee costs and outside services expenses.

Other income (expense), net. For the year ended December 31, 2019, we expensed $5.4 million of development costs related to projects we no longer intend to construct.

Income tax expense decreased primarily due to tax benefits for excess deferred tax amortization related to tax reform.



	For the year ended December 31,
Contracted power plant fleet availability (a)	2019		2018		2017
Coal-fired plants ^(b)	91.0	%	92.7	%	86.0	%
Other plants ^(c)	85.0	%	96.8	%	96.4	%
Total availability	87.8	%	94.9	%	91.6	%

_________________________


(a)	Availability is calculated using a weighted average based on capacity of our generating fleet.


(b)	2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.


(c)	2019 included planned outages at Neil Simpson CT and Lange CT.

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Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. The following table represents our credit rating from each agency’s review which were in effect at December 31, 2019:



Rating Agency	Senior Secured Rating
S&P ^(a)	A
Moody’s ^(b)	A1
Fitch ^(c)	A

__________


(a)	On April 30, 2019, S&P affirmed A rating.


(b)	On December 20, 2019, Moody’s affirmed A1 rating.


(c)	On August 29, 2019, Fitch affirmed A rating.

Critical Accounting Policies Involving Significant Accounting Estimates

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

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

Regulation

Our utility operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric 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 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 for recovery in current rates or in future rate proceedings.

To some degree, we are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.

As of December 31, 2019 and 2018, we had total regulatory assets of $76 million and $76 million respectively, and total regulatory liabilities of $166 million and $163 million respectively. See Note 7 of the Notes to the Financial Statements for further information.

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Income Taxes

We file a federal income tax return with other members of the Parent consolidated group. Each tax-paying 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.

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.

As of December 31, 2019, we have a regulatory liability associated with TCJA related items of $98 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, 2019, the Company has amortized $3.1 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in 2019, 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 financial statements.

See Note 9 of the Notes to the Financial Statements in this Annual Report on Form 10-K for additional information.

Pension and Other Postretirement Benefits

As described in Note 12 of the Financial Statements in this Annual Report on Form 10-K, we have a defined benefit pension plan, a post-retirement healthcare plan and non-qualified retirement plans. A Master Trust was established for the investment of assets of the defined benefit pension plan.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, health care 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.

The 2020 pension benefit cost for our non-contributory funded pension plan is expected to be $2.1 million compared to $0.6 million in 2019. The increase in pension benefit cost is driven primarily by a decrease in the discount rate and lower expected return on assets.

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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	2019 Increase/(Decrease) PBO/APBO ^(a)	2020 Increase/(Decrease) Expense - Pretax

Pension
Discount rate ^(b)	+/- 0.5	(3,879)/4,270	(703)/709
Expected return on assets	+/- 0.5	N/A	(282)/282

OPEB
Discount rate ^(b)	+/- 0.5	(225)/245	9/(10)
Expected return on assets	+/- 0.5	N/A	N/A

__________________________


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


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

New Accounting Pronouncements

See Note 1 of our Notes to the Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2019 or pending adoption.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page

Management’s Report on Internal Controls Over Financial Reporting	27
Report of Independent Registered Public Accounting Firm	28

Statements of Income	29
Statements of Comprehensive Income	30
Balance Sheets	31
Statements of Cash Flows	33
Statements of Common Stockholder’s Equity	34
Notes to the Financial Statements	35
Note 1. Business Description and Summary of Significant Accounting Policies	35
Note 2. Revenue	40
Note 3. Property, Plant and Equipment	41
Note 4. Jointly Owned Facilities	41
Note 5. Long-term Debt	42
Note 6. Fair Value of Financial Instruments	43
Note 7. Regulatory Matters	44
Note 8. Leases	46
Note 9. Income Taxes	47
Note 10. Comprehensive Income	49
Note 11. Supplemental Cash Flow Information	50
Note 12. Employee Benefit Plans	50
Note 13. Commitments and Contingencies	56
Note 14. Related-Party Transactions	59
Note 15. Quarterly Historical Data (unaudited)	61

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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, 2019, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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, 2019.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting because this requirement is inapplicable to companies such as ours which are known as non-accelerated filers.

Black Hills Power

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Black Hills Power, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the "Company") as of December 31, 2019 and 2018, the related statements of income, comprehensive income,common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

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 and in accordance with auditing standards generally accepted in the United States of America. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 18, 2020

We have served as the Company’s auditor since 2002.

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BLACK HILLS POWER, INC.

STATEMENTS OF INCOME



Years ended December 31,	2019			2018			2017
	(in thousands)

Revenue	$	i 291,219		$	i 298,080		$	i 288,433

Operating expenses:
Fuel and purchased power	i 73,115			i 92,886			i 87,638
Operations and maintenance	i 84,661			i 79,523			i 74,064
Depreciation and amortization	i 41,322			i 39,649			i 35,862
Taxes - property	i 8,184			i 7,687			i 7,043
Total operating expenses	i 207,282			i 219,745			i 204,607

Operating income	i 83,937			i 78,335			i 83,826

Other income (expense):
Interest expense	( i 23,972		)	( i 22,545		)	( i 22,421		)
AFUDC - borrowed	i 1,437			i 521			i 1,137
Interest income	i 817			i 676			i 904
AFUDC - equity	i —			i 221			i 2,165
Other income (expense), net	( i 5,816		)	( i 891		)	( i 185		)
Total other income (expense)	( i 27,534		)	( i 22,018		)	( i 18,400		)

Income before income taxes	i 56,403			i 56,317			i 65,426
Income tax expense	( i 9,501		)	( i 10,672		)	( i 14,128		)

Net income	$	i 46,902		$	i 45,645		$	i 51,298

The accompanying Notes to the Financial Statements are an integral part of these Financial Statements.

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BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME



Years ended December 31,	2019			2018		2017
	(in thousands)

Net income	$	i 46,902		$	i 45,645	$	i 51,298

Other comprehensive income (loss):
Benefit plan liability adjustments - net gain (loss) (net of tax of $83, $(62), and $50 respectively)	( i 312		)	i 235		( i 94		)
Benefit plan liability adjustments - prior service costs (net of tax of $2, $0 and $0, respectively)	( i 8		)	i —		i —
Reclassification adjustment of benefit plan liability - net (gain) loss (net of tax of $(166), $(22), and $(30), respectively)	( i 101		)	i 81		i 56
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(132), $(13), and $(22), respectively)	( i 68		)	i 51		i 42
Other comprehensive income (loss), net of tax	( i 489		)	i 367		i 4

Comprehensive income	$	i 46,413		$	i 46,012	$	i 51,302

See Note 10 for additional disclosure related to comprehensive income.

The accompanying Notes to the Financial Statements are an integral part of these Financial Statements.

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BLACK HILLS POWER, INC.

BALANCE SHEETS



As of December 31,	2019			2018
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash	$	i 6		$	i 112
Accounts receivable, net	i 25,532			i 28,431
Accounts receivable from affiliates	i 7,838			i 8,119
Materials, supplies and fuel	i 27,950			i 24,853
Regulatory assets, current	i 21,588			i 19,052
Other current assets	i 4,949			i 4,538
Total current assets	i 87,863			i 85,105

Investments	i 5,079			i 4,889

Property, plant and equipment	i 1,494,670			i 1,381,045
Less: accumulated depreciation and amortization	( i 400,054		)	( i 376,160		)
Total property, plant and equipment, net	i 1,094,616			i 1,004,885

Other assets:
Regulatory assets, non-current	i 54,109			i 56,680
Other assets, non-current	i 18,690			i 9,729
Total other assets, non-current	i 72,799			i 66,409
TOTAL ASSETS	$	i 1,260,357		$	i 1,161,288

The accompanying Notes to the Financial Statements are an integral part of these Financial Statements.

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BLACK HILLS POWER, INC.

BALANCE SHEETS

(Continued)



As of December 31,	2019			2018
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	i 20,654		$	i 25,122
Accounts payable to affiliates	i 32,121			i 25,804
Accrued liabilities	i 25,492			i 34,193
Money pool notes payable	i 57,585			i 38,690
Notes payable to Parent	i 25,000			i —
Regulatory liabilities, current	i 3,162			i 2,574
Total current liabilities	i 164,014			i 126,383

Long-term debt	i 340,176			i 340,035

Deferred credits and other liabilities:
Deferred income tax liabilities, net	i 112,202			i 114,009
Regulatory liabilities, non-current	i 163,009			i 160,642
Benefit plan liabilities	i 14,636			i 14,606
Other, non-current liabilities	i 15,397			i 1,368
Total deferred credits and other liabilities	i 305,244			i 290,625

Commitments and contingencies (Notes 5, 12, 13 and 14)	i			i

Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	i 23,416			i 23,416
Additional paid-in capital	i 39,575			i 39,575
Retained earnings	i 389,312			i 342,145
Accumulated other comprehensive income (loss)	( i 1,380		)	( i 891		)
Total stockholder’s equity	i 450,923			i 404,245
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	i 1,260,357		$	i 1,161,288

The accompanying Notes to the Financial Statements are an integral part of these Financial Statements.

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BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS



Years ended December 31,	2019			2018			2017
	(in thousands)
Operating activities:
Net income	$	i 46,902		$	i 45,645		$	i 51,298
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	i 41,322			i 39,649			i 35,862
Deferred income taxes	( i 4,281		)	i 5,218			i 1,004
Employee benefits	i 778			i 1,518			i 817
Other adjustments	i 9,325			i 2,555			i 264
Change in operating assets and liabilities -
Accounts receivable and other current assets	( i 933		)	( i 3,576		)	i 3,287
Accounts payable and other current liabilities	( i 9,881		)	( i 5,648		)	( i 7,254		)
Regulatory assets	( i 3,290		)	i 27			i 978
Regulatory liabilities	i 639			i 2,561			i —
Contributions to defined benefit pension plan	( i 1,753		)	( i 1,795		)	( i 4,000		)
Other operating activities	( i 1,089		)	( i 1,407		)	( i 1,853		)
Net cash provided by operating activities	i 77,739			i 84,747			i 80,403

Investing activities:
Property, plant and equipment additions	( i 122,833		)	( i 73,456		)	( i 79,566		)
Other investing activities	i 1,093			( i 488		)	( i 861		)
Net cash (used in) investing activities	( i 121,740		)	( i 73,944		)	( i 80,427		)

Financing activities:
Change in money pool notes payable, net	i 18,895			( i 10,707		)	( i 194		)
Notes payable to parent	i 25,000			i —			i —
Net cash provided by (used in) financing activities	i 43,895			( i 10,707		)	( i 194		)

Net change in cash	( i 106		)	i 96			( i 218		)

Cash beginning of year	i 112			i 16			i 234
Cash end of year	$	i 6		$	i 112		$	i 16

See Note 11 for Supplemental Cash Flows information.

The accompanying Notes to the Financial Statements are an integral part of these Financial Statements.

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BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY



	2019			2018			2017
	(in thousands)
Common stock shares:
Balance beginning of year	i 23,416			i 23,416			i 23,416
Issuance of common stock	i —			i —			i —
Balance end of year	i 23,416			i 23,416			i 23,416

Common stock amounts:
Balance beginning of year	$	i 23,416		$	i 23,416		$	i 23,416
Issuance of common stock	i —			i —			i —
Balance end of year	$	i 23,416		$	i 23,416		$	i 23,416

Additional paid-in capital:
Balance beginning of year	$	i 39,575		$	i 39,575		$	i 39,575
Issuance of common stock	i —			i —			i —
Balance end of year	$	i 39,575		$	i 39,575		$	i 39,575

Retained earnings:
Balance beginning of year	$	i 342,145		$	i 332,499		$	i 322,933
Net income	i 46,902			i 45,645			i 51,298
Non-cash dividend to Parent company	i —			( i 36,000		)	( i 42,000		)
Implementation of ASU 2016-02 Leases	( i 7		)	i —			i —
Other	i 272			i 1			i 268
Balance end of year	$	i 389,312		$	i 342,145		$	i 332,499

Accumulated other comprehensive loss:
Balance beginning of year	$	( i 891	)	$	( i 1,258	)	$	( i 1,262	)
Other comprehensive (loss) income, net of tax	( i 489		)	i 367			i 4
Balance end of year	$	( i 1,380	)	$	( i 891	)	$	( i 1,258	)

Total stockholder’s equity	$	i 450,923		$	i 404,245		$	i 394,232

The accompanying Notes to the Financial Statements are an integral part of these Financial Statements.

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NOTES TO THE FINANCIAL STATEMENTS

December 31, 2019, 2018 and 2017

(1) i BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc., doing business as Black Hills Energy (“South Dakota Electric,” the “Company,” “we,” “us,” or “our”), is a regulated electric utility serving customers in Montana, South Dakota and Wyoming. We are a wholly-owned subsidiary of BHC, a public registrant listed on the New York Stock Exchange.

Basis of Presentation

The financial statements include the accounts of South Dakota Electric and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 4) and are prepared in accordance with GAAP.

Use of Estimates

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.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. As of December 31, 2019 and 2018, we have i no cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts, net of write-offs or payment received.

We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

Following is a summary of accounts receivable as of December 31 (in thousands):



	2019			2018
Accounts receivable, trade	$	i 14,778		$	i 16,236
Unbilled revenue	i 10,914			i 12,333
Less Allowance for doubtful accounts	( i 160		)	( i 138		)
Accounts receivable, net	$	i 25,532		$	i 28,431

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Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):



	Balance at beginning of year		Additions charged to costs and expenses		Deductions charged to costs and expenses			Balance at end of year
2019	$	i 138	$	i 899	$	( i 877	)	$	i 160
2018	$	i 224	$	i 911	$	( i 997	)	$	i 138
2017	$	i 157	$	i 882	$	( i 815	)	$	i 224

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are recorded using the weighted-average cost method.

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.

Regulatory Accounting

Our regulated electric operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. We account for income and expense items in accordance with accounting standards for regulated operations:


•	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, 2019 and 2018, we had total regulatory assets of $ i 76 million and $ i 76 million respectively, and total regulatory liabilities of $ i 166 million and $ i 163 million respectively. See Note 7 for further information.

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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.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of i 2.2% in 2019, i 2.3% in 2018 and i 2.1% in 2017.

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands):



	2019		2018
Accrued employee compensation, benefits and withholdings	$	i 4,387	$	i 4,206
Accrued property taxes	i 6,685		i 6,332
Accrued income taxes	i 1,946		i 12,536
Customer deposits and prepayments	i 5,486		i 5,204
Accrued interest	i 4,935		i 4,627
Other (none of which is individually significant)	i 2,053		i 1,288
Total accrued liabilities	$	i 25,492	$	i 34,193

Derivatives and Hedging Activities

Derivatives are measured at fair value and recognized as either assets or liabilities on the Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our operations, we enter into contracts to buy and sell energy to meet the requirements of our customers.

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From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, or to lock in the Treasury yield component associated with anticipated issuance of senior notes. For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of December 31, 2019, we have no outstanding interest rate swap agreements.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists.

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. We currently do not have any Level 3 investments.

Income Taxes

We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

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.

We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

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We recognize interest income or interest expense and penalties related to income tax matters in Income tax expense on the 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, non-current liabilities or in Deferred income tax liabilities, net on the accompanying Balance Sheets. See Note 9 for additional information.

Recently Issued Accounting Standards

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. We are currently reviewing this standard to assess the impact on our financial position, results of operations and 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. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. 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.

Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19

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. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted.

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 doubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

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We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easements agreements.

Adoption of the new standard resulted in the recording of an operating lease right-of-use asset and off-setting obligation liability of $ i 14 million, primarily for the Wygen III ground lease, as of January 1, 2019.

See Note 8 for additional details on leases.

(2) i 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 electric utility services tariffs - Our regulated operations, as defined by ASC 980, 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 commodity electricity and 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 regulated utility sales are subject to regulatory-approved tariffs.

•

Power sales agreements - We have long-term wholesale power sales agreements with other load serving entities for the sale of excess power from owned generating units. In addition to these long-term contracts, the Company also sells excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price, and is variable based on energy delivered.

The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition. Sales tax and other similar taxes are excluded from revenues.



	Year ended December 31, 2019		Year ended December 31, 2018
	(in thousands)
Customer types:
Retail	$	i 202,569	$	i 197,184
Wholesale	i 19,078		i 33,687
Market - off-system sales	i 16,475		i 17,691
Transmission/Other	i 50,329		i 49,015
Revenue from contracts with customers	i 288,451		i 297,577
Other revenues	i 2,768		i 503
Total revenues	$	i 291,219	$	i 298,080

Timing of revenue recognition:
Services transferred over time	$	i 288,451	$	i 297,577
Revenue from contracts with customers	$	i 288,451	$	i 297,577

/ /

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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 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 revenue accounted for under separate accounting guidance, including alternative revenue programs revenue under ASC 980.

Significant Judgments and Estimates

Unbilled Revenue

To the extent that deliveries have occurred but a bill has not been issued, the Company accrues an estimate of the revenue since the latest billing. This estimate is calculated based on 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 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 and is further discussed above. We do not typically incur costs that would be capitalized, to obtain or fulfill a contract.

(3) i PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):



				2019				2018
				Weighted				Weighted
				Average				Average
	2019			Useful Life (in years)	2018			Useful Life (in years)
Property, plant, and equipment:
Production	$	i 612,517		i 46	$	i 588,565		i 46
Transmission	i 235,390			i 51	i 208,610			i 48
Distribution	i 431,783			i 46	i 394,475			i 45
Plant acquisition adjustment ^(a)	i 4,870			i 32	i 4,870			i 32
General	i 165,342			i 29	i 154,621			i 28
Total plant-in-service	i 1,449,902				i 1,351,141
Construction work in progress	i 44,768				i 29,904
Total property, plant and equipment	i 1,494,670				i 1,381,045
Less accumulated depreciation and amortization	( i 400,054		)		( i 376,160		)
Total property, plant and equipment, net	$	i 1,094,616			$	i 1,004,885

__________________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with i 11 years remaining.

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(4) i JOINTLY OWNED FACILITIES

Our financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses is reflected in the appropriate categories of operating expenses in the Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.


•	We own a i 20% interest in the Wyodak Plant (the “Plant”), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the Plant’s capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses.

•

We own a i 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the SPP region. The total transfer capacity of the transmission tie is i 400 MW, including i 200 MW West to East and i 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.


•	We own a i 52% interest in the Wygen III power plant. 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 a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.


•	We own i 55 MW of the Cheyenne Prairie combined cycle, a i 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Wyoming Electric owns the remaining i 40 MW. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

As of December 31, 2019, our interests in jointly-owned generating facilities and transmission systems were (in thousands):

Interest in jointly-owned facilities

Plant in Service

Construction Work in Progress

Less Accumulated Depreciation

Plant Net of Accumulated Depreciation

Wyodak Plant

i 116,074

i 729

( i 64,413

)

i 52,390

Transmission Tie

i 19,862

i 4,161

( i 6,612

)

i 17,411

Wygen III

i 146,161

i 400

( i 25,518

)

i 121,043

Cheyenne Prairie

i 92,684

i 532

( i 14,202

)

i 79,014

(5) i LONG-TERM DEBT

Long-term debt outstanding at December 31 was as follows (in thousands):



		Interest Rate at		Balance Outstanding
	Due Date	December 31, 2019		December 31, 2019		December 31, 2018
First Mortgage Bonds due 2032	August 15, 2032	i 7.23	%	i 75,000		i 75,000
First Mortgage Bonds due 2039	November 1, 2039	i 6.13	%	i 180,000		i 180,000
First Mortgage Bonds due 2044	October 20, 2044	i 4.43	%	i 85,000		i 85,000
Series 94A Debt ^(a)	June 1, 2024	i 1.84	%	i 2,855		i 2,855
Less unamortized debt discount				( i 82	)	( i 86	)
Less unamortized deferred financing costs				( i 2,597	)	( i 2,734	)
Long-term Debt, net				i 340,176		i 340,035

___________________


(a)	Variable interest rate at December 31, 2019.

Net deferred financing costs of approximately $ i 2.6 million and $ i 2.7 million were recorded on the accompanying Balance Sheets in long-term debt at December 31, 2019 and 2018, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $ i 0.1 million for each of the years ended December 31, 2019, 2018 and 2017 are included in Interest expense on the accompanying Statements of Income.

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Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, 2019.

Long-term Debt Maturities

Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts and unamortized deferred financing costs) are as follows (in thousands):



2020	$	i —
2021	$	i —
2022	$	i —
2023	$	i —
2024	$	i 2,855
Thereafter	$	i 340,000

(6) i FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at December 31 were as follows (in thousands):



	2019				2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash ^(a)	$	i 6	$	i 6	$	i 112	$	i 112
Notes payable to Parent ^(b)	$	i 25,000	$	i 25,000	$	i —	$	i —
Long-term debt ^(c)	$	i 340,176	$	i 458,286	$	i 340,035	$	i 412,894

_______________


(a)	The cash fair value approximates carrying value and therefore is classified as Level 1 in the fair value hierarchy. We believe that the market risk arising from cash in a bank account is minimal.


(b)	Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.


(c)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified as Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.

Notes payable to Parent

For additional information on our Notes payable to Parent, see Note 14.

Long-Term Debt

For additional information on our long-term debt, see Note 5.

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(7) i REGULATORY MATTERS

We had the following regulatory assets and liabilities as of December 31 (in thousands):



	2019			2018
Regulatory assets
Loss on reacquired debt^(a)	$	i 989		$	i 1,259
Deferred taxes on AFUDC ^(b)	i 4,927			i 5,020
Employee benefit plans and related deferred taxes ^(c)	i 20,661			i 19,868
Deferred energy and fuel cost adjustments^(a)	i 23,203			i 20,334
Deferred taxes on flow through accounting ^(c)	i 9,801			i 8,749
Decommissioning costs ^(b)	i 6,211			i 8,196
Vegetation management ^(a)	i 8,062			i 10,366
Other regulatory assets ^(a)	i 1,843			i 1,940
Total regulatory assets	i 75,697			i 75,732
Less current regulatory assets	( i 21,588		)	( i 19,052		)
Regulatory assets, non-current	$	i 54,109		$	i 56,680

Regulatory liabilities
Cost of removal for utility plant ^(a)	$	i 57,318		$	i 52,366
Employee benefit plans and related deferred taxes ^(c)	i 7,023			i 7,518
Excess deferred income taxes ^(c)	i 98,228			i 100,276
TCJA revenue reserve	i 3,162			i 2,523
Other regulatory liabilities ^(c)	i 440			i 533
Total regulatory liabilities	i 166,171			i 163,216
Less current regulatory liabilities	( i 3,162		)	( i 2,574		)
Regulatory liabilities, non-current	$	i 163,009		$	i 160,642

____________________

(a) We are allowed 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 increases in rates.

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.

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 itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and other post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income. 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.

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Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. We file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by the applicable state utility commissions.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.

Decommissioning Costs - We received approval in 2014 for regulatory treatment on the remaining net book values and decommissioning costs of our decommissioned coal plants.

Vegetation Management Costs - We received approval in 2013 for regulatory treatment on vegetation management maintenance costs for our distribution system rights-of-way.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and other postretirement benefit 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.

Excess Deferred Income Taxes - The revaluation of our deferred tax assets and liabilities due to the passage of the TCJA is recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See Note 9 for additional information.

TCJA Revenue Reserve - Revenue to be returned to customers as a result of the TCJA. See Note 9 for additional information.

Regulatory Matters

Settlement

On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the i 6-year moratorium period by an additional i 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $ i 5.4 million of development costs 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 i 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA.

Renewable Ready

In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and related jointly-filed CPCN to construct Corriedale. The wind project will be jointly owned by the i two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by i 12.5 MW to i 32.5 MW. The i two electric utilities also received a determination from the WPSC that the wind project can be increased to i 52.5 MW. The $ i 79 million project is expected to be in service by year-end 2020.

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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, 2019 the annual revenue requirement increased by $ i 1.9 million and included estimated weighted average capital additions of $ i 31 million for 2018 and 2019 combined. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.

(8) i LEASES

We have a ground lease for the Wygen III generating facility with an affiliate and communication tower site and operation center facility leases with third parties. Our leases have remaining terms ranging from i 1 year to i 30 years.

The components of lease expense were as follows (in thousands):



	Income Statement Location	For the year ended December 31, 2019
Operating lease cost	Operations and maintenance	$	i 908
Variable lease cost	Operations and maintenance	i 137
Total lease cost		$	i 1,045

Supplemental balance sheet information related to leases was as follows (in thousands):



	Balance Sheet Location	As of December 31, 2019
Assets:
Operating lease assets	Other assets, non-current	$	i 14,374
Total lease assets		$	i 14,374

Liabilities:
Current:
Operating leases	Accrued liabilities	$	i 293

Noncurrent:
Operating leases	Other deferred credits and other liabilities	i 14,105
Total lease liabilities		$	i 14,398

Supplemental cash flow information related to leases was as follows (in thousands):



	For the year ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	i 912
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	i —



	As of December 31, 2019
Weighted average remaining lease term (years):
Operating leases	i 30 years

Weighted average discount rate:
Operating leases	i 4.3	%

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Scheduled maturities of operating lease liabilities for future years were as follows (in thousands):



	Total
2020	$	i 912
2021	i 911
2022	i 911
2023	i 908
2024	i 906
Thereafter	i 21,128
Total lease payments	i 25,676
Less imputed interest	i 11,278
Present value of lease liabilities	$	i 14,398

As previously disclosed in Note 11 of the Notes to the Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands):



	Operating Leases
2019	$	i 911
2020	i 856
2021	i 855
2022	i 856
2023	i 853
Thereafter	i 21,947
Total lease payments	$	i 26,278

(9) i INCOME TAXES

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 has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $ i 103 million. Of the $ i 103 million, approximately $ i 101 million was ultimately reclassified to a regulatory liability. As of December 31, 2019 we have a regulatory liability associated with TCJA related items of $ i 98 million. 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, 2019, the Company has amortized $ i 3.1 million of this regulatory liability.

Income tax expense for the years ended December 31 was as follows (in thousands):



	2019			2018		2017
Current:
Federal	$	i 13,782		$	i 5,454	$	i 13,124

Deferred:
Federal	( i 4,281		)	i 5,218		i 1,004

Total income tax expense	$	i 9,501		$	i 10,672	$	i 14,128

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The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):



	2019			2018
Deferred tax assets:
Regulatory liabilities	$	i 25,623		$	i 25,587
Other	i 9,128			i 4,721
Total deferred tax assets	i 34,751			i 30,308

Deferred tax liabilities:
Accelerated depreciation and other plant related differences	( i 125,138		)	( i 125,594		)
Regulatory assets	( i 7,193		)	( i 7,147		)
Deferred costs	( i 8,264		)	( i 8,572		)
Other	( i 6,358		)	( i 3,004		)
Total deferred tax liabilities	( i 146,953		)	( i 144,317		)

Net deferred tax liability	$	( i 112,202	)	$	( i 114,009	)

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:



	2019	2018	2017
Federal statutory rate	i 21.0%	i 21.0%	i 35.0%
Amortization of excess deferred and investment tax credits	( i 3.0)	( i 1.3)	( i 0.1)
Flow-through adjustments ^(a)	( i 1.5)	( i 1.7)	( i 1.8)
TCJA corporate rate reduction ^(b)	i —	i 2.5	( i 9.2)
Other	i 0.3	( i 1.6)	( i 2.3)
	i 16.8%	i 18.9%	i 21.6%

_________________________


(a)	Flow-through adjustments related primarily to an accounting method for tax purposes that allows us to take a current tax deduction for repair costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to tax expense.

(b)

On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21%, effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes required by the change. During the year ended December 31, 2018, we recorded approximately $ i 0.9 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items.

/ i

The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands):



	2019			2018
Unrecognized tax benefits at January 1	$	i 249		$	i 302
Additions for current year tax positions	i —			i —
Additions for prior year tax positions	i —			i 2
Reductions for prior year tax positions	( i 33		)	( i 55		)
Unrecognized tax benefits at December 31	$	i 216		$	i 249

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is not material to the financial results of the Company.

It is the Company’s continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2019 and 2018, the interest expense recognized was not material to the financial results of the Company.

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We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations on or before December 31, 2020.

We file income tax returns in the United States federal jurisdictions as a member of the BHC consolidated group.

(10) i OTHER COMPREHENSIVE INCOME

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges and the amortization of components of our defined benefit plans. 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 Statements of Income for the period, net of tax (in thousands):



	Location on the Statements of Income	Amounts Reclassified from AOCI
		December 31, 2019			December 31, 2018
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	( i 64	)	$	( i 64	)
Income tax	Income tax benefit (expense)	i 132			i 13
Total reclassification adjustments related to cash flow hedges, net of tax		$	i 68		$	( i 51	)

Amortization of components of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	( i 65	)	$	( i 103	)
Income tax	Income tax benefit (expense)	i 166			i 22
Total reclassification adjustments related to defined benefit plans, net of tax		$	i 101		$	( i 81	)

Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $ i 50 million of our First Mortgage Bonds due on August 15, 2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $ i 1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated other comprehensive loss and is being amortized over the life of the related bonds.

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Balances by classification included within AOCI, net of tax, on the accompanying Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Employee Benefit Plans			Total

As of December 31, 2018	$	( i 500	)	$	( i 391	)	$	( i 891	)
Other comprehensive income (loss) before reclassifications	i —			( i 320		)	( i 320		)
Amounts reclassified from AOCI	( i 68		)	( i 101		)	( i 169		)
As of December 31, 2019	$	( i 568	)	$	( i 812	)	$	( i 1,380	)


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Employee Benefit Plans			Total

As of December 31, 2017	$	( i 551	)	$	( i 707	)	$	( i 1,258	)
Other comprehensive income (loss) before reclassifications	i —			i 235			i 235
Amounts reclassified from AOCI	i 51			i 81			i 132
As of December 31, 2018	$	( i 500	)	$	( i 391	)	$	( i 891	)

(11) i SUPPLEMENTAL CASH FLOW INFORMATION



Years ended December 31,	2019			2018			2017
	(in thousands)
Non-cash investing and financing activities -
Accrued property, plant and equipment purchases at December 31	$	i 12,305		$	i 15,180		$	i 6,565
Non-cash decrease to money pool note receivable, net	$	i —		$	( i 36,000	)	$	( i 42,000	)
Non-cash dividend to Parent	$	i —		$	i 36,000		$	i 42,000

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	( i 21,909	)	$	( i 21,988	)	$	( i 21,517	)
Income taxes (paid), net	$	( i 24,372	)	$	( i 10,394	)	$	( i 12,719	)

(12) i EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

BHC sponsors 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 to 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 i 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 i 20% per year with i 100% vesting when the participant has i 5 years of service with the Company.

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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 allocation range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2019, the expected rate of return on pension plan assets is based on the targeted asset allocation range of i 29% to i 37% return-seeking assets and i 63% to i 71% liability-hedging assets.

Our Pension Plan is funded in compliance with the federal government’s funding requirements.

Plan Assets

The percentages of total plan asset by investment category of our Pension Plan assets at December 31 were as follows:



	2019		2018
Equity securities	i 20	%	i 17	%
Real estate	i 3		i 4
Fixed income funds	i 71		i 71
Cash and cash equivalents	i 2		i 3
Hedge funds	i 4		i 5
Total	i 100	%	i 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. Pre-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plan. Healthcare coverage for Medicare-eligible BHP retirees is provided through an individual market healthcare exchange.

Plan Assets

We fund our Healthcare Plan on a cash basis as benefits are paid.

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Plan Contributions

Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare benefits include company and participant paid premiums.

Contributions for the years ended December 31 were as follows (in thousands):



	2019		2018
Defined Contribution Plan
Company retirement contributions	$	i 888	$	i 876
Company matching contributions	$	i 1,275	$	i 1,272



	2019		2018
Defined Benefit Plans
Defined Benefit Pension Plan	$	i 1,753	$	i 1,795
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	i 739	$	i 388
Supplemental Non-qualified Defined Benefit Plans	$	i 266	$	i 238

While we do not have required contributions, we expect to make approximately $ i 1.7 million in contributions to our Pension Plan in 2020.

Fair Value Measurements

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):

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

i —

i 8

i —

i 8

i —

i 8

Common Collective Trust - Cash and Cash Equivalents

i —

i 978

i —

i 978

i —

i 978

Common Collective Trust - Equity

i —

i 12,072

i —

i 12,072

i —

i 12,072

Common Collective Trust - Fixed Income

i —

i 42,449

i —

i 42,449

i —

i 42,449

Common Collective Trust - Real Estate

i —

i 1,974

Hedge Funds

i —

i 2,709

Total investments measured at fair value

i —

i 55,507

i —

i 55,507

i 4,683

i 60,190

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Pension Plan

December 31, 2018

Level 1

Level 2

Level 3

Total Investments Measured at Fair Value

NAV ^(a)

Total Investments

AXA Equitable General Fixed Income

i —

i 261

i —

i 261

i —

i 261

Common Collective Trust - Cash and Cash Equivalents

i —

i 1,388

i —

i 1,388

i —

i 1,388

Common Collective Trust - Equity

i —

i 9,436

i —

i 9,436

i —

i 9,436

Common Collective Trust - Fixed Income

i —

i 39,047

i —

i 39,047

i —

i 39,047

Common Collective Trust - Real Estate

i —

i 9

i —

i 9

i 1,896

i 1,905

Hedge Funds

i —

i 2,627

Total investments measured at fair value

i —

i 50,141

i —

i 50,141

i 4,523

i 54,664

________________________

(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.

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. 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. i 20% of the shares may be redeemed at the end of each month with a i 10-day notice and full redemptions are available at the end of each quarter with i 30-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.

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Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Balance Sheets, components of the net periodic expense and elements of AOCI:

Benefit Obligations

Defined Benefit Pension Plan

Supplemental Non-qualified Defined Benefit Plans

Non-pension Defined Benefit Postretirement Healthcare Plan

As of December 31 (in thousands)

2019

2018

2019

2018

2019

2018

Change in benefit obligation:

Projected benefit obligation at beginning of year

i 61,919

i 67,562

i 2,992

i 3,418

i 5,055

i 5,970

Service cost

i 365

i 516

i —

i 148

i 193

Interest cost

i 2,410

i 2,194

i 114

i 108

i 186

i 179

Actuarial loss (gain)

i 7,482

( i 2,878

)

i 406

( i 296

)

i 507

( i 889

)

Benefits paid

( i 5,234

)

( i 3,562

)

( i 266

)

( i 238

)

( i 739

)

( i 389

)

Plan participants transfer to affiliate

i 119

( i 1,913

)

i —

( i 77

)

( i 129

)

Plan participants’ contributions

i —

i 96

i 120

Projected benefit obligation at end of year

i 67,061

i 61,919

i 3,246

i 2,992

i 5,176

i 5,055

Employee Benefit Plan Assets

Defined Benefit Pension Plan

Supplemental Non-qualified Defined Benefit Plans

Non-pension Defined Benefit Postretirement Healthcare Plan

As of December 31 (in thousands)

2019

2018

2019

2018

2019

2018

Beginning fair value of plan assets

i 54,664

i 59,884

i —

Investment income (loss)

i 8,902

( i 1,884

)

i —

Employer contributions

i 1,753

i 1,795

i 266

i 238

i 643

i 268

Retiree contributions

i —

i 96

i 120

Benefits paid

( i 5,234

)

( i 3,563

)

( i 266

)

( i 238

)

( i 739

)

( i 388

)

Plan participants transfer to affiliate

i 105

( i 1,568

)

i —

Ending fair value of plan assets

i 60,190

i 54,664

i —

/ i

The funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands):



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2019		2018		2019		2018		2019		2018
Regulatory asset	$	i 20,117	$	i 19,099	$	i —	$	i —	$	i —	$	i —
Current liability	$	i —	$	i —	$	i 321	$	i 230	$	i 586	$	i 466
Non-current liability	$	i 7,121	$	i 7,255	$	i 2,925	$	i 2,762	$	i 4,590	$	i 4,589
Regulatory liability	$	i —	$	i —	$	i —	$	i —	$	i 1,675	$	i 2,441

Accumulated Benefit Obligation



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31 (in thousands)	2019		2018		2019		2018		2019		2018
Accumulated benefit obligation	$	i 65,225	$	i 59,987	$	i 3,246	$	i 2,992	$	i 5,176	$	i 5,055

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Components of Net Periodic Expense

Net periodic expense consisted of the following for the year ended December 31 (in thousands):

Defined Benefit

Pension Plan

Supplemental
Non-qualified Defined Benefit Plans

Non-pension Defined Benefit Postretirement Healthcare Plan

2019

2018

2017

2019

2018

2017

2019

2018

2017

Service cost

i 365

i 516

i 545

i —

i 148

i 193

i 206

Interest cost

i 2,410

i 2,194

i 2,341

i 114

i 108

i 116

i 186

i 179

i 176

Expected return on assets

( i 3,405

)

( i 3,545

)

( i 3,591

)

i —

Amortization of prior service cost (credits)

i 10

i 43

i —

( i 336

)

( i 336

)

( i 336

)

Recognized net actuarial loss (gain)

i 1,221

i 2,063

i 1,230

i 65

i 103

i 87

i —

Net periodic expense

i 601

i 1,271

i 568

i 179

i 211

i 203

( i 2

)

i 36

i 46

For the years ended December 31, 2019 and 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense, on the Statements of Income. For the year ended December 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Statements of Income.

AOCI

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
	2019		2018		2019		2018		2019		2018
Net (gain) loss	$	i —	$	i —	$	i 812	$	i 391	$	i —	$	i —
Total AOCI	$	i —	$	i —	$	i 812	$	i 391	$	i —	$	i —

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Assumptions



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2019		2018		2017		2019		2018		2017		2019		2018		2017
Weighted-average assumptions used to determine benefit obligations:
Discount rate	i 3.27	%	i 4.40	%	i 3.71	%	i 3.10	%	i 4.30	%	i 3.62	%	i 3.15	%	i 4.28	%	i 3.60	%
Rate of increase in compensation levels	i 3.49	%	i 3.52	%	i 3.43	%	N/A		N/A		N/A		N/A		N/A		N/A

Weighted-average assumptions used to determine net periodic benefit cost for plan year:
Discount rate^(a)	i 4.40	%	i 3.71	%	i 4.27	%	i 4.30	%	i 3.62	%	i 4.12	%	i 4.28	%	i 3.60	%	i 3.84	%
Expected long-term rate of return on assets ^(b)	i 6.00	%	i 6.25	%	i 6.75	%	N/A		N/A		N/A		i 3.00	%	i 3.93	%	N/A
Rate of increase in compensation levels	i 3.52	%	i 3.43	%	i 3.47	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________


(a)	The estimated discount rate for the Defined Benefit Pension Plan is i 3.27% for the calculation of the 2020 net periodic pension costs.


(b)	The expected rate of return on plan assets is i 5.25% for the calculation of the 2020 net periodic pension cost.

The healthcare benefit obligation was determined at December 31 as follows:



	2019		2018
Trend Rate - Medical
Pre-65 for next year	i 6.40	%	i 6.70	%
Pre-65 Ultimate trend rate	i 4.50	%	i 4.50	%
Trend Year	i 2027		i 2027

Post-65 for next year	i 4.92	%	i 4.94	%
Post-65 Ultimate trend rate	i 4.50	%	i 4.50	%
Trend Year	i 2028		i 2026

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
2020	$	i 3,620	$	i 321	$	i 586
2021	$	i 3,766	$	i 317	$	i 622
2022	$	i 3,833	$	i 315	$	i 591
2023	$	i 3,951	$	i 311	$	i 522
2024	$	i 4,022	$	i 308	$	i 474
2025-2028	$	i 19,882	$	i 1,142	$	i 1,853

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(13) i COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

We have the following power purchase and transmission services agreements, not including related party agreements, as of December 31, 2019 (see Note 14 for information on related party agreements):


•	A PPA with PacifiCorp, expiring December 31, 2023, for the purchase of i 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.


•	A firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides i 50 MW of capacity and energy to be transmitted annually by PacifiCorp.


•	A PPA with PRPA to purchase up to i 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):



Contract	Contract Type	2019		2018		2017
PacifiCorp	Electric capacity and energy	$	i 7,477	$	i 13,681	$	i 13,218
PacifiCorp	Transmission access	$	i 1,741	$	i 1,742	$	i 1,671
Thunder Creek	Gas transport capacity	$	i 422	$	i 633	$	i 633
PRPA	Wind energy	$	i 688	$	i 223	$	i —

Future Contractual Obligations

The following is a schedule of future minimum payments required under power purchase, transmission services and gas supply agreements (in thousands):



2020	$	i 6,531
2021	$	i 6,203
2022	$	i 6,203
2023	$	i 6,203
2024	$	i —
Thereafter	$	i —

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Power Sales Agreements

We have the following significant long-term power sales contracts with non-affiliated third-parties:


•	During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with i 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.

•

An agreement to serve MDU capacity and energy up to a maximum of i 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023. Additionally, we have firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with MDU through December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

•

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first i 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which is renewed annually on September 3, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

•

We have an amended agreement, effective January 1, 2019, to supply up to i 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028. The terms of the contract run 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. i 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
2019-2020	i 15	MW	i 10	MW	i 5	MW
2020-2022	i 15	MW	i 7	MW	i 8	MW
2022-2023	i 15	MW	i 8	MW	i 7	MW
2023-2028	i 10	MW	i 5	MW	i 5	MW


•	An agreement through December 31, 2021 to provide i 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.

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. They 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.

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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 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 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.

(14) i RELATED-PARTY TRANSACTIONS

Dividend to Parent

We did not record any dividends in 2019. We recorded dividends to our Parent of $ i 36 million and changed the Utility Money Pool note by $ i 36 million in 2018.

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):



	2019		2018
Accounts receivable from affiliates	$	i 7,838	$	i 8,119
Accounts payable to affiliates	$	i 32,121	$	i 25,804

Money Pool Notes Receivable and Notes Payable

We participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however, the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of BHC’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus i 1.0%. The cost of borrowing under the Utility Money Pool was i 2.21% at December 31, 2019.

We had the following balances with the Utility Money Pool as of December 31 (in thousands):

Interest income (expense) relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands):



	2019			2018			2017
Interest income (expense)	$	( i 775	)	$	( i 401	)	$	i 272

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Notes payable to Parent

_______________

(a) Note bears interest at i 4.51%, expired December 31, 2019, is eligible for annual renewal and was renewed through December 31, 2020. Interest payable related to this note was $ i 0.2 million as of December 31, 2019.

Interest expense allocation from Parent

BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2019, 2018 and 2017, we were allocated $ i 1.2 million, $ i 1.3 million, and $ i 1.4 million, respectively, of interest expense from BHC.

Other Balances and Transactions

We have the following Power Purchase, Transmission Services, and Ground Lease Agreements with affiliated entities:


•	Wyoming Electric has a PPA with Happy Jack, expiring September 3, 2028, which provides up to i 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells i 50% of the facility output to South Dakota Electric.


•	Wyoming Electric has a PPA with Silver Sage, expiring September 30, 2029, which provides up to i 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells i 20 MW of energy from Silver Sage to South Dakota Electric.


•	A Generation Dispatch Agreement with Wyoming Electric that requires us to purchase all of Wyoming Electric’s excess energy.


•	A Wygen III Ground Lease with WDRC expiring in 2050 with i three automatic renewal terms of i 20 years each.

Related-party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of i 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

Related-party Revenue and Purchases

We had the following related-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:



	2019		2018		2017
	(in thousands)
Revenues:
Energy sold to Wyoming Electric	$	i 1,333	$	i 2,064	$	i 2,481
Rent from electric properties	$	i 3,583	$	i 3,634	$	i 3,680
Horizon Point shared facility revenue	$	i 12,026	$	i 11,211	$	i 1,420

Fuel and purchased power:
Purchases from WRDC mine	$	i 17,041	$	i 17,532	$	i 15,948
Purchase of excess energy from Wyoming Electric	$	i 856	$	i 511	$	i 601
Purchase of renewable wind energy from Wyoming Electric - Happy Jack	$	i 1,968	$	i 1,942	$	i 1,924
Purchase of renewable wind energy from Wyoming Electric - Silver Sage	$	i 3,579	$	i 3,586	$	i 3,290
Gas transportation service agreement with Wyoming Electric for firm and interruptible gas transportation	$	i 309	$	i 364	$	i 393

Table of Contents

Related-party Corporate Support

We had the following corporate support for the years ended December 31:



	2019		2018		2017
	(in thousands)
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	i 39,667	$	i 34,578	$	i 27,869

Horizon Point Shared Facilities Agreement

South Dakota Electric and BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility.

(15) i QUARTERLY HISTORICAL DATA (Unaudited)

We operate on a calendar year basis. i The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2019
Revenues	$	i 79,041	$	i 69,246	$	i 77,022	$	i 65,910
Operating income	$	i 24,642	$	i 17,310	$	i 22,004	$	i 19,981
Net income	$	i 15,497	$	i 10,148	$	i 13,743	$	i 7,514

2018
Revenues	$	i 73,815	$	i 70,676	$	i 78,067	$	i 75,522
Operating income	$	i 20,364	$	i 19,495	$	i 21,428	$	i 17,048
Net income	$	i 11,760	$	i 11,125	$	i 13,317	$	i 9,443

Table of Contents


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of 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, 2019. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2019, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting is presented on Page 27 of this Annual Report on Form 10-K.

ITEM 9B. OTHER INFORMATION

None.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table sets forth the aggregate fees for services provided to us for the fiscal years ended December 31 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):



Deloitte & Touche LLP	2019		2018
Audit Fees	$	510	$	592
Tax Fees	272		195
Total	$	782	$	787

Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.

Tax Fees. Fees for services related to tax compliance, tax planning and advice including assistance with tax audits. These services include assistance regarding federal tax compliance and advice, review of tax returns, and federal tax planning.

The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit Committee’s pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establishes pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.

Table of Contents



ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Financial Statements

		Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.

	2.	Schedules

Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2019, 2018 and 2017



		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 elsewhere in the financial statements incorporated by reference in this Form 10-K.

SCHEDULE II

Valuation and qualifying accounts are detailed within Note 1 of the Notes to the Financial Statements in this Annual Report on Form 10-K.

Table of Contents


3.	Exhibits



Exhibit Number	Description

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 March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

4.1*	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. 333-150669-01)).
	First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan 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. 333-150669-01)).
	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 Registration Statement on Form S-3 (No. 333-150669-01)).
	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).

10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

31.1	Certification of Chief Executive Officer pursuant to Rule13a-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 Rule13a-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.

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)

_________________________


*	Previously filed as part of the filing indicated and incorporated by reference herein.

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.


ITEM 16.	FORM 10-K SUMMARY

None.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		BLACK HILLS POWER, INC.

		By	/s/ *LINDEN R. EVANS*
		Linden R. Evans, Chairman, President and
		Chief Executive Officer
Dated:	February 18, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



/s/ *LINDEN R. EVANS*	Director and	February 18, 2020
Linden R. Evans, Chairman, President and	Principal Executive Officer
Chief Executive Officer

/s/ *RICHARD W. KINZLEY*	Director and	February 18, 2020
Richard W. Kinzley, Senior Vice President	Principal Financial and
and Chief Financial Officer	Accounting Officer

/s/ *BRIAN G. IVERSON*	Director	February 18, 2020
Brian G. Iverson

This ‘10-K’ Filing	Date	Other Filings

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Filed on:	2/18/20
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Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).