UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
¨	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 1-07978



BLACK HILLS POWER, INC.
Incorporated in South Dakota		IRS Identification Number 46-0111677
7001 Mount Rushmore Road, Rapid City, South Dakota 57702

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

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

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

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x 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.

Yes x 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.

Yes x 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).

Yes x 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 ¨

Non-accelerated filer x (Do not check if a smaller reporting company)

Smaller reporting company ¨

Emerging growth company ¨

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. ¨

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

Yes ¨ No x

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

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 $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, 2019
Common stock, $1.00 par value	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.



TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS AND ABBREVIATIONS	3

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	6

ITEM 1A.	RISK FACTORS	12

ITEM 1B.	UNRESOLVED STAFF COMMENTS	18

ITEM 3.	LEGAL PROCEEDINGS	18

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	18

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	19

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	25

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	59

ITEM 9A.	CONTROLS AND PROCEDURES	59

ITEM 9B.	OTHER INFORMATION	59

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	59

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	60

ITEM 16.	FORM 10-K SUMMARY	61

	SIGNATURES	62

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
Baseload plant	A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate.
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation, the Parent of Black Hills Power, Inc.
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business of our utility company as well as our utility affiliates
Black Hills Energy South Dakota Electric	Includes Black Hills Power’s operations in South Dakota, Wyoming and Montana
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of BHC (doing business as Black Hills Energy South Dakota)
Black Hills Service Company	Black Hills Service Company LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Energy Wyoming Electric	Includes Cheyenne Light’s electric utility operations
CFTC	United States Commodity Futures Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial service on October 1, 2014.
City of Gillette	Gillette, Wyoming
Cooling degree day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
CPP	Clean Power Plan
CT	Combustion turbine
DC	Direct current
DSM	Demand Side Management
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers.
EIA	Environmental Improvement Adjustment
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
GCA	Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.



GHG	Greenhouse gases
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Happy Jack	Happy Jack Wind Farm, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
IRS	Internal Revenue Service
kV	Kilovolt
LIBOR	London Interbank Offered Rate
MAPP	Mid-Continent Area Power Pool
MATS	Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units
MDU	Montana-Dakota Utilities Company
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
NOL	Net Operating Loss
NOAA	National Oceanic and Atmospheric Administration
NOAA Climate Normals	This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NO_x	Nitrogen Oxide
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
Peak System Load	Peak system load represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership.
PPA	Power Purchase 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
SourceGas	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s Rating Services



Spinning Reserve	Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages.
SPP	Southwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States
TCA	Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate review.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
TFA	Transmission Facility Adjustment
Thunder Creek	Thunder Creek Gas Services, LLC
WECC	Western Electricity Coordinating Council
Winter Storm Atlas	An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC
Wyodak Plant	Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.
Wyoming Electric	Includes Cheyenne Light’s electric utility operations

PART I

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, and 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.

ITEMS 1 and 2. BUSINESS AND PROPERTIES

General

Black Hills Power (the “Company”, “we”, “us” and “our”) is a regulated electric utility incorporated in South Dakota, doing business as South Dakota Electric and serving customers in South Dakota, Wyoming and Montana. We began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation (“Parent” or “BHC”). Engaging in the generation, transmission and distribution of electricity provides a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends to our Parent, and our overall performance and growth.

As of December 31, 2018, our ownership interests in electric generation plants were as follows:



Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	Year Installed
Wygen III^(a)	Coal	Gillette, WY	52%	57.2	2010
Neil Simpson II	Coal	Gillette, WY	100%	90.0	1995
Wyodak ^(b)	Coal	Gillette, WY	20%	72.4	1978
Cheyenne Prairie ^(c)	Gas	Cheyenne, WY	58%	55.0	2014
Neil Simpson CT	Gas	Gillette, WY	100%	40.0	2000
Lange CT	Gas	Rapid City, SD	100%	40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, SD	100%	10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, SD	100%	80.0	1977-1979
				444.6

_______________________


(a)	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. WRDC furnishes all of the coal fuel supply for the plant.


(b)	Wyodak is a 362 MW mine-mouth coal-fired power plant owned 80% by PacifiCorp and 20% by us. This baseload plant is operated by PacifiCorp and WRDC furnishes all of the coal fuel supply for 100% of the plant.


(c)	Cheyenne Prairie, a gas-fired power generation facility includes one combined-cycle, 95 MW unit that is jointly owned by Wyoming Electric (40 MW) and us (55 MW).

Distribution and Transmission. Our distribution and transmission system serves approximately 73,000 electric customers, with an electric transmission system of 1,231 miles of high voltage lines (greater than 69 kV) and 2,539 miles of lower voltage lines (69 kV or less). In addition, we jointly own 44 miles of high voltage lines with Basin Electric. Our service territory covers areas with a strong and stable economic base including western South Dakota, northeastern Wyoming and southeastern Montana. A majority of our retail electric revenues in 2018 were generated in South Dakota. We are subject to state regulation by the SDPUC, the WPSC and the MTPSC.

The following are characteristics of our distribution and transmission business:


•	We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2018 was comprised of 32% commercial, 25% residential, 11% contract wholesale, 6% wholesale off-system, 11% industrial and 15% municipal and other revenue.

•

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 United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the SPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. Our electric system is located in the WECC region. 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.


•	We have firm point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the Western region through December 31, 2023.


•	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.

Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:


•	MDU owns a 25% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.


•	We have an agreement through December 31, 2023 under which we serve MDU with capacity and energy up to a maximum of 50 MW.

•

The City of Gillette owns a 23% ownership interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement we will also provide the City of Gillette its operating component of spinning reserves.


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

•

We have an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 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. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:



2019-2020	15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2022	15 MW - 7 MW contingent on Wygen III and 8 MW contingent on Neil Simpson II
2022-2023	15 MW - 8 MW contingent on Wygen III and 7 MW contingent on Neil Simpson II
2023-2028	10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide approximately 445 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately 52% of our energy requirements in 2018 and purchased approximately 48% which was supplied under the following contracts:


•	A PPA with PacifiCorp expiring on December 31, 2023, whereby we purchase 50 MW of coal-fired baseload power.


•	A PPA with Wyoming Electric expiring on September 3, 2028, under which we will purchase up to 14.7 MW of wind energy through Wyoming Electric’s agreement with Happy Jack.


•	A PPA with Wyoming Electric expiring on September 30, 2029, under which we will purchase up to 20 MW of wind energy through Wyoming Electric’s agreement with Silver Sage.


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


•	A PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

Since 1995, we have been a net producer of energy. Our 2018 winter peak system load was 379 MW and our 2018 summer peak system load was 437 MW. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market, and through short-term sales contracts primarily in the WECC and MAPP regions. Our 220 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for wholesale off-system sales.

Operating Agreements

Horizon Point Agreement - We have an arrangement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

Gas Transportation Service Agreement - We have a gas transportation service agreement with Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

Shared Services Agreement - We have a shared services agreement with Wyoming Electric and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by, or performed for, an affiliate entity. Wyoming Electric and us receive certain staffing and management services from Black Hills Service Company for Cheyenne Prairie.

Jointly Owned Facilities - We are parties to an agreement with the City of Gillette and MDU for joint ownership of Wygen III. We charge the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.

Ground Lease Agreement - We have a Wygen III ground lease agreement with WRDC that expires in 2050 with three automatic renewal terms of 20 years each.

Regulations

Regulatory Accounting

We follow accounting for regulated utility operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions in which we operate. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our regulated operations. In the event we determine that we no longer meet the accounting criteria for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material.

Rate Regulation

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,TCA, Energy Efficiency Cost Recovery/DSM	70%
SD		7.76%			5/2014	TFA	N/A
SD		7.76%			6/2011	EIA	N/A
WY	9.9%	8.13%	46.7%/53.3%	$46.8	10/2014	ECA	65%
FERC	10.8%	8.76%	43%/57%		2/2009	FERC Transmission Tariff	N/A

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 Wyoming and South Dakota 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.

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 period effective July 1, 2017. See Management’s Discussion and Analysis of Results of Operations in Item 7 of this Annual Report on Form 10-K for further information.

•

An annual adjustment clause which provides for the over or under recovery of fuel 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 additional 30%. During the six-year moratorium period effective July 1, 2017, 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.


•	We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of our open access transmission tariff.

Common Use System (CUS). 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 $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.

Tariff Filing

On December 17, 2018, Wyoming Electric and us filed for approval of new, voluntary renewable energy tariffs to serve customer requests for renewable energy resources. Requests to approve the voluntary tariffs, known as Renewable Ready Service Tariffs, were submitted to the SDPUC and WPSC. The renewable ready tariffs would provide large commercial and industrial customers and governmental agencies an option to purchase utility-scale renewable energy. As proposed, customers would be able to enter into contracts with Black Hills Energy to purchase renewable energy for periods of five to 25 years.

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, 2018, we were subject to the following renewable energy portfolio standards or objectives:


•	South Dakota. In 2015, South Dakota 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.

•

Montana. Montana has 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, the Montana Legislature adopted legislation that excluded us from all renewable portfolio standard requirements under Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.


•	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 prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. Portfolio standards may 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.

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 has not been sent for publication. Until the EPA issues the rule for publication, we can not quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation 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 $40 million if PacifiCorp is required to install a Selective Catalytic Reactor for NO_xcontrol. At the present time, a court date is being scheduled to hear arguments.

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 and poses significantly less risk that the Clean Power Plan. The 60-day comment period has ended and the EPA is reviewing comments prior to issuing a final 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 11 of the Notes to Financial Statements in this Annual Report on Form 10-K.

New Accounting Pronouncements

See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2018 or pending adoption.

ITEM 1A. RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. The following 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. These important factors and other matters discussed herein could cause our actual results or outcomes to differ materially.

Regulatory commissions may refuse to approve some or all of the utility rate increases we may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable.

Our regulated electric 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 rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

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

Our financial performance depends on the successful operation of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.

Operating electric generating facilities and electric transmission and distribution systems involves risks, including:


•	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, 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 ability to operate our facilities;


•	Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;


•	Operational limitations imposed by environmental and other regulatory requirements;


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


•	Labor relations.


•	Our ability to transition and replace our retirement-eligible employees;


•	Inability to recruit and retain skilled technical labor; and


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

Changes in the interpretation of the TCJA could adversely affect us.

On December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and modifies or repeals many business deductions and credits. The new tax law contains several provisions that impacted our 2017 and 2018 financial results and will impact the Company into the future.

If there are future changes and amendments to the TCJA, if we are unable to obtain reasonable outcomes with our utility regulators in passing future benefits of the TCJA back to customers, or if our interpretations on the provisions of depreciation or interest deductibility in the TCJA change, our results of operations, financial position or cash flows could be materially impacted.

Construction, expansion, refurbishment and operation of power generating and transmission facilities involve significant risks which could reduce profitability.

The construction, expansion, refurbishment and operation of power generating and transmission facilities involve many risks, including:


•	The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;


•	Contractual restrictions upon the timing of scheduled outages;


•	The cost of supplying or securing replacement power during scheduled and unscheduled outages;


•	The unavailability or increased cost of equipment;


•	The cost of recruiting and retaining or the unavailability of skilled labor;


•	Supply interruptions, work stoppages and labor disputes;


•	Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;


•	Opposition by members of the public or special-interest groups;


•	Weather interferences;


•	Availability and cost of fuel supplies;


•	Unexpected engineering, environmental or geological problems; and


•	Unanticipated cost overruns.

The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.

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

Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.

We rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to our natural gas-fired power plants. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.

National and regional economic conditions may cause increased counterparty risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position and liquidity.

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

Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, cost of capital and other operating costs.

Our credit rating on our First Mortgage Bonds 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 to complete new financings on reasonable terms, or at all. A credit rating downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.

Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.

A portion of our net income is attributable to sales of contract and off-system wholesale electricity. Energy prices are influenced by many factors outside our control, including, among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions, and the rules, regulations and actions of system operators in those markets. As a result, wholesale power markets may be subject to significant, unpredictable price fluctuations over relatively short periods of time.

Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events that could give rise to additional costs and cause a substantial loss to us.

Inherent in our electricity transmission and distribution activities are a variety of hazards and operating risks, such as fires, releases of hazardous materials, explosions and operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public lands), environmental pollution, impairment of our operations, and substantial financial losses to us. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.

Operating results can be adversely affected by variations from normal weather conditions.

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

Our business is located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these events. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial condition or cash flows.

The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity.

Our business is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can 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 can 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.

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 we 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.

Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.

Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.

Developments in federal and state laws concerning GHG regulations and air emissions relating to climate may adversely impact operations, financial results and materially increase our generation and production costs, which could render some of our generating units uneconomical to operate and maintain.

To the extent climate change occurs, our business could be adversely impacted, although we believe is likely that any such resulting impacts would occur very gradually over a very long period of time and thus would be difficult to quantify with any degree of specificity. Cooler temperatures in our electric 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 “Business and Properties.”

Due to uncertainty as to the final outcome of federal climate regulation, legal challenges, state clean power plan developments or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position.

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.

Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, 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 operations and/or our financial results.

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

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. During their assessment of these controls, management 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.

Threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways.

Terrorist acts or other similar events could harm our business by limiting its ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.

A cyber attack may disrupt our operations, or lead to a loss or misuse of confidential and proprietary information and create a potential liability.

We use and operate sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric distribution systems, could result in a full or partial disruption of our electric operations. Cyber attacks targeting other key information technology systems, including our third-party vendors’ 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 as a result of a cyber attack could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems or our third-party vendors’ systems were to fail or be breached by a cyber attack or a computer virus and be unable to recover in a timely way, we would be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised which could have a material adverse effect not only on our financial results, but on our public reputation as well.

Market performance or changes in other assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.

As discussed in Note 8 to the Financial Statements in this Annual Report on Form 10-K, we have a defined benefit pension plan (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria), defined post-retirement healthcare plan and a non-qualified retirement plan that cover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.

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

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

Our electric 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.

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 11, “Commitments and Contingencies,” of our Notes to 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.


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

Significant Events

2018 Overview

On December 17, 2018, South Dakota Electric and Wyoming Electric filed for approval with the SDPUC and WPSC new, voluntary renewable energy tariffs to serve customer requests for renewable energy resources. In addition, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a $57 million, 40 MW wind generation project near Cheyenne, Wyoming.

On December 12, 2018, Moody’s affirmed South Dakota Electric’s credit rating at A1.

On November 20, 2018, we placed in service a 33-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018. The remaining 94-mile segment is expected to be in service by the end of 2019.

On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the Company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.6 million was delivered to customers in October 2018.

On August 16, 2018, we entered into a PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

On August 9, 2018, S&P upgraded South Dakota Electric’s credit rating to A.

On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A.

2017 Overview

On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the TFA and the EIA, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, is being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million. The June 16, 2017 settlement had no impact to base rates.

Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

Non-GAAP Financial Measure

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

In our Management’s Discussion and Analysis of Results of Operations, 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 natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

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



For the years ended December 31,	2018			Variance			2017			Variance			2016
	(in thousands)
Revenue	$	298,080		$	9,647		$	288,433		$	20,801		$	267,632
Fuel and purchased power	92,886			5,248			87,638			12,612			75,026
Gross margin ^(a)	205,194			4,399			200,795			8,189			192,606

Operating expenses	126,859			9,890			116,969			9,943			107,026
Operating income	78,335			(5,491		)	$	83,826		(1,754		)	85,580

Interest expense, net	(21,348		)	(968		)	(20,380		)	(188		)	(20,192		)
Other income (expense), net	(670		)	(2,650		)	1,980			(298		)	2,278
Income tax expense	(10,672		)	3,456			(14,128		)	8,400			(22,528		)
Net income	$	45,645		$	(5,653	)	$	51,298		$	6,160		$	45,138


(a)	Non-GAAP measure

2018 Compared to 2017

Gross margin increased primarily due to $9.8 million of Horizon Point shared facility revenue, higher power marketing and wholesale revenue of $3.0 million, higher rider revenues of $2.3 million primarily related to transmission investment recovery, and a $1.7 million increase in residential margins primarily from higher usage per customer. These increases were partially offset by a $10.3 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs and lower commercial and industrial demand volume of $2.1 million.

Operations and maintenance increased due to higher depreciation and property taxes of $4.4 million from higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line. Vegetation management expenses increased by $3.4 million compared to the prior year, and higher employee and facility costs comprise the remainder of the increase compared to the the prior year.

Interest expense, net increased due to higher prior year AFUDC associated with higher prior year capital spend.

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

Income tax expense: The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the enactment of the TCJA on December 22, 2017. Additionally, in 2018, we recorded $0.9 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes compared to a net tax benefit of $6.0 million in 2017 as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA.

2017 Compared to 2016

Gross margin increased over the prior year reflecting a $5.6 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling and heating degree days and higher customer counts were slightly offset by lower usage per customer and lower commercial and industrial demand. Both heating and cooling degree days’ variances from normal were favorable when compared to prior year comparisons to normal.

Operations and maintenance increased primarily due to $4.0 million in higher vegetation management expenses, $3.2 million in increased maintenance costs from higher outages, higher employee costs as a result of prior year integration activities, transition expenses charged to BHC related to its 2016 acquisition of SourceGas and increased amortization expenses as a result of the SDPUC settlement.

Interest expense, net and other income, net were comparable to the same period in the prior year.

Income tax expense: The effective tax rate decreased in 2017 due to a tax benefit of $6.0 million resulting from re-measurement of net deferred tax liabilities in accordance with the ASC 740 and the enactment of the TCJA on December 22, 2017. This benefit was primarily related to the repricing of net operating losses and other tax basis items not included in the ratemaking construct.

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



Electric Revenue by Customer Type (in thousands)
	2018		Percentage Change		2017		Percentage Change		2016
Residential	$	75,319	4	%	$	72,764	1	%	$	72,084
Commercial	95,509		(1	)%	96,531		(1	)%	97,579
Industrial	32,748		(2	)%	33,464		—	%	33,409
Municipal	3,571		(4	)%	3,707		—	%	3,705
Total retail revenue	207,147		—	%	206,466		—	%	206,777
Wholesale ^(a)	33,687		11	%	30,435		79	%	17,037
Market - off-system sales ^(b)	17,692		24	%	14,271		(8	)%	15,431
Total electric sales	258,526		3	%	251,172		5	%	239,245
Other revenue ^(c)	39,554		6	%	37,261		31	%	28,387
Total revenue	$	298,080	3	%	$	288,433	8	%	$	267,632

_________________________


(a)	Increases in 2018 and 2017 were primarily driven by higher volumes sold on long-term wholesale contracts.


(b)	Increase in 2018 was due to higher trading volume opportunities.


(c)	Increase in 2017 is primarily due to higher transmission revenues.



Megawatt Hours Sold by Customer Type
	2018	Percentage Change		2017	Percentage Change		2016
Residential	546,825	4	%	526,730	1	%	520,798
Commercial	751,479	(2	)%	769,463	(2	)%	783,319
Industrial	407,683	(5	)%	430,300	—	%	429,912
Municipal	31,636	(5	)%	33,272	(1	)%	33,591
Total retail quantity sold	1,737,623	(1	)%	1,759,765	—	%	1,767,620
Wholesale ^(a)	900,854	25	%	722,659	193	%	246,630
Market - off-system sales^(b)	518,725	2	%	509,963	(15	)%	597,695
Total quantity sold	3,157,202	6	%	2,992,387	15	%	2,611,945
Losses and company use ^(c)	203,194	4	%	195,005	26	%	155,370
Total energy	3,360,396	5	%	3,187,392	15	%	2,767,315

_________________________


(a)	Increases in 2018 and 2017 were primarily driven by higher volumes sold on long-term wholesale contracts.


(b)	Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales.


(c)	Includes company uses, line losses, and excess exchange production.

We own approximately 445 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.



Regulated Power Plant Fleet Availability
	2018		2017		2016
Coal-fired plants ^(a)	92.7	%	86.0	%	86.5	%
Other plants	96.8	%	96.4	%	98.0	%
Total availability	94.9	%	91.6	%	93.0	%

_________________________


(a)	Both 2017 and 2016 included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.



Megawatt Hours Generated and Purchased
	2018	Percentage Change		2017	Percentage Change		2016

Coal-fired	1,598,957	8	%	1,485,254	1	%	1,467,403
Natural Gas and Oil ^{(a) (b)}	135,265	40	%	96,661	(18	)%	118,467
Total generated ^{(a) (b)}	1,734,222	10	%	1,581,915	—	%	1,585,870

Total purchased ^(c)	1,626,174	1	%	1,605,477	36	%	1,181,445
Total generated and purchased ^(c)	3,360,396	5	%	3,187,392	15	%	2,767,315

_________________________


(a)	Decrease in 2017 is driven by the ability to purchase excess generation in the open market at a lower cost than to generate.


(b)	Increase in 2018 is primarily due to low natural gas prices and the ability to generate at a lower cost than to purchase excess generation on the open market.


(c)	Increase in 2017 and 2018 is driven by increased volumes on long-term wholesale contracts.



Heating and Cooling Degree Days
	2018		2017		2016
Actual
Heating degree days	7,749		6,870		6,402
Cooling degree days	488		709		646

Variance from 30-year average ^(a)
Heating degree days	8	%	(4	)%	(10	)%
Cooling degree days	(23	)%	11	%	(4	)%

______________


(a)	30-year average is from NOAA Climate Normals

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, 2018:



Rating Agency	Rating
S&P	A
Moody’s	A1
Fitch	A

Critical 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 Financial Statements in this Annual Report on Form 10-K.

Regulation

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

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 for recovery in current rates or in future rate proceedings.

Income Taxes

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

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. 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.

The Company has revalued the deferred income taxes at the 21% federal tax rate as of December 31, 2017 and as a result, deferred tax assets and liabilities were reduced by approximately $103 million. Of the $103 million, approximately $97 million was reclassified to a regulatory liability. As of December 31, 2018, the Company has a regulatory liability associated with TCJA related items of $100 million, completing 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, 2018, the Company has amortized $0.9 million of regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, 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 6 of the Notes to Financial Statements in this Annual Report on Form 10-K for additional information.

Pension and Other Postretirement Benefits

As described in Note 8 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 pension benefit cost for 2019 for our non-contributory funded pension plan is expected to be $0.6 million compared to $1.3 million in 2018. The decrease in pension benefit cost is driven primarily by an increase in the discount rate.

The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:



		December 31,
Assumptions	Percentage Change	2018 Increase/(Decrease) PBO/APBO ^(a)	2019 Increase/(Decrease) Expense - Pretax

Pension
Discount rate ^(b)	+/- 0.5	(3,413)/3,744	(1,078)/733
Expected return on assets	+/- 0.5	N/A	(284)/284

OPEB
Discount rate ^(b)	+/- 0.5	(210)/228	7/(8)
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.



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



	Page

Management’s Report on Internal Controls Over Financial Reporting	26

Report of Independent Registered Public Accounting Firm	27

Statements of Income for the three years ended December 31, 2018	28

Statements of Comprehensive Income for the three years ended December 31, 2018	29

Balance Sheets as of December 31, 2018 and 2017	30

Statements of Cash Flows for the three years ended December 31, 2018	32

Statements of Common Stockholder’s Equity for the three years ended December 31, 2018	33

Notes to Financial Statements	34

Management’s Report on Internal Control over Financial Reporting

Management of Black Hills Power is 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, 2018, 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, 2018.

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

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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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 Public Company Accounting Oversight Board (United States) (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 20, 2019

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

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME



Years ended December 31,	2018			2017			2016
	(in thousands)

Revenue	$	298,080		$	288,433		$	267,632

Operating expenses:
Fuel and purchased power	92,886			87,638			75,026
Operations and maintenance	79,523			74,064			66,384
Depreciation and amortization	39,649			35,862			34,030
Taxes - property	7,687			7,043			6,612
Total operating expenses	219,745			204,607			182,052

Operating income	78,335			83,826			85,580

Other income (expense):
Interest expense	(22,545		)	(22,421		)	(22,908		)
AFUDC - borrowed	521			1,137			1,140
Interest income	676			904			1,576
AFUDC - equity	221			2,165			2,165
Other income (expense), net	(891		)	(185		)	113
Total other income (expense)	(22,018		)	(18,400		)	(17,914		)

Income before income taxes	56,317			65,426			67,666
Income tax expense	(10,672		)	(14,128		)	(22,528		)

Net income	$	45,645		$	51,298		$	45,138

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

STATEMENTS OF COMPREHENSIVE INCOME



Years ended December 31,	2018		2017			2016
	(in thousands)

Net income	$	45,645	$	51,298		$	45,138

Other comprehensive income (loss):
Benefit plan liability adjustments - net gain (loss) (net of tax of $(62), $50, and $27 respectively)	235		(94		)	(50		)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(22), $(30), and $(29), respectively)	81		56			53
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(13), $(22), and $(22), respectively)	51		42			42
Other comprehensive income	367		4			45

Comprehensive income	$	46,012	$	51,302		$	45,183

See Note 7 for additional disclosure related to comprehensive income.

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

BALANCE SHEETS



As of December 31,	2018			2017
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash	$	112		$	16
Accounts receivable, net	28,431			29,050
Accounts receivable from affiliates	8,119			5,664
Materials, supplies and fuel	24,853			23,443
Regulatory assets, current	19,052			18,993
Other current assets	4,538			4,724
Total current assets	85,105			81,890

Investments	4,889			4,926

Property, plant and equipment	1,381,045			1,311,819
Less: accumulated depreciation and amortization	(376,160		)	(358,946		)
Total property, plant and equipment, net	1,004,885			952,873

Other assets:
Regulatory assets, non-current	56,680			59,710
Other assets, non-current	9,729			3,747
Total other assets, non-current	66,409			63,457
TOTAL ASSETS	$	1,161,288		$	1,103,146

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

BALANCE SHEETS

(Continued)



As of December 31,	2018			2017
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	25,122		$	14,766
Accounts payable to affiliates	25,804			25,653
Accrued liabilities	34,193			38,205
Money pool notes payable	38,690			13,397
Regulatory liabilities, current	2,574			842
Total current liabilities	126,383			92,863

Long-term debt	340,035			339,895

Deferred credits and other liabilities:
Deferred income tax liabilities, net	114,009			110,618
Regulatory liabilities, non-current	160,642			148,013
Benefit plan liabilities	14,606			16,285
Other, non-current liabilities	1,368			1,240
Total deferred credits and other liabilities	290,625			276,156

Commitments and contingencies (Notes 4, 8, 9 and 11)

Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416
Additional paid-in capital	39,575			39,575
Retained earnings	342,145			332,499
Accumulated other comprehensive loss	(891		)	(1,258		)
Total stockholder’s equity	404,245			394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,161,288		$	1,103,146

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS



Years ended December 31,	2018			2017			2016
	(in thousands)
Operating activities:
Net income	$	45,645		$	51,298		$	45,138
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	39,649			35,862			34,030
Deferred income taxes	5,218			1,004			20,690
Employee benefits	1,518			817			1,770
AFUDC - equity	(221		)	(2,165		)	(2,165		)
Other adjustments	2,776			2,429			391
Change in operating assets and liabilities -
Accounts receivable and other current assets	(3,576		)	3,287			(3,963		)
Accounts payable and other current liabilities	(5,648		)	(7,254		)	6,175
Regulatory assets	27			978			(4,023		)
Regulatory liabilities	2,561			—			—
Contributions to defined benefit pension plan	(1,795		)	(4,000		)	(820		)
Other operating activities	(1,407		)	(1,853		)	(8,339		)
Net cash provided by operating activities	84,747			80,403			88,884

Investing activities:
Property, plant and equipment additions	(73,456		)	(79,566		)	(84,750		)
Change in money pool notes receivable, net	—			—			(4,095		)
Other investing activities	(488		)	(861		)	(102		)
Net cash (used in) investing activities	(73,944		)	(80,427		)	(88,947		)

Financing activities:
Change in money pool notes payable, net	(10,707		)	(194		)	—
Net cash provided by (used in) financing activities	(10,707		)	(194		)	—

Net change in cash	96			(218		)	(63		)

Cash beginning of year	16			234			297
Cash end of year	$	112		$	16		$	234

See Note 10 for Supplemental Cash Flows information.

The accompanying notes to financial statements are an integral part of these financial statements.

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY



	2018			2017			2016
	(in thousands)
Common stock shares:
Balance beginning of year	23,416			23,416			23,416
Issuance of common stock	—			—			—
Balance end of year	23,416			23,416			23,416

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

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

Retained earnings:
Balance beginning of year	$	332,499		$	322,933		$	330,295
Net income	45,645			51,298			45,138
Non-cash dividend to Parent company	(36,000		)	(42,000		)	(52,500		)
Other adjustments	1			268			—
Balance end of year	$	342,145		$	332,499		$	322,933

Accumulated other comprehensive loss:
Balance beginning of year	$	(1,258	)	$	(1,262	)	$	(1,307	)
Other comprehensive (loss) income, net of tax	367			4			45
Balance end of year	$	(891	)	$	(1,258	)	$	(1,262	)

Total stockholder’s equity	$	404,245		$	394,232		$	384,662

The accompanying notes to financial statements are an integral part of these financial statements.

NOTES TO FINANCIAL STATEMENTS

December 31, 2018, 2017 and 2016

(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

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

Basis of Presentation

The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3) and are prepared in accordance with GAAP.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of 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 Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. As of December 31, 2018 and 2017, we have no cash equivalents.

Regulatory Accounting

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

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



	2018			2017
Regulatory assets
Loss on reacquired debt^(a)	$	1,259		$	1,534
Deferred taxes on AFUDC ^(b)	5,020			5,095
Employee benefit plans and related deferred taxes ^(c)	19,868			19,465
Deferred energy and fuel cost adjustments^(a)	20,334			19,602
Deferred taxes on flow through accounting ^(c)	8,749			7,579
Decommissioning costs ^(b)	8,196			10,252
Vegetation management ^(a)	10,366			12,669
Other regulatory assets ^(a)	1,940			2,507
	$	75,732		$	78,703
Less current regulatory assets	(19,052		)	(18,993		)
Regulatory assets, non-current	$	56,680		$	59,710

Regulatory liabilities
Cost of removal for utility plant ^(a)	$	52,366		$	44,056
Employee benefit plans and related deferred taxes ^(c)	7,518			6,808
Excess deferred income taxes ^(c)	100,276			97,101
TCJA revenue reserve	2,523			—
Other regulatory liabilities ^(c)	533			890
	$	163,216		$	148,855
Less current regulatory liabilities	(2,574		)	(842		)
Regulatory liabilities, non-current	$	160,642		$	148,013

____________________

(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 - The early redemption premium on reacquired debt is being amortized over the remaining term of the original bonds.

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. Such amounts have been grossed-up to reflect the revenue requirement associated with a rate regulated environment.

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. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

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 additional details below.

TCJA Revenue Reserve - Revenue subject to refund at December 31, 2018, represents revenue reserved as a result of the TCJA. See below “TCJA Revenue Reserve” under Revenue recognition for further disclosure.

Excess Deferred Income Taxes

As of December 31, 2018 and 2017, we have a regulatory liability associated with TCJA related items of approximately $100 million and $97 million, respectively. The majority of this regulatory liability relates to excess deferred taxes resulting from the remeasurement of deferred tax assets and liabilities in 2017. 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, 2018, the Company has amortized $0.9 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, 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. See Note 6 for more information.

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):



	2018			2017
Accounts receivable, trade	$	16,236		$	15,994
Unbilled revenue	12,333			13,280
Less Allowance for doubtful accounts	(138		)	(224		)
Accounts receivable, net	$	28,431		$	29,050

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
2018	$	224	$	911	$	(997	)	$	138
2017	$	157	$	882	$	(815	)	$	224
2016	$	207	$	644	$	(694	)	$	157

Revenue Recognition

Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. 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 rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract 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 regulator-empowered statute 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, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, 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, 2018
	(in thousands)
Customer types:
Retail	$	197,184
Wholesale	33,687
Market - off-system sales	17,691
Transmission/Other	49,015
Revenue from contracts with customers	297,577
Other revenues	503
Total revenues	$	298,080

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

The majority of the 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

TCJA revenue reserve

The TCJA or “tax reform”, signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. We have been collaborating with our regulators in the states in which we provide utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and recorded a revenue reserve of approximately $10 million during the year ended December 31, 2018.

On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the Company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. As of December 31, 2018, approximately $7.6 million has been delivered to customers and approximately $2.5 million remains in reserve.

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.

Practical Expedients

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.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

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 are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets.

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 2.3% in 2018, 2.1% in 2017 and 2.2% in 2016.

Accrued Liabilities

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



	2018		2017
Accrued employee compensation, benefits and withholdings	$	4,206	$	4,305
Accrued property taxes	6,332		5,930
Accrued income taxes	12,536		17,472
Customer deposits and prepayments	5,204		4,863
Accrued interest	4,627		4,708
Other (none of which is individually significant)	1,288		927
Total accrued liabilities	$	34,193	$	38,205

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instruments be recognized in earnings unless specific hedge accounting criteria are met and designated accordingly, including the normal purchase and normal sales exception. Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur.

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, 2018, we have no outstanding interest rate swap agreements.

Revenues and expenses on contracts that qualify as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. 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. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.

Fair Value Measurements

We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ 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 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 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.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit 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 on the accompanying Balance Sheets. See Note 6 for additional information.

Recently Issued Accounting Standards

Leases, ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the original guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.

We adopted this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we elected the practical expedient which provides for no assessment of these easements. Further, we adopted the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We elected the “package of three” practical expedient. We have implemented a new lease accounting system and adjusted related procedures and controls accordingly. We will record an operating lease right of use asset and an off-setting operating lease obligation liability as of January 1, 2019 for approximately $14 million, respectively, primarily driven by the intercompany ground lease with WRDC for Wygen III. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 1.

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the year ended December 31, 2018. Retrospective impact was not material and therefore not adjusted. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

(2) PROPERTY, PLANT AND EQUIPMENT

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



				2018				2017
				Weighted				Weighted
				Average				Average
	2018			Useful Life (in years)	2017			Useful Life (in years)
Electric plant:
Production	$	588,565		46	$	587,323		46
Transmission	208,610			48	186,045			49
Distribution	394,475			45	375,214			46
Plant acquisition adjustment ^(a)	4,870			32	4,870			32
General	154,621			28	153,535			32
Total plant-in-service	1,351,141				1,306,987
Construction work in progress	29,904				4,832
Total electric plant	1,381,045				1,311,819
Less accumulated depreciation and amortization	(376,160		)		(358,946		)
Electric plant net of accumulated depreciation and amortization	$	1,004,885			$	952,873

__________________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 12 years remaining.

(3) JOINTLY OWNED FACILITIES

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


•	We own a 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 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 400 MW, including 200 MW West to East and 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 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 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Wyoming Electric owns the remaining 40 MW. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

As of December 31, 2018, 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		Accumulated Depreciation
Wyodak Plant	$	115,198	$	384	$	61,730
Transmission Tie	$	20,855	$	1,860	$	6,667
Wygen III	$	140,072	$	645	$	22,647
Cheyenne Prairie	$	92,053	$	69	$	11,460

(4) LONG-TERM DEBT

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



		Interest Rate at		Balance Outstanding
	Due Date	December 31, 2018		December 31, 2018		December 31, 2017
First Mortgage Bonds due 2032	August 15, 2032	7.23	%	75,000		75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13	%	180,000		180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43	%	85,000		85,000
Less unamortized debt discount				(86	)	(90	)
Series 94A Debt ^(a)	June 1, 2024	1.93	%	2,855		2,855
Less unamortized deferred financing costs				(2,734	)	(2,870	)
Long-term Debt				340,035		339,895

___________________


(a)	Variable interest rate at December 31, 2018.

Net deferred financing costs of approximately $2.7 million and $2.9 million were recorded on the accompanying Balance Sheets in long-term debt at December 31, 2018 and 2017, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million for each of the years ended December 31, 2018, 2017 and 2016 are included in Interest expense on the accompanying Statements of Income.

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, 2018.

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):



2019	$	—
2020	$	—
2021	$	—
2022	$	—
2023	$	—
Thereafter	$	342,855

(5) FAIR VALUE OF FINANCIAL INSTRUMENTS

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



	2018				2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash ^(a)	$	112	$	112	$	16	$	16
Long-term debt ^{(b) (c)}	$	340,035	$	412,894	$	339,895	$	446,978

_______________


(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)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.


(c)	Carrying amount of long-term debt is net of deferred financing costs.

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Long-Term Debt

For additional information on our long-term debt, see Note 4.

(6) 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 $103 million. Of the $103 million, approximately $97 million was reclassified to a regulatory liability. As of December 31, 2018 we have a regulatory liability associated with TCJA related items of $100 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, 2018, the Company has amortized $0.9 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.

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



	2018			2017		2016
Current:
Federal	$	5,454		$	13,124	$	1,838

Deferred:
Federal	5,958			1,004		20,690
Excess deferred tax amortization	(740		)	—		—
	$	5,218		$	1,004	$	20,690

Total income tax expense	$	10,672		$	14,128	$	22,528

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



	2018			2017
Deferred tax assets:
Employee benefits	$	2,404		$	3,012
Regulatory liabilities	25,587			24,984
Other	2,317			1,678
Total deferred tax assets	30,308			29,674

Deferred tax liabilities:
Accelerated depreciation and other plant related differences	(125,594		)	(122,002		)
Regulatory assets	(7,147		)	(7,008		)
Employee benefits	(2,719		)	(2,595		)
Deferred costs	(8,572		)	(8,447		)
Other	(285		)	(240		)
Total deferred tax liabilities	(144,317		)	(140,292		)

Net deferred tax liability	$	(114,009	)	$	(110,618	)

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



	2018	2017	2016
Federal statutory rate	21.0%	35.0%	35.0%
Amortization of excess deferred and investment tax credits	(1.3)	(0.1)	(0.4)
AFUDC Equity	0.1	(1.0)	(0.9)
Flow-through adjustments ^(a)	(1.7)	(1.8)	(0.9)
Tax credits	—	—	(0.1)
TCJA corporate rate reduction ^(b)	2.5	(9.2)	—
Other	(1.7)	(1.3)	0.6
	18.9%	21.6%	33.3%

_________________________


(a)	Flow-through adjustments related primarily to an accounting method change 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 $0.9 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items.

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):



	2018			2017
Unrecognized tax benefits at January 1	$	302		$	493
Additions for current year tax positions	—			13
Additions for prior year tax positions	2			—
Reductions for prior year tax positions	(55		)	(204		)
Unrecognized tax benefits at December 31	$	249		$	302

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, 2018 and 2017, the interest expense recognized was not material to the financial results of the Company.

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, 2019.

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

(7) 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 components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):



	Location on the Statements of Income (Loss)	Amounts Reclassified from AOCI
		2018			2017
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	64		$	64
Income tax	Income tax benefit (expense)	(13		)	(22		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	51		$	42

Amortization of defined benefit plans:
Actuarial gain (loss)	Operations and maintenance	$	103		$	86
Income tax	Income tax benefit (expense)	(22		)	(30		)
Total reclassification adjustments related to defined benefit plans, net of tax		$	81		$	56

Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $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 $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.

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):



	Interest Rate Swaps			Employee Benefit Plans			Total

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


	Interest Rate Swaps			Employee Benefit Plans			Total

As of December 31, 2016	$	(593	)	$	(669	)	$	(1,262	)
Other comprehensive income (loss) before reclassifications	—			(94		)	(94		)
Amounts reclassified from AOCI	42			56			98
As of December 31, 2017	$	(551	)	$	(707	)	$	(1,258	)

(8) 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 50% of their eligible compensation on a pre-tax or after-tax basis.

The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

Defined Benefit Pension Plan (Pension Plan)

We have a defined benefit pension plan (“Pension Plan”) covering certain eligible employees. 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 has been closed to new employees and 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, 2018, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 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:



	2018		2017
Equity securities	17	%	26	%
Real estate	4		4
Fixed income funds	71		63
Cash and cash equivalents	3		1
Hedge funds	5		6
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plans

BHC sponsors retiree healthcare plans (Healthcare Plans) 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 plans. Healthcare coverage for Medicare-eligible BHP retirees is provided through an individual market healthcare exchange.

Plan Assets

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

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):



	2018		2017
Defined Contribution Plans
Company Retirement Contribution	$	876	$	861
Matching Contributions	$	1,272	$	1,306



	2018		2017
Defined Benefit Plans
Defined Benefit Pension Plan	$	1,795	$	4,000
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	388	$	348
Supplemental Non-qualified Defined Benefit Plan	$	238	$	246

While we do not have required contributions, we expect to make approximately $1.8 million in contributions to our Pension Plan in 2019.

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, 2018
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV ^(a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	261	$	—	$	261	$	—	$	261
Common Collective Trust - Cash and Cash Equivalents	—		1,388		—		1,388		—		1,388
Common Collective Trust - Equity	—		9,436		—		9,436		—		9,436
Common Collective Trust - Fixed Income	—		39,047		—		39,047		—		39,047
Common Collective Trust - Real Estate	—		9		—		9		1,896		1,905
Hedge Funds	—		—		—		—		2,627		2,627
Total investments measured at fair value	$	—	$	50,141	$	—	$	50,141	$	4,523	$	54,664



Pension Plan	December 31, 2017
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV ^(a)		Total Investments
AXA Equitable General Fixed Income	$	—	$	184	$	—	$	184	$	—	$	184
Common Collective Trust - Cash and Cash Equivalents	—		314		—		314		—		314
Common Collective Trust - Equity	—		15,749		—		15,749		—		15,749
Common Collective Trust - Fixed Income	—		37,732		—		37,732		—		37,732
Common Collective Trust - Real Estate	—		249		—		249		2,258		2,507
Hedge Funds	—		—		—		—		3,398		3,398
Total investments measured at fair value	$	—	$	54,228	$	—	$	54,228	$	5,656	$	59,884

________________________

(a)

Certain investments that are measured at fair value using Net Asset Value “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. 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. 20% of the shares may be redeemed at the end of each month with a 10-day notice and full redemptions are available at the end of each quarter with 45-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.

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 Plans
As of December 31 (in thousands)	2018			2017			2018			2017			2018			2017
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	67,562		$	64,973		$	3,418		$	3,404		$	5,970		$	5,843
Service cost	516			545			—			—			193			206
Interest cost	2,194			2,341			108			116			179			176
Actuarial loss (gain)	(2,878		)	4,008			(296		)	144			(889		)	130
Benefits paid	(3,562		)	(3,445		)	(238		)	(246		)	(389		)	(348		)
Plan participants transfer to affiliate	(1,913		)	(860		)	—			—			(129		)	(137		)
Plan participants’ contributions	—			—			—			—			120			100
Projected benefit obligation at end of year	$	61,919		$	67,562		$	2,992		$	3,418		$	5,055		$	5,970

Employee Benefit Plan Assets



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
As of December 31 (in thousands)	2018			2017			2018			2017			2018			2017
Beginning fair value of plan assets	$	59,884		$	53,888		$	—		$	—		$	—		$	—
Investment income (loss)	(1,884		)	6,150			—			—			—			—
Employer contributions	1,795			4,000			238			246			268			248
Retiree contributions	—			—			—			—			120			100
Benefits paid	(3,563		)	(3,445		)	(238		)	(246		)	(388		)	(348		)
Plan participants transfer to affiliate	(1,568		)	(709		)	—			—			—			—
Ending fair value of plan assets	$	54,664		$	59,884		$	—		$	—		$	—		$	—

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 Plans
	2018		2017		2018		2017		2018		2017
Regulatory asset	$	19,099	$	18,998	$	—	$	—	$	—	$	—
Current liability	$	—	$	—	$	230	$	245	$	466	$	534
Non-current liability	$	7,255	$	7,676	$	2,762	$	3,173	$	4,589	$	5,436
Regulatory liability	$	—	$	—	$	—	$	—	$	2,441	$	1,758

Accumulated Benefit Obligation



	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
As of December 31 (in thousands)	2018		2017		2018		2017		2018		2017
Accumulated benefit obligation	$	59,987	$	64,782	$	2,992	$	3,418	$	5,055	$	5,970

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
	2018			2017			2016			2018		2017		2016		2018			2017			2016
Service cost	$	516		$	545		$	606		$	—	$	—	$	—	$	193		$	206		$	204
Interest cost	2,194			2,341			2,499			108		116		122		179			176			187
Expected return on assets	(3,545		)	(3,591		)	(3,632		)	—		—		—		—			—			—
Amortization of prior service cost (credits)	43			43			43			—		—		—		(336		)	(336		)	(337		)
Recognized net actuarial loss (gain)	2,063			1,230			1,995			103		87		82		—			—			—
Net periodic expense	$	1,271		$	568		$	1,511		$	211	$	203	$	204	$	36		$	46		$	54

For the year ended December 31, 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 years ended December 31, 2017 and 2016, 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. See Note 1 for additional information.

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
	2018		2017		2018		2017		2018		2017
Net (gain) loss	$	—	$	—	$	391	$	707	$	—	$	—
Total AOCI	$	—	$	—	$	391	$	707	$	—	$	—

Assumptions



	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
	2018		2017		2016		2018		2017		2016		2018		2017		2016
Weighted-average assumptions used to determine benefit obligations:
Discount rate	4.40	%	3.71	%	4.27	%	4.30	%	3.62	%	4.12	%	4.28	%	3.60	%	3.84	%
Rate of increase in compensation levels	3.52	%	3.43	%	3.47	%	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)	3.71	%	4.27	%	4.63	%	3.62	%	4.12	%	4.29	%	3.60	%	3.84	%	4.03	%
Expected long-term rate of return on assets ^(b)	6.25	%	6.75	%	6.75	%	N/A		N/A		N/A		3.93	%	N/A		N/A
Rate of increase in compensation levels	3.43	%	3.47	%	3.57	%	N/A		N/A		N/A		N/A		N/A		N/A

_____________________________


(a)	The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs.


(b)	The expected rate of return on plan assets is 6.00% for the calculation of the 2019 net periodic pension cost.

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



	2018		2017
Trend Rate - Medical
Pre-65 for next year	6.70	%	7.00	%
Pre-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2027		2027

Post-65 for next year	4.94	%	5.00	%
Post-65 Ultimate trend rate	4.50	%	4.50	%
Trend Year	2026		2026

Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on this Form 10-K for additional details.

The following benefit payments, 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
2019	$	3,660	$	230	$	466
2020	$	3,774	$	227	$	534
2021	$	3,924	$	322	$	566
2022	$	4,031	$	319	$	577
2023	$	4,102	$	315	$	554
2024-2028	$	20,759	$	1,274	$	2,243

(9) RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $36 million and $42 million in 2018 and 2017 respectively, and changed the Utility Money Pool note by $36 million and $42 million in 2018 and 2017, respectively.

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):



	2018		2017
Accounts receivable from affiliates	$	8,119	$	5,664
Accounts payable to affiliates	$	25,804	$	25,653

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 1.0%. The cost of borrowing under the Utility Money Pool was 3.06% at December 31, 2018.

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

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



	2018			2017		2016
Interest income (expense)	$	(401	)	$	272	$	1,047

Interest expense allocation from Parent

BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2018, 2017 and 2016, we were allocated $1.3 million, $1.4 million, and $1.9 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:


•	An agreement, expiring September 3, 2028, with Wyoming Electric to acquire 15 MW of the facility output from Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028, Wyoming Electric has agreed to sell up to 15 MW of the facility output from Happy Jack to us.


•	An agreement, expiring September 30, 2029, with Wyoming Electric to acquire 20 MW of the facility output from Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029, Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to us.


•	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 three automatic renewal terms of 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 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:



	2018		2017		2016
	(in thousands)
Revenues:
Energy sold to Cheyenne Light	$	2,064	$	2,481	$	2,440
Rent from electric properties	$	3,634	$	3,680	$	5,046
Horizon Point shared facility revenue	$	11,211	$	1,420	$	—

Fuel and purchased power:
Purchases of coal from WRDC	$	17,532	$	15,948	$	16,227
Purchase of excess energy from Cheyenne Light	$	511	$	601	$	252
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	1,942	$	1,924	$	1,918
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	3,586	$	3,290	$	3,300
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	364	$	393	$	399

Related-party Corporate Support

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



	2018		2017		2016
	(in thousands)
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	34,578	$	27,869	$	25,748

Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

(10) SUPPLEMENTAL CASH FLOW INFORMATION



Years ended December 31,	2018			2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	15,180		$	6,565		$	5,521
Non-cash decrease to money pool note receivable, net	$	(36,000	)	$	(42,000	)	$	(52,500	)
Non-cash dividend to Parent	$	36,000		$	42,000		$	52,500

Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(21,988	)	$	(21,517	)	$	(21,320	)
Income taxes (paid) refunded	$	(10,394	)	$	(12,719	)	$	—

(11) 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, 2018 (see Note 9 for information on related party agreements):


•	A PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 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 50 MW of capacity and energy to be transmitted annually by PacifiCorp.


•	An agreement with Thunder Creek for gas transport capacity, expiring October 31, 2019.


•	A PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029

Money pool notes payable

BLACK HILLS POWER INC 10-K