UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
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| 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
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| For the fiscal year ended December 31, 2018 |
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| For the transition period from ___________________ to __________________ |
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| Commission File Number 1-07978 |
BLACK HILLS POWER, INC.
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| BLACK HILLS POWER, INC. |
| Incorporated in South Dakota | | IRS Identification Number 46-0111677 |
625 Ninth Street,7001 Mount Rushmore Road, Rapid City, South Dakota 5770157702 |
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| Registrant’s telephone number, including area code: (605) 721-1700 |
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| Securities registered pursuant to Section 12(b) of the Act: None |
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| 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 definedor an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act).Act.
Large accelerated filer ¨ Accelerated filer ¨
Non-accelerated filer x (Do not check if a smaller reporting company)
Smaller reporting company¨
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨ No x
State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
All outstanding shares are held by the Registrant’s parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $0.
Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
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| Class | Outstanding at January 31, 20162019 |
| 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.
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| TABLE OF CONTENTS |
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| | GLOSSARY OF TERMS AND ABBREVIATIONS | |
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| ITEMS 1. and 2. | BUSINESS AND PROPERTIES | |
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| ITEM 1A. | RISK FACTORS | |
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| ITEM 1B. | UNRESOLVED STAFF COMMENTS | |
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| ITEM 3. | LEGAL PROCEEDINGS | |
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| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | |
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS | |
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| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | |
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| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | |
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| ITEM 9A. | CONTROLS AND PROCEDURES | |
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| ITEM 9B. | OTHER INFORMATION | |
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| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES | |
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| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | |
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| ITEM 16. | FORM 10-K SUMMARY | |
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| | SIGNATURES | |
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| INDEX TO EXHIBITS | |
GLOSSARY OF TERMS AND ABBREVIATIONS
The following terms and abbreviations appear in the text of this report and have the definitions described below:
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| AC | Alternating Current |
| AFUDC | Allowance for Funds Used During Construction |
| AOCI | Accumulated Other Comprehensive Income |
| ASC | Accounting Standards Codification |
| ASU | Accounting Standards Update as issued by FASB |
| Baseload plant | A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate. |
| Basin Electric | Basin Electric Power Cooperative |
| BHC | Black Hills Corporation, the Parent of Black Hills Power, Inc. |
| Black Hills Electric Generation | Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
| Black Hills Energy | The name used to conduct the business of our utility company as well as our utility affiliates |
Black Hills Utility Holdings, Inc.,Energy South Dakota Electric | Includes Black Hills Power’s operations in South Dakota, Wyoming and its subsidiariesMontana |
| Black Hills Non-regulated Holdings | Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of BHC |
| Black Hills Power | Black Hills Power, Inc., a direct, wholly-owned subsidiary of BHC (doing business as Black Hills Energy South Dakota) |
| Black Hills Service Company | Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills CorporationBHC |
| Black Hills Utility Holdings | Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC |
| Black Hills Energy Wyoming Electric | Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated HoldingsIncludes Cheyenne Light’s electric utility operations |
| CFTC | United States Commodity Futures Trading Commission |
| Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC |
| Cheyenne Prairie | Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial operationsservice 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 |
| CT | Combustion turbine |
| DC | Direct current |
| DSM | Demand Side Management |
| ECA | Energy Cost Adjustment --- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers. |
| EIA | Environmental Improvement Adjustment |
| EPA | United States Environmental Protection Agency |
| FASB | Financial Accounting Standards Board |
| FDIC | Federal DepositoryDeposit Insurance Corporation |
| FERC | Federal Energy Regulatory Commission |
| Fitch | Fitch Ratings |
| GAAP | Accounting principles generally accepted in the United States of America |
| GCA | Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers. |
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| GHG | Greenhouse gasgases |
| 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,Farm, LLC, a subsidiary of Duke Energy Generation Services |
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| 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 DakotaMontana-Dakota Utilities Company |
| MEAN | Municipal Energy Agency of Nebraska |
| Moody’s | Moody’s Investor Services, Inc. |
| MTPSC | Montana Public Service Commission |
| MW | Megawatts |
| MWh | Megawatt-hours |
| N/A | Not Applicable |
| Native load | Energy required to serve customers within our service territory |
| NAV | Net Asset Value |
| NERC | North American Electric Reliability Corporation |
| NOL | Net operating lossOperating Loss |
| NOAA | National Oceanic and Atmospheric Administration |
| NOAA Climate Normals | This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
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NOx | Nitrogen oxideOxide |
| OCI | Other Comprehensive Income |
| OPEB | Other Post-Employment Benefits |
| OSHA | Occupational Safety and Health Organization |
| PacifiCorp | PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway |
| Peak System Load | Peak system load represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership. |
| PPA | Power Purchase Agreement |
| SDPUC | South Dakota Public Utilities Commission |
| SEC | United States Securities and Exchange Commission |
| Silver Sage | Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services |
SO2 | Sulfur dioxideDioxide |
| SourceGas | SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy) |
| South Dakota Electric | Includes Black Hills Power operations in South Dakota, Wyoming and Montana |
| S&P | Standard & Poor’s Rating Services |
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| Spinning Reserve | Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages. |
| SPP | Southwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States |
| TCA | Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.review. |
| TCJA | Tax Cuts and Jobs Act enacted on December 22, 2017 |
| TFA | Transmission Facility Adjustment |
| Thunder Creek | Thunder Creek Gas Services, LLC |
TIPA | Tax Increase Prevention Act of 2014 |
| WECC | Western Electricity Coordinating Council |
| Winter Storm Atlas | An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history. |
| WPSC | Wyoming Public Service Commission |
| WRDC | Wyodak Resources Development Corporation, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, LLC |
| Wyodak Plant | Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, is owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant. |
| Wyoming Electric | Includes Cheyenne Light’s electric utility operations
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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 Companywe may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis.Analysis of Financial Condition and Results of Operations.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’sOur expectations, beliefs and projections are expressed in good faith and are believed by the Company towe believe we have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’sour records and other data available from third parties. Nonetheless, the Company’sour 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 undertakeswe undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’sour 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,us are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.
ITEMS 1 and 2. BUSINESS AND PROPERTIES
General
Black Hills Power (“the Company,” “we,”(the “Company”, “we”, “us” and “our”) is a regulated electric utility incorporated in South Dakota, doing business as South Dakota Electric and serving customers in South Dakota, Wyoming and Montana. We began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation (“Parent” or “BHC”). Engaging in the generation, transmission and distribution of electricity provides a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends to our Parent, and our overall performance and growth.
As of December 31, 2015,2018, our ownership interests in electric generation plants were as follows:
| | Unit (1) | Fuel Type | Location | Ownership Interest % | Owned Capacity (MW) | Year Installed | Fuel Type | Location | Ownership Interest % | Owned Capacity (MW) | Year Installed |
Wygen III (1)(a) | Coal | Gillette, WY | 52% | 57.2 | 2010 | Coal | Gillette, WY | 52% | 57.2 | 2010 |
| Neil Simpson II | Coal | Gillette, WY | 100% | 90.0 | 1995 | Coal | Gillette, WY | 100% | 90.0 | 1995 |
Wyodak (2)(b) | Coal | Gillette, WY | 20% | 72.4 | 1978 | Coal | Gillette, WY | 20% | 72.4 | 1978 |
Cheyenne Prairie (3)(c) | Gas | Cheyenne, WY | 58% | 55.0 | 2014 | Gas | Cheyenne, WY | 58% | 55.0 | 2014 |
| Neil Simpson CT | Gas | Gillette, WY | 100% | 40.0 | 2000 | Gas | Gillette, WY | 100% | 40.0 | 2000 |
| Lange CT | Gas | Rapid City, SD | 100% | 40.0 | 2002 | Gas | Rapid City, SD | 100% | 40.0 | 2002 |
| Ben French Diesel #1-5 | Oil | Rapid City, SD | 100% | 10.0 | 1965 | Oil | Rapid City, SD | 100% | 10.0 | 1965 |
| Ben French CTs #1-4 | Gas/Oil | Rapid City, SD | 100% | 80.0 | 1977-1979 | Gas/Oil | Rapid City, SD | 100% | 80.0 | 1977-1979 |
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(1)(a) | We operate Wygen III, a 110 MW mine-mouth coal-fired power plant and own a 52% interest in the facility. MDU owns a 25% interest and the City of Gillette owns the remaining 23% interest. WRDC furnishes all of the coal fuel supply for the plant. |
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(2)(b) | Wyodak is a 362 MW mine-mouth coal-fired power plant owned 80% by PacifiCorp and 20% by us. This baseload plant is operated by PacifiCorp and WRDC furnishes all of the coal fuel supply for 100% of the plant. |
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(3)(c) | Cheyenne Prairie, a gas-fired power generation facility includes one combined-cycle, 95 MW unit that is jointly owned by Cheyenne LightWyoming Electric (40 MW) and us (55 MW). This facilitywas placed into commercial operations on October 1, 2014. |
Distribution and Transmission. Our distribution and transmission system serves approximately 71,00073,000 electric customers, with an electric transmission system of 1,1791,231 miles of high voltage lines (greater than 69 kV) and 2,4852,539 miles of lower voltage lines.lines (69 kV or less). In addition, we jointly own 44 miles of high voltage lines with Basin Electric. Our service territory covers areas with a strong and stable economic base including western South Dakota, northeastern Wyoming and southeastern Montana. Approximately 90%A majority of our retail electric revenues in 20152018 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, 20152018 was comprised of 36%32% commercial, 26%25% residential, 6%11% contract wholesale, 8%6% wholesale off-system, 12%11% industrial and 12%15% 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 Westernwestern United States and the Easterneastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPPSPP 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. Our electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern interconnectiongrid without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tiegrids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously. This transfer capabilitysimultaneously, provides additional opportunityopportunities to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and enables us 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 December 31, 2023.
We have firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with MDU through 2017,December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.
Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:
MDU owns a 25% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.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 theirits operating component of spinning reserves.
•An agreement under which wethrough December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.
We have an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023.2028. The terms of the contract run from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:follows:
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2016-2017 | 20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II |
2018-20192019-2020 | 15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
2020-20212020-2022 | 1215 MW - 67 MW contingent on Wygen III and 68 MW contingent on Neil Simpson II |
| 2022-2023 | 15 MW - 8 MW contingent on Wygen III and 7 MW contingent on Neil Simpson II |
| 2023-2028 | 10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II.II |
Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide approximately 445 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. We generated approximately 53%52% of our energy requirements in 20152018 and purchased approximately 47%48% which was supplied under the following contracts:
A PPA with PacifiCorp expiring inon December 31, 2023, whereby we purchase 50 MW of coal-fired baseload power.
A PPA with Cheyenne LightWyoming Electric expiring inon September 3, 2028, under which we will purchase up to 14.7 MW of wind energy through Cheyenne Light’sWyoming Electric’s agreement with Happy Jack.
A PPA with Cheyenne LightWyoming Electric expiring inon September 30, 2029, under which we will purchase up to 20 MW of wind energy through Cheyenne Light’sWyoming Electric’s agreement with Silver Sage.
A Generation Dispatch Agreement with Cheyenne LightWyoming Electric that requires us to purchase all of Cheyenne Light’sWyoming Electric’s excess energy.
A PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.
Since 1995, we have been a net producer of energy. Our 20152018 winter peak system load was 369379 MW and our 20152018 summer peak system load was 424437 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 Horizon Point Agreement - We have an arrangement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.
Gas Transportation Service Agreement - On October 1, 2014 we entered intoWe have a gas transportation service agreement with Cheyenne LightWyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.
Shared Services Agreement - We have a shared services agreement with Cheyenne LightWyoming Electric and Black Hills Wyoming whereby each entity charges for the use of assets and the performance of services being used by, or performed for, an affiliate entity. The revenuesWyoming Electric and expenses associated with these assets are included in rate base.us receive certain staffing and management services from Black Hills Service Company for Cheyenne Prairie.
Jointly Owned Facilities - We are parties to an agreement with the City of Gillette and MDU for joint ownership of Wygen III. We charge the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant.
Regulations
Rate Regulation
The following table illustrates certain enacted regulatory information with respect to the states in which we operate:
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| 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 |
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.Ground Lease Agreement - We have rate adjustment mechanismsa Wygen III ground lease agreement with WRDC that expires in Wyoming, Montana and South Dakota which provide for pass-through2050 with three automatic renewal terms 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, 2014.20 years each.
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.
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.
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.
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.
Rate Regulation
The following table illustrates certain enacted regulatory information with respect to the states in which we operate:
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| Jurisdic-tion | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Authorized Capital Structure Debt/Equity | Authorized Rate Base (in millions) | Effective Date | Additional Tariffed Mechanisms | Percentage of Off-System Sale Profits Shared with Customers |
| SD | Global Settlement | 7.76% | Global Settlement | $543.9 | 10/2014 | ECA,TCA, Energy Efficiency Cost Recovery/DSM | 70% |
| SD | | 7.76% | | | 5/2014 | TFA | N/A |
| SD | | 7.76% | | | 6/2011 | EIA | N/A |
| WY | 9.9% | 8.13% | 46.7%/53.3% | $46.8 | 10/2014 | ECA | 65% |
| FERC | 10.8% | 8.76% | 43%/57% | | 2/2009 | FERC Transmission Tariff | N/A |
Rates for our retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. We have rate adjustment mechanisms in Wyoming and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. We are also subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. We have been granted market-based rate authority by FERC and are not required to file cost-based tariffs for wholesale electric rates. Rates charged by us for use of our transmission system are subject to regulation by FERC.
Some of the mechanisms we have in place include:
An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. We also have a TFA tariff which recovers the costs associated with transmission facility improvements. The EIA and TFA were suspended for a six-year period effective July 1, 2017. See Management’s Discussion and Analysis of Results of Operations in Item 7 of this Annual Report on Form 10-K for further information.
An annual adjustment clause which provides for the over or under recovery of fuel and purchased power cost incurred to serve South Dakota customers. Additionally, this ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $1.0 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $1.0 million. We retain the additional 30%. During the six-year moratorium period effective July 1, 2017, the 100% credit of power marketing margin increased from $1.0 million to $2.0 million. The ECA methodology allows us to directly assign renewable resources and firm purchases to the customer load. In Wyoming, a similar fuel and purchased power cost adjustment is also in place.
We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of our open access transmission tariff.
Common Use System (CUS). The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.
Tariff Filing
On December 17, 2018, Wyoming Electric and us filed for approval of new, voluntary renewable energy tariffs to serve customer requests for renewable energy resources. Requests to approve the voluntary tariffs, known as Renewable Ready Service Tariffs, were submitted to the SDPUC and WPSC. The renewable ready tariffs would provide large commercial and industrial customers and governmental agencies an option to purchase utility-scale renewable energy. As proposed, customers would be able to enter into contracts with Black Hills Energy to purchase renewable energy for periods of five to 25 years.
State Regulation
Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage us to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. At December 31, 2018, we were subject to the following renewable energy portfolio standards or objectives:
South Dakota. In 2015, South Dakota adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources.
Montana. Montana has established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, the Montana Legislature adopted legislation that excluded us from all renewable portfolio standard requirements under Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements.
Wyoming. Wyoming currently has no renewable energy portfolio standard.
Absent a specific renewable energy mandate in the territories we serve, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. Portfolio standards may continue to increase the power supply costs of our electric utility operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.
Environmental Matters
Water Issues. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013 and published the final rule on November 3, 2015. In 2017, the EPA postponed the implementation of the rule and set a timeline in 2018 to revise the rule. To date, the rule has not been sent for publication. Until the EPA issues the rule for publication, we can not quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation impact the next permit renewal, which will be in 2020.
Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for Sulfur Dioxide (SO2), Nitrogen Oxide (NOx) and Opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.
We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut the power plant down if a predicted emission limit is to be exceeded. Similar efforts have been taken and similar results achieved with our natural gas fired combustion turbine sites as well.
Regional Haze (Impacts to the Wyodak Power Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas.The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed PacifiCorp to install low-NOx burners in the Wyodak Plant, of which we own 20%. The EPA did not agree with the State of Wyoming’s determination and overruled it in a Federal Implementation Plan (FIP). The State of Wyoming and other interested parties are challenging the EPA’s determination. If the challenge is unsuccessful, additional capital investment would be necessary to bring the Wyodak Plant into compliance. Our 20% share of this capital investment for the facility would be approximately $40 million if PacifiCorp is required to install a Selective Catalytic Reactor for NOx control. At the present time, a court date is being scheduled to hear arguments.
Affordable Clean Energy Rule. The EPA was directed to repeal, revise, and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy rule. The rule focuses on heat rate improvements on coal-fired boiler units and poses significantly less risk that the Clean Power Plan. The 60-day comment period has ended and the EPA is reviewing comments prior to issuing a final rule.
Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 11 of the Notes to Financial Statements in this Annual Report on Form 10-K.
New Accounting Pronouncements
See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 20152018 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.materially.
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.recoverable.
Our electricityregulated electric operations are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. 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 direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that 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.review. To the extent we are able to pass through such costs to customers and a state public utility commission subsequently determines that such costs should not have been paid by customers, we may be required to refund such costs to customers. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.
Our financial performance depends on the successful operationsoperation of our facilities. If the risks involved in our operations are not appropriately managed or mitigated, our operations may not be successful and this could adversely affect our results of operations.
Operating electric generating facilities and electric transmission and distribution systems involves risks, including:
Operational limitations imposedDisrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by environmentalunaffiliated parties, to deliver the electricity that we sell to our retail and other regulatory requirements;wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;
Interruptions to supply of fuel and other commodities used in generation and distribution. We purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit theour 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 service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;
Operational limitations imposed by environmental and other regulatory requirements;
Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak plant;
Labor relations.
Our ability to transition and replace our retirement-eligible employees;
Inability to recruit and retain skilled technical labor; and
Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions; andfunctions.
Labor relations.Changes in the interpretation of the TCJA could adversely affect us.
NationalOn December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and regional economic conditions may cause increased counter-party risk, late paymentsmodifies or repeals many business deductions and uncollectible accounts, which could adversely affectcredits. The new tax law contains several provisions that impacted our 2017 and 2018 financial results and will impact the Company into the future.
If there are future changes and amendments to the TCJA, if we are unable to obtain reasonable outcomes with our utility regulators in passing future benefits of the TCJA back to customers, or if our interpretations on the provisions of depreciation or interest deductibility in the TCJA change, our results of operations, financial position or 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 liquiditycash flows could be adverselymaterially 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.
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;
ContractContractual restrictions upon the timing of scheduled outages;
CostThe cost of supplying or securing replacement power during scheduled and unscheduled outages;
The unavailability or increased cost of equipment;
The cost of recruiting and retaining or the unavailability of skilled labor;
Supply interruptions, work stoppages and labor disputes;
Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;
Opposition by members of the public or special-interest groups;
Weather interferences;
Availability and cost of fuel supplies;
Unexpected engineering, environmental or geological problems; and
Unanticipated cost overruns.
The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.
Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.
Our revenues, results of operations and financial condition are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our results of operations, financial position or cash flows.
Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.
We rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to our natural gas-fired power plants. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.
National and regional economic conditions may cause increased counterparty risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position and liquidity.
A future recession may lead to an increase in late payments from retail, commercial and industrial utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.
Our credit ratings could be lowered below investment grade in the future. If this were to occur, it could impact our access to capital, cost of capital and other operating costs.
Our credit rating on our First Mortgage Bonds is A1 by Moody’s, A by S&P and A by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on reasonable terms, or at all. A credit rating downgrade could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.
Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.
A portion of our net income is attributable to sales of contract and off-system wholesale electricity. The related powerEnergy 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 aremay be subject to significant, unpredictable price fluctuations over relatively short periods of time.
Our energy production, transmission and distribution activities involve numerous risks that may result in accidents and other catastrophic events. These events that could disrupt or impair our operations, creategive rise to additional costs and cause a substantial loss to us.
Inherent in our electricity transmission and distribution activities are a variety of hazards and operating risks, such as fires, releases of hazardous materials, explosions and mechanical problems that could cause substantial adverse financial impacts.operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public parks)lands), environmental pollution, impairment of our operations, and substantial financial 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.substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.
Our operatingOperating results can be adversely affected by variations from normal weather patterns.conditions.
Our utility business is a seasonal business and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Unusually mild summers and winters therefore could have an adverse effect on our results of operations, financial condition and results of operations.or cash flows.
Our businesses arebusiness is located in areas that could be subject to seasonal natural disasters such as severe snow and ice storms, flooding and wildfires. These factors could result in interruption of our business, damage to our property such as power lines and substations, and repair and clean-up costs associated with these storms.events. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates thereby resulting in a negative impact on our results of operations, financial condition andor cash flows.
The failurecosts to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and any failure to do so, could adversely affect our results of operations, financial position or liquidity. 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,numerous environmental and other laws and regulations affecting many aspects of federal, stateits present and local authorities. Wefuture operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally mustrequire us to obtain and comply with a wide variety of regulations,environmental licenses, permits, inspections and other approvals in order to operate, which couldapprovals. Compliance with environmental laws and regulations can require significant capital expenditures, including expenditures for cleanup costs and operating costs. If we faildamages arising from contaminated properties. Failure to comply with these requirements, we could be subject to civil or criminal liability andenvironmental regulations may result in the imposition of fines, penalties liensand injunctive measures affecting operating assets.
We may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or fines; claimsregulations could result in additional costs of operation for property damageexisting facilities or personal injury; and/ orimpede the development of new facilities. Although it is not expected that the costs to comply with current 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 andwill have a detrimentalmaterial adverse effect on our business.
Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect ourfinancial position, results of operation and financial condition. We expect ouroperations or cash flows, future 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.costs could have a significant negative impact.
Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost of such insurance, could be affectedimpacted 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 or inadequate facility maintenance, distribution property losses and cyber securitycyber-security risks.
Municipal governments may seek to limit or deny franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.
Municipal governments within our utility service territories possess the power of condemnation and could seekestablish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.
FederalDevelopments in federal and state laws concerning greenhouse gasGHG regulations and air emissions relating to climate may adversely impact operations, financial results and materially increase our generation and production costs, andwhich could render some of our generating units uneconomical to operate and maintain.
To the extent climate change occurs, our business could be adversely impacted, although we believe is likely that any such resulting impacts would occur very gradually over a very long period of time and thus would be difficult to quantify with any degree of specificity. Cooler temperatures in our electric service territories could adversely affect financial results through lower MWh sold and associated lower revenues.
We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. Recent developmentsDevelopments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants will likelymay 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.section “Business and Properties.”
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,regulation, legal challenges, state clean power plan developments or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, cash flows or financial position. 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.
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 generatingcoal-fired power generation facilities and potential increased load of our combined cycle natural gas firedgas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, and SEC may impose significant 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 actionbusiness, which could have a material adverse effect on our operations and/or our financial results.
Certain Federal laws, including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, and wind, could be restricted or delayed, or we could be required to implement expensive mitigation measures.
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. During their assessment of these controls, management 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.ways.
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 businessesbusiness by limiting theirits ability to generate, purchase or transmit power and by delaying theirthe development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.
The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.
A 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, or 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 ofoperate 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, including our third-party vendors’ systems, could further add to a full or partial disruption toof 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, requiresassets, including certain safeguards be implemented to deter cyber attacks.required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber-attacks.cyber attacks. If our information technology systems or our third-party vendors’ systems were to fail or be breached by a cyber attack or a computer virus and be unable to be recoveredrecover 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 plansplan 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.
WeAs discussed in Note 8 to the Financial Statements in this Annual Report on Form 10-K, we have a defined benefit pension plan (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria), defined post-retirement healthcare plan and a non-qualified retirement plan that covers a substantial portion of ourcover certain eligible employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.
Increasing costs associated with our health care plans and other benefits may adversely affect our results of operations, financial position or liquidity.
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. TheSignificant regulatory developments have, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
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.
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.
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
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| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER |
MATTERS
All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS |
Significant Events
2018 Overview
On December 17, 2018, South Dakota Electric and Wyoming Electric filed for approval with the SDPUC and WPSC new, voluntary renewable energy tariffs to serve customer requests for renewable energy resources. In addition, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a $57 million, 40 MW wind generation project near Cheyenne, Wyoming.
On December 12, 2018, Moody’s affirmed South Dakota Electric’s credit rating at A1.
On November 20, 2018, we placed in service a 33-mile segment of a $70 million, 175-mile, 230-kilovolt transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018. The remaining 94-mile segment is expected to be in service by the end of 2019.
On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the Company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. The aggregate 2018 benefit of approximately $7.6 million was delivered to customers in October 2018.
On August 16, 2018, we entered into a PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.
On August 9, 2018, S&P upgraded South Dakota Electric’s credit rating to A.
On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A.
2017 Overview
On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the TFA and the EIA, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, is being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million. The June 16, 2017 settlement had no impact to base rates.
Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.
In our Management’s Discussion and Analysis of Results of Operations, gross margin is calculated as operating revenue less cost of fuel and purchased power. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.
Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
| | | For the years ended December 31, | 2015 | Variance | 2014 | Variance | 2013 | 2018 | Variance | 2017 | Variance | 2016 |
| | (in thousands) | (in thousands) |
| Revenue | $ | 277,864 |
| $ | 9,376 |
| $ | 268,488 |
| $ | 14,461 |
| $ | 254,027 |
| $ | 298,080 |
| $ | 9,647 |
| $ | 288,433 |
| $ | 20,801 |
| $ | 267,632 |
|
| Fuel and purchased power | 83,339 |
| (10,637 | ) | 93,976 |
| 4,539 |
| 89,437 |
| 92,886 |
| 5,248 |
| 87,638 |
| 12,612 |
| 75,026 |
|
Gross margin | 194,525 |
| 20,013 |
| 174,512 |
| 9,922 |
| 164,590 |
| 205,194 |
| 4,399 |
| 200,795 |
| 8,189 |
| 192,606 |
|
| | | |
| Operating expenses | 106,611 |
| 1,213 |
| 105,398 |
| 3,152 |
| 102,246 |
| 126,859 |
| 9,890 |
| 116,969 |
| 9,943 |
| 107,026 |
|
| Operating income | 87,914 |
| 18,800 |
| 69,114 |
| 6,770 |
| 62,344 |
| 78,335 |
| (5,491 | ) | $ | 83,826 |
| (1,754 | ) | 85,580 |
|
| | | |
| Interest expense, net | (21,174 | ) | (1,472 | ) | (19,702 | ) | (411 | ) | (19,291 | ) | (21,348 | ) | (968 | ) | (20,380 | ) | (188 | ) | (20,192 | ) |
| Other income | 1,034 |
| 372 |
| 662 |
| 123 |
| 539 |
| |
| Other income (expense), net | | (670 | ) | (2,650 | ) | 1,980 |
| (298 | ) | 2,278 |
|
| Income tax expense | (22,600 | ) | (6,088 | ) | (16,512 | ) | (3,093 | ) | (13,419 | ) | (10,672 | ) | 3,456 |
| (14,128 | ) | 8,400 |
| (22,528 | ) |
| Net income | $ | 45,174 |
| $ | 11,612 |
| $ | 33,562 |
| $ | 3,389 |
| $ | 30,173 |
| $ | 45,645 |
| $ | (5,653 | ) | $ | 51,298 |
| $ | 6,160 |
| $ | 45,138 |
|
2018 Compared to 2017
Gross margin increased primarily due to $9.8 million of Horizon Point shared facility revenue, higher power marketing and wholesale revenue of $3.0 million, higher rider revenues of $2.3 million primarily related to transmission investment recovery, and a $1.7 million increase in residential margins primarily from higher usage per customer. These increases were partially offset by a $10.3 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs and lower commercial and industrial demand volume of $2.1 million.
Operations and maintenance increased due to higher depreciation and property taxes of $4.4 million from higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line. Vegetation management expenses increased by $3.4 million compared to the prior year, and higher employee and facility costs comprise the remainder of the increase compared to the the prior year.
Interest expense, net increased due to higher prior year AFUDC associated with higher prior year capital spend.
Other income, net decreased due to the presentation change of non-service pension costs to Other income (expense), net in the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associated with higher prior year capital spend.
Income tax expense: The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the enactment of the TCJA on December 22, 2017. Additionally, in 2018, we recorded $0.9 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes compared to a net tax benefit of $6.0 million in 2017 as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA.
2017 Compared to 2016
Gross margin increased over the prior year reflecting a $5.6 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling and heating degree days and higher customer counts were slightly offset by lower usage per customer and lower commercial and industrial demand. Both heating and cooling degree days’ variances from normal were favorable when compared to prior year comparisons to normal.
Operations and maintenance increased primarily due to $4.0 million in higher vegetation management expenses, $3.2 million in increased maintenance costs from higher outages, higher employee costs as a result of prior year integration activities, transition expenses charged to BHC related to its 2016 acquisition of SourceGas and increased amortization expenses as a result of the SDPUC settlement.
Interest expense, net and other income, net were comparable to the same period in the prior year.
Income tax expense: The effective tax rate decreased in 2017 due to a tax benefit of $6.0 million resulting from re-measurement of net deferred tax liabilities in accordance with the ASC 740 and the enactment of the TCJA on December 22, 2017. This benefit was primarily related to the repricing of net operating losses and other tax basis items not included in the ratemaking construct.
The following tables provide certain electric utility operating statistics for the years ended December 31 (dollars in thousands):31:
| | | Revenue | |
| Customer Base | 2015 | Percentage Change | 2014 | Percentage Change | 2013 | |
| Electric Revenue by Customer Type (in thousands) | | Electric Revenue by Customer Type (in thousands) |
| | | 2018 | Percentage Change | 2017 | Percentage Change | 2016 |
| Residential | $ | 72,659 |
| 4 | % | $ | 69,712 |
| 8 | % | $ | 64,566 |
| $ | 75,319 |
| 4 | % | $ | 72,764 |
| 1 | % | $ | 72,084 |
|
| Commercial | 100,511 |
| 9 | % | 91,882 |
| 14 | % | 80,289 |
| 95,509 |
| (1 | )% | 96,531 |
| (1 | )% | 97,579 |
|
| Industrial | 33,336 |
| 17 | % | 28,451 |
| 3 | % | 27,705 |
| 32,748 |
| (2 | )% | 33,464 |
| — | % | 33,409 |
|
| Municipal | 3,626 |
| 6 | % | 3,409 |
| — | % | 3,421 |
| 3,571 |
| (4 | )% | 3,707 |
| — | % | 3,705 |
|
| 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 retail revenue | | 207,147 |
| — | % | 206,466 |
| — | % | 206,777 |
|
Wholesale (a) | | 33,687 |
| 11 | % | 30,435 |
| 79 | % | 17,037 |
|
Market - off-system sales (b) | | 17,692 |
| 24 | % | 14,271 |
| (8 | )% | 15,431 |
|
| Total electric sales | 250,910 |
| 3 | % | 242,662 |
| 7 | % | 227,517 |
| 258,526 |
| 3 | % | 251,172 |
| 5 | % | 239,245 |
|
Other revenue | 26,954 |
| 4 | % | 25,826 |
| (3 | )% | 26,510 |
| 39,554 |
| 6 | % | 37,261 |
| 31 | % | 28,387 |
|
| Total revenue | $ | 277,864 |
| 3 | % | $ | 268,488 |
| 6 | % | $ | 254,027 |
| $ | 298,080 |
| 3 | % | $ | 288,433 |
| 8 | % | $ | 267,632 |
|
_________________________
| |
| (a) | Increases in 2018 and 2017 were primarily driven by higher volumes sold on long-term wholesale contracts. |
| |
| (b) | Increase in 2018 was due to higher trading volume opportunities. |
| |
| (c) | Increase in 2017 is primarily due to higher transmission revenues. |
| | | MWh Sold | |
| Customer Base | 2015 | Percentage Change | 2014 | Percentage Change | 2013 | |
| Megawatt Hours Sold by Customer Type | | Megawatt Hours Sold by Customer Type |
| | | 2018 | Percentage Change | 2017 | Percentage Change | 2016 |
| Residential | 521,828 |
| (4 | )% | 542,008 |
| (2 | )% | 555,204 |
| 546,825 |
| 4 | % | 526,730 |
| 1 | % | 520,798 |
|
| Commercial | 792,466 |
| 1 | % | 782,238 |
| 7 | % | 730,701 |
| 751,479 |
| (2 | )% | 769,463 |
| (2 | )% | 783,319 |
|
| Industrial | 429,140 |
| 7 | % | 399,648 |
| (1 | )% | 404,009 |
| 407,683 |
| (5 | )% | 430,300 |
| — | % | 429,912 |
|
| Municipal | 31,924 |
| — | % | 32,076 |
| (7 | )% | 34,344 |
| 31,636 |
| (5 | )% | 33,272 |
| (1 | )% | 33,591 |
|
| 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 |
| |
| Total retail quantity sold | | 1,737,623 |
| (1 | )% | 1,759,765 |
| — | % | 1,767,620 |
|
Wholesale (a) | | 900,854 |
| 25 | % | 722,659 |
| 193 | % | 246,630 |
|
Market - off-system sales(b) | | 518,725 |
| 2 | % | 509,963 |
| (15 | )% | 597,695 |
|
| Total quantity sold | | 3,157,202 |
| 6 | % | 2,992,387 |
| 15 | % | 2,611,945 |
|
Losses and company use | 167,332 |
| (6 | )% | 177,577 |
| 12 | % | 158,845 |
| 203,194 |
| 4 | % | 195,005 |
| 26 | % | 155,370 |
|
| Total energy | 3,040,703 |
| (1 | )% | 3,082,675 |
| (5 | )% | 3,243,143 |
| 3,360,396 |
| 5 | % | 3,187,392 |
| 15 | % | 2,767,315 |
|
_________________________
| |
| (a) | Increases in 2018 and 2017 were primarily driven by higher volumes sold on long-term wholesale contracts. |
| |
| (b) | Decrease in 2017 was primarily driven by commodity prices that impacted power marketing sales. |
| |
| (c) | Includes company uses, line losses, and excess exchange production. |
We own approximately 445 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023. 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 | Regulated Power Plant Fleet Availability |
| Coal-fired plants | 91.1% | 91.8% | | 96.3% | |
| | | 2018 | 2017 | 2016 |
Coal-fired plants (a) | | 92.7 | % | 86.0 | % | 86.5 | % |
| Other plants | 96.0% | 91.5% | (a) | 96.8% | 96.8 | % | 96.4 | % | 98.0 | % |
| Total availability | 93.9% | 91.6% | | 96.5% | 94.9 | % | 91.6 | % | 93.0 | % |
_________________________
| |
| (a) | 2014 decrease from 2013 was due to the scheduling ofBoth 2017 and 2016 included outages. 2017 included planned outages in 2014 compared to 2013.at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak. |
|
| | | | | | | | | | |
| 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 | % |
|
| | | | | | | | | | |
| Megawatt Hours Generated and Purchased |
| | 2018 | Percentage Change | 2017 | Percentage Change | 2016 |
| | | | | | |
| Coal-fired | 1,598,957 |
| 8 | % | 1,485,254 |
| 1 | % | 1,467,403 |
|
Natural Gas and Oil (a) (b) | 135,265 |
| 40 | % | 96,661 |
| (18 | )% | 118,467 |
|
Total generated (a) (b) | 1,734,222 |
| 10 | % | 1,581,915 |
| — | % | 1,585,870 |
|
| | | | | | |
Total purchased (c) | 1,626,174 |
| 1 | % | 1,605,477 |
| 36 | % | 1,181,445 |
|
Total generated and purchased (c) | 3,360,396 |
| 5 | % | 3,187,392 |
| 15 | % | 2,767,315 |
|
_________________________
| |
| (a) | Decrease in 2017 is driven by the ability to purchase excess generation in the open market at a lower cost than to generate. |
| |
| (b) | Increase in 2018 is primarily due to low natural gas prices and the ability to generate at a lower cost than to purchase excess generation on the open market. |
| |
| (c) | Increase in 2017 and 2018 is driven by increased volumes on long-term wholesale contracts. |
|
| | | | | | |
| Heating and Cooling Degree Days |
| | 2018 | 2017 | 2016 |
| Actual | | | |
| Heating degree days | 7,749 |
| 6,870 |
| 6,402 |
|
| Cooling degree days | 488 |
| 709 |
| 646 |
|
| | | | |
Variance from 30-year average (a) | | | |
| Heating degree days | 8 | % | (4 | )% | (10 | )% |
| Cooling degree days | (23 | )% | 11 | % | (4 | )% |
______________
| |
| (a) | 30-year average is from NOAA Climate Normals |
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 maintenanceincreased 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.
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, 2015:2018:
|
| |
| Rating Agency | Rating |
| S&P | A-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 ourthe Notes to Financial Statements in this Annual Report on Form 10-K.
Pension and Other Postretirement BenefitsRegulation
Our utility operations are subject to regulation with respect to rates, service area, accounting, and various other matters by state and federal regulatory authorities. The Company, as described in Note 8 toaccounting regulations provide that rate-regulated public utilities account and report assets and liabilities consistent with 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 assetseconomic effects of the defined benefit pension plans. Each participating retirement plan has an undivided interestmanner in the Master Trust.which independent third-party regulators establish rates. Regulatory assets generally represent incurred or accrued costs that have been deferred when future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
Accounting for pension and other postretirement benefit obligations involves numerous assumptions,Management continually assesses the most significant of which relate to the discount rate for measuring the present valueprobability of future plan obligations; expected long-term rates of return on plan assets;recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate of future increases in compensation levels;orders, 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. Althoughhistorical precedents are considered. As a result, we believe our assumptions arethat the accounting prescribed under rate-based regulation remains appropriate significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our regulatory assets are probable for recovery in current rates or in 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.proceedings.
Income Taxes
We file a federal income tax return with other members of the Parent consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.
We useOn December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. The Company uses the asset and liability method ofin accounting for income taxes. Under thisthe asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as 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
The Company has revalued the deferred income taxes at the 21% federal tax rate as of December 31, 2015, we classify all2017 and as a result, deferred tax assets and liabilities were reduced by approximately $103 million. Of the $103 million, approximately $97 million was reclassified to a regulatory liability. As of December 31, 2018, the Company has a regulatory liability associated with TCJA related items of $100 million, completing the revaluation of deferred taxes pursuant to the TCJA. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as non-current amounts.prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $0.9 million of regulatory liability. The prior period is presentedportion that was eligible for amortization under the previous guidance for classifying deferred tax assetsaverage rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and deferred tax liabilities as current and non-current.may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. 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 ourof the Notes to Financial Statements in this Annual Report on Form 10-K for additional information.
ContingenciesPension and Other Postretirement Benefits
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 contingenciesAs described in Note 118 of the Financial Statements in this Annual Report on Form 10-K.10-K, we have a defined benefit pension plan, a post-retirement healthcare plan and non-qualified retirement plans. A Master Trust was established for the investment of assets of the defined benefit pension plan.
23Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, health care cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
The pension benefit cost for 2019 for our non-contributory funded pension plan is expected to be $0.6 million compared to $1.3 million in 2018. The decrease in pension benefit cost is driven primarily by an increase in the discount rate.
The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
|
| | | | |
| | December 31, |
| Assumptions | Percentage Change | 2018 Increase/(Decrease) PBO/APBO (a) | | 2019 Increase/(Decrease) Expense - Pretax |
| | | | |
| Pension | | | | |
Discount rate (b) | +/- 0.5 | (3,413)/3,744 | | (1,078)/733 |
| Expected return on assets | +/- 0.5 | N/A | | (284)/284 |
| | | | |
| OPEB | | | | |
Discount rate (b) | +/- 0.5 | (210)/228 | | 7/(8) |
| Expected return on assets | +/- 0.5 | N/A | | N/A |
__________________________
| |
| (a) | Projected benefit obligation (PBO) for pension plans and accumulated postretirement benefit obligation (APBO) for OPEB plans. |
| |
| (b) | Impact on service cost, interest cost and amortization of gains or losses. |
|
| |
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO FINANCIAL STATEMENTS
|
| |
| | Page |
| | |
| Management’s Report on Internal Controls Over Financial Reporting | |
| | |
| Report of Independent Registered Public Accounting Firm | |
| | |
Statements of Income for the three years ended December 31, 20152018 | |
| | |
Statements of Comprehensive Income (Loss) for the three years ended December 31, 20152018 | |
| | |
Balance Sheets as of December 31, 20152018 and 20142017 | |
| | |
Statements of Cash Flows for the three years ended December 31, 20152018 | |
| | |
Statements of Common Stockholder’s Equity for the three years ended December 31, 20152018 | |
| | |
| Notes to Financial Statements | |
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, 2015,2018, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 20152018.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting because this requirement is inapplicable to companies such as ours which are known as non-accelerated filers.
Black Hills Power
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors and Stockholder of
Black Hills Power, Inc.
Rapid City, South Dakota
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Black Hills Power, Inc. (the “Company”"Company") as of December 31, 20152018 and 2014, and2017, 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 included2018, the financial statementrelated notes and the schedule listed in the Index at Item 15. 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements and financial statement schedule are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the Company's financial statements and financial statement schedule based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding 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
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. 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, 201620, 2019
We have served as the Company’s auditor since 2002.
BLACK HILLS POWER, INC.
STATEMENTS OF INCOME
| | | Years ended December 31, | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 |
| | (in thousands) | (in thousands) |
| | | |
| Revenue | $ | 277,864 |
| $ | 268,488 |
| $ | 254,027 |
| $ | 298,080 |
| $ | 288,433 |
| $ | 267,632 |
|
| | | |
| Operating expenses: | | |
| Fuel and purchased power | 83,339 |
| 93,976 |
| 89,437 |
| 92,886 |
| 87,638 |
| 75,026 |
|
| Operations and maintenance | 68,088 |
| 70,356 |
| 68,857 |
| 79,523 |
| 74,064 |
| 66,384 |
|
| Depreciation and amortization | 32,552 |
| 29,100 |
| 28,125 |
| 39,649 |
| 35,862 |
| 34,030 |
|
| Taxes - property | 5,971 |
| 5,942 |
| 5,264 |
| 7,687 |
| 7,043 |
| 6,612 |
|
| Total operating expenses | 189,950 |
| 199,374 |
| 191,683 |
| 219,745 |
| 204,607 |
| 182,052 |
|
| | | |
| Operating income | 87,914 |
| 69,114 |
| 62,344 |
| 78,335 |
| 83,826 |
| 85,580 |
|
| | | |
| Other income (expense): | | |
| Interest expense | (22,337 | ) | (20,569 | ) | (19,725 | ) | (22,545 | ) | (22,421 | ) | (22,908 | ) |
| AFUDC - borrowed | 506 |
| 248 |
| 186 |
| 521 |
| 1,137 |
| 1,140 |
|
| Interest income | 657 |
| 619 |
| 248 |
| 676 |
| 904 |
| 1,576 |
|
| AFUDC - equity | 918 |
| 519 |
| 368 |
| 221 |
| 2,165 |
| 2,165 |
|
| Other expense | (117 | ) | (105 | ) | (196 | ) | |
| Other income | 233 |
| 248 |
| 367 |
| |
| Other income (expense), net | | (891 | ) | (185 | ) | 113 |
|
| Total other income (expense) | (20,140 | ) | (19,040 | ) | (18,752 | ) | (22,018 | ) | (18,400 | ) | (17,914 | ) |
| | | |
| Income before income taxes | 67,774 |
| 50,074 |
| 43,592 |
| 56,317 |
| 65,426 |
| 67,666 |
|
| Income tax expense | (22,600 | ) | (16,512 | ) | (13,419 | ) | (10,672 | ) | (14,128 | ) | (22,528 | ) |
| | | |
| Net income | $ | 45,174 |
| $ | 33,562 |
| $ | 30,173 |
| $ | 45,645 |
| $ | 51,298 |
| $ | 45,138 |
|
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF COMPREHENSIVE INCOME (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 |
|
|
| | | | | | | | | |
| Years ended December 31, | 2018 | 2017 | 2016 |
| | (in thousands) |
| | | | |
| Net income | $ | 45,645 |
| $ | 51,298 |
| $ | 45,138 |
|
| | | | |
| Other comprehensive income (loss): | | | |
| Benefit plan liability adjustments - net gain (loss) (net of tax of $(62), $50, and $27 respectively) | 235 |
| (94 | ) | (50 | ) |
| Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(22), $(30), and $(29), respectively) | 81 |
| 56 |
| 53 |
|
| Derivative instruments designated as cash flow hedges: | | | |
| Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(13), $(22), and $(22), respectively) | 51 |
| 42 |
| 42 |
|
| Other comprehensive income | 367 |
| 4 |
| 45 |
|
| | | | |
| Comprehensive income | $ | 46,012 |
| $ | 51,302 |
| $ | 45,183 |
|
See Note 7 for additional disclosure related to comprehensive income.
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
BALANCE SHEETS
| | | As of December 31, | 2015 | 2014 | 2018 | 2017 |
| | (in thousands, except share amounts) | (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 |
| |
| Cash | | $ | 112 |
| $ | 16 |
|
| Accounts receivable, net | | 28,431 |
| 29,050 |
|
| Accounts receivable from affiliates | | 8,119 |
| 5,664 |
|
| Materials, supplies and fuel | 24,282 |
| 20,965 |
| 24,853 |
| 23,443 |
|
| Deferred income tax assets, net, current | — |
| 13,661 |
| |
| Regulatory assets, current | 14,096 |
| 10,257 |
| 19,052 |
| 18,993 |
|
| Other current assets | 43,118 |
| 4,954 |
| 4,538 |
| 4,724 |
|
| Total current assets | 199,707 |
| 165,376 |
| 85,105 |
| 81,890 |
|
| | | |
| Investments | 4,725 |
| 4,584 |
| 4,889 |
| 4,926 |
|
| | | |
| Property, plant and equipment | 1,166,126 |
| 1,115,061 |
| 1,381,045 |
| 1,311,819 |
|
| Less accumulated depreciation and amortization | (326,074 | ) | (309,767 | ) | |
| Less: accumulated depreciation and amortization | | (376,160 | ) | (358,946 | ) |
| Total property, plant and equipment, net | 840,052 |
| 805,294 |
| 1,004,885 |
| 952,873 |
|
| | | |
| Other assets: | | |
| Regulatory assets, non-current | 71,717 |
| 68,427 |
| 56,680 |
| 59,710 |
|
| Other, non-current assets | 3,292 |
| 11,708 |
| |
| Total other assets | 75,009 |
| 80,135 |
| |
| Other assets, non-current | | 9,729 |
| 3,747 |
|
| Total other assets, non-current | | 66,409 |
| 63,457 |
|
| TOTAL ASSETS | $ | 1,119,493 |
| $ | 1,055,389 |
| $ | 1,161,288 |
| $ | 1,103,146 |
|
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
BALANCE SHEETS
(Continued)
| | | As of December 31, | 2015 | 2014 | 2018 | 2017 |
| | (in thousands, except share amounts) | (in thousands, except share amounts) |
| LIABILITIES AND STOCKHOLDER’S EQUITY | | |
| Current liabilities: | | |
| Accounts payable | $ | 21,297 |
| $ | 30,543 |
| $ | 25,122 |
| $ | 14,766 |
|
| Accounts payable - affiliates | 30,032 |
| 19,242 |
| |
| Accounts payable to affiliates | | 25,804 |
| 25,653 |
|
| Accrued liabilities | 69,454 |
| 16,415 |
| 34,193 |
| 38,205 |
|
| Money pool notes payable | | 38,690 |
| 13,397 |
|
| Regulatory liabilities, current | — |
| 3,073 |
| 2,574 |
| 842 |
|
| Total current liabilities | 120,783 |
| 69,273 |
| 126,383 |
| 92,863 |
|
| | | |
| Long-term debt | 342,756 |
| 342,752 |
| 340,035 |
| 339,895 |
|
| | | |
| Deferred credits and other liabilities: | | |
| Deferred income tax liabilities, net, non-current | 188,961 |
| 193,042 |
| |
| Deferred income tax liabilities, net | | 114,009 |
| 110,618 |
|
| Regulatory liabilities, non-current | 51,583 |
| 51,916 |
| 160,642 |
| 148,013 |
|
| Benefit plan liabilities | 20,033 |
| 20,981 |
| 14,606 |
| 16,285 |
|
| Other, non-current liabilities | 3,398 |
| 2,631 |
| 1,368 |
| 1,240 |
|
| Total deferred credits and other liabilities | 263,975 |
| 268,570 |
| 290,625 |
| 276,156 |
|
| | | |
| Commitments and contingencies (Notes 4, 8, 9 and 11) |
|
|
| | | |
| Stockholder’s equity: | | |
| Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued | 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
|
| Additional paid-in capital | 39,575 |
| 39,575 |
| 39,575 |
| 39,575 |
|
| Retained earnings | 330,295 |
| 313,622 |
| 342,145 |
| 332,499 |
|
| Accumulated other comprehensive loss | (1,307 | ) | (1,819 | ) | (891 | ) | (1,258 | ) |
| Total stockholder’s equity | 391,979 |
| 374,794 |
| 404,245 |
| 394,232 |
|
| TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY | $ | 1,119,493 |
| $ | 1,055,389 |
| $ | 1,161,288 |
| $ | 1,103,146 |
|
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWS
| | | Years ended December 31, | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 |
| | (in thousands) | (in thousands) |
| Operating activities: | | |
| Net income | $ | 45,174 |
| $ | 33,562 |
| $ | 30,173 |
| $ | 45,645 |
| $ | 51,298 |
| $ | 45,138 |
|
| Adjustments to reconcile net income to net cash provided by operating activities - | | |
| Depreciation and amortization | 32,552 |
| 29,100 |
| 28,125 |
| 39,649 |
| 35,862 |
| 34,030 |
|
| Deferred income taxes | 7,690 |
| 16,518 |
| 13,582 |
| 5,218 |
| 1,004 |
| 20,690 |
|
| Employee benefits | | 1,518 |
| 817 |
| 1,770 |
|
| AFUDC - equity | (918 | ) | (519 | ) | (368 | ) | (221 | ) | (2,165 | ) | (2,165 | ) |
| Employee benefits | 2,403 |
| 1,295 |
| 3,094 |
| |
| Other adjustments | 232 |
| (2,330 | ) | 1,400 |
| 2,776 |
| 2,429 |
| 391 |
|
| Change in operating assets and liabilities - | | |
| Accounts receivable and other current assets | (2,236 | ) | (10,412 | ) | (5,265 | ) | (3,576 | ) | 3,287 |
| (3,963 | ) |
| Accounts payable and other current liabilities | 21,652 |
| 10,829 |
| 1,180 |
| (5,648 | ) | (7,254 | ) | 6,175 |
|
| Contributions to defined benefit pension plan | — |
| (1,696 | ) | (2,299 | ) | |
| Regulatory assets | (3,839 | ) | (5,366 | ) | 107 |
| 27 |
| 978 |
| (4,023 | ) |
| Regulatory liabilities | (2,479 | ) | 2,479 |
| (17 | ) | 2,561 |
| — |
| — |
|
| Contributions to defined benefit pension plan | | (1,795 | ) | (4,000 | ) | (820 | ) |
| Other operating activities | (5,680 | ) | (6,624 | ) | (3,149 | ) | (1,407 | ) | (1,853 | ) | (8,339 | ) |
| Net cash provided by operating activities | 94,551 |
| 66,836 |
| 66,563 |
| 84,747 |
| 80,403 |
| 88,884 |
|
| | | |
| Investing activities: | | |
| Property, plant and equipment additions | (56,795 | ) | (82,826 | ) | (74,390 | ) | (73,456 | ) | (79,566 | ) | (84,750 | ) |
| Notes receivable from affiliate companies, net | (36,687 | ) | (51,334 | ) | 6,353 |
| |
| Change in money pool notes receivable, net | | — |
| — |
| (4,095 | ) |
| Other investing activities | (128 | ) | (154 | ) | (72 | ) | (488 | ) | (861 | ) | (102 | ) |
| Net cash provided by (used in) investing activities | (93,610 | ) | (134,314 | ) | (68,109 | ) | |
| Net cash (used in) investing activities | | (73,944 | ) | (80,427 | ) | (88,947 | ) |
| | | |
| Financing activities: | | |
| Long-term debt - repayments | — |
| (12,200 | ) | — |
| |
| Long-term debt - issuance | — |
| 85,000 |
| — |
| |
| Other financing activities | (2 | ) | (961 | ) | — |
| |
| Change in money pool notes payable, net | | (10,707 | ) | (194 | ) | — |
|
| Net cash provided by (used in) financing activities | (2 | ) | 71,839 |
| — |
| (10,707 | ) | (194 | ) | — |
|
| | | |
| Net change in cash and cash equivalents | 939 |
| 4,361 |
| (1,546 | ) | |
| Net change in cash | | 96 |
| (218 | ) | (63 | ) |
| | | |
| Cash and cash equivalents: | | |
| Beginning of year | 6,620 |
| 2,259 |
| 3,805 |
| |
| End of year | $ | 7,559 |
| $ | 6,620 |
| $ | 2,259 |
| |
| Cash beginning of year | | 16 |
| 234 |
| 297 |
|
| Cash end of year | | $ | 112 |
| $ | 16 |
| $ | 234 |
|
See Note 10 for Supplemental Cash Flows information.
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| | | | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 |
| | (in thousands) | (in thousands) |
| Common stock shares: | | |
| Balance beginning of year | 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
|
| Issuance of common stock | — |
| — |
| — |
| — |
| — |
| — |
|
| Balance end of year | 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
| 23,416 |
|
| | | |
| Common stock amounts: | | |
| Balance beginning of year | $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
|
| Issuance of common stock | — |
| — |
| — |
| — |
| — |
| — |
|
| Balance end of year | $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
| $ | 23,416 |
|
| | | |
| Additional paid-in capital: | | |
| Balance beginning of year | $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
|
| Issuance of common stock | — |
| — |
| — |
| — |
| — |
| — |
|
| Balance end of year | $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
| $ | 39,575 |
|
| | | |
| Retained earnings: | | |
| Balance beginning of year | $ | 313,622 |
| $ | 280,060 |
| $ | 257,887 |
| $ | 332,499 |
| $ | 322,933 |
| $ | 330,295 |
|
| Net income | 45,174 |
| 33,562 |
| 30,173 |
| 45,645 |
| 51,298 |
| 45,138 |
|
| Non-cash dividend to Parent company | (28,501 | ) | — |
| (8,000 | ) | (36,000 | ) | (42,000 | ) | (52,500 | ) |
| Other adjustments | | 1 |
| 268 |
| — |
|
| Balance end of year | $ | 330,295 |
| $ | 313,622 |
| $ | 280,060 |
| $ | 342,145 |
| $ | 332,499 |
| $ | 322,933 |
|
| | | |
| Accumulated other comprehensive loss: | | |
| Balance beginning of year | $ | (1,819 | ) | $ | (1,197 | ) | $ | (1,420 | ) | $ | (1,258 | ) | $ | (1,262 | ) | $ | (1,307 | ) |
| Other comprehensive (loss) income, net of tax | 512 |
| (622 | ) | 223 |
| 367 |
| 4 |
| 45 |
|
| Balance end of year | $ | (1,307 | ) | $ | (1,819 | ) | $ | (1,197 | ) | $ | (891 | ) | $ | (1,258 | ) | $ | (1,262 | ) |
| | | |
| Total stockholder’s equity | $ | 391,979 |
| $ | 374,794 |
| $ | 341,854 |
| $ | 404,245 |
| $ | 394,232 |
| $ | 384,662 |
|
The accompanying notes to financial statements are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
December 31, 2015, 20142018, 2017 and 20132016
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Power, Inc., doing business as South Dakota Electric (the Company, “we,”“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. ActualChanges in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. As of December 31, 2018 and 2017, we have no cash equivalents.
Regulatory Accounting
Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC.
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 which could require these net regulatory assets to our regulated operations.be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that weour regulated net assets 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 thatwhich 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.
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 |
|
|
| | | | | | |
| | 2018 | 2017 |
| Regulatory assets | | |
Loss on reacquired debt (a) | $ | 1,259 |
| $ | 1,534 |
|
Deferred taxes on AFUDC (b) | 5,020 |
| 5,095 |
|
Employee benefit plans and related deferred taxes (c) | 19,868 |
| 19,465 |
|
Deferred energy and fuel cost adjustments(a) | 20,334 |
| 19,602 |
|
Deferred taxes on flow through accounting (c) | 8,749 |
| 7,579 |
|
Decommissioning costs (b) | 8,196 |
| 10,252 |
|
Vegetation management (a) | 10,366 |
| 12,669 |
|
Other regulatory assets (a) | 1,940 |
| 2,507 |
|
| | $ | 75,732 |
| $ | 78,703 |
|
| Less current regulatory assets | (19,052 | ) | (18,993 | ) |
| Regulatory assets, non-current | $ | 56,680 |
| $ | 59,710 |
|
| | | |
| Regulatory liabilities | | |
Cost of removal for utility plant (a) | $ | 52,366 |
| $ | 44,056 |
|
Employee benefit plans and related deferred taxes (c) | 7,518 |
| 6,808 |
|
Excess deferred income taxes (c) | 100,276 |
| 97,101 |
|
| TCJA revenue reserve | 2,523 |
| — |
|
Other regulatory liabilities (c) | 533 |
| 890 |
|
| | $ | 163,216 |
| $ | 148,855 |
|
| Less current regulatory liabilities | (2,574 | ) | (842 | ) |
| Regulatory liabilities, non-current | $ | 160,642 |
| $ | 148,013 |
|
____________________
(a) RecoveryWe are allowed a recovery of costs but we are not allowed a rate of return.
| |
| (b) | In addition to recovery of costs, we are allowed a rate of return. |
| |
| (c) | In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively. |
| |
(d) | Includes approximately $5.0 million of vegetation management expenses.base. |
Regulatory assets represent items we expect to recover from customers through probable future increases in rates.
Unamortized Loss on Reacquired Debt - The early redemption premium on reacquired bondsdebt is being amortized over the remaining term of the original bonds.
Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.
Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plansplan and other post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation-defined benefit plans to record the full pension and post-retirement benefit obligations. Such amounts have been grossed-up to reflect the revenue requirement associated with a rate regulated environment.
Deferred Energy Costsand Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our utility customers that areis either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. We file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by the applicable state utility commissions.
Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. 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 was established to reflect thethat 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 tofor costs considered repairscurrently deductible for tax purposes, andbut are capitalized for book purposes.
Decommissioning Costs - We received approval in 2014 for regulatory treatment on the remaining net book values and decommissioning costs of our decommissioned coal plants.
Vegetation Management Costs - We received approval in 2013 for regulatory treatment on vegetation management maintenance costs for our distribution system rights-of-way.
Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.
Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.
Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcareother postretirement benefit costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirementcompensation-retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - definedcompensation-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 ofassociated with a rate regulated environment.
Excess Deferred Income Taxes - The revaluation of our deferred tax assets and liabilities due to the passage of the TCJA is recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See additional details below.
TCJA Revenue Reserve - Revenue subject to refund at December 31, 2018, represents revenue reserved as a result of the TCJA. See below “TCJA Revenue Reserve” under Revenue recognition for further disclosure.
Excess Deferred Income Taxes
As of December 31, 2018 and 2017, we have a regulatory liability associated with TCJA related items of approximately $100 million and $97 million, respectively. The majority of this regulatory liability relates to excess deferred taxes resulting from the remeasurement of deferred tax assets and liabilities in 2017. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $0.9 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. See Note 6 for more information.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts, net of write-offs or payment received.
We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. The
In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance is calculated by applying estimated write-off factorsfor doubtful accounts to various classes of outstanding receivables, including unbilled revenue. The write-off factors usedreduce the net receivable balance to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s bestthe amount we reasonably expect to collect. However, if circumstances change, our estimate of future collection success given the existing collections environment.recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.
Following is a summary of accounts receivable atas of 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 |
|
|
| | | | | | |
| | 2018 | 2017 |
| Accounts receivable, trade | $ | 16,236 |
| $ | 15,994 |
|
| Unbilled revenue | 12,333 |
| 13,280 |
|
| Less Allowance for doubtful accounts | (138 | ) | (224 | ) |
| Accounts receivable, net | $ | 28,431 |
| $ | 29,050 |
|
Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):
|
| | | | | | | | | | | | |
| | Balance at beginning of year | Additions charged to costs and expenses | Deductions charged to costs and expenses | Balance at end of year |
| 2018 | $ | 224 |
| $ | 911 |
| $ | (997 | ) | $ | 138 |
|
| 2017 | $ | 157 |
| $ | 882 |
| $ | (815 | ) | $ | 224 |
|
| 2016 | $ | 207 |
| $ | 644 |
| $ | (694 | ) | $ | 157 |
|
Revenue Recognition
Revenue isRevenues are recognized when there is persuasive evidence ofin an arrangement with a fixed or determinable price, delivery has occurredamount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:
Regulated electric utility services tariffs - Our regulated operations, as defined by ASC 980, provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of commodity electricity and electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our regulated utility sales are subject to regulatory-approved tariffs.
Power sales agreements - We have been rendered, and collectibilitylong-term wholesale power sales agreements with other load serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is reasonably assured. Taxes collected from our customers are recordedobligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, the Company also sells excess energy to other load-serving entities on a net basis (excluded from Revenue).short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price, and is variable based on energy delivered.
Utility revenues
The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition. Sales tax and other similar taxes are excluded from revenues.
|
| | | |
| | Year ended December 31, 2018 |
| | (in thousands) |
| Customer types: | |
| Retail | $ | 197,184 |
|
| Wholesale | 33,687 |
|
| Market - off-system sales | 17,691 |
|
| Transmission/Other | 49,015 |
|
| Revenue from contracts with customers | 297,577 |
|
| Other revenues | 503 |
|
| Total revenues | $ | 298,080 |
|
| | |
| Timing of revenue recognition: | |
| Services transferred over time | $ | 297,577 |
|
| Revenue from contracts with customers | $ | 297,577 |
|
The majority of the our revenue contracts are based on authorized rates approved byvariable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our revenues. Variable consideration constraints in the state regulatory agencies andform of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the FERC. Revenues relatedprincipal in our revenue contracts, as we have control over the services prior to those services being transferred to the sale, transmissioncustomer.
Revenue Not in Scope of ASC 606
Other revenues included in the table above include revenue accounted for under separate accounting guidance, including alternative revenue programs revenue under ASC 980.
Significant Judgments and distributionEstimates
TCJA revenue reserve
The TCJA or “tax reform”, signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. We have been collaborating with our regulators in the states in which we provide utility service to deliver to customers the benefits of energy,a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We estimated and deliveryrecorded a revenue reserve of service are generally recorded when service is rendered or energy isapproximately $10 million during the year ended December 31, 2018.
On September 4, 2018, the SDPUC approved a settlement agreement for South Dakota Electric allowing the Company to pass on the benefits of a lower corporate federal income tax rate to our South Dakota retail customers. As of December 31, 2018, approximately $7.6 million has been delivered to customers. customers and approximately $2.5 million remains in reserve.
Unbilled Revenue
To the extent that deliveries have occurred but a bill has not been issued, we accruethe Company accrues an estimate of the revenue since the latest billing. This estimate is calculated based uponon 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,Accounts receivable, net on the accompanying Balance Sheets.
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable and is further discussed above. We do not typically incur costs that would be capitalized, to obtain or fulfill a contract.
Practical Expedients
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.
We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.
Materials, Supplies and Fuel
Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on arecorded using the 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 termestimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost when placed in service.cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets.
The cost of regulated electricutility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. RemovalEstimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.3% in 2015, 2.3%2018, 2.1% in 20142017 and 2.1%2.2% in 2013.2016.
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands):
|
| | | | | | |
| | 2018 | 2017 |
| Accrued employee compensation, benefits and withholdings | $ | 4,206 |
| $ | 4,305 |
|
| Accrued property taxes | 6,332 |
| 5,930 |
|
| Accrued income taxes | 12,536 |
| 17,472 |
|
| Customer deposits and prepayments | 5,204 |
| 4,863 |
|
| Accrued interest | 4,627 |
| 4,708 |
|
| Other (none of which is individually significant) | 1,288 |
| 927 |
|
| Total accrued liabilities | $ | 34,193 |
| $ | 38,205 |
|
Derivatives and Hedging Activities
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 underThe accounting standards for derivatives and hedging require that are not exempted such as normal purchase/normal sale, are required toderivative instruments be recorded inon the balance sheet as either an asset or liability measured at its fair value. Accounting standards for derivatives require thatvalue and changes in the derivative instrument’s fair valueinstruments be recognized currently in earnings unless specific hedge accounting criteria are met.met and designated accordingly, including the normal purchase and normal sales exception. Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur.
Accounting standards for derivatives allow hedge accounting for qualifying fair value and cash flow hedges. GainFrom time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, 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 earningslock in the same accounting period. Conversely,Treasury yield component associated with anticipated issuance of senior notes. For swaps that settled in connection with the issuance of senior debt, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reportedis deferred as a component in AOCI and recognized as interest expense over the life of other comprehensive income and be reclassified into earnings or as a regulatory asset or regulatory liability, netthe senior note. As 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.December 31, 2018, we have no outstanding interest rate swap agreements.
Revenues and expenses on contracts that qualify are designated as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions,exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.
Fair Value Measurements
Accounting standards for fair value measurements provide a single definition of fair value asWe use 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 afollowing fair value hierarchy that prioritizes thefor determining 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).
Financialour financial instruments. Our financial instruments’ assets and liabilities carried at fair valuefor financial instruments are classified and disclosed in one of the following threefair value categories:
Level 1 -— Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.
Level 2 -— Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 -— Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions a market participant would use in pricing the asset or liability.
Impairment of Long-Lived Assets
We periodically evaluate whether eventsAssets and circumstances have occurred whichliabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the estimated useful life orplacement within the recoverabilityfair value hierarchy levels. We record transfers, if necessary, between levels at the end of the remaining balancereporting period for all of our long-lived assets. Iffinancial instruments.
Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such events or circumstances were to indicate thatas a significant decrease in the carrying amountfrequency and volume in which the instrument is traded, negatively impacting the availability of these assets wasobservable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. We currently do not 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.have any Level 3 investments.
Income Taxes
We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.
We useThe Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. At
On December 31, 2015, we have chosen22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to early adopt onas the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%.
We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a prospective basis ASU 2015-17method results in the investment tax credit being amortized as discussed below under Recently Issued and Adopted Accounting Standards. Asa reduction to income tax expense over the estimated useful lives 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.underlying property that gave rise to the credit.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income.
We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other, - non-current liabilities on the accompanying Balance Sheets. See Note 6 for additional information.
Recently Issued and Adopted Accounting PrinciplesStandards
Balance Sheet Classification of Deferred Taxes,Leases, ASU 2015-172016-02
In November 2015,February 2016, the FASB issued ASU 2015-17 providing2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the original guidance, on financial statement presentation for deferred tax assetslessees and deferred tax liabilities. All deferred taxes are to belessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented as non-current. FASB issued this guidance as partin the year of its initiative to reduce complexity in accounting standards. Thisadoption. The 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.
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. Early2018, with early adoption is permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported.
We adopted this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we elected the practical expedient which provides for no assessment of these easements. Further, we adopted the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We elected the “package of three” practical expedient. We have chosenimplemented a new lease accounting system and adjusted related procedures and controls accordingly. We will record an operating lease right of use asset and an off-setting operating lease obligation liability as of January 1, 2019 for approximately $14 million, respectively, primarily driven by the intercompany ground lease with WRDC for Wygen III. Adoption of this standard did not to early adopt ASU 2015-03.have a material impact on our financial position, results of operations or cash flows.
Recently Adopted Accounting Standards
Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issued
Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers. TheCustomers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, provides companies withrevenue is recognized when 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 whencustomer obtains control of thepromised goods or services transfersin an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. The guidance alsostandard requires additional disclosure aboutof the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. On July 9, 2015, FASB votedWe applied the five-step method outlined in the ASU to deferall in-scope revenue streams and elected the effective datemodified retrospective implementation method. Implementation 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 standard did not have a material impact that adoption of ASU 2014-09 will have on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 1.
Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07
Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the year ended December 31, 2018. Retrospective impact was not material and therefore not adjusted. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15
Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.
(2) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
| | | | | 2015 | | 2014 | | | 2018 | | 2017 |
| | | Weighted | | Weighted | | | Weighted | | Weighted |
| | | Average | | Average | Lives (in years) | | Average | | Average |
| | 2015 | Useful Life (in years) | 2014 | Useful Life (in years) | Minimum | Maximum | 2018 | Useful Life (in years) | 2017 | Useful Life (in years) |
| Electric plant: | | | | | | | | |
| Production | $ | 569,182 |
| 46 | $ | 567,936 |
| 48 | 40 | 65 | $ | 588,565 |
| 46 | $ | 587,323 |
| 46 |
| Transmission | 117,708 |
| 48 | 115,949 |
| 46 | 40 | 60 | 208,610 |
| 48 | 186,045 |
| 49 |
| Distribution | 353,241 |
| 46 | 336,652 |
| 39 | 20 | 60 | 394,475 |
| 45 | 375,214 |
| 46 |
Plant acquisition adjustment (a) | 4,870 |
| 32 | 4,870 |
| 32 | 4,870 |
| 32 | 4,870 |
| 32 |
| General | 88,939 |
| 22 | 79,738 |
| 22 | 5 | 40 | 154,621 |
| 28 | 153,535 |
| 32 |
| Total plant-in-service | 1,133,940 |
| | 1,105,145 |
| | 1,351,141 |
| | 1,306,987 |
| |
| Construction work in progress | 32,186 |
| | 9,916 |
| | 29,904 |
| | 4,832 |
| |
| Total electric plant | 1,166,126 |
| | 1,115,061 |
| | 1,381,045 |
| | 1,311,819 |
| |
| Less accumulated depreciation and amortization | (326,074 | ) | | (309,767 | ) | | (376,160 | ) | | (358,946 | ) | |
| Electric plant net of accumulated depreciation and amortization | $ | 840,052 |
| | $ | 805,294 |
| | $ | 1,004,885 |
| | $ | 952,873 |
| |
__________________
| |
| (a) | The plant acquisition adjustment is included in rate base and is being recovered with 1512 years remaining. |
(3) JOINTLY OWNED FACILITIES
We useOur financial statements include our share of several jointly-owned utility facilities as described below. Our share of the proportionate consolidation method to account for our percentage interestfacilities’ expenses are reflected in the assets, liabilities andappropriate categories of operating expenses in the Statements of Income (Loss). Each owner of the following facilities:facility is responsible for financing its investment in the jointly-owned facilities.
We own a 20% interest in the Wyodak Plant (the “Plant”), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the Plant’s capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses.
We own a 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPPSPP region. The total transfer capacity of the transmission tie is 400 MW, -including 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses.
We own a 52% interest in the Wygen III power plant. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.
We own 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Cheyenne LightWyoming Electric 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, 2015,2018, 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 | Plant in Service | Construction Work in Progress | Accumulated Depreciation |
| Wyodak Plant | $ | 111,532 |
| $ | 1,039 |
| $ | 56,812 |
| $ | 115,198 |
| $ | 384 |
| $ | 61,730 |
|
| Transmission Tie | $ | 19,648 |
| $ | — |
| $ | 5,390 |
| $ | 20,855 |
| $ | 1,860 |
| $ | 6,667 |
|
| Wygen III | $ | 137,860 |
| $ | 446 |
| $ | 16,217 |
| $ | 140,072 |
| $ | 645 |
| $ | 22,647 |
|
| Cheyenne Prairie | $ | 91,081 |
| $ | — |
| $ | 3,301 |
| $ | 92,053 |
| $ | 69 |
| $ | 11,460 |
|
(4) LONG-TERM DEBT
Long-term debt outstanding at December 31 was as follows (in thousands):
| | | | | | | | | | | Interest Rate at | Balance Outstanding |
| | Maturity Date | Interest Rate | 2015 | 2014 | Due Date | December 31, 2018 | December 31, 2017 |
| First Mortgage Bonds due 2032 | August 15, 2032 | 7.23 | % | $ | 75,000 |
| $ | 75,000 |
| August 15, 2032 | 7.23 | % | 75,000 |
| 75,000 |
|
| First Mortgage Bonds due 2039 | November 1, 2039 | 6.125 | % | 180,000 |
| 180,000 |
| November 1, 2039 | 6.13 | % | 180,000 |
| 180,000 |
|
| First Mortgage Bonds due 2044 | October 20, 2044 | 4.43 | % | 85,000 |
| 85,000 |
| October 20, 2044 | 4.43 | % | 85,000 |
| 85,000 |
|
| Unamortized discount, First Mortgage Bonds due 2039 | | | (99 | ) | (103 | ) | |
| Less unamortized debt discount | | | | (86 | ) | (90 | ) |
Series 94A Debt (a) | June 1, 2024 | 0.75 | % | 2,855 |
| 2,855 |
| June 1, 2024 | 1.93 | % | 2,855 |
| 2,855 |
|
| Long-term debt | | | $ | 342,756 |
| $ | 342,752 |
| |
| Less unamortized deferred financing costs | | | | (2,734 | ) | (2,870 | ) |
| Long-term Debt | | | | 340,035 | 339,895 |
___________________
| |
| (a) | Variable interest rate at December 31, 2015.2018. |
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$2.7 million and $3.3$2.9 million were recorded on the accompanying Balance Sheets in Other, non-current assetslong-term debt at December 31, 20152018 and 2014,2017, respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1$0.1 million, $0.1 million and $0.1 million for each of the years ended December 31, 2015, 20142018, 2017 and 2013, respectively,2016 are included in Interest expense on the accompanying Statements of Income.
Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, 2015.2018.
Long-term Debt Maturities
Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts)discounts and unamortized deferred financing costs) are as follows (in thousands):
| | | 2016 | $ | — |
| |
| 2017 | $ | — |
| |
| 2018 | $ | — |
| |
| 2019 | $ | — |
| $ | — |
|
| 2020 | $ | — |
| $ | — |
|
| 2021 | | $ | — |
|
| 2022 | | $ | — |
|
| 2023 | | $ | — |
|
| Thereafter | $ | 342,855 |
| $ | 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 |
|
|
| | | | | | | | | | | | |
| | 2018 | 2017 |
| | Carrying Value | Fair Value | Carrying Value | Fair Value |
Cash (a) | $ | 112 |
| $ | 112 |
| $ | 16 |
| $ | 16 |
|
Long-term debt (b) (c) | $ | 340,035 |
| $ | 412,894 |
| $ | 339,895 |
| $ | 446,978 |
|
_______________
| |
| (a) | FairThe cash 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 inas Level 1 in the fair value hierarchy. We believe that the market risk arising from cash in a bank account is minimal. |
| |
| (b) | Long-term debt is valued 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 ratingsliabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying |
| |
| (c) | 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.is net of deferred financing costs. |
The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.
Cash and Cash EquivalentsLong-Term Debt
Included in cash and cash equivalents is cash and overnight repurchase agreement accounts. As part ofFor additional information on 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.long-term debt, see Note 4.
(6) INCOME TAXES
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $103 million. Of the $103 million, approximately $97 million was reclassified to a regulatory liability. As of December 31, 2018 we have a regulatory liability associated with TCJA related items of $100 million. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $0.9 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.
Income tax expense (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 |
|
|
| | | | | | | | | |
| | 2018 | 2017 | 2016 |
| Current: | | | |
| Federal | $ | 5,454 |
| $ | 13,124 |
| $ | 1,838 |
|
| | | | |
| Deferred: | | | |
| Federal | 5,958 |
| 1,004 |
| 20,690 |
|
| Excess deferred tax amortization | (740 | ) | — |
| — |
|
| | $ | 5,218 |
| $ | 1,004 |
| $ | 20,690 |
|
| | | | |
| Total income tax expense | $ | 10,672 |
| $ | 14,128 |
| $ | 22,528 |
|
The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
| | | | 2015 | 2014 | 2018 | 2017 |
| Deferred tax assets: | | |
| Employee benefits | $ | 4,683 |
| $ | 4,995 |
| $ | 2,404 |
| $ | 3,012 |
|
| Net operating loss | 15 |
| 14,794 |
| |
| Regulatory liabilities | 9,908 |
| 10,824 |
| 25,587 |
| 24,984 |
|
| Other | 16,171 |
| 2,864 |
| 2,317 |
| 1,678 |
|
| Total deferred tax assets | 30,777 |
| 33,477 |
| 30,308 |
| 29,674 |
|
| | | |
| Deferred tax liabilities: | | |
| Accelerated depreciation and other plant related differences | (187,666 | ) | (184,478 | ) | (125,594 | ) | (122,002 | ) |
| AFUDC | (8,571 | ) | (8,365 | ) | |
| Regulatory assets | (4,236 | ) | (3,910 | ) | (7,147 | ) | (7,008 | ) |
| Employee benefits | (3,003 | ) | (3,723 | ) | (2,719 | ) | (2,595 | ) |
| Deferred costs | (14,765 | ) | (11,324 | ) | (8,572 | ) | (8,447 | ) |
| Other | (1,497 | ) | (1,058 | ) | (285 | ) | (240 | ) |
| Total deferred tax liabilities | (219,738 | ) | (212,858 | ) | (144,317 | ) | (140,292 | ) |
| | | |
| Net deferred tax assets (liabilities) | $ | (188,961 | ) | $ | (179,381 | ) | |
| Net deferred tax liability | | $ | (114,009 | ) | $ | (110,618 | ) |
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
| | | | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 |
| Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 21.0% | 35.0% |
| Amortization of excess deferred and investment tax credits | (0.1 | ) | (0.3 | ) | (0.3 | ) | (1.3) | (0.1) | (0.4) |
| Equity AFUDC | (0.6 | ) | (0.1 | ) | — |
| |
Flow through adjustments (a) | (0.9 | ) | (1.9 | ) | (2.5 | ) | |
| AFUDC Equity | | 0.1 | (1.0) | (0.9) |
Flow-through adjustments (a) | | (1.7) | (1.8) | (0.9) |
| Tax credits | — |
| (0.2 | ) | (0.8 | ) | — | (0.1) |
TCJA corporate rate reduction (b) | | 2.5 | (9.2) | — |
| Other | — |
| 0.5 |
| (0.6 | ) | (1.7) | (1.3) | 0.6 |
| | 33.4 | % | 33.0 | % | 30.8 | % | 18.9% | 21.6% | 33.3% |
_________________________
| |
| (a) | The flow-throughFlow-through adjustments relaterelated 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.costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customerstax expense. |
| |
| (b) | On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21%, effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes required by the change. During the year ended December 31, 2018, we recorded approximately $0.9 million of additional tax expense associated with changes in the formprior estimated impacts 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.TCJA related items. |
The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands):
| | | | 2015 | 2014 | 2018 | 2017 |
| Unrecognized tax benefits at January 1 | $ | 1,623 |
| $ | 2,443 |
| $ | 302 |
| $ | 493 |
|
| Additions for current year tax positions | | — |
| 13 |
|
| Additions for prior year tax positions | 888 |
| 434 |
| 2 |
| — |
|
| Reductions for prior year tax positions | (247 | ) | (1,254 | ) | (55 | ) | (204 | ) |
| Additions for current year tax positions | — |
| — |
| |
| Unrecognized tax benefits at December 31 | $ | 2,264 |
| $ | 1,623 |
| $ | 249 |
| $ | 302 |
|
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.not material to the financial results of the Company.
It is ourthe Company’s continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 20152018 and 2014,2017, the interest expense recognized was not material to ourthe financial results.results of the Company.
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 forWe do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations on or before December 31, 2016.2019.
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
We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.
The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):
| | | | Derivatives Designated as Cash Flow Hedges | Amounts Reclassified from AOCI | Location on the Statements of Income (Loss) | Amounts Reclassified from AOCI |
| | | 2015 | 2014 | | 2018 | 2017 |
| Gains and Losses on cash flow hedges | | | |
| Interest rate swaps gain (loss) | Interest expense | $ | 64 |
| $ | 64 |
| |
| Gains and (losses) on cash flow hedges: | | | |
| Interest rate swaps | | Interest expense | $ | 64 |
| $ | 64 |
|
| Income tax | Income tax benefit (expense) | 319 |
| (364 | ) | Income tax benefit (expense) | (13 | ) | (22 | ) |
| Total reclassification adjustments related to cash flow hedges, net of tax | | $ | 383 |
| $ | (300 | ) | | $ | 51 |
| $ | 42 |
|
| | | | | |
| Amortization of defined benefit plans: | | | | |
| Actuarial gain (loss) | Operations and maintenance | $ | 94 |
| $ | 45 |
| Operations and maintenance | $ | 103 |
| $ | 86 |
|
| Income tax | Income tax benefit (expense) | (33 | ) | (16 | ) | Income tax benefit (expense) | (22 | ) | (30 | ) |
| Total reclassification adjustments related to defined benefit plans, net of tax | | $ | 61 |
| $ | 29 |
| | $ | 81 |
| $ | 56 |
|
Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $50 million of our First Mortgage Bonds due on August 15, 2032.2032. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated other comprehensive loss and is being amortized over the life of the related bonds.
Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands):
|
| | | | | | | | | |
| | Interest Rate Swaps | Employee Benefit Plans | Total |
| | | | |
| As of December 31, 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 | ) |
|
| | | | | | | | | |
| | Interest Rate Swaps | Employee Benefit Plans | Total |
| | | | |
| As of December 31, 2017 | $ | (551 | ) | $ | (707 | ) | $ | (1,258 | ) |
| Other comprehensive income (loss) before reclassifications | — |
| 235 |
| 235 |
|
| Amounts reclassified from AOCI | 51 |
| 81 |
| 132 |
|
| As of December 31, 2018 | $ | (500 | ) | $ | (391 | ) | $ | (891 | ) |
| | | | |
| | |
| | Interest Rate Swaps | Employee Benefit Plans | Total |
| | | | |
| As of December 31, 2016 | $ | (593 | ) | $ | (669 | ) | $ | (1,262 | ) |
| Other comprehensive income (loss) before reclassifications | — |
| (94 | ) | (94 | ) |
| Amounts reclassified from AOCI | 42 |
| 56 |
| 98 |
|
| As of December 31, 2017 | $ | (551 | ) | $ | (707 | ) | $ | (1,258 | ) |
(8) EMPLOYEE BENEFIT PLANS
Funded Status of BenefitDefined Contribution Plans
The funded status of the postretirement benefitBHC sponsors a 401(k) retirement savings plan is required to be recognized(the 401(k) Plan). Participants in the statement401(k) Plan may elect to invest a portion of financial position.their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The funded status for401(k) Plan provides employees the pension plan is measured as the difference between the projected benefit obligation and the fair valueopportunity to invest up to 50% of plan assets. their eligible compensation on a pre-tax or after-tax basis.
The funded status401(k) Plan provides a Company matching contribution for all othereligible participants. Certain eligible participants who are not currently accruing a benefit plans is measured asin 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,also receive a Company retirement contribution based on the unfunded statusparticipant’s age and years of our Supplemental Non-qualified Defined Benefit Plans was $3.4 millionservice. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the unfunded statusparticipant has 5 years of our Non-pension Defined Benefit Postretirement Healthcare Plans was $6.2 million.
We apply accounting standards for regulated operations, and accordingly,service with 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.Company.
Defined Benefit Pension Plan (Pension Plan)
We have a defined benefit pension plan (“Pension Plan”) covering certain eligible employees. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan has been closed to new employees and certain employees who did not meet age and service based criteria.
The Pension Plan assets are held in a Master Trust 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 Our Board of Directors havehas approved the Plans’Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plans’Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Plans’Pension Plan’s benefit payment obligations. The Pension Plans’Plan’s assets consist primarily of equity, fixed income and hedged investments.
The expected long-term rate of return for investments was 6.75%on the Pension Plan assets is determined by reviewing the historical and 6.75% forexpected returns of both equity and fixed income markets, taking into account asset allocation, the 2015correlation between asset class returns, and 2014the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target allocation range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2018, the expected rate of return on pension plan years, respectively. assets is based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 71% liability-hedging assets.
Our Pension Plan funding policy is funded in accordancecompliance with the federal government’s funding requirements.
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 | 2018 | 2017 |
| Equity securities | 26 | % | 27 | % | 17 | % | 26 | % |
| Real estate | 5 |
| 5 |
| 4 |
| 4 |
|
| Fixed income funds | 59 |
| 58 |
| 71 |
| 63 |
|
| Cash and cash equivalents | 1 |
| 2 |
| 3 |
| 1 |
|
| Hedge funds | 9 |
| 8 |
| 5 |
| 6 |
|
| Total | 100 | % | 100 | % | 100 | % | 100 | % |
Supplemental Non-qualified Defined Benefit Retirement Plans
We have various supplemental retirement plans (“Supplemental Plans”) for key executives.executives of the Company. The Supplemental Plansplans are non-qualified defined benefit plans.and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules.schedules and are not funded by the Company.
Supplemental Plan Assets
We do not fund our Supplemental PlansPlans. We fund on a cash basis as benefits are paid.
Non-pension Defined Benefit Postretirement Healthcare PlanPlans
EmployeesBHC sponsors retiree healthcare plans (Healthcare Plans) for employees who are participants in our Non-Pension Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimummeet certain age and years of service requirements are entitled to postretirement healthcare benefits. Theseat retirement. Healthcare Plan 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 ourPre-65 retirees receive their retiree medical plan. We have determined thatbenefits through the Black Hills self-insured retiree medical plans. Healthcare Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualifycoverage for the Medicare Part D subsidy.Medicare-eligible BHP retirees is provided through an individual market healthcare exchange.
Plan Assets
We fund our Healthcare Plans on a cash basis as benefits are paid.
Plan Contributions and Estimated Cash Flows
CashContributions to the Pension Plan are cash contributions for pension plans are made directly to the Pension Plan Trust accounts.Master Trust. Healthcare benefits include company and Supplemental Plan contributions are made in the form of benefit payments. participant paid premiums.
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 |
|
|
| | | | | | |
| | 2018 | 2017 |
| Defined Contribution Plans | | |
| Company Retirement Contribution | $ | 876 |
| $ | 861 |
|
| Matching Contributions | $ | 1,272 |
| $ | 1,306 |
|
|
| | | | | | |
| | 2018 | 2017 |
| Defined Benefit Plans | | |
| Defined Benefit Pension Plan | $ | 1,795 |
| $ | 4,000 |
|
| Non-Pension Defined Benefit Postretirement Healthcare Plans | $ | 388 |
| $ | 348 |
|
| Supplemental Non-qualified Defined Benefit Plan | $ | 238 |
| $ | 246 |
|
While we aredo not have required contributions, we expect to contributemake approximately $1.6$1.8 million in contributions to our Defined Benefit Pension Plan in 2016.2019.
Fair Value Measurements
As required by accounting standards for fair value measurements, assetsAssets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. OurThe Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.
The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31 (in thousands):
| | | Defined Benefit Pension Plan | 2015 | |
| Pension Plan | | December 31, 2018 |
| | Level 1 | Level 2 | Level 3 | Total Fair Value | Level 1 | Level 2 | Level 3 | Total Investments Measured at Fair Value | NAV (a) | Total Investments |
| AXA Equitable General Fixed Income | | $ | — |
| $ | 261 |
| $ | — |
| $ | 261 |
| $ | — |
| $ | 261 |
|
| Common Collective Trust - Cash and Cash Equivalents | $ | — |
| $ | 498 |
| $ | — |
| $ | 498 |
| — |
| 1,388 |
| — |
| 1,388 |
| — |
| 1,388 |
|
| Common Collective Trust - Equity | — |
| 14,198 |
| — |
| 14,198 |
| — |
| 9,436 |
| — |
| 9,436 |
| — |
| 9,436 |
|
| Common Collective Trust - Fixed Income | — |
| 32,615 |
| — |
| 32,615 |
| — |
| 39,047 |
| — |
| 39,047 |
| — |
| 39,047 |
|
| Common Collective Trust - Real Estate | — |
| 418 |
| 2,113 |
| 2,531 |
| — |
| 9 |
| — |
| 9 |
| 1,896 |
| 1,905 |
|
| Hedge Funds | — |
| — |
| 4,881 |
| 4,881 |
| — |
| — |
| — |
| — |
| 2,627 |
| 2,627 |
|
| Total investments measured at fair value | $ | — |
| $ | 47,729 |
| $ | 6,994 |
| $ | 54,723 |
| $ | — |
| $ | 50,141 |
| $ | — |
| $ | 50,141 |
| $ | 4,523 |
| $ | 54,664 |
|
| | | Defined Benefit Pension Plan | 2014 | |
| Pension Plan | | December 31, 2017 |
| | Level 1 | Level 2 | Level 3 | Total Fair Value | Level 1 | Level 2 | Level 3 | Total Investments Measured at Fair Value | NAV (a) | Total Investments |
| AXA Equitable General Fixed Income | | $ | — |
| $ | 184 |
| $ | — |
| $ | 184 |
| $ | — |
| $ | 184 |
|
| Common Collective Trust - Cash and Cash Equivalents | $ | — |
| $ | 899 |
| $ | — |
| $ | 899 |
| — |
| 314 |
| — |
| 314 |
| — |
| 314 |
|
| Common Collective Trust - Equity | — |
| 16,107 |
| — |
| 16,107 |
| — |
| 15,749 |
| — |
| 15,749 |
| — |
| 15,749 |
|
| Common Collective Trust - Fixed Income | — |
| 34,474 |
| — |
| 34,474 |
| — |
| 37,732 |
| — |
| 37,732 |
| — |
| 37,732 |
|
| Common Collective Trust - Real Estate | — |
| 761 |
| 1,918 |
| 2,679 |
| — |
| 249 |
| — |
| 249 |
| 2,258 |
| 2,507 |
|
| Hedge Funds | — |
| — |
| 4,939 |
| 4,939 |
| — |
| — |
| — |
| — |
| 3,398 |
| 3,398 |
|
| Total investments measured at fair value | $ | — |
| $ | 52,241 |
| $ | 6,857 |
| $ | 59,098 |
| $ | — |
| $ | 54,228 |
| $ | — |
| $ | 54,228 |
| $ | 5,656 |
| $ | 59,884 |
|
________________________
| |
| (a) | Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. |
Cash and Cash Equivalents: This category is comprised of theAXA Equitable General Fixed Income Fundand Common Collective Trusts - cash and cash equivalents. The AXA Equitable General Fixed Income Fund: This fund is a fund of diversified portfolios,portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placeplaced 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 whichof loans with similar characteristics have.characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.
Common Collective Trust:Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.
Common Collective Trust - RealTrust-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.
The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.
46Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy.
Hedge Funds: HedgeThese 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,20% of the shares may be redeemed at the end of each month with a 10-day notice and full redemptions are available at the end of each quarter with a 65 day45-day notice, and areis limited to a percentage of the total net assetassets 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. |
Other Plan ReconciliationsInformation
The following tables provide a reconciliation of the Employee Benefit Plan’semployee benefit plan obligations, and fair value of assets and amounts recognized in the Balance Sheets, components of the net periodic expense and elements of regulatory assets and liabilities and AOCI (in thousands):AOCI:
Benefit Obligations
| | | | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans
|
| | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | |
| As of December 31 (in thousands) | | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Change in benefit obligation: | | |
| Projected benefit obligation at beginning of year | $ | 71,178 |
| $ | 60,223 |
| $ | 3,599 |
| $ | 3,131 |
| $ | 6,038 |
| $ | 5,850 |
| $ | 67,562 |
| $ | 64,973 |
| $ | 3,418 |
| $ | 3,404 |
| $ | 5,970 |
| $ | 5,843 |
|
| Service cost | 797 |
| 704 |
| — |
| — |
| 233 |
| 222 |
| 516 |
| 545 |
| — |
| — |
| 193 |
| 206 |
|
| Interest cost | 2,956 |
| 2,991 |
| 142 |
| 146 |
| 214 |
| 241 |
| 2,194 |
| 2,341 |
| 108 |
| 116 |
| 179 |
| 176 |
|
| Actuarial loss (gain) | (5,650 | ) | 11,879 |
| (104 | ) | 540 |
| 27 |
| 115 |
| (2,878 | ) | 4,008 |
| (296 | ) | 144 |
| (889 | ) | 130 |
|
| Benefits paid | (3,284 | ) | (4,452 | ) | (211 | ) | (218 | ) | (387 | ) | (488 | ) | (3,562 | ) | (3,445 | ) | (238 | ) | (246 | ) | (389 | ) | (348 | ) |
| Asset transfer (to) from affiliate | (38 | ) | (167 | ) | — |
| — |
| (7 | ) | 24 |
| |
| Medicare Part D adjustment | — |
| — |
| — |
| — |
| (30 | ) | (15 | ) | |
| Plan participants transfer to affiliate | | (1,913 | ) | (860 | ) | — |
| — |
| (129 | ) | (137 | ) |
| Plan participants’ contributions | — |
| — |
| — |
| — |
| 120 |
| 89 |
| — |
| — |
| — |
| — |
| 120 |
| 100 |
|
| Projected benefit obligation at end of year | $ | 65,959 |
| $ | 71,178 |
| $ | 3,426 |
| $ | 3,599 |
| $ | 6,208 |
| $ | 6,038 |
| $ | 61,919 |
| $ | 67,562 |
| $ | 2,992 |
| $ | 3,418 |
| $ | 5,055 |
| $ | 5,970 |
|
A reconciliation of the fair value of
Employee Benefit Plan assets (as of the December 31 measurement date) is as follows (in thousands):Assets
|
| | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 |
| Beginning market value of plan assets | $ | 59,098 |
| $ | 56,405 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Investment income | (1,057 | ) | 5,462 |
| — |
| — |
| — |
| — |
|
| Benefits paid | (3,284 | ) | (4,452 | ) | (211 | ) | — |
| (387 | ) | — |
|
| Participant contributions | — |
| — |
| — |
| — |
| 120 |
| — |
|
| Employer contributions | — |
| 1,696 |
| 211 |
| — |
| 267 |
| — |
|
| Asset transfer to affiliate | (34 | ) | (13 | ) | — |
| — |
| — |
| — |
|
| Ending market value of plan assets | $ | 54,723 |
| $ | 59,098 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans
|
| As of December 31 (in thousands) | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Beginning fair value of plan assets | $ | 59,884 |
| $ | 53,888 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Investment income (loss) | (1,884 | ) | 6,150 |
| — |
| — |
| — |
| — |
|
| Employer contributions | 1,795 |
| 4,000 |
| 238 |
| 246 |
| 268 |
| 248 |
|
| Retiree contributions | — |
| — |
| — |
| — |
| 120 |
| 100 |
|
| Benefits paid | (3,563 | ) | (3,445 | ) | (238 | ) | (246 | ) | (388 | ) | (348 | ) |
| Plan participants transfer to affiliate | (1,568 | ) | (709 | ) | — |
| — |
| — |
| — |
|
| Ending fair value of plan assets | $ | 54,664 |
| $ | 59,884 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
AmountsThe funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands):
| | | | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plan | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans
|
| | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Regulatory asset (liability) | $ | 19,816 |
| $ | 22,717 |
| $ | — |
| $ | — |
| $ | (1,946 | ) | $ | 2,306 |
| |
| Regulatory asset | | $ | 19,099 |
| $ | 18,998 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Current liability | $ | — |
| $ | — |
| $ | (216 | ) | $ | (217 | ) | $ | (619 | ) | $ | (519 | ) | $ | — |
| $ | — |
| $ | 230 |
| $ | 245 |
| $ | 466 |
| $ | 534 |
|
| Non-current liability | $ | (11,236 | ) | $ | (12,080 | ) | $ | (3,210 | ) | $ | (3,382 | ) | $ | (5,587 | ) | $ | (5,519 | ) | $ | 7,255 |
| $ | 7,676 |
| $ | 2,762 |
| $ | 3,173 |
| $ | 4,589 |
| $ | 5,436 |
|
| Regulatory liability | | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,441 |
| $ | 1,758 |
|
Accumulated Benefit Obligation (in thousands)
|
| | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 |
| Accumulated benefit obligation | $ | 62,240 |
| $ | 65,699 |
| $ | 3,426 |
| $ | 3,599 |
| $ | 6,208 |
| $ | 6,038 |
|
|
| | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental
Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans
|
| As of December 31 (in thousands) | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Accumulated benefit obligation | $ | 59,987 |
| $ | 64,782 |
| $ | 2,992 |
| $ | 3,418 |
| $ | 5,055 |
| $ | 5,970 |
|
Components of Net Periodic Expense
Net periodic expense consisted of the following for the year ended December 31 (in thousands):
| | | | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan | Defined Benefit Pension Plan | Supplemental
Non-qualified Defined Benefit Plans
| Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 |
| Service cost | $ | 797 |
| $ | 704 |
| $ | 852 |
| $ | — |
| $ | — |
| $ | — |
| $ | 233 |
| $ | 222 |
| $ | 216 |
| $ | 516 |
| $ | 545 |
| $ | 606 |
| $ | — |
| $ | — |
| $ | — |
| $ | 193 |
| $ | 206 |
| $ | 204 |
|
| Interest cost | 2,956 |
| 2,991 |
| 2,969 |
| 142 |
| 146 |
| 133 |
| 214 |
| 241 |
| 239 |
| 2,194 |
| 2,341 |
| 2,499 |
| 108 |
| 116 |
| 122 |
| 179 |
| 176 |
| 187 |
|
| Expected return on assets | (3,935 | ) | (3,702 | ) | (3,764 | ) | — |
| — |
| — |
| — |
| — |
| — |
| (3,545 | ) | (3,591 | ) | (3,632 | ) | — |
| — |
| — |
| — |
| — |
| — |
|
| Amortization of prior service cost (credits) | 43 |
| 43 |
| 43 |
| — |
| — |
| — |
| (336 | ) | (335 | ) | (278 | ) | 43 |
| 43 |
| 43 |
| — |
| — |
| — |
| (336 | ) | (336 | ) | (337 | ) |
| Amortization of transition obligation | — |
| — |
| 2,609 |
| — |
| — |
| — |
| — |
| — |
| — |
| |
| Recognized net actuarial loss (gain) | 2,196 |
| 940 |
| — |
| 93 |
| 45 |
| 66 |
| — |
| — |
| 9 |
| 2,063 |
| 1,230 |
| 1,995 |
| 103 |
| 87 |
| 82 |
| — |
| — |
| — |
|
| Net periodic expense | $ | 2,057 |
| $ | 976 |
| $ | 2,709 |
| $ | 235 |
| $ | 191 |
| $ | 199 |
| $ | 111 |
| $ | 128 |
| $ | 186 |
| $ | 1,271 |
| $ | 568 |
| $ | 1,511 |
| $ | 211 |
| $ | 203 |
| $ | 204 |
| $ | 36 |
| $ | 46 |
| $ | 54 |
|
AccumulatedFor the year ended December 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other Comprehensive Income (Loss)expense, on the Statements of Income. For the years ended December 31, 2017 and 2016, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Statements of Income. See Note 1 for additional information.
Amounts
AOCI
For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
|
| | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2015 | 2014 | 2015 | 2014 | 2015 | 2014 |
| Net loss | $ | — |
| $ | — |
| $ | 673 |
| $ | (801 | ) | $ | — |
| $ | — |
|
| Prior service cost | — |
| — |
| — |
| — |
| — |
| — |
|
| Total accumulated other comprehensive income (loss) | $ | — |
| $ | — |
| $ | 673 |
| $ | (801 | ) | $ | — |
| $ | — |
|
|
| | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 |
| Net (gain) loss | $ | — |
| $ | — |
| $ | 391 |
| $ | 707 |
| $ | — |
| $ | — |
|
| Total AOCI | $ | — |
| $ | — |
| $ | 391 |
| $ | 707 |
| $ | — |
| $ | — |
|
The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2016 are as follows (in thousands): |
| | | | | | | | | |
| | Defined Benefits Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| Net gain (loss) | $ | 1,297 |
| $ | 53 |
| $ | — |
|
| Prior service cost | 28 |
| — |
| (218 | ) |
| Total net periodic benefit cost expected to be recognized during calendar year 2016 | $ | 1,325 |
| $ | 53 |
| $ | (218 | ) |
Assumptions
| | | | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 |
| Weighted-average assumptions used to determine benefit obligations: | | |
| Discount rate | 4.63 | % | 4.25 | % | 5.10 | % | 4.29 | % | 3.98 | % | 4.68 | % | 4.03 | % | 3.70 | % | 4.45 | % | 4.40 | % | 3.71 | % | 4.27 | % | 4.30 | % | 3.62 | % | 4.12 | % | 4.28 | % | 3.60 | % | 3.84 | % |
| Rate of increase in compensation levels | 3.57 | % | 3.86 | % | 3.86 | % | N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| 3.52 | % | 3.43 | % | 3.47 | % | N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| N/A |
|
| | | �� | |
| Weighted-average assumptions used to determine net periodic benefit cost for plan year: | | |
| Discount rate | 4.25 | % | 5.10 | % | 4.35 | % | 3.98 | % | 4.68 | % | 3.88 | % | 3.70 | % | 4.45 | % | 3.65 | % | |
Discount rate (a) | | 3.71 | % | 4.27 | % | 4.63 | % | 3.62 | % | 4.12 | % | 4.29 | % | 3.60 | % | 3.84 | % | 4.03 | % |
Expected long-term rate of return on assets (a)(b) | 6.75 | % | 6.75 | % | 7.25 | % | N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| 6.25 | % | 6.75 | % | 6.75 | % | N/A |
| N/A |
| N/A |
| 3.93 | % | N/A |
| N/A |
|
| Rate of increase in compensation levels | 3.86 | % | 3.86 | % | 3.91 | % | N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| 3.43 | % | 3.47 | % | 3.57 | % | N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| N/A |
|
_____________________________
| |
| (a) | The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs. |
| |
| (b) | The expected rate of return on plan assets is 6.75%6.00% for the calculation of the 20162019 net periodic pension cost. |
The healthcare benefit obligation was determined at December 31 as follows:
|
| | | | |
| | 2015 | 2014 |
| Healthcare trend rate pre-65 | | |
| Trend for next year | 6.35 | % | 7.50 | % |
| Ultimate trend rate | 4.50 | % | 4.50 | % |
| Year Ultimate Trend Reached | 2024 |
| 2027 |
|
| | | |
| Healthcare trend rate post-65 | | |
| Trend for next year | 5.20 | % | 6.25 | % |
| Ultimate trend rate | 4.50 | % | 4.50 | % |
| Year Ultimate Trend Reached | 2023 |
| 2024 |
|
|
| | | | |
| | 2018 | 2017 |
| Trend Rate - Medical | | |
| Pre-65 for next year | 6.70 | % | 7.00 | % |
| Pre-65 Ultimate trend rate | 4.50 | % | 4.50 | % |
| Trend Year | 2027 |
| 2027 |
|
| | | |
| Post-65 for next year | 4.94 | % | 5.00 | % |
| Post-65 Ultimate trend rate | 4.50 | % | 4.50 | % |
| Trend Year | 2026 |
| 2026 |
|
We do not pre-fund our post-retirement benefit plan. The table below shows the estimated impacts of an increase or decrease to our healthcare trend rate for our Retiree Health Care Plan (in thousands):
|
| | | | | | |
| Change in Assumed Trend Rate | Service and Interest Costs | Accumulated Periodic Postretirement Benefit Obligation |
| 1% increase | $ | 10 |
| $ | 221 |
|
| 1% decrease | $ | (1 | ) | $ | (205 | ) |
Beginning in 2016, the company will changewe changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. 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. Previously, those costs were determined using a single weighted-average discount rate. 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 new method provides 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. See "Pension“Pension and Postretirement Benefit Obligations"Obligations” within our Critical Accounting Policies in Item 7 on this Form 10-K for additional details.
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
|
| | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| 2016 | $ | 3,492 |
| $ | 216 |
| $ | 619 |
|
| 2017 | $ | 3,594 |
| $ | 248 |
| $ | 618 |
|
| 2018 | $ | 3,677 |
| $ | 246 |
| $ | 613 |
|
| 2019 | $ | 3,814 |
| $ | 243 |
| $ | 607 |
|
| 2020 | $ | 3,911 |
| $ | 240 |
| $ | 621 |
|
| 2021-2025 | $ | 21,108 |
| $ | 1,583 |
| $ | 2,841 |
|
|
| | | | | | | | | |
| | Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-Pension Defined Benefit Postretirement Healthcare Plan |
| 2019 | $ | 3,660 |
| $ | 230 |
| $ | 466 |
|
| 2020 | $ | 3,774 |
| $ | 227 |
| $ | 534 |
|
| 2021 | $ | 3,924 |
| $ | 322 |
| $ | 566 |
|
| 2022 | $ | 4,031 |
| $ | 319 |
| $ | 577 |
|
| 2023 | $ | 4,102 |
| $ | 315 |
| $ | 554 |
|
| 2024-2028 | $ | 20,759 |
| $ | 1,274 |
| $ | 2,243 |
|
Defined Contribution Plan
The Parent sponsors a 401(k) retirement savings plan in which our employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. The plan provides for company matching contributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service.
(9) RELATED-PARTY TRANSACTIONS
Non-Cash Dividend to Parent
In 2015, weWe recorded a non-cash dividenddividends to our Parent for approximately $28.5of $36 million and decreased$42 million in 2018 and 2017 respectively, and changed the utility money poolUtility Money Pool note receivable, net for approximately $28.5 million. No amounts were recorded for 2014.by $36 million and $42 million in 2018 and 2017, respectively.
Receivables and Payables
We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands):
|
| | | | | | |
| | 2015 | 2014 |
| Receivable - affiliates | $ | 5,747 |
| $ | 5,350 |
|
| Accounts payable - affiliates | $ | 30,032 |
| $ | 19,242 |
|
|
| | | | | | |
| | 2018 | 2017 |
| Accounts receivable from affiliates | $ | 8,119 |
| $ | 5,664 |
|
| Accounts payable to affiliates | $ | 25,804 |
| $ | 25,653 |
|
Money Pool Notes Receivable and Notes Payable
We have aparticipate in the Utility Money Pool Agreement (the Agreement) with BHC, Cheyenne Light and Black Hills Utility Holdings.. Under the agreement,Agreement, we may borrow from BHCthe pool; however the Agreement restricts usthe pool from loaning funds to BHC or to any of BHCs’BHC’s non-utility subsidiaries. The Agreement does not restrict us from makingpaying dividends to BHC. Borrowings under the agreementAgreement bear interest at the weighted average daily cost of our parent company’s credit facilityBHC’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one monthone-month LIBOR rate plus 1.0%.
The cost of borrowing under the Utility Money Pool was 1.45%3.06% at December 31, 2015.2018.
We had the following balances with the Utility Money Pool as of December 31 (in thousands):
|
| | | | | | |
| | 2015 | 2014 |
| Notes receivable (payable), net | $ | 76,813 |
| $ | 68,626 |
|
|
| | | | | | |
| | 2018 | 2017 |
| Money pool notes payable | $ | 38,690 |
| $ | 13,397 |
|
Net interestInterest income (expense) relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands):
|
| | | | | | | | | |
| | 2015 | 2014 | 2013 |
| Net interest income (expense) | $ | 1,153 |
| $ | 304 |
| $ | 505 |
|
|
| | | | | | | | | |
| | 2018 | 2017 | 2016 |
| Interest income (expense) | $ | (401 | ) | $ | 272 |
| $ | 1,047 |
|
Interest expense allocation from Parent
BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2018, 2017 and 2016, we were allocated $1.3 million, $1.4 million, and $1.9 million, respectively, of interest expense from BHC.
Other Balances and Transactions
We have the following Power Purchase, and Transmission Services , and Ground Lease Agreements with affiliated entities:
An agreement, expiring September 3, 2028, with Cheyenne LightWyoming Electric to acquire 15 MW of the facility output from Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028,, Cheyenne Light Wyoming Electric has agreed to sell up to 15 MW of the facility output from Happy Jack to us.
An agreement, expiring September 30, 2029, with Cheyenne LightWyoming Electric to acquire 20 MW of the facility output from Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029,, Cheyenne Light Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to us.
A Generation Dispatch Agreement with Cheyenne LightWyoming Electric that requires us to purchase all of Cheyenne Light’sWyoming Electric’s excess energy.
A Wygen III Ground Lease with WDRC expiring in 2050 with three automatic renewal terms of 20 years each.
Related-party Gas Transportation Service Agreement
On October 1, 2014, we entered into a gas transportation service agreement with Cheyenne LightWyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.
Related-party Revenue and Purchases
We had the following related partyrelated-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income:
| | | | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 |
| | (in thousands) | (in thousands) |
| Revenues: | | |
| Energy sold to Cheyenne Light | $ | 1,857 |
| $ | 1,894 |
| $ | 1,338 |
| $ | 2,064 |
| $ | 2,481 |
| $ | 2,440 |
|
| Rent from electric properties | $ | 4,772 |
| $ | 4,102 |
| $ | 3,627 |
| $ | 3,634 |
| $ | 3,680 |
| $ | 5,046 |
|
| Horizon Point shared facility revenue | | $ | 11,211 |
| $ | 1,420 |
| $ | — |
|
| | | |
| Purchases: | | |
| Purchase of coal from WRDC | $ | 16,401 |
| $ | 16,861 |
| $ | 18,542 |
| |
| Fuel and purchased power: | | |
| Purchases of coal from WRDC | | $ | 17,532 |
| $ | 15,948 |
| $ | 16,227 |
|
| Purchase of excess energy from Cheyenne Light | $ | 898 |
| $ | 3,033 |
| $ | 3,640 |
| $ | 511 |
| $ | 601 |
| $ | 252 |
|
| Purchase of renewable wind energy from Cheyenne Light - Happy Jack | $ | 1,578 |
| $ | 1,959 |
| $ | 1,886 |
| $ | 1,942 |
| $ | 1,924 |
| $ | 1,918 |
|
| Purchase of renewable wind energy from Cheyenne Light - Silver Sage | $ | 2,739 |
| $ | 3,200 |
| $ | 3,207 |
| $ | 3,586 |
| $ | 3,290 |
| $ | 3,300 |
|
| Corporate support services from Parent, Black Hills Service Company and Black Hills Utility Holdings | $ | 26,655 |
| $ | 32,332 |
| $ | 30,738 |
| |
| Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation | | $ | 364 |
| $ | 393 |
| $ | 399 |
|
Related-party Corporate Support
We had the following corporate support for the years ended December 31:
|
| | | | | | | | | |
| | 2018 | 2017 | 2016 |
| | (in thousands) |
| Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings | $ | 34,578 |
| $ | 27,869 |
| $ | 25,748 |
|
Horizon Point Agreement
We have a shared facility agreement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.
(10) SUPPLEMENTAL CASH FLOW INFORMATION
| | | Years ended December 31, | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 |
| | (in thousands) | (in thousands) |
| Non-cash investing and financing activities - | | |
| Property, plant and equipment acquired with accrued liabilities | $ | 3,870 |
| $ | 4,234 |
| $ | 13,590 |
| $ | 15,180 |
| $ | 6,565 |
| $ | 5,521 |
|
| Non-cash decrease to money pool note receivable, net | $ | (28,501 | ) | $ | — |
| $ | (8,000 | ) | $ | (36,000 | ) | $ | (42,000 | ) | $ | (52,500 | ) |
| Non-cash dividend to Parent company | $ | 28,501 |
| $ | — |
| $ | 8,000 |
| |
| Non-cash dividend to Parent | | $ | 36,000 |
| $ | 42,000 |
| $ | 52,500 |
|
| | | |
| Supplemental disclosure of cash flow information: | | |
| Cash (paid) refunded during the period for - | | |
| Interest (net of amounts capitalized) | $ | (21,913 | ) | $ | (19,573 | ) | $ | (19,174 | ) | $ | (21,988 | ) | $ | (21,517 | ) | $ | (21,320 | ) |
| Income taxes | $ | — |
| $ | — |
| $ | 219 |
| |
| Income taxes (paid) refunded | | $ | (10,394 | ) | $ | (12,719 | ) | $ | — |
|
(11) COMMITMENTS AND CONTINGENCIES
Power Purchase and Transmission Services Agreements
We have the following power purchase and transmission services agreements, not including related party agreements, as of December 31, 20152018 (see Note 9 for information on related party agreements):
A PPA with PacifiCorp, expiring on December 31, 2023,, which provides for the purchase by us of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants;
plants.
A firm point-to-point transmission accessservice agreement to deliver up to with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of power on PacifiCorp’s transmission systemcapacity and energy to wholesale customers in the western region through December 31, 2023; and
be transmitted annually by PacifiCorp.
An agreement with Thunder Creek for gas transport capacity, expiring in October 31, 2019.2019.
A PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.
Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):
| | | Contract | Contract Type | 2015 | 2014 | 2013 | Contract Type | 2018 | 2017 | 2016 |
| PacifiCorp | Electric capacity and energy | $ | 13,990 |
| $ | 13,943 |
| $ | 13,026 |
| Electric capacity and energy | $ | 13,681 |
| $ | 13,218 |
| $ | 12,221 |
|
| PacifiCorp | Transmission access | $ | 1,213 |
| $ | 1,227 |
| $ | 1,384 |
| Transmission access | $ | 1,742 |
| $ | 1,671 |
| $ | 1,428 |
|
| Thunder Creek | Gas transport capacity | $ | 633 |
| $ | 633 |
| $ | 633 |
| Gas transport capacity | $ | 633 |
| $ | 633 |
| $ | 633 |
|
| Platte River Power Authority | | Wind energy | $ | 223 |
| $ | — |
| $ | — |
|
Future Contractual Obligations
The following is a schedule of future minimum payments required under the power purchase, transmission services, land and facility and vehicleoperating leases, and gas supply agreements (in thousands):
| | | 2016 | $ | 12,827 |
| |
| 2017 | $ | 12,824 |
| |
| 2018 | $ | 6,513 |
| |
| 2019 | $ | 6,408 |
| $ | 8,050 |
|
| 2020 | $ | 5,880 |
| $ | 7,693 |
|
| 2021 | | $ | 7,059 |
|
| 2022 | | $ | 7,059 |
|
| 2023 | | $ | 7,056 |
|
| Thereafter | $ | 17,641 |
| $ | 21,947 |
|
Long-Term Power Sales Agreements
We have the following power sales agreements as of December 31, 2015:2018:
An agreement with MDU to supply up to a maximum of 25 MW on a cost reimbursement basis duringDuring periods of reduced production at Wygen III;III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.
AAn agreement to serve MDU capacity and energy agreement with MDU through December 31, 2023 to supply up to a maximum of 50 MW;MW in excess of Wygen III ownership. This agreement expires December 31, 2023.
An agreement with the City of Gillette to supply its first 23 MW on a cost reimbursement basis duringDuring periods of reduced production at Wygen III.III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, wewhich expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves;
A unit-contingent energy and capacity sales agreement with MEAN expiring on May 31, 2023. This contract is based on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The energy and capacity purchase requirements decrease over the term of the agreement; and
reserves.
A PPA with MEAN expiring May 31, 2023.2028. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.
Oil Creek FireAn agreement through December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.
On June 29, 2012,
Environmental Matters
We are subject to costs resulting from a forestnumber of federal, state and grassland fire occurredlocal laws and regulations which affect future planning and existing operations. They can result in the western Black Hills of Wyoming. On April 16, 2013, private landowners filed suit in the United States District Court for the District of Wyoming asserting that the fire was caused by Black Hills Power’s negligent maintenance of a transmission line. The Company denied these claims. These landowners sought recovery for reclamation and rehabilitation costs, damage to fencingincreased capital expenditures, operating and other personal property, alleged injury to timber, grass or hay, livestockcosts as a result of compliance, remediation and related operations, and diminished value of real estate. The State of Wyoming intervened in the lawsuit, asserting claims for fire suppression costs, and similar damage claims related to state-owned lands. As of December 31, 2015, we believed that a loss associated with settlement of pending claims was probable. Accordingly, we had recorded a loss contingency liability related to these claims and a receivable for costs we believed were reimbursable and probable of recovery under our insurance coverage. In consideration of the risk and uncertainty of litigation, the Company subsequently concluded a settlement of all claims, with all partiesmonitoring obligations. Due to the litigation. On January 4, 2016,environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.
Solid Waste Disposal
Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the court entered its order dismissingimpoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the litigationstate providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.
In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with prejudice. The resolution of the State and private claims did not have a material effect upon our consolidated financial condition, results of operations or cash flows.state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.
For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K.
Legal Proceedings
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.
In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.
Environmental Matters
We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.
Air
Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO2, NOx, mercury particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.
Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen III and Wyodak plants. Title IV of the Clean Air Act created an SO2 allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2045.
The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule, 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 Ben French, Osage and Neil Simpson I on March 21, 2014. The net book value of these plants was allowed regulatory accounting treatment and is recorded as a Regulatory Asset on the accompanying Balance Sheets.
Solid Waste Disposal
Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years.
In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years.
(12) QUARTERLY HISTORICAL DATA (Unaudited)
We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter (in thousands):
| | | | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter |
| 2015 | | |
| Operating revenues | $ | 70,283 |
| $ | 68,038 |
| $ | 72,111 |
| $ | 67,432 |
| |
| 2018 | | |
| Revenues | | $ | 73,815 |
| $ | 70,676 |
| $ | 78,067 |
| $ | 75,522 |
|
| Operating income | $ | 21,490 |
| $ | 21,143 |
| $ | 23,456 |
| $ | 21,825 |
| $ | 20,364 |
| $ | 19,495 |
| $ | 21,428 |
| $ | 17,048 |
|
| Net income | $ | 10,403 |
| $ | 10,547 |
| $ | 12,287 |
| $ | 11,937 |
| $ | 11,760 |
| $ | 11,125 |
| $ | 13,317 |
| $ | 9,443 |
|
| | | |
| 2014 | | |
| Operating revenues | $ | 71,267 |
| $ | 60,741 |
| $ | 67,729 |
| $ | 68,751 |
| |
| 2017 | | |
| Revenues | | $ | 73,794 |
| $ | 66,053 |
| $ | 73,938 |
| $ | 74,648 |
|
| Operating income | $ | 17,546 |
| $ | 13,782 |
| $ | 19,007 |
| $ | 18,779 |
| $ | 23,376 |
| $ | 17,712 |
| $ | 23,698 |
| $ | 19,040 |
|
| Net income | $ | 8,643 |
| $ | 6,230 |
| $ | 9,916 |
| $ | 8,773 |
| $ | 12,570 |
| $ | 9,287 |
| $ | 13,826 |
| $ | 15,615 |
|
In 2018, we recorded $0.9 million of income tax expense associated with changes in the prior estimated impact of tax reform on deferred income taxes compared to a net tax benefit of $6.0 million in 2017 as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA.
| |
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND |
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2015.2018. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2018, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
|
|
Management’s Report on Internal Control over Financial Reporting is presented on Page 2526 of this Annual Report on Form 10-K. |
During our fourth fiscal quarter, there have been no changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table sets forth the aggregate fees accrued for services provided to us for the fiscal years ended December 31 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):
| | | Deloitte & Touche LLP | 2015 | 2014 | 2018 | 2017 |
| Audit Fees | $ | 360 |
| $ | 337 |
| $ | 592 |
| $ | 407 |
|
| Tax Fees | 16 |
| 7 |
| 195 |
| 31 |
|
| Audit-related fees | — |
| — |
| |
| Total | $ | 376 |
| $ | 344 |
| $ | 787 |
| $ | 438 |
|
Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.
Tax Fees. Fees for services related to tax compliance, tax planning and advice including tax assistance with tax audits. These services include assistance regarding federal tax compliance and advice, review of tax returns, and federal tax planning.
Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit Fees.” These services may include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.
The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit Committee’s pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establishes pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.
|
| |
| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
|
| | |
| (a) | 1. | Financial Statements |
| | | |
| | | Financial statements required by Item 15 are listed in the index included in Item 8 of Part II. |
| | | |
| | 2. | Schedules |
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2015, 20142018, 2017 and 20132016
|
| | |
| | | All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K. |
SCHEDULE II
|
| | | | | | | | | | | | |
BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, |
| |
| Description | Balance at beginning of year | Additions charged to costs and expenses | Deductions charged to costs and expenses | Balance at end of year |
| | (in thousands) |
| Allowance for doubtful accounts: | | | | |
| 2015 | $ | 261 |
| $ | 602 |
| $ | (656 | ) | $ | 207 |
|
| 2014 | $ | 220 |
| $ | 699 |
| $ | (658 | ) | $ | 261 |
|
| 2013 | $ | 102 |
| $ | 754 |
| $ | (636 | ) | $ | 220 |
|
|
| |
| Exhibit Number | Description |
| | |
| 3.1* | |
| | |
| 3.2* | Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000). |
| |
3.3* | |
| | |
| 4.1* | |
| |
| |
| |
| | |
| 10.1* | |
| | |
| 10.2* | |
| |
10.3* | Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 2, 2014). |
| | |
| 31.1 | |
| | |
| 31.2 | |
| | |
| 32.1 | |
| | |
| 32.2 | |
| | |
| 101 | Financials for XBRL Format |
_________________________
| |
| * | Previously filed as part of the filing indicated and incorporated by reference herein. |
| |
(a) | See (a) 3. Exhibits above. |
| |
(b) | See (a) 2. Schedules above. |
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.
The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.
| |
| ITEM 16. | FORM 10-K SUMMARY |
57None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | | |
| | | BLACK HILLS POWER, INC. |
| | | |
| | | By | /s/ DAVIDLINDEN R. EMERYEVANS |
| | | DavidLinden R. Emery,Evans, Chairman, President and Chief Executive Officer |
| | | Chief Executive Officer |
| Dated: | February 26, 201620, 2019 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
|
| | |
/s/ DAVIDLINDEN R. EMERYEVANS | Director and | February 26, 201620, 2019 |
DavidLinden R. Emery,Evans, Chairman, President and | Principal Executive Officer | |
| Chief Executive Officer | | |
| | | |
| /s/ RICHARD W. KINZLEY | Director and | February 26, 201620, 2019 |
| Richard W. Kinzley, Senior Vice President | Principal Financial and | |
| and Chief Financial Officer | Accounting Officer | |
| | | |
/s/ LINDEN R. EVANSBRIAN G. IVERSON | Director | February 26, 201620, 2019 |
Linden R. Evans | | |
| | |
/s/ STEVEN J. HELMERS | Director | February 26, 2016 |
Steven J. HelmersBrian G. Iverson | | |
INDEX TO EXHIBITS
|
| |
Exhibit Number | Description |
| |
3.1* | Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)). |
| |
3.2* | Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000). |
| |
3.3* | Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999). |
| |
4.1* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc., and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014). |
| |
10.1* | Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.2* | Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.3* | Bond Purchase Agreement dated as of June 30, 2014 by and among Black Hills Power, Inc., New York Life Insurance Company, New York Life Insurance and Annuity Corporation, Teachers Insurance and Annuity Association of America, John Hancock Life Insurance Company (U.S.A.), John Hancock Life & Health Insurance Company, John Hancock Life Insurance Company of New York and United of Omaha Life Insurance Company (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on July 2, 2014). |
| |
31.1 | Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
31.2 | Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
101 | Financial Statements for XBRL Format |
_________________________
| |
* | Previously filed as part of the filing indicated and incorporated by reference herein. |