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EX-31.2 - EXHIBIT 31.2 - BLACK HILLS POWER INCbhpex-312cfo122014.htm
EX-32.1 - EXHIBIT 32.1 - BLACK HILLS POWER INCbhpex-321ceo122014.htm
EX-32.2 - EXHIBIT 32.2 - BLACK HILLS POWER INCbhpex-322cfo122014.htm
EX-31.1 - EXHIBIT 31.1 - BLACK HILLS POWER INCbhpex-311ceo122014.htm


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, 2015
¨
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
625 Ninth Street, Rapid City, South Dakota 57701
 
 
 
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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer    ¨    Accelerated filer    ¨    Non-accelerated filer    x     Smaller reporting company    ¨

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, 2016
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
 
 
 
ITEMS 1. and 2.
BUSINESS AND PROPERTIES
 
 
 
ITEM 1A.
RISK FACTORS
 
 
 
ITEM 1B.
UNRESOLVED STAFF COMMENTS
 
 
 
ITEM 3.
LEGAL PROCEEDINGS
 
 
 
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
 
 
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
 
 
 
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
 
 
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
 
 
ITEM 9A.
CONTROLS AND PROCEDURES
 
 
 
ITEM 9B.
OTHER INFORMATION
 
 
 
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
 
 
 
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
 
 
 
SIGNATURES
 
 
 
 
INDEX TO EXHIBITS


2



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
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 Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC
Black Hills Service Company
Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Wyoming
Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated Holdings
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 operations on October 1, 2014.
City of Gillette
The City of Gillette, Wyoming, affiliate of the JPB.
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.
CPCN
Certificate of Public Convenience and Necessity
CPP
Clean Power Plan
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.
EPA
United States Environmental Protection Agency
FASB
Financial Accounting Standards Board
FDIC
Federal Depository Insurance Corporation
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
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 Farms, LLC, a subsidiary of Duke Energy Generation Services

3



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
JPB
Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The JPB financed the purchase of 23% of the Wygen III power plant for the City of Gillette.
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
NERC
North American Electric Reliability Corporation
NOL
Net operating loss
NOx
Nitrogen oxide
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
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.
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 case.
Thunder Creek
Thunder Creek Gas Services, LLC
TIPA
Tax Increase Prevention Act of 2014
WECC
Western Electricity Coordinating Council
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC


4



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, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s 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 the Company undertakes 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 the Company’s 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 the Company, 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 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”). 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, 2015, our ownership interests in electric generation plants were as follows:
Unit (1)
Fuel
Type
Location
Ownership
Interest %
Owned Capacity (MW)
Year
Installed
Wygen III (1)
Coal
Gillette, WY
52%
57.2
2010
Neil Simpson II
Coal
Gillette, WY
100%
90.0
1995
Wyodak (2)
Coal
Gillette, WY
20%
72.4
1978
Cheyenne Prairie (3)
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
 
_______________________
(1)
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.
(2)
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.
(3)
Cheyenne Prairie, a gas-fired power generation facility includes one combined-cycle, 95 MW unit that is jointly owned by Cheyenne Light (40 MW) and us (55 MW). This facility was placed into commercial operations on October 1, 2014.


5



Distribution and Transmission. Our distribution and transmission system serves approximately 71,000 electric customers, with an electric transmission system of 1,179 miles of high voltage lines (greater than 69 kV) and 2,485 miles of lower voltage lines. 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. Approximately 90% of our retail electric revenues in 2015 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, 2015 was comprised of 36% commercial, 26% residential, 6% contract wholesale, 8% wholesale off-system, 12% industrial and 12% municipal and other revenue.

We own 35% and Basin Electric owns 65% 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 the Eastern United States, respectively. This transmission tie provides transmission access to both the WECC region in the West and the MAPP region in the East. Our system is located in the WECC region. The total transfer capacity of the tie is 200 MW from West to East and 200 MW from East to West. This transmission tie allows us to buy and sell energy in the Eastern interconnection without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tie accommodates scheduling transactions in both directions simultaneously. This transfer capability provides additional opportunity to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and to take advantage of the power price differentials between the two electric grids. Additionally, our system is capable of directly interconnecting up to 80 MW of generation or load to the Eastern transmission grid. Transmission constraints within the MAPP transmission system may limit the amount of capacity that may be directly interconnected to the Eastern system at any given time.

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 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 2017, 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 their operating component of spinning reserves.

An agreement under which we supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. 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:
2016-2017
20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019
15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021
12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023
10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II.

6




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 53% of our energy requirements in 2015 and purchased approximately 47% which was supplied under the following contracts:

A PPA with PacifiCorp expiring in 2023, whereby we purchase 50 MW of coal-fired baseload power.

A PPA with Cheyenne Light expiring in 2028, under which we will purchase up to 14.7 MW of wind energy through Cheyenne Light’s agreement with Happy Jack.

A PPA with Cheyenne Light expiring in 2029, under which we will purchase up to 20 MW of wind energy through Cheyenne Light’s agreement with Silver Sage.

A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light’s excess energy.

Since 1995, we have been a net producer of energy. Our 2015 winter peak system load was 369 MW and our 2015 summer peak system load was 424 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

Related-party Gas Transportation Service Agreement - On October 1, 2014 we entered into a gas transportation service agreement with Cheyenne Light 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 Cheyenne Light 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. The revenues and expenses associated with these assets are included in rate base.

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.

Regulations

Rate Regulation

The following table illustrates certain enacted regulatory information with respect to the states in which we operate:

State
Authorized Rate of Return on Equity
Authorized Return on Rate Base
Capital Structure Debt/Equity
Effective Date
Other Tariffs, Riders and Rate Matters
Percentage of Off-System Sale Profits Shared with Customers
SD
Global Settlement
7.76%
Global Settlement
10/2014
ECA,TCA, Energy Efficiency Cost Recovery/ DSM
70%
SD
 
8.16%
 
6/2011
Environmental Improvement Cost Recovery Adjustment Tariff
N/A
WY
9.9%
8.13%
46.7%/53.3%
10/2014
ECA
65%
MT
15.0%
11.73%
47%/53%
1983
ECA
N/A
FERC
10.8%
9.10%
43%/57%
2/2009
FERC Transmission Tariff
N/A


7



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, Montana and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. In December 2015, we filed an application with the MTPSC to cancel the Montana Quarterly Fuel Rider and we expect a decision in the first quarter of 2016. 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 are:

An approved vegetation management recovery mechanism that allows for recovery of and a return on prudently-incurred vegetation management costs.

In South Dakota we have an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers receive a credit equal to 70% of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. Wyoming has a similar Fuel and Purchased Power Cost Adjustment.

In South Dakota we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011 and recovers costs associated with generation plant environmental improvements.

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

Rate Matters

South Dakota

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for us of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides us a return on our investment in Cheyenne Prairie and associated infrastructure, and provides recovery of our share of operating expenses for this natural gas fired facility. We implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

Transmission

On July 23, 2015, we received approval from the WPSC for a CPCN originally filed on July 22, 2014 to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. We received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion of this line. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in 2016.


8



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, 2015, we were subject to the following renewable energy portfolio standards or objectives:

South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015.

Montana. In 2005 Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, we filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. However, 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 South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. Mandatory portfolio standards have increased, and 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 Regulations

We are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the safety and health of personnel and the public. These laws and regulations affect a broad range of our utility activities, and generally regulate: (i) the protection of air and water quality; (ii) the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of, and emergency response in connection with hazardous and toxic materials and wastes, including asbestos; and (iii) the protection of plant and animal species and minimization of noise emissions. We have incurred, and expect to incur, capital, operating and maintenance costs for the operations of our plants to comply with these laws and regulations. While the requirements are evolving, it is virtually certain that environmental requirements placed on the operations will continue to be more restrictive.

In 2011, the EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates on December 21, 2012, which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule and our evaluation of costs to retrofit these plants, we suspended operations at the Osage plant on October 1, 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Osage, Ben French and Neil Simpson I on March 21, 2014.

On February 16, 2012, the EPA published in the Federal Register the National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units (MATS), which became effective on April 16, 2012. This rule imposes requirements for mercury, acid gases, metals and other pollutants. Affected units had a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain very limited circumstances. The current state air permit for Wygen III provides mercury emission limits and monitoring requirements with which we are in compliance. Neil Simpson II and Wygen III have been utilized for internal study and review of mercury emission control technology and have mercury monitors in place. Due to mercury absorbent issues encountered in 2015, the state of Wyoming approved a one year compliance deadline extension to April 16, 2016 for Neil Simpson II and Wygen III, for mercury only. The other components of the MATS rule remain in effect and these plants are in compliance with those requirements. The Wyodak plant is in compliance with all requirements of the MATS regulation.


9



On June 3, 2010, the EPA promulgated the GHG Tailoring Rule, implementing regulations of GHG for permitting purposes. This rule will impact us in the event of a major modification at an existing facility or in the event we establish a new major source of GHG emissions, as defined by EPA regulations. Upon renewal of operating permits for existing permitted facilities, monitoring and reporting requirements will be implemented. This rule established the basis for EPA’s October 23, 2015 suite of GHG emission rules for existing, new, modified and reconstructed facilities. The portion of this rule-making that applies to existing power generation sources is known as the Clean Power Plan (CPP). The portion of this rule-making that applies to new generating units effectively prohibits new coal-fired power plants from being constructed until carbon capture and sequestration becomes technically and economically feasible. The basis of the CPP regulation is to decrease existing coal-fired generation, increase the utilization of existing gas-fired combined cycle generation, increase renewable energy and increase use of DSM. States are required to develop and submit compliance plans to the EPA, with the initial submittal due by September 2016. The rule allows for a two year extension to submit a final plan and the states we operate in have indicated they will be submitting the extension request. Also on October 23, 2015, EPA proposed a Federal Implementation Plan, which will be imposed on any state that fails to submit a plan or fails to include the required contents of the plan. That rule will contain the modeling standards for CPP compliance and will be an integral part of state plan development. On February 9, 2016, the U.S. Supreme Court entered an order staying the Clean Power Plan. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. We do not expect a final judicial decision on challenges to the CPP earlier than mid-2017. While we cannot predict the terms of state plans, any limits on CO2 emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2015 we met with South Dakota and Wyoming regulatory agencies to discuss the rule implementation and potential compliance pathways.

Wyoming passed GHG legislation in 2012 and 2013, enabling the state to implement the EPA’s GHG program. Wyoming adopted and submitted a GHG regulatory program to the EPA, which the EPA approved and published in the November 22, 2013 Federal Register. As of December 23, 2013, Wyoming has full jurisdiction over the GHG permitting program which includes the transfer of the Cheyenne Prairie EPA GHG air permit, to the state of Wyoming. This eliminates the increased time, expense and considerable risk of obtaining a permit from the EPA.

In 2015, we reported 2014 GHG emissions from our Power Generation facilities in order to comply with the EPA’s GHG Annual Inventory regulation, issued in 2009. We continue to report annual GHG emissions as required by the EPA. Climate change issues are the subject of a number of lawsuits, the outcome of which could impact the utility industry. We will continue to review GHG impacts as legislation or regulation develops and litigation is resolved.

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 and the closure of certain generating facilities. 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. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility customers and other purchasers of the power generated by our non-regulated power plants, including utility affiliates. Any unrecovered costs could have a material impact on our results of operations, financial position or cash flows. 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.

In August 2012, the EPA proposed revisions to the Electric Utility New Source Performance Standards for stationary combustion turbines. This rule is expected to be finalized in 2016 and, as proposed, will be applicable to Cheyenne Prairie and eventually all the combustion turbines in our fleet. Among other things, the rule seeks to eliminate startup exemptions and clearly define overhauls for impact on the EPA’s New Source Review regulations, with the intention of eventually bringing all units under the applicability of this rule. The primary impact is expected to be on our older existing units, which will eventually be required to meet tighter NOx emission limitations.

By May 3, 2013, all of our diesel generator engines were required to comply with EPA’s Stationary Reciprocating Internal Combustion Engine Hazardous Air Pollutant regulations. Evaluations were completed, emission control equipment was installed and emission testing confirmed compliance with those requirements.


10



In 2011, the State of Wyoming issued a letter requiring Neil Simpson II to include startup and shutdown SO2 and NOx emissions when evaluating compliance with permitted emission limits. This represented a significant change from requirements in the original 1993 air permit. Minor engineered design changes were made to improve scrubber performance during startup. Those changes enabled the unit to meet the new requirements. The unit was previously fitted with state of the art low NOx burners that support compliance with this new requirement. Also in 2014, Neil Simpson II and Wygen III have converted startup fuel from diesel to natural gas to support potential start-up requirements and future GHG state compliance plans.

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.

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 2015 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 from those discussed in our forward-looking statements, or otherwise.

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable, which could adversely affect our results of operations, financial position or liquidity.

Our electricity 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. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. 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 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 will 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 case. 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.


11



Our financial performance depends on the successful operations 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 involves risks, including:

Operational limitations imposed by environmental and other regulatory requirements;

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 the ability to operate our facilities;

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

Inability to recruit and retain skilled technical labor;

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;

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

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; and

Labor relations.

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

A future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-regulated customers. If late payments and uncollectible accounts increase, our results of operations, financial position and liquidity could be adversely impacted.

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

Our credit rating on our First Mortgage Bonds is A1 by Moody’s, A- by S&P and A by Fitch. Any reduction in our credit ratings by the rating agencies could adversely affect our ability to refinance our existing debt and to complete new financings on reasonable terms or at all. In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations. A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.


12



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;

Contract restrictions upon the timing of scheduled outages;

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;

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 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.

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. The related power 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 the system operators in those markets. Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant, unpredictable price fluctuations over relatively short periods of time.


13



Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events could disrupt or impair our operations, create additional costs and cause 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 mechanical problems that could cause substantial adverse financial impacts. These events could result in injury or loss of human life, significant damage to property or natural resources (including public parks), environmental pollution, impairment of our operations, and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. 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 significant.

Our operating results can be adversely affected by variations from normal weather patterns.

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 financial condition and results of operations.

Our businesses are 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 storms. 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 and cash flows.

The failure to achieve or maintain compliance with existing or future governmental laws, regulations or requirements could adversely affect our results of operations, financial position or liquidity. Additionally, the potentially high cost of complying with such requirements or addressing environmental liabilities could also adversely affect our results of operations, financial position or liquidity.

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to operate, which could require significant capital expenditures and operating costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of penalties, liens or fines; claims for property damage or personal injury; and/ or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures or cause us to reevaluate the feasibility of continued operations at certain sites and have a detrimental effect on our business.

Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.

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 affected by developments affecting insurance businesses, international, national, state or local events and company-specific 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, distribution property losses and cyber security risks.


14



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 seek 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 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.

Federal and state laws concerning greenhouse gas regulations and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.
We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likely 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 caption “Environmental Regulations.”
On February 16, 2012, the EPA published in the Federal Register MATS, with an effective date of April 16, 2012. Affected units had a compliance deadline of April 16, 2015, with a pathway defined to apply for a one year extension due to certain circumstances. We applied for and received a one year extension for mercury only, with the remaining aspects of the MATS rule remaining in effect. All our impacted plants (Neil Simpson II, Wygen III and the Wyodak Plant) are in compliance with the applicable rule provisions.
The GHG Tailoring Rule, implementing regulations of GHG for permitting purposes, became effective in June 2010. This rule will impact us in the event of a major modification at an existing facility or in the event of a new major source as defined by EPA regulations. Upon renewal of operating permits for existing facilities monitoring and reporting requirements will be implemented. New projects or major modifications to existing projects will result in a Best Available Control Technology review that could impose more stringent emissions control practices and technologies. The EPA’s GHG New Source Performance Standard for new steam electric generating units was published October 23, 2015. The rule effectively prohibits new coal fired units until carbon capture and sequestration becomes technically and economically feasible.
On October 23, 2015, the EPA finalized the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and DSM. This rule could have a significant impact on our coal and natural gas generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. On February 9, 2016, the U.S. Supreme Court entered an order staying the Clean Power Plan. The stay of the CPP will remain in place until the U.S. Supreme Court either denies a petition for certiorari following the U.S. Court of Appeals’ decision on the substantive challenges to the CPP, if one is submitted, or until the U.S. Supreme Court enters judgment following grant of a petition for certiorari. The effect of the order is to delay the CPP’s compliance deadlines until challenges to the CPP have been fully litigated and the U.S. Supreme Court has ruled. We do not expect a final judicial decision on challenges to the CPP earlier than mid-2017. While we cannot predict the terms of state plans, any limits on CO2 emissions at our existing plants could have a material impact on our customer rates, financial position, results of operations and/or cash flows. In 2015, we met with state air programs and public utility commissions on several occasions. We will continue to work closely with state regulatory staff as these plans develop.
Due to uncertainty as to the final outcome of federal climate change legislation, 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. The impact of GHG legislation or regulation on our company will depend upon many factors, including but not limited to, the timing of implementation, state clean power plan requirements, the GHG sources that are regulated, the overall GHG emissions cap level and the availability of technologies to control or reduce GHG emissions. If an allowance or credit trading structure is implemented, the impact will depend on the allocation of emission allowances to specific sources, the costs of those allowances or credits and the effect of carbon regulation on natural gas and coal prices.

15



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 generating facilities and potential increased load of our combined cycle natural gas fired 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, EPA, OSHA and SEC may impose significant and sometimes punitive civil and criminal penalties to enforce compliance requirements relative to our business. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the NERC, with similar penalty authority for violations. If a serious regulatory violation did occur, and penalties were imposed by FERC or another federal agency, this action 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 or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.

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 and could adversely affect our results of operations, financial position and liquidity.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their 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.


16



A disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation), within our system or within a neighboring system. Any such disruption could have a material impact on our financial results.

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

We operate in a highly regulated industry that requires the continuous use and operation of 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 and gas distribution systems, could result in a full or partial disruption of our electric operations. Cyber attacks targeting other key information technology systems could further add to a full or partial disruption to 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. FERC, through the North American Electric Reliability Corporation, requires certain safeguards be implemented to deter cyber attacks. 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 were to fail or be breached by a cyber attack or a computer virus, and be unable to be recovered 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 plans 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.

We have a defined benefit pension plan that covers a substantial portion of our 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 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. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

In March 2010, the President of the United States signed the Patient Protection and Affordable Care Act of 2010 as amended by the Health Care and Education Reconciliation Act of 2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the organization and the specific impacts on a company’s employees. Certain provisions of the 2010 Acts are effective while other provisions of the 2010 Acts will be effective in future years. The 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes as well as changes to the costs of our plans. The ultimate extent and cost of these changes cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of the 2010 Acts become available.


17



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

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,
2015
Variance
2014
Variance
2013
 
(in thousands)
Revenue
$
277,864

$
9,376

$
268,488

$
14,461

$
254,027

Fuel and purchased power
83,339

(10,637
)
93,976

4,539

89,437

Gross margin
194,525

20,013

174,512

9,922

164,590

 
 
 
 
 
 
Operating expenses
106,611

1,213

105,398

3,152

102,246

Operating income
87,914

18,800

69,114

6,770

62,344

 
 
 
 
 
 
Interest expense, net
(21,174
)
(1,472
)
(19,702
)
(411
)
(19,291
)
Other income
1,034

372

662

123

539

Income tax expense
(22,600
)
(6,088
)
(16,512
)
(3,093
)
(13,419
)
Net income
$
45,174

$
11,612

$
33,562

$
3,389

$
30,173



18



The following tables provide certain electric utility operating statistics for the years ended December 31 (dollars in thousands):
Revenue
Customer Base
2015
Percentage Change
2014
Percentage Change
2013
Residential
$
72,659

4
 %
$
69,712

8
 %
$
64,566

Commercial
100,511

9
 %
91,882

14
 %
80,289

Industrial
33,336

17
 %
28,451

3
 %
27,705

Municipal
3,626

6
 %
3,409

 %
3,421

Total retail sales
210,132

9
 %
193,454

10
 %
175,981

Contract wholesale
17,537

(17
)%
21,206

(3
)%
21,956

Wholesale off-system
23,241

(17
)%
28,002

(5
)%
29,580

Total electric sales
250,910

3
 %
242,662

7
 %
227,517

Other revenue
26,954

4
 %
25,826

(3
)%
26,510

Total revenue
$
277,864

3
 %
$
268,488

6
 %
$
254,027


MWh Sold
Customer Base
2015
Percentage Change
2014
Percentage Change
2013
Residential
521,828

(4
)%
542,008

(2
)%
555,204

Commercial
792,466

1
 %
782,238

7
 %
730,701

Industrial
429,140

7
 %
399,648

(1
)%
404,009

Municipal
31,924

 %
32,076

(7
)%
34,344

Total retail sales
1,775,358

1
 %
1,755,970

2
 %
1,724,258

Contract wholesale
260,893

(23
)%
340,871

(5
)%
357,193

Wholesale off-system
837,120

4
 %
808,257

(19
)%
1,002,847

Total electric sales
2,873,371

(1
)%
2,905,098

(6
)%
3,084,298

Losses and company use
167,332

(6
)%
177,577

12
 %
158,845

Total energy
3,040,703

(1
)%
3,082,675

(5
)%
3,243,143


We own approximately 445 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023. On March 21, 2014, we retired the Ben French, Neil Simpson I, and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. On October 1, 2014, we transferred the remaining net book value of these retired plants to a regulatory asset in accordance with an order granted by the SDPUC. These plants are primarily replaced by our share of Cheyenne Prairie.

Regulated Power Plant Fleet Availability
2015
2014
 
2013
Coal-fired plants
91.1%
91.8%
 
96.3%
Other plants
96.0%
91.5%
(a) 
96.8%
Total availability
93.9%
91.6%
 
96.5%
_________________________
(a)
2014 decrease from 2013 was due to the scheduling of outages in 2014 compared to 2013.

19



Resources
2015
Percentage Change
2014
Percentage Change
2013
MWh generated:
 
 
 
 
 
Coal
1,537,744

(3
)%
1,591,061

(10
)%
1,768,483

Gas
80,944

80
 %
44,984

35
 %
33,374

 
1,618,688

(1
)%
1,636,045

(9
)%
1,801,857

 
 
 
 
 
 
MWh purchased
1,422,015

(2
)%
1,446,630

 %
1,441,286

Total resources
3,040,703

(1
)%
3,082,675

(5
)%
3,243,143


Heating and Cooling Degree Days
2015
2014
2013
Actual
 
 
 
Heating degree days
6,521

7,373

7,582

Cooling degree days
577

481

724

 
 
 
 
Variance from 30-year average
 
 
 
Heating degree days
(8
)%
4
 %
9
%
Cooling degree days
(14
)%
(28
)%
8
%

2015 Compared to 2014

Gross margin increased primarily due to a return on capital investments in Cheyenne Prairie which increased gross margins by $11.9 million and increased energy cost recoveries by $2.7 million. Retail margins increased $4.7 million primarily due to commercial and industrial load increases from higher MWh sold. These increases are partially offset by an approximately $1.7 million decrease in residential margins driven primarily by a 12% decrease in heating degree days compared to the same period in the prior year.

Operations and maintenance increased reflecting an increase in depreciation expense primarily due to a higher asset base and amortization of regulatory plant decommissioning costs.

Interest expense, net increased primarily due to interest costs from the $85 million of permanent financing put in place during the fourth quarter of 2014 for Cheyenne Prairie.

Other income, net was comparable to the prior year.

Income tax expense: The 2015 effective tax rate is comparable to the prior year.

2014 Compared to 2013

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $6.0 million and $1.8 million from the Cheyenne Prairie construction financing rider. An increase in commercial and industrial MWh sold increased gross margins $2.3 million. These increases were partially offset by a $1.1 million decrease in wholesale margins driven by plant outages affecting unit-contingent wholesale contracts.

Operations and maintenance increased primarily due to an increase in depreciation, driven by an increased asset base, higher employee costs, property taxes, and a true-up made in the prior year for generation dispatch services billed to a third party. These were partially offset by a decrease in vegetation management expenses.

Interest expense, net increased primarily due to the increase in long-term debt from permanent financing put in place for Cheyenne Prairie by the sale of $85 million of first mortgage bonds on October 1, 2014.

Other income, net was comparable to the prior year.


20



Income tax expense: The effective rate is higher in 2014 due to an unfavorable true-up adjustment and the recording of the 2012 research and development credit in 2013.

Financing Plans and Activity

On October 1, 2014, in a private placement transaction to provide permanent financing for Cheyenne Prairie, we issued
$85 million of 4.43% coupon first mortgage bonds due October 20, 2044. Proceeds from the bond sale also funded the September 30, 2014 early redemption of our 5.35% $12 million pollution control revenue bonds, originally due October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

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, 2015:

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

Significant Events

Regulatory Matters

On July 23, 2015, we received approval from the WPSC for a CPCN originally filed on July 22, 2014 to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. We received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion of this line. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in 2016.

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for us of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides us a return on our investment in Cheyenne Prairie and associated infrastructure, and provides recovery of our share of operating expenses for this natural gas fired facility. We implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

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 our Notes to Financial Statements in this Annual Report on Form 10-K.


21



Pension and Other Postretirement Benefits

The Company, as described in Note 8 to the Financial Statements in this Annual Report on Form 10-K, has a defined benefit pension plan and post-retirement healthcare plan. As of December 31, 2012, a Master Trust was established for the investment of assets of the defined benefit pension plans. Each participating retirement plan has an undivided interest in the Master Trust.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. 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 discount rate used to determine annual defined benefit pension costs accruals will be 4.25% in 2016 and the discount rate used in 2015 was 4.25%. In selecting the discount rate, we consider cash flow durations for each plan’s liabilities on high credit fixed income yield curves for comparable durations. We do not pre-fund our non-qualified plans or postretirement healthcare plans.

Beginning in 2016, the Company will change 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. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Prior to 2016, the service and interest costs were determined using a single weighted-average discount rate based on hypothetical AA Above Median yield curves used to measure the benefit obligation at the beginning of the period. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income.
The Company changed to the new method to provide a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The company will account for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 service costs are 4.81%, 4.88% and 4.18% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The discount rates used to measure the 2016 interest costs are 3.90%, 3.82% and 3.17% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.63% for pension, 4.50% for supplemental non-qualified defined benefit and 4.03% for other postretirement benefit costs. The decrease in the 2016 service and interest costs is approximately $0.5 million, $0.03 million and $0.1 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method.

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.

We use the asset and liability method of accounting for income taxes. Under this 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 net 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 have chosen to early adopt on a prospective basis ASU 2015-17. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current amounts. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current.


22



In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. With respect to changes in tax law, the Protecting Americans from Tax Hikes Act of 2015, which was enacted December 18, 2015, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. The Tax Increase Prevention Act (TIPA), which was enacted December 19, 2014, did not have a material impact on the amounts provided for income taxes including our ability to realize deferred tax assets. Certain provisions of the TIPA involving primarily the extension of 50 percent bonus depreciation resulted in the generation of a NOL for federal income tax purposes in 2014.

In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations had the effect of a change in law and as a result the impact was taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We implemented all of the provisions of the final regulations with the filing of the 2013 federal income tax return in September 2014. The adoption of the final regulations did not have a material impact on our financial statements.

See Note 6 in our Notes to Financial Statements in this Annual Report on Form 10-K for additional information.

Contingencies

When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position, results of operations and cash flows. We describe any contingencies in Note 11 of the Financial Statements in this Annual Report on Form 10-K.


23



ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS



 
Page
 
 
Management’s Report on Internal Controls Over Financial Reporting
 
 
Report of Independent Registered Public Accounting Firm
 
 
Statements of Income for the three years ended December 31, 2015
27 
 
 
Statements of Comprehensive Income (Loss) for the three years ended December 31, 2015
 
 
Balance Sheets as of December 31, 2015 and 2014
 
 
Statements of Cash Flows for the three years ended December 31, 2015
 
 
Statements of Common Stockholder’s Equity for the three years ended December 31, 2015
 
 
Notes to Financial Statements


24



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, 2015, 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, 2015.

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


25



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
Black Hills Power, Inc.
Rapid City, South Dakota

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the “Company”) as of December 31, 2015 and 2014, and the related statements of income, comprehensive income (loss), common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
February 26, 2016


26



BLACK HILLS POWER, INC.
STATEMENTS OF INCOME

Years ended December 31,
2015
2014
2013
 
(in thousands)
 
 
 
 
Revenue
$
277,864

$
268,488

$
254,027

 
 
 
 
Operating expenses:
 
 
 
Fuel and purchased power
83,339

93,976

89,437

Operations and maintenance
68,088

70,356

68,857

Depreciation and amortization
32,552

29,100

28,125

Taxes - property
5,971

5,942

5,264

Total operating expenses
189,950

199,374

191,683

 
 
 
 
Operating income
87,914

69,114

62,344

 
 
 
 
Other income (expense):
 
 
 
Interest expense
(22,337
)
(20,569
)
(19,725
)
AFUDC - borrowed
506

248

186

Interest income
657

619

248

AFUDC - equity
918

519

368

Other expense
(117
)
(105
)
(196
)
Other income
233

248

367

Total other income (expense)
(20,140
)
(19,040
)
(18,752
)
 
 
 
 
Income before income taxes
67,774

50,074

43,592

Income tax expense
(22,600
)
(16,512
)
(13,419
)
 
 
 
 
Net income
$
45,174

$
33,562

$
30,173



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


27




BLACK HILLS POWER, INC.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Years ended December 31,
2015
2014
2013
 
(in thousands)
 
 
 
 
Net income
$
45,174

$
33,562

$
30,173

 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
Benefit plan liability adjustments - net gain (loss) (net of tax of $(36), $189 and $(73), respectively)
68

(351
)
139

Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(33), $(16) and $(23), respectively)
61

29

43

Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $319, $(364) and $(23), respectively)
383

(300
)
41

Other comprehensive income (loss), net of tax
512

(622
)
223

 
 
 
 
Comprehensive income (loss), net of tax
$
45,686

$
32,940

$
30,396


See Note 7 for additional disclosure related to comprehensive income.

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

28



BLACK HILLS POWER, INC.
BALANCE SHEETS
As of December 31,
2015
2014
 
(in thousands, except share amounts)
ASSETS
 
 
Current assets:
 
 
Cash and cash equivalents
$
7,559

$
6,620

Receivables - customers, net
27,856

34,684

Receivables - affiliates
5,747

5,350

Other receivables, net
236

259

Money pool notes receivable
76,813

68,626

Materials, supplies and fuel
24,282

20,965

Deferred income tax assets, net, current

13,661

Regulatory assets, current
14,096

10,257

Other current assets
43,118

4,954

Total current assets
199,707

165,376

 
 
 
Investments
4,725

4,584

 
 
 
Property, plant and equipment
1,166,126

1,115,061

Less accumulated depreciation and amortization
(326,074
)
(309,767
)
Total property, plant and equipment, net
840,052

805,294

 
 
 
Other assets:
 
 
Regulatory assets, non-current
71,717

68,427

Other, non-current assets
3,292

11,708

Total other assets
75,009

80,135

TOTAL ASSETS
$
1,119,493

$
1,055,389


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


29



BLACK HILLS POWER, INC.
BALANCE SHEETS
(Continued)

As of December 31,
2015
2014
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
 
 
Current liabilities:
 
 
Accounts payable
$
21,297

$
30,543

Accounts payable - affiliates
30,032

19,242

Accrued liabilities
69,454

16,415

Regulatory liabilities, current

3,073

Total current liabilities
120,783

69,273

 
 
 
Long-term debt
342,756

342,752

 
 
 
Deferred credits and other liabilities:
 
 
Deferred income tax liabilities, net, non-current
188,961

193,042

Regulatory liabilities, non-current
51,583

51,916

Benefit plan liabilities
20,033

20,981

Other, non-current liabilities
3,398

2,631

Total deferred credits and other liabilities
263,975

268,570

 
 
 
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
330,295

313,622

Accumulated other comprehensive loss
(1,307
)
(1,819
)
Total stockholder’s equity
391,979

374,794

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
1,119,493

$
1,055,389


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

30



BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWS

Years ended December 31,
2015
2014
2013
 
(in thousands)
Operating activities:
 
 
 
Net income
$
45,174

$
33,562

$
30,173

Adjustments to reconcile net income to net cash provided by operating activities -
 
 
 
Depreciation and amortization
32,552

29,100

28,125

Deferred income taxes
7,690

16,518

13,582

AFUDC - equity
(918
)
(519
)
(368
)
Employee benefits
2,403

1,295

3,094

Other adjustments
232

(2,330
)
1,400

Change in operating assets and liabilities -
 
 
 
Accounts receivable and other current assets
(2,236
)
(10,412
)
(5,265
)
Accounts payable and other current liabilities
21,652

10,829

1,180

Contributions to defined benefit pension plan

(1,696
)
(2,299
)
Regulatory assets
(3,839
)
(5,366
)
107

Regulatory liabilities
(2,479
)
2,479

(17
)
Other operating activities
(5,680
)
(6,624
)
(3,149
)
Net cash provided by operating activities
94,551

66,836

66,563

 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(56,795
)
(82,826
)
(74,390
)
Notes receivable from affiliate companies, net
(36,687
)
(51,334
)
6,353

Other investing activities
(128
)
(154
)
(72
)
Net cash provided by (used in) investing activities
(93,610
)
(134,314
)
(68,109
)
 
 
 
 
Financing activities:
 
 
 
Long-term debt - repayments

(12,200
)

Long-term debt - issuance

85,000


Other financing activities
(2
)
(961
)

Net cash provided by (used in) financing activities
(2
)
71,839


 
 
 
 
Net change in cash and cash equivalents
939

4,361

(1,546
)
 
 
 
 
Cash and cash equivalents:
 
 
 
Beginning of year
6,620

2,259

3,805

End of year
$
7,559

$
6,620

$
2,259


See Note 10 for Supplemental Cash Flows information.

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

31



BLACK HILLS POWER, INC.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

 
2015
2014
2013
 
(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
$
313,622

$
280,060

$
257,887

Net income
45,174

33,562

30,173

Non-cash dividend to Parent company
(28,501
)

(8,000
)
Balance end of year
$
330,295

$
313,622

$
280,060

 
 
 
 
Accumulated other comprehensive loss:
 
 
 
Balance beginning of year
$
(1,819
)
$
(1,197
)
$
(1,420
)
Other comprehensive (loss) income, net of tax
512

(622
)
223

Balance end of year
$
(1,307
)
$
(1,819
)
$
(1,197
)
 
 
 
 
Total stockholder’s equity
$
391,979

$
374,794

$
341,854


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

32



NOTES TO FINANCIAL STATEMENTS
December 31, 2015, 2014 and 2013

 
(1)    BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (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. Actual results could differ from those estimates.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be 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.

Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating our electric operations. 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 criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.

Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheets.

33



We had the following regulatory assets and liabilities as follows as of December 31 (in thousands):
 
Maximum Recovery Period (in years)
2015
2014
Regulatory assets:
 
 
 
Unamortized loss on reacquired debt (a)
9
$
2,096

$
2,377

AFUDC(b)
45
8,571

8,365

Employee benefit plans(c)
12
20,866

24,418

Deferred energy costs(a)
1
19,875

14,696

Flow through accounting(a)
35
12,104

11,171

Decommissioning costs (b)
9
13,686

11,786

Other regulatory assets(a) (d)
2
8,615

5,871

Total regulatory assets
 
$
85,813

$
78,684

 
 
 
 
Regulatory liabilities:
 
 
 
Cost of removal for utility plant(a)
53
$
38,131

$
35,510

Employee benefit plans(c)
12
12,616

14,538

Other regulatory liabilities(c)
13
836

4,941

Total regulatory liabilities
 
$
51,583

$
54,989

____________________
(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, respectively.
(d)
Includes approximately $5.0 million of vegetation management expenses.

Regulatory assets represent items we expect to recover from customers through rates.

Unamortized Loss on Reacquired Debt - The early redemption premium on reacquired bonds is being amortized over the remaining term of the original bonds.

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 plans and 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 Costs - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that are 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.


34



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. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset established to reflect the 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 consistent with the flow-through method with respect to costs considered repairs for tax purposes and 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.

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 retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement aspect of a rate regulated environment.

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. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collection success given the existing collections environment.

Following is a summary of accounts receivable at December 31 (in thousands):
 
2015
2014
Accounts receivable trade
$
15,268

$
24,946

Unbilled revenues
12,795

9,999

Allowance for doubtful accounts
(207
)
(261
)
Net accounts receivable trade
$
27,856

$
34,684



35



Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. Taxes collected from our customers are recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, we accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month, and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Receivables- customers, net on the accompanying Balance Sheets.

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis.

Other Current Assets

The following amounts by major classification are included in Other current assets on the accompanying Balance Sheets as of (in thousands):
 
December 31, 2015

December 31, 2014

Accrued receivables related to litigation expenses and settlements
$
39,050

$

Other (none of which is individually significant)
4,068

4,954

Total other current assets
$
43,118

$
4,954


Accrued Liabilities

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

 
December 31, 2015
December 31, 2014
Accrued employee compensation, benefits and withholdings
$
5,054

$
4,689

Accrued property taxes
4,962

4,721

Accrued payments related to litigation expenses and settlements
38,750


Accrued income taxes
13,031


Customer deposits and prepayments
2,216

1,934

Accrued interest
4,600

4,662

Other (none of which is individually significant)
841

409

Total accrued liabilities
$
69,454

$
16,415


Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.


36



Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is AFUDC, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations 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.

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 2015, 2.3% in 2014 and 2.1% in 2013.

Derivatives and Hedging Activities

From time to time we utilize risk management contracts including forward purchases and sales to hedge the price of fuel for our combustion turbines and fixed-for-float swaps to fix the interest on any variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. Gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, net of tax, in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales 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 exceptions, 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

Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.


37



Level 2 - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, 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 include significant inputs that are generally less observable from objective sources.

Impairment of Long-Lived Assets

We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, we would recognize an impairment loss.

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.

We use the asset and liability method in accounting for income taxes. Under the 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. At December 31, 2015, we have chosen to early adopt on a prospective basis ASU 2015-17 as discussed below under Recently Issued and Adopted Accounting Standards. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current.

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 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 and Adopted Accounting Principles

Balance Sheet Classification of Deferred Taxes, ASU 2015-17

In November 2015, the FASB issued ASU 2015-17 providing guidance on financial statement presentation for deferred tax assets and deferred tax liabilities. All deferred taxes are to be presented as non-current. FASB issued this guidance as part of its initiative to reduce complexity in accounting standards. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years (i.e., in the first quarter of 2017 for calendar year-end companies). The guidance may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively by reclassifying the comparative balance sheets. Early adoption is permitted. We have chosen early adoption as of December 31, 2015, on a prospective basis. At December 31, 2015, the balance sheet reflects a net non-current deferred tax liability of $189 million. The balance sheet presentation as of December 31, 2014 was not adjusted retrospectively and remains as previously reported with a net current deferred tax asset of $14 million and a non-current deferred tax liability of $193 million.


38



Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted. We have chosen not to early adopt ASU 2015-03.

Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance would be effective for annual and interim reporting periods beginning after December 15, 2018 and early adoption is permitted. We are currently assessing the impact that adoption of ASU 2014-09 will have 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):
 
 
2015
 
2014
 
 
 
Weighted
 
Weighted
 
 
 
 
Average
 
Average
Lives (in years)
 
2015
Useful Life (in years)
2014
Useful Life (in years)
Minimum
Maximum
Electric plant:
 
 
 
 
 
 
Production
$
569,182

46
$
567,936

48
40
65
Transmission
117,708

48
115,949

46
40
60
Distribution
353,241

46
336,652

39
20
60
Plant acquisition adjustment (a)
4,870

32
4,870

32
32
32
General
88,939

22
79,738

22
5
40
Total plant-in-service
1,133,940

 
1,105,145

 
 
 
Construction work in progress
32,186

 
9,916

 
 
 
Total electric plant
1,166,126

 
1,115,061

 
 
 
Less accumulated depreciation and amortization
(326,074
)
 
(309,767
)
 
 
 
Electric plant net of accumulated depreciation and amortization
$
840,052

 
$
805,294

 
 
 
__________________
(a)
The plant acquisition adjustment is included in rate base and is being recovered with 15 years remaining.


39



(3)    JOINTLY OWNED FACILITIES

We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following 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 MAPP region. The total transfer capacity of the transmission tie is 400 MW - 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. Cheyenne Light owns the remaining 40 MW. This facility was placed into commercial operations on October 1, 2014. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.

The investments in our jointly owned plants and accumulated depreciation are included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plants is included in the corresponding categories of operating expenses in the accompanying Statements of Income. Each of the respective owners is responsible for providing its own financing.

As of December 31, 2015, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (in thousands):
Interest in jointly-owned facilities
Plant in Service
Construction Work in Progress
Accumulated Depreciation
Wyodak Plant
$
111,532

$
1,039

$
56,812

Transmission Tie
$
19,648

$

$
5,390

Wygen III
$
137,860

$
446

$
16,217

Cheyenne Prairie
$
91,081

$

$
3,301


(4)    LONG-TERM DEBT

Long-term debt outstanding at December 31 was as follows (in thousands):
 
Maturity Date
Interest Rate
2015
2014
First Mortgage Bonds due 2032
August 15, 2032
7.23
%
$
75,000

$
75,000

First Mortgage Bonds due 2039
November 1, 2039
6.125
%
180,000

180,000

First Mortgage Bonds due 2044
October 20, 2044
4.43
%
85,000

85,000

Unamortized discount, First Mortgage Bonds due 2039
 
 
(99
)
(103
)
Series 94A Debt (a)
June 1, 2024
0.75
%
2,855

2,855

Long-term debt
 
 
$
342,756

$
342,752

___________________
(a)
Variable interest rate at December 31, 2015.

40




On October 1, 2014 we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044. Proceeds from our bond sale funded the early redemption of our 5.35% $12 million pollution control revenue bonds, originally due October 1, 2024.

Net deferred financing costs of approximately $3.1 million and $3.3 million were recorded on the accompanying Balance Sheets in Other, non-current assets at December 31, 2015 and 2014, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million, $0.1 million and $0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, 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, 2015.

Long-term Debt Maturities

Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts) are as follows (in thousands):
2016
$

2017
$

2018
$

2019
$

2020
$

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):
 
2015
2014
 
Carrying Value
Fair Value
Carrying Value
Fair Value
Cash and cash equivalents (a)
$
7,559

$
7,559

$
6,620

$
6,620

Long-term debt, including current maturities (b)
$
342,756

$
404,864

$
342,752

$
430,497

_______________
(a)
Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
(b)
Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods. For additional information on our long-term debt see Note 4.

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

Cash and Cash Equivalents

Included in cash and cash equivalents is cash and overnight repurchase agreement accounts. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.


41



(6)    INCOME TAXES

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

 
2015
2014
2013
Current
$
14,910

$
(6
)
$
(163
)
Deferred
7,690

16,518

13,582

Total income tax expense
$
22,600

$
16,512

$
13,419


The temporary differences which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
 
2015
2014
Deferred tax assets:
 
 
Employee benefits
$
4,683

$
4,995

Net operating loss
15

14,794

Regulatory liabilities
9,908

10,824

Other
16,171

2,864

Total deferred tax assets
30,777

33,477

 
 
 
Deferred tax liabilities:
 
 
Accelerated depreciation and other plant related differences
(187,666
)
(184,478
)
AFUDC
(8,571
)
(8,365
)
Regulatory assets
(4,236
)
(3,910
)
Employee benefits
(3,003
)
(3,723
)
Deferred costs
(14,765
)
(11,324
)
Other
(1,497
)
(1,058
)
Total deferred tax liabilities
(219,738
)
(212,858
)
 
 
 
Net deferred tax assets (liabilities)
$
(188,961
)
$
(179,381
)

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
 
2015
2014
2013
Federal statutory rate
35.0
 %
35.0
 %
35.0
 %
Amortization of excess deferred and investment tax credits
(0.1
)
(0.3
)
(0.3
)
Equity AFUDC
(0.6
)
(0.1
)

Flow through adjustments (a)
(0.9
)
(1.9
)
(2.5
)
Tax credits

(0.2
)
(0.8
)
Other

0.5

(0.6
)
 
33.4
 %
33.0
 %
30.8
 %
_________________________
(a)
The flow-through adjustments relate primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow through method.


42



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):
 
2015
2014
Unrecognized tax benefits at January 1
$
1,623

$
2,443

Additions for prior year tax positions
888

434

Reductions for prior year tax positions
(247
)
(1,254
)
Additions for current year tax positions


Unrecognized tax benefits at December 31
$
2,264

$
1,623


The reductions for prior year tax positions relate to the reversal through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million.

It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2015 and 2014, the interest expense recognized was not material to our financial results.

In January 2016, the Company reached an agreement in principle with IRS Appeals with respect to research and development tax credits and deductions for tax years 2007 through 2009, and expect a reduction of approximately $0.4 million with respect to our liability for unrecognized tax benefits on or before December 31, 2016.

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

At December 31, 2015, we are no longer in a federal NOL carry forward position.

(7)    COMPREHENSIVE INCOME

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):
 
Derivatives Designated as Cash Flow Hedges
Amounts Reclassified from AOCI
 
 
2015
2014
Gains and Losses on cash flow hedges
 
 
 
Interest rate swaps gain (loss)
Interest expense
$
64

$
64

Income tax
Income tax benefit (expense)
319

(364
)
Total reclassification adjustments related to cash flow hedges, net of tax
 
$
383

$
(300
)
 
 
 
 
Amortization of defined benefit plans:
 
 
 
Actuarial gain (loss)
Operations and maintenance
$
94

$
45

Income tax
Income tax benefit (expense)
(33
)
(16
)
Total reclassification adjustments related to defined benefit plans, net of tax
 
$
61

$
29


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.


43



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, 2014
$
(1,018
)
$
(801
)
$
(1,819
)
Other comprehensive income (loss)
383

129

512

As of December 31, 2015
$
(635
)
$
(672
)
$
(1,307
)
 
 
 
 
 
 
 
Interest Rate Swaps
Employee Benefit Plans
Total
 
 
 
 
As of December 31, 2013
$
(719
)
$
(478
)
$
(1,197
)
Other comprehensive income (loss)
(299
)
(323
)
(622
)
As of December 31, 2014
$
(1,018
)
$
(801
)
$
(1,819
)

(8)    EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of the postretirement benefit plan is required to be recognized in the statement of financial position. The funded status for the pension plan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. The measurement date of the plans is December 31, our year-end balance sheet date. As of December 31, 2015, the unfunded status of our Defined Benefit Pension Plan was $11 million, the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $3.4 million and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $6.2 million.

We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.

Defined Benefit 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.

Pension Plan assets are held in a Master Trust that was established for the investment of assets of the Plan and other Employer-sponsored retirement plans. Each participating retirement plan has an undivided interest in the Master Trust.
The BHC Board of Directors have approved the Plans’ 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 Plans’ 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 Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments. The expected long-term rate of return for investments was 6.75% and 6.75% for the 2015 and 2014 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.


44



Pension Plan Assets

The percentages of total plan asset fair value by investment category of our Pension Plan assets at December 31 were as follows:
 
2015
2014
Equity securities
26
%
27
%
Real estate
5

5

Fixed income funds
59

58

Cash and cash equivalents
1

2

Hedge funds
9

8

Total
100
%
100
%

Supplemental Non-qualified Defined Benefit Retirement Plans

We have various supplemental retirement plans (“Supplemental Plans”) for key executives. The Supplemental Plans are non-qualified defined benefit plans. The Supplemental Plans are subject to various vesting schedules.

Supplemental Plan Assets

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

Non-pension Defined Benefit Postretirement Healthcare Plan

Employees who are participants in our Non-Pension Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Plan Assets

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

Plan Contributions and Estimated Cash Flows

Cash contributions for pension plans are made directly to the Pension Plan Trust accounts. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands):
 
2015
2014
Defined Benefit Plans
 
 
Defined Benefit Pension Plan
$

$
1,696

Non-pension Defined Benefit Postretirement Healthcare Plan
$
267

$
399

Supplemental Non-qualified Defined Benefit Plan
$
211

$
217

 
 
 
Defined Contribution Plans
 
 
Company Retirement Contribution
$
811

$
638

Matching Contributions
$
1,423

$
1,377


Although we are not required we expect to contribute approximately $1.6 million to our Defined Benefit Pension Plan in 2016.


45



Fair Value Measurements

As required by accounting standards for 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. Our 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 as of December 31 (in thousands):
Defined Benefit Pension Plan
2015
 
Level 1
Level 2
Level 3
Total Fair Value
Common Collective Trust - Cash and Cash Equivalents
$

$
498

$

$
498

Common Collective Trust - Equity

14,198


14,198

Common Collective Trust - Fixed Income

32,615


32,615

Common Collective Trust - Real Estate

418

2,113

2,531

Hedge Funds


4,881

4,881

Total investments measured at fair value
$

$
47,729

$
6,994

$
54,723


Defined Benefit Pension Plan
2014
 
Level 1
Level 2
Level 3
Total Fair Value
Common Collective Trust - Cash and Cash Equivalents
$

$
899

$

$
899

Common Collective Trust - Equity

16,107


16,107

Common Collective Trust - Fixed Income

34,474


34,474

Common Collective Trust - Real Estate

761

1,918

2,679

Hedge Funds


4,939

4,939

Total investments measured at fair value
$

$
52,241

$
6,857

$
59,098


Cash and Cash Equivalents: This category is comprised of the AXA Equitable General Fixed Income Fund and Common Collective Trusts - cash and cash equivalents. The AXA Equitable General Fixed Income Fund is a fund of diversified portfolios, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately place 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 at which loans with similar characteristics have. 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.

Common Collective Trust: 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. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.


46



Hedge Funds: Hedge 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. Generally, shares may be redeemed at the end of each quarter with a 65 day notice and are limited to a percentage of total net asset 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. The Plan’s investment in the hedge fund is categorized as Level 3.
The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):
 
2015
Balance, beginning of period
$
6,857

Purchase
93

Unrealized gain (loss)
63

Settlements
(19
)
Balance, end of period
$
6,994


The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):
 
Fair Value at
Valuation
Level 3
Range (Weighted)
 
December 31, 2015
Technique
Input
Average
Assets:
 
 
 
 
Common Collective Trust - Real Estate (a)
$
2,113

Market Approach
Redemption Restriction
N/A
Hedge Funds (b)
$
4,881

Market Approach
Redemption Restriction
N/A
_____________
(a)
The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.
(b)
The fair value of the Hedge Funds is determined based on pricing provided or reviewed by third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed annually as they are issued.


47



Plan Reconciliations

The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):

Benefit Obligations
 
Defined Benefit Pension Plan
Supplemental Non-qualified Defined Benefit Retirement Plans
Non-pension Defined Benefit Postretirement Healthcare Plan
 
2015
2014
2015
2014
2015
2014
Change in benefit obligation:
 
 
 
 
 
 
Projected benefit obligation at beginning of year
$
71,178

$
60,223

$
3,599

$
3,131

$
6,038

$
5,850

Service cost
797

704



233

222

Interest cost
2,956

2,991

142

146

214