0000066756 ale:PointinTimeMember ale:U.S.WaterServicesMember 2017-01-01 2017-12-31
United States
Securities and Exchange Commission
Washington, D.C. 20549
|
| | |
| (Mark One) | |
| | T☒ | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the year ended December 31, 2019
|
| | For the fiscal year ended December 31, 2017
|
| | | |
| £☐ | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
| | | For the transition period from ______________ to ______________ |
Commission File Number 1-3548
ALLETE, Inc.
(Exact name of registrant as specified in its charter) |
| | |
| Minnesota | | 41-0418150 |
| (State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
30 West Superior Street, Duluth, Minnesota55802-2093
(Address of principal executive offices, including zip code)
(218) (218) 279-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
|
| | |
| Title of each class | Trading Symbol | Name of each exchange on which registered |
| Common Stock, without par value | ALE | New York Stock Exchange |
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. Yesx☒ 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 ¨☐Nox☒
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. Yesx☒ 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx☒ 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. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): |
| | |
Large Accelerated Filer x
| Accelerated Filer ¨
| Non-Accelerated Filer ¨
|
| Smaller Reporting Company ¨
| Emerging Growth Company ¨
|
Large Accelerated Filer☒Accelerated Filer ☐Non-Accelerated Filer ☐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☒
The aggregate market value of voting stock held by nonaffiliates on June 30, 201728, 2019, was $3,637,956,646.$4,285,299,935.
As of February 1, 20182020, there were 51,143,65651,696,497 shares of ALLETE Common Stock, without par value, outstanding.
Documents Incorporated By Reference
Portions of the Proxy Statement for the 20182020 Annual Meeting of Shareholders are incorporated by reference in Part III.
Index
Index (Continued)
Definitions
The following abbreviations or acronyms are used in the text. References in this report to “we,” “us” and “our” are to ALLETE, Inc. and its subsidiaries, collectively.
|
| |
| Abbreviation or Acronym | Term |
| AFUDC | Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods |
| ALLETE | ALLETE, Inc. |
| ALLETE Clean Energy | ALLETE Clean Energy, Inc. and its subsidiaries |
| ALLETE Properties | ALLETE Properties, LLC and its subsidiaries |
| ALLETE South Wind | ALLETE South Wind, LLC |
| ALLETE Transmission Holdings | ALLETE Transmission Holdings, Inc. |
| ArcelorMittal | ArcelorMittal USA, Inc. |
ASC | Accounting Standards Codification |
| ATC | American Transmission Company LLC |
| Basin | Basin Electric Power Cooperative |
| Bison | Bison Wind Energy Center |
| BNI Energy | BNI Energy, Inc. and its subsidiary |
| Boswell | Boswell Energy Center |
| Camp Ripley | Camp Ripley Solar Array |
| CIP | Conservation Improvement Program |
| Cliffs | Cleveland-Cliffs Inc. |
CO2
| Carbon Dioxide |
| Company | ALLETE, Inc. and its subsidiaries |
| DC | Direct Current |
| EIS | Environmental Impact Statement |
EITE | Energy-Intensive Trade-Exposed |
| EPA | United States Environmental Protection Agency |
ERP Iron Ore | ERP Iron Ore, LLC |
| ESOP | Employee Stock Ownership Plan |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| Form 8-K | ALLETE Current Report on Form 8-K |
| Form 10-K | ALLETE Annual Report on Form 10-K |
| Form 10-Q | ALLETE Quarterly Report on Form 10-Q |
| GAAP | Generally Accepted Accounting Principles in the United States of America |
| GHG | Greenhouse Gases |
| GNTL | Great Northern Transmission Line |
| Invest Direct | ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan |
| IRP | Integrated Resource Plan |
| Item ___ | Item ___ of this Form 10-K |
| kV | Kilovolt(s) |
| kW / kWh | Kilowatt(s) / Kilowatt-hour(s) |
| Laskin | Laskin Energy Center |
LIBOR | London Interbank Offered Rate |
Magnetation | Magnetation, LLC |
| Manitoba Hydro | Manitoba Hydro-Electric Board |
| MBtu | Million British thermal units |
Definitions (continued)
|
| |
Abbreviation or Acronym | Term |
Mesabi Metallics | Mesabi Metallics Company, LLC |
| Minnesota Power | An operating division of ALLETE, Inc. |
| Minnkota Power | Minnkota Power Cooperative, Inc. |
| MISO | Midcontinent Independent System Operator, Inc. |
| Montana-Dakota Utilities | Montana-Dakota Utilities Co., a divisionsubsidiary of MDU Resources Group, Inc. |
| Moody’s | Moody’s Investors Service, Inc. |
Definitions (continued)
|
| |
| Abbreviation or Acronym | Term |
| MPCA | Minnesota Pollution Control Agency |
| MPUC | Minnesota Public Utilities Commission |
| MW / MWh | Megawatt(s) / Megawatt-hour(s) |
| NDPSC | North Dakota Public Service Commission |
| NERC | North American Electric Reliability Corporation |
| Nobles 2 | Nobles 2 Power Partners, LLC |
| NOL | Net Operating Loss |
NO2 | Nitrogen Dioxide |
NOX
| Nitrogen Oxides |
| Northern States Power | Northern States Power Company, a subsidiary of Xcel Energy Inc. |
| Northshore Mining | Northshore Mining Company, a wholly-owned subsidiary of Cliffs |
| Note ___ | Note ___ to the consolidated financial statements in this Form 10-K |
| NTEC | Nemadji Trail Energy Center |
| NYSE | New York Stock Exchange |
| Oliver Wind I | Oliver Wind I Energy Center |
| Oliver Wind II | Oliver Wind II Energy Center |
| Palm Coast Park District | Palm Coast Park Community Development District in Florida |
| PolyMet | PolyMet Mining Corp. |
| PPA / PSA | Power Purchase Agreement / Power Sales Agreement |
| PPACA | Patient Protection and Affordable Care Act of 2010 |
| PSCW | Public Service Commission of Wisconsin |
| RSOP | Retirement Savings and Stock Ownership Plan |
| SEC | Securities and Exchange Commission |
Shell EnergyS&P | Shell Energy North America (US), L.P.S&P Global Ratings |
| Silver Bay Power | Silver Bay Power Company, a wholly-owned subsidiary of Cliffs |
SO2 | Sulfur Dioxide |
| Square Butte | Square Butte Electric Cooperative, a North Dakota cooperative corporation |
Standard & Poor’s | S&P Global Ratings |
| SWL&P | Superior Water, Light and Power Company |
| Taconite Harbor | Taconite Harbor Energy Center |
| Taconite Ridge | Taconite Ridge Energy Center |
| Tenaska | Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC |
Thomson | Thomson Energy Center |
| TCJA | Tax Cuts and Jobs Act of 2017 (Public Law 115-97) |
| Tonka Water | Tonka Equipment Company |
| Town Center District | Town Center at Palm Coast Community Development District in Florida |
TransAlta | TransAlta Energy Marketing (U.S.) Inc. |
| United Taconite | United Taconite LLC, a wholly-owned subsidiary of Cliffs |
| UPM Blandin | UPM, Blandin paper mill owned by UPM-Kymmene Corporation |
| U.S. | United States of America |
| U.S. Water Services | U.S. Water Services, Holding CompanyInc. and its subsidiaries |
| USS Corporation | United States Steel Corporation |
| WTG | Wind Turbine Generator |
Forward-Looking Statements
Statements in this report that are not statements of historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there can be no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies (often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” ��intends,“intends,” “plans,” “projects,” “likely,” “will continue,” “could,” “may,” “potential,” “target,” “outlook” or words of similar meaning) are not statements of historical facts and may be forward-looking.
In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of ALLETE in this Form 10-K, in presentations, on our website, in response to questions or otherwise. These statements are qualified in their entirety by reference to, and are accompanied by, the following important factors, in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements:
our ability to successfully implement our strategic objectives;
global and domestic economic conditions affecting us or our customers;
changes in and compliance with laws and regulations;
changes in tax rates or policies or in rates of inflation;
the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;
weather conditions, natural disasters and pandemic diseases;
our ability to access capital markets, bank financing and bank financing;other financing sources;
changes in interest rates and the performance of the financial markets;
project delays or changes in project costs;
changes in operating expenses and capital expenditures and our ability to raise revenues from our customers in regulated rates or sales price increases at our Energy Infrastructure and Related Services businesses;customers;
the impacts of commodity prices on ALLETE and our customers;
our ability to attract and retain qualified, skilled and experienced personnel;
effects of emerging technology;
war, acts of terrorism and cyberattacks;cybersecurity attacks;
our ability to manage expansion and integrate acquisitions;
population growth rates and demographic patterns;
wholesale power market conditions;
federal and state regulatory and legislative actions that impact regulated utility economics, including our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities and utility infrastructure, recovery of purchased power, capital investments and other expenses, including present or prospective environmental matters;
effects of competition, including competition for retail and wholesale customers;
effects of restructuring initiatives in the electric industry;
the impacts on our Regulated Operations segmentbusinesses of climate change and future regulation to restrict the emissions of GHG;
effects of increased deployment of distributed low-carbon electricity generation resources;
the impacts of laws and regulations related to renewable and distributed generation;
pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;
our current and potential industrial and municipal customers’ ability to execute announced expansion plans;
real estate market conditions where our legacy Florida real estate investment is located may not improve; and
the success of efforts to realize value from, invest in, and develop new opportunities in, our Energy Infrastructure and Related Services businesses; andopportunities.
factors affecting our Energy Infrastructure and Related Services businesses, including fluctuations in the volume of customer orders, unanticipated cost increases, changes in legislation and regulations impacting the industries in which the customers served operate, the effects of weather, creditworthiness of customers, ability to obtain materials required to perform services, and changing market conditions.
Forward Looking Statements (Continued)
Additional disclosures regarding factors that could cause our results or performance to differ from those anticipated by this report are discussed in Part 1, Item 1A under the heading “Risk Factors” of this Form 10-K. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward‑looking statement to reflect events or circumstances after the date on which that 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 these factors, nor can it assess the impact of each of these factors on the businesses of ALLETE 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. Readers are urged to carefully review and consider the various disclosures made by ALLETE in this Form 10-K and in other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect ALLETE’s business.
Part I
Item 1. Business
Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 145,000 retail customers. Minnesota Power also has 1615 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 4. Regulatory Matters.)
ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in fourfive states, approximately 535660 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 380 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.
U.S. Water Services providesprovided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. On March 26, 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.
Corporate and Otheris comprised of BNI Energy, our coal mining operations in North Dakota, our investment in Nobles 2, a 49 percent equity interest in the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota, ALLETE Properties, our legacy Florida real estate investment, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,0004,000 acres of land in Minnesota, and earnings on cash and investments.
ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2017,2019, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.
| | | Year Ended December 31 | 2017 |
| 2016 |
| 2015 (a) |
| 2019 |
| 2018 |
| 2017 |
|
| | | |
Consolidated Operating Revenue – Millions |
| $1,419.3 |
|
| $1,339.7 |
|
| $1,486.4 |
|
| $1,240.5 |
|
| $1,498.6 |
|
| $1,419.3 |
|
| | | |
| Percentage of Consolidated Operating Revenue | | |
| Regulated Operations | 75 | % | 75 | % | 67 | % | 84 | % | 71 | % | 75 | % |
ALLETE Clean Energy | 6 | % | 6 | % | 18 | % | 5 | % | 11 | % | 6 | % |
U.S. Water Services | 11 | % | 10 | % | 8 | % | 3 | % | 11 | % | 11 | % |
| Corporate and Other | 8 | % | 9 | % | 7 | % | 8 | % | 7 | % | 8 | % |
| | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
| |
| (a) | Includes the construction and sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities for $197.7$81.1 million in 2015.2018. |
| |
| (b) | ALLETE sold U.S. Water Services in the first quarter of 2019. |
For a detailed discussion of results of operations and trends, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. For business segment information, see Note 1. Operations and Significant Accounting Policies and Note 17.14. Business Segments.
REGULATED OPERATIONS
Electric Sales / Customers
| | | Regulated Utility Kilowatt-hours Sold | | | | | | | | | | | | |
| Year Ended December 31 | 2017 |
| % | 2016 |
| % | 2015 |
| % | 2019 |
| % | 2018 |
| % | 2017 |
| % |
| Millions | | | | | | | | | | | | |
| Retail and Municipal | | | | | | | | | | | | |
| Residential | 1,096 |
| 7 | 1,102 |
| 8 | 1,113 |
| 8 | 1,130 |
| 8 | 1,140 |
| 8 | 1,096 |
| 7 |
| Commercial | 1,420 |
| 10 | 1,442 |
| 10 | 1,462 |
| 10 | 1,390 |
| 10 | 1,426 |
| 10 | 1,420 |
| 10 |
| Industrial | 7,327 |
| 50 | 6,456 |
| 45 | 6,635 |
| 46 | 7,277 |
| 54 | 7,261 |
| 50 | 7,327 |
| 50 |
| Municipal | 799 |
| 5 | 816 |
| 6 | 833 |
| 6 | 672 |
| 5 | 798 |
| 5 | 799 |
| 5 |
| Total Retail and Municipal | 10,642 |
| 72 | 9,816 |
| 69 | 10,043 |
| 70 | 10,469 |
| 77 | 10,625 |
| 73 | 10,642 |
| 72 |
| Other Power Suppliers | 4,039 |
| 28 | 4,316 |
| 31 | 4,310 |
| 30 | 3,185 |
| 23 | 3,953 |
| 27 | 4,039 |
| 28 |
| Total Regulated Utility Kilowatt-hours Sold | 14,681 |
| 100 | 14,132 |
| 100 | 14,353 |
| 100 | 13,654 |
| 100 | 14,578 |
| 100 | 14,681 |
| 100 |
Industrial Customers. In 20172019, industrial customers represented 5054 percent of total regulated utility kWh sales. Our industrial customers are primarily in the taconite mining, iron concentrate, paper, pulp and secondary wood products, and pipeline industries.
| | | Industrial Customer Kilowatt-hours Sold | | | | | | | | | | | | |
| Year Ended December 31 | 2017 |
| % | 2016 |
| % | 2015 |
| % | 2019 |
| % | 2018 |
| % | 2017 |
| % |
| Millions | | | | | | | | | | | | |
| Taconite/Iron Concentrate | 4,930 |
| 67 | 3,906 |
| 61 | 4,000 |
| 60 | |
| Taconite | | 5,039 |
| 69 | 5,039 |
| 69 | 4,930 |
| 67 |
| Paper, Pulp and Secondary Wood Products | 1,104 |
| 15 | 1,303 |
| 20 | 1,456 |
| 22 | 1,014 |
| 14 | 987 |
| 14 | 1,104 |
| 15 |
| Pipelines and Other Industrial | 1,293 |
| 18 | 1,247 |
| 19 | 1,179 |
| 18 | 1,224 |
| 17 | 1,235 |
| 17 | 1,293 |
| 18 |
| Total Industrial Customer Kilowatt-hours Sold | 7,327 |
| 100 | 6,456 |
| 100 | 6,635 |
| 100 | 7,277 |
| 100 | 7,261 |
| 100 | 7,327 |
| 100 |
Six taconite facilities served by Minnesota Power made up approximately 7080 percent of 20162018 iron ore pellet production in the U.S. according to data from the Minnesota Department of Revenue 20172019 Mining Tax Guide. Sales to taconite customers and iron concentrate customers represented 4,9305,039 million kWh, or 6769 percent of total industrial customer kWh sales in 2017.2019. Taconite, an iron-bearingiron‑bearing rock of relatively low iron content, is abundantly available in northern Minnesota and an important domestic source of raw material for the steel industry. Taconite processing plants use large quantities of electric power to grind the iron-bearing rock, and agglomerate and pelletize the iron particles into taconite pellets. Iron concentrate reclamation facilities also use large quantities of electricity to extract and process iron-bearing tailings left from previous mining operations to produce iron ore concentrate.
Minnesota Power’s taconite customers are capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five10 percent of Minnesota taconite production has been exported outside of North America. Minnesota Power also provides electric service to three iron concentrate facilities capable of producing up to approximately 4 million tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets. These iron concentrate facilities are owned in whole, or in part, by ERP Iron Ore and are currently idled. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)
There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 7480 percent of capacity in 2017 (712019 (78 percent in 20162018 and 74 percent in 2015)2017). The World Steel Association, an association of over 160 steel producers, national and regional steel industry associations, and steel research institutes representing approximately 85 percent of world steel production, projected U.S. steel consumption in 20182020 will increase by approximately 1one percent compared to 2017.2019.
REGULATED OPERATIONS (Continued)
Industrial Customers (Continued)
The following table reflects Minnesota Power’s taconite customers’ production levels for the past ten years:
| | Minnesota Power Taconite Customer Production | | Year | | Tons (Millions) | | Tons (Millions) |
2017* | | 37 | |
| 2019* | | | 37 |
| 2018 | | | 39 |
| 2017 | | | 38 |
| 2016 | | 28 | | 28 |
| 2015 | | 31 | | 31 |
| 2014 | | 39 | | 39 |
| 2013 | | 37 | | 37 |
| 2012 | | 39 | | 39 |
| 2011 | | 39 | | 39 |
| 2010 | | 35 | | 35 |
| 2009 | | 17 | |
| 2008 | | 39 | |
| Source: Minnesota Department of Revenue 2017 Mining Tax Guide for years 2008 - 2016. | |
| Source: Minnesota Department of Revenue 2019 Mining Tax Guide for years 2010 - 2018. | | Source: Minnesota Department of Revenue 2019 Mining Tax Guide for years 2010 - 2018. |
* Preliminary data from the Minnesota Department of Revenue. |
Minnesota Power’s taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in Minnesota Power’s taconite customers’ production would impact our annual earnings per share by approximately $0.04, net of expected power marketing sales at current prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Minnesota Power proactively sells power in the wholesale power markets that is temporarily not required by industrial customers to optimize the value of its generating facilities. Long-term reductions in taconite production or a permanent shut down of a taconite customer may lead Minnesota Power to file a general rate case to recover lost revenue.
In addition to serving the taconite industry, Minnesota Power serves a number of customers in the paper, pulp and secondary wood products industry, which represented 1,1041,014 million kWh, or 1514 percent of total industrial customer kWh sales in 20172019. Minnesota Power also has agreements to provide steam for two of its paper and pulp customers for use in the customers’ operations. The four major paper and pulp mills we serve reported operating at or near, full capacitysimilar levels in 2017; however, the smaller of UPM Blandin’s two paper machines was closed in the fourth quarter of 2017. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.)2019 compared to 2018.
Large Power Customer Contracts. Minnesota Power has nineeight Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. The customers consist of six taconite facilities two iron concentrate reclamation facilities and four paper and pulp mills. Certain facilities have common ownership and are served under combined contracts.
Large Power Customer contracts require Minnesota Power to have a certain amount of generating capacity available. In turn, each Large Power Customer is required to pay a minimum monthly demand charge that covers the fixed costs associated with having this capacity available to serve the customer, including a return on common equity. Most contracts allow customers to establish the level of megawatts subject to a demand charge on a four-month basis and require that a portion of their megawatt needs be committed on a take-or-pay basis for at least a portion of the term of the agreement. In addition to the demand charge, each Large Power Customer is billed an energy charge for each kWh used that recovers the variable costs incurred in generating electricity. Five of the Large Power Customer contracts have interruptible service which provides a discounted demand rate in exchange for the ability to interrupt the customers during system emergencies. Minnesota Power also provides incremental production service for customer demand levels above the contractual take-or-pay levels. There is no demand charge for this service and energy is priced at an increment above Minnesota Power’s cost. Incremental production service is interruptible.
REGULATED OPERATIONS (Continued)
Large Power Customer Contracts (Continued)
All contracts with Large Power Customers continue past the contract termination date unless the required advance notice of cancellation has been given. The required advance notice of cancellation varies from two to four years. Such contracts minimize the impact on earnings that otherwise would result from significant reductions in kWh sales to such customers. Large Power Customers are required to take all of their purchased electric service requirements from Minnesota Power for the duration of their contracts. The rates and corresponding revenue associated with capacity and energy provided under these contracts are subject to change through the same regulatory process governing all retail electric rates. (See Item 1. Business – Regulated Operations – Regulatory Matters – Electric Rates.Rates.)
Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customer’s energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite‑producing Large Power Customers have generally predictable energy usage on a week-to-week basis and any differences that occur are trued-up the following month.
Contract Status for Minnesota Power Large Power Customers
As of February 1, 2018December 31, 2019
|
| | | | |
| Customer | Industry | Location | Ownership | Earliest Termination Date |
| ArcelorMittal – Minorca Mine | Taconite | Virginia, MN | ArcelorMittal S.A. | December 31, 2025 |
Hibbing Taconite Co. (a) | Taconite | Hibbing, MN | 62.3% ArcelorMittal S.A. 23.0% Cliffs 14.7% USS Corporation | February 28, 2022December 31, 2023 |
| United Taconite and Northshore Mining | Taconite | Eveleth, MN and Babbitt, MN | Cliffs | December 31, 2026 |
USS Corporation (USS – Minnesota Ore) (a)(b) | Taconite | Mt. Iron, MN and Keewatin, MN | USS Corporation | February 28, 2022December 31, 2023 |
Magnetation (c)
| Iron Concentrate | Coleraine, MN and Bovey, MN | ERP Iron Ore | December 31, 2025 |
| Boise, Inc.(a) | Paper | International Falls, MN | Packaging Corporation of America | December 31, 2023 |
UPM Blandin(a)(d) | Paper | Grand Rapids, MN | UPM-Kymmene Corporation | February 28, 2022December 31, 2029 |
NewPage CorporationVerso Duluth Mill | Paper and Pulp | Duluth, MN | Verso Corporation | December 31, 20222024 |
Sappi Cloquet LLC (a) | Paper and Pulp | Cloquet, MN | Sappi Limited | February 28, 2022December 31, 2023 |
| |
| (a) | The contract will terminate four years from the date of written notice from either Minnesota Power or the customer. No notice of contract cancellation has been given by either party. Thus, the earliest date of cancellation is February 28, 2022.December 31, 2023. |
| |
| (b) | USS Corporation owns both the Minntac Plant in Mountain Iron, MN, and the Keewatin Taconite Plant in Keewatin, MN. |
| |
(c) | On January 30, 2017, ERP Iron Ore, LLC purchased substantially all of Magnetation’s assets pursuant to an asset purchase agreement approved by the U.S. Bankruptcy Court for the District of Minnesota. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.) |
| |
(d) | The smaller of UPM Blandin’s two paper machines was closed in the fourth quarter of 2017. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.) |
Residential and Commercial Customers. In 2017,2019, residential and commercial customers represented 1718 percent of total regulated utility kWh sales.
Municipal Customers. In 20172019, municipal customers represented 5five percent of total regulated utility kWh sales. All of the municipal contracts include a termination clause requiring a three-year notice to terminate.
REGULATED OPERATIONS (Continued)
Municipal Customers (Continued)
Minnesota Power’s wholesale electric contractcontracts with the Nashwauk Public Utilities Commission is15 non-affiliated municipal customers in Minnesota have termination dates ranging from 2024 through at least 2032, with a majority of contracts effective through at least December 31, 2032. No termination notice may be given for this2024. (See Note 4. Regulatory Matters.)
The contract prior to July 1, 2029. The wholesale electric service contracts with SWL&P and another municipal customer are effective through at least February 28, 2021, and throughexpired on June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided a contract termination notice in June 2016.2019. Minnesota Power currently provideshistorically provided approximately 29 MW of average monthly demand to this customer. The rates included in these three contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.
Minnesota Power’s wholesale electric contracts with 14 municipal customers are effective through at least December 31, 2024. No termination notices may be given prior to three years before maturity. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will be determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.
REGULATED OPERATIONS (Continued)
Other Power Suppliers. The Company also enters into off-system sales with Other Power Suppliers. These sales are at market‑based prices into the MISO market on a daily basis or through bilateral agreements of various durations.
Our PSAs are detailed in Note 9. Commitments, Guarantees and Contingencies, with additional disclosure provided in the following paragraphs.
Basin PSA.PSAs. Minnesota Power has an agreement to sell 100 MW of capacity and energy to Basin for a ten-year period which expires in April 2020. The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on the cost of fuel. The agreement also allows Minnesota Power to recover a pro rata share of increased costs related to emissions that occur during the last five years of the contract. Minnesota Power has antwo additional agreementagreements to sell 100 MW of capacity to Basin at fixed rates for a two-year period that began in June 2016.prices. (See Note 9. Commitments, Guarantees and Contingencies.)
Minnkota Power PSA. Minnesota Power has a PSA with Minnkota Power where Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold approximately 28 percent to Minnkota Power in 20172019 (28 percent in 20162018 and in 2015)2017). (See Note 11. Commitments, Guarantees and Contingencies.Power Supply – Long-Term Purchased Power.)
Silver Bay Power PSA. In 2016, Minnesota Power and Silver Bay Power entered into a long-term PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which hashad previously been served predominately through self-generation by Silver Bay Power. In the yearsStarting in 2016, through 2019, Minnesota Power is supplyingsupplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power hashad the option to purchase additional energy from Minnesota Power as it transitionstransitioned away from self-generation. On December 31,In the third quarter of 2019, Silver Bay Power will ceaseceased self-generation and Minnesota Power will supplybegan supplying the full energy requirements for Silver Bay Power.
Seasonality
The operations of our industrial customers, which make up a large portion of our electric sales, are not typically subject to significant seasonal variations. (See Electric Sales / Customers.) As a result, Minnesota Power is generally not subject to significant seasonal fluctuations in electric sales; however, Minnesota Power and SWL&P electric and natural gas sales to other customers may be affected by seasonal differences in weather. In general, peak electric sales occur in the winter and summer months with fewer electric sales in the spring and fall months. Peak sales of natural gas generally occur in the winter months. Additionally, our regulated utilities have historically generated fewer sales and less revenue when weather conditions are milder in the winter and summer.
Power Supply
In order to meet its customers’ electric requirements, Minnesota Power utilizes a mix of its own generation and purchased power. As of December 31, 2017,2019, Minnesota Power’s generating capability is primarily coal-fired, but also includes wind energy, hydroelectric, natural gas-fired, and biomass co-fired generation, hydroelectric generation, wind energy generation and solar generation. In 2017, Minnesota Power had record hydroelectric and wind energy generation. Purchased power primarily consists of long-term coal, wind and hydro PPAs as well as market purchases. The following table reflects Minnesota Power’s generating capabilities as of December 31, 2017,2019, and total electrical supply for 2017.2019. Minnesota Power had an annual net peak load of 1,5991,573 MW on December 27, 2017.November 11, 2019.
REGULATED OPERATIONS (Continued)
Power Supply (Continued)
|
| | | | | | | | |
| | | | | | Year Ended |
| | Unit | Year | Net | | December 31, 2019 |
| Regulated Utility Power Supply | No. | Installed | Capability | | Generation and Purchases |
| | | | MW | | MWh | % |
| Coal-Fired | | | | | | |
Boswell Energy Center (a) | 3 | 1973 | 355 |
| | | |
| in Cohasset, MN | 4 | 1980 | 468 |
| (b) | | |
| | | | 823 |
| | 4,160,011 |
| 29.6 |
| Taconite Harbor Energy Center | 1 | 1957 | 75 |
| | | |
| in Schroeder, MN | 2 | 1957 | 75 |
| | | |
| | | | 150 |
| (c) | — |
| — |
| Total Coal-Fired | | | 973 |
| | 4,160,011 |
| 29.6 |
| Biomass Co-Fired / Natural Gas | | | | | | |
| Hibbard Renewable Energy Center in Duluth, MN | 3 & 4 | 1949, 1951 | 62 |
| | 21,846 |
| 0.2 |
| Laskin Energy Center in Hoyt Lakes, MN | 1 & 2 | 1953 | 110 |
| | 19,454 |
| 0.1 |
| Total Biomass Co-Fired / Natural Gas | | | 172 |
| | 41,300 |
| 0.3 |
Hydro (d) | | | | | | |
| Group consisting of ten stations in MN | Multiple | Multiple | 120 |
| | 643,771 |
| 4.6 |
Wind (e) | | | | | | |
| Taconite Ridge Energy Center in Mt. Iron, MN | Multiple | 2008 | 25 |
| | 46,808 |
| 0.3 |
| Bison Wind Energy Center in Oliver and Morton Counties, ND | Multiple | 2010-2014 | 497 |
| | 1,571,045 |
| 11.2 |
| Total Wind | | | 522 |
| | 1,617,853 |
| 11.5 |
| Solar | | | | | | |
| Camp Ripley Solar Array near Little Falls, MN | Multiple | 2016 | 10 |
| | 14,069 |
| 0.1 |
| Total Generation | | | 1,797 |
| | 6,477,004 |
| 46.1 |
| | | | | | | |
| Long-Term Purchased Power | | | | | | |
Lignite Coal - Square Butte near Center, ND (f) | | | | | 1,435,546 |
| 10.2 |
| Wind - Oliver County, ND | | | | | 293,761 |
| 2.1 |
| Hydro - Manitoba Hydro in Manitoba, Canada | | | | | 331,019 |
| 2.3 |
| Total Long-Term Purchased Power | | |
|
| | 2,060,326 |
| 14.6 |
Other Purchased Power (g) | | | | | 5,521,456 |
| 39.3 |
| Total Purchased Power | | |
|
| | 7,581,782 |
| 53.9 |
| Total Regulated Utility Power Supply | | | 1,797 |
| | 14,058,786 |
| 100.0 |
|
| | | | | | | | |
| | | | | | Year Ended |
| | Unit | Year | Net | | December 31, 2017 |
| Regulated Utility Power Supply | No. | Installed | Capability | | Generation and Purchases |
| | | | MW | | MWh | % |
| Coal-Fired | | | | | | |
| Boswell Energy Center | 1 | 1958 | 67 |
| (a) | | |
| in Cohasset, MN | 2 | 1960 | 68 |
| (a) | | |
| | 3 | 1973 | 355 |
| | | |
| | 4 | 1980 | 468 |
| (b) | | |
| | | | 958 |
| | 6,286,858 |
| 41.4 |
| Taconite Harbor Energy Center | 1 | 1957 | 75 |
| | | |
| in Schroeder, MN | 2 | 1957 | 75 |
| | | |
| | | | 150 |
| (c) | — |
| — |
| Total Coal-Fired | | | 1,108 |
| | 6,286,858 |
| 41.4 |
| Biomass Co-Fired / Natural Gas | | | | | | |
| Hibbard Renewable Energy Center in Duluth, MN | 3 & 4 | 1949, 1951 | 62 |
| | 4,502 |
| — |
| Laskin Energy Center in Hoyt Lakes, MN | 1 & 2 | 1953 | 110 |
| | 5,615 |
| 0.1 |
| Total Biomass Co-Fired / Natural Gas | | | 172 |
| | 10,117 |
| 0.1 |
Hydro (d) | | | | | | |
| Group consisting of ten stations in MN | Multiple | Multiple | 120 |
| | 773,707 |
| 5.1 |
Wind (e) | | | | | | |
| Taconite Ridge Energy Center in Mt. Iron, MN | Multiple | 2008 | 25 |
| | 56,594 |
| 0.4 |
| Bison Wind Energy Center in Oliver and Morton Counties, ND | Multiple | 2010-2014 | 497 |
| | 1,775,474 |
| 11.7 |
| Total Wind | | | 522 |
| | 1,832,068 |
| 12.1 |
| Solar | | | | | | |
| Camp Ripley Solar Array near Little Falls, MN | Multiple | 2016 | 10 |
| | 17,129 |
| 0.1 |
| Total Generation | | | 1,932 |
| | 8,919,879 |
| 58.8 |
| | | | | | | |
| Long-Term Purchased Power | | | | | | |
Lignite Coal - Square Butte near Center, ND (f) | | | | | 1,739,781 |
| 11.5 |
| Wind - Oliver County, ND | | | | | 341,785 |
| 2.2 |
| Hydro - Manitoba Hydro in Manitoba, Canada | | | | | 305,532 |
| 2.0 |
| Total Long-Term Purchased Power | | |
|
| | 2,387,098 |
| 15.7 |
Other Purchased Power (g) | | | | | 3,867,865 |
| 25.5 |
| Total Purchased Power | | |
|
| | 6,254,963 |
| 41.2 |
| Total Regulated Utility Power Supply | | | 1,932 |
| | 15,174,842 |
| 100.0 |
| |
| (a) | In 2016, Minnesota Power announced thatretired Boswell Units 1 and 2 will be retired in the fourth quarter of 2018. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.) |
| |
| (b) | Boswell Unit 4 net capability shown above reflects Minnesota Power’s ownership percentage of 80 percent. WPPI Energy owns 20 percent of Boswell Unit 4. (See Note 3. Jointly-Owned Facilities and Projects.Assets.) |
| |
| (c) | Taconite Harbor Units 1 and 2 were idled in 2016. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.) |
| |
| (d) | Hydro consists of 10 stations with 34 generating units. |
| |
| (e) | Taconite Ridge consists of 10 WTGs and Bison consists of 165 WTGs. |
| |
| (f) | Minnesota Power has a PSA with Minnkota Power whereby Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power. (See Electric Sales / Customers.) |
| |
| (g) | Includes short-term market purchases in the MISO market and from Other Power Suppliers. |
REGULATED OPERATIONS (Continued)
Power Supply (Continued)
Fuel. Minnesota Power purchases low-sulfur, sub-bituminous coal from the Powder River Basin region located in Montana and Wyoming. Coal consumption in 20172019 for electric generation at Minnesota Power’s coal-fired generating stations was 2.5 million tons (3.8 million tons in 2018; 3.8 million tons (4.2 million tons in 2016; 4.4 million tons in 2015)2017). As of December 31, 2017,2019, Minnesota Power had coal inventories of 1.20.9 million tons (1.4(0.9 million tons as of December 31, 2016)2018). Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2018 and a portion of its coal requirements through December 2021. In 2018,2020, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. Minnesota Power continues to explore other future coal supply options and believes that adequate supplies of low-sulfur, sub‑bituminous coal will continue to be available.
Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018.2021. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.
| | Coal Delivered to Minnesota Power | | Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
| 2019 |
| 2018 |
| 2017 |
|
| Average Price per Ton |
| $36.50 |
|
| $35.87 |
|
| $27.00 |
|
| $35.31 |
|
| $38.89 |
|
| $36.50 |
|
| Average Price per MBtu |
| $2.01 |
|
| $1.98 |
|
| $1.49 |
|
| $1.94 |
|
| $2.10 |
|
| $2.01 |
|
Long-Term Purchased Power. Minnesota Power has contracts to purchase capacity and energy from various entities, including output from certain coal, wind, hydro and solar generating facilities.
Our PPAs are detailed in Note 11.9. Commitments, Guarantees and Contingencies, with additional disclosure provided in the following paragraph.
Square Butte PPA. Under the PPA with Square Butte that extends through 2026, Minnesota Power is entitled to 50 percent of the output of Square Butte’s 455 MW coal-fired generating unit. (See Note 11.9. Commitments, Guarantees and Contingencies.) BNI Energy mines and sells lignite coal to Square Butte. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit. Square Butte’s cost of lignite consumed in 20172019 was approximately $1.88 per MBtu ($1.60 per MBtu in 2018; $1.71 per MBtu ($1.57 per MBtu in 2016; $1.55 per MBtu in 2015)2017). (See Electric Sales / Customers – Minnkota Power PSA.)
Transmission and Distribution
We have electric transmission and distribution lines of 500 kV (8 miles), 345 kV (242 miles), 250 kV (466(465 miles), 230 kV (717 miles), 161 kV (43 miles), 138 kV (190 miles), 115 kV (1,280(1,285 miles) and less than 115 kV (6,334(6,345 miles). We own and operate 167158 substations with a total capacity of 8,5408,875 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.
CapX2020. Minnesota Power was a participant in the CapX2020 initiative which represented an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consisted of electric cooperatives and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, assessed the transmission system and projected growth in customer demand for electricity through 2020. Minnesota Power participated in three CapX2020 projects which were completed and placed in service in 2011, 2012 and 2015.
Great Northern Transmission Line. As a condition of thea 250 MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction ofis constructing the GNTL, an approximately 220-mile220‑mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.
REGULATED OPERATIONS (Continued)
Transmission and Distribution (Continued)
In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Note 4. Regulatory Matters.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL, which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-constructionConstruction activities commenced in the first quarter of 2017, with construction expectedand Minnesota Power expects the GNTL to be completed in 2020. Totalcomplete and in-service by mid-2020. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710approximately $700 million, of which Minnesota Power’s portion is expected to be between $300 million and $350approximately $325 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions in aid of construction.to capital. Total project costs of $152.4$633.3 million have been incurred through December 31, 2017,2019, of which $67.6$339.6 million has been recovered from a subsidiary of Manitoba Hydro. (See Note 9. Commitments, Guarantees and Contingencies.)
Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. In December 2016, Manitoba Hydro filed an application with the National Energy Board in Canada requesting authorization to construct and operate an international transmission line. Both provincial and federal approvals are pending. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014 and is anticipated to be in service by early 2021.
REGULATED OPERATIONS (Continued)
Investment in ATC
Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of December 31 2017,2019, our equity investment in ATC was $118.7$141.6 million ($135.6($128.1 million as of December 31, 2016)2018). The decrease in our equity investment in ATC in 2017 is due to the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies, and Note 5. Investment in ATC.Equity Investments.)
In September 2016, the FERC issued an order reducing ATC’s authorized return on equity to 10.32is 9.88 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. Prior to this order, ATC had been allowed a return on equity of 12.2 percent which had been impacted by reductions for estimated refunds related to complaints filed with the FERC by several customers located within the MISO service area.
In June 2016, a federal administrative law judge ruled on an additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.2010.38 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision frombased on a November 2019 FERC order. In this order, the FERC reduced the base return on theequity for regional transmission organizations as recommended by an administrative law judge’s recommendation is pending. (See Note 4. Regulatory Matters.)judge with refunds ordered for prior periods. Multiple parties to the complaint have appealed the FERC order.
ATC’s 10-year transmission assessment, which covers the years 20172019 through 2026,2028, identifies a need for between $2.8$2.9 billion and $3.6 billion in transmission system investments. These investments by ATC, if undertaken, are expected to be funded through a combination of internally generated cash, debt and investor contributions. As opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro rata ownership interest in ATC.
Properties
Our Regulated Operations businesses own office and service buildings, an energy control center, repair shops, electric plants, transmission facilities and storerooms in various localities in Minnesota, Wisconsin and North Dakota. All of the electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. Most of the generating plants and substations are located on real property owned by Minnesota Power or SWL&P, subject to the lien of a mortgage, whereas most of the electric lines are located on real property owned by others with appropriate easement rights or necessary permits from governmental authorities. WPPI Energy owns 20 percent of Boswell Unit 4. WPPI Energy has the right to use our transmission line facilities to transport its share of Boswell generation. (See Note 3. Jointly-Owned Facilities and Projects.Assets.)
REGULATED OPERATIONS (Continued)
Regulatory Matters
We are subject to the jurisdiction of various regulatory authorities and other organizations.
Electric Rates. All rates and contract terms in our Regulated Operations are subject to approval by applicable regulatory authorities. Minnesota Power and SWL&P design their retail electric service rates based on cost of service studies under which allocations are made to the various classes of customers as approved by the MPUC or the PSCW. Nearly all retail sales include billing adjustment clauses, which may adjust electric service rates for changes in the cost of fuel and purchased energy, recovery of current and deferred conservation improvement programexpenditures and recovery of certain transmission, renewable and environmental investments.
Minnesota Public Utilities Commission. The MPUC has regulatory authority over Minnesota Power’s retail service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters. Minnesota Power’s current retail rates are based on a March 2018 MPUC retail rate order that allows for a 9.25 percent return on common equity and a 53.81 percent equity ratio. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments.
20162020 Minnesota General Rate Case. In On November 2016,1, 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 910.6 percent for retail customers. The rate filing soughtseeks a return on equity of 10.2510.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generatedgenerate approximately $55$66 million in additional revenue. In orders dated December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders,23, 2019, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7$36.1 million beginning January 1, 2017.2020.
On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately $49 million on an annualized basis. At a hearing on January 18, 2018, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Upon commencement of final rates, we expect additional revenue of approximately $13 million on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which will be fully offset by the recognition of a corresponding reserve. As a result of the MPUC’s decisions on January 18, 2018, Minnesota Power has recorded a reserve for an interim rate refund of approximately $32 million as of December 31, 2017. The MPUC also disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. An order from the MPUC setting forth the effective date of final rates is expected by March 12, 2018. Minnesota Power will review this order for potential reconsideration of certain issues at that time.
As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a decrease to depreciation expense of approximately $25 million pre-tax in 2017.
REGULATED OPERATIONS (Continued)
Regulatory Matters (Continued)
Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 which established that it is the energy policy of Minnesota to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued on October 13, 2017, that modified the order dated April 20, 2017. During 2017, Minnesota Power provided discounts of $8.6 million which were recorded as a receivable. On September 29, 2017, Minnesota Power informed its EITE customers that it had suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately $15 million annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, EITE discounts will offset interim rate refund reserves for non-EITE customers.
Additional regulatory proceedings pending with the MPUC are detailed in Note 4. Regulatory Matters.
REGULATED OPERATIONS (Continued)
Regulatory Matters (Continued)
Public Service Commission of Wisconsin. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas and water, issuances of securities and other matters.
2016 Wisconsin General Rate Case.SWL&P’s current retail rates are based on a 2017 PSCW retail rateDecember 2018 order effective August 14, 2017, that allows for a 10.5 percent return on common equity of 10.4 percent and a 5555.0 percent equity ratio. SWL&P’s retail rates prior to August 14, 2017, were based on&P anticipates filing a 2012 PSCW retailgeneral rate order that provided for a 10.9 percent return on equity.case in the second quarter of 2020.
North Dakota Public Service Commission. The 2017 PSCW retail rate order authorizes SWL&P to collect on average a 2.9 percent increaseNDPSC has jurisdiction over site and route permitting of generation and transmission facilities in rates for retail customers (3.8 percent increase in electric rates; 4.8 percent decrease in natural gas rates; and 9.8 percent increase in water rates). On an annualized basis, SWL&P expects to collect additional revenue of $2.5 million.North Dakota.
Federal Energy Regulatory Commission. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for transmission of electricity in interstate commerce, electricity sold at wholesale (including the rates for Minnesota Power’s municipal and wholesale customers), natural gas transportation, certain accounting and record‑keeping practices, certain activities of our regulated utilities and the operations of ATC. FERC jurisdiction also includes enforcement of NERC mandatory electric reliability standards. Violations of FERC rules are subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation. Regulatory proceedings pending with the FERC are detailed in Note 4. Regulatory Matters.
North Dakota Public Service Commission. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities in North Dakota.
Regional Organizations
Midcontinent Independent System Operator, Inc. Minnesota Power, SWL&P and ATC are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, their transmission networks are under the regional operational control of MISO. Minnesota Power and SWL&P take and provide transmission service under the MISO open access transmission tariff. In cooperation with stakeholders, MISO continues its efforts to overseemanages the safe, cost-effective delivery of electric power across all or parts of 15 states and the Canadian province of Manitoba which includes nearly 176,000200,000 MW of generating capacity.
North American Electric Reliability Corporation. The NERC has been certified by the FERC as the national electric reliability organization. The NERC ensures the reliability of the North American bulk power system. The NERC oversees eightsix regional entities that establish requirements, approved by the FERC, for reliable operation and maintenance of power generation facilities and transmission systems. Minnesota Power is subject to these reliability requirements and can incur significant penalties for non‑compliance.
REGULATED OPERATIONS (Continued)
Regional Organizations (Continued)
Midwest Reliability Organization (MRO).Minnesota Power and ATC are members of the MRO, one of the eightsix regional entities overseen by the NERC. The MRO's primary responsibilities are to: ensure compliance with mandatory reliability standards by entities who own, operate or use the interconnected, international bulk power system; conduct assessments of the grid's ability to meet electricity demand in the region; and analyze regional system events.
The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, and all or parts of the states of Illinois, Iowa, Minnesota, Michigan, Montana, Nebraska, North Dakota, South Dakota and Wisconsin.16 states. The region includes more than 130200 organizations that are involved in the production and delivery of electricity to more than 20 million people.electricity. These organizations include municipal utilities, cooperatives, investor-owned utilities, transmission system operators, a federal power marketing agency, Canadian Crown corporations and independent power producers.
Minnesota Legislation
Renewable Energy. Minnesota law requires 25 percent of electric utilities’ applicable retail and municipal energy sales in Minnesota to be from renewable energy sources by 2025. Minnesota law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 andincluding 20 percent by 2020. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power’s 2015 IRP, which was filed with the MPUC in 2015 and approved with modifications by the MPUC in a July 2016 order, includesincluded an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – EnergyForward.)
REGULATED OPERATIONS (Continued)
Minnesota Legislation (Continued)
Minnesota Power continues to execute its renewable energy strategy through renewable projects that will ensure it meets the identified state mandate at the lowest cost for customers. Minnesota Power has exceeded the interim milestone requirements to date with approximately 3127 percent of its applicable retail and municipal energy sales supplied by renewable energy sources in 2017.2019.
Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved Camp Ripley, a 10 MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligiblePower expects to meet both parts of the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. Minnesota Power believes Camp Ripley and the community solar garden arrays will meet approximately one-third of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. The proposal to incentivize customer-sited solar installations and the community solar garden subscriptions is expected to meet a portion of the required small scale solar mandate.(See Note 4. Regulatory Matters.)
Competition
Retail electric energy sales in Minnesota and Wisconsin are made to customers in assigned service territories. As a result, most retail electric customers in Minnesota do not have the ability to choose their electric supplier. Large energy users of 2 MW and above that are located outside of a municipality are allowed to choose a supplier upon MPUC approval. Minnesota Power serves 1210 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. No other large commercial or small industrial customers in Minnesota Power’s service territory have sought a provider outside Minnesota Power’s service territory since 1994.territory. Retail electric and natural gas customers in Wisconsin do not have the ability to choose their energy supplier. In both states, however, electricity may compete with other forms of energy. Customers may also choose to generate their own electricity, or substitute other forms of energy for their manufacturing processes.
REGULATED OPERATIONS (Continued)
Competition (Continued)
In 2017, 52019, five percent of total regulated utility kWh sales were to municipal customers in Minnesota by contract. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through at least December 31, 2032. Minnesota Power wholesale electric contracts with 14 municipal customers are effective through at least December 31, 2024. In June 2016, one of Minnesota Power’svarying dates ranging from 2024 through 2029. The contract with another municipal customers provided a contract termination notice effectivecustomer expired on June 30, 2019. (See Electric Sales / Customers.)
The FERC has continued with its efforts to promote a more competitive wholesale market through open-access electric transmission and other means. As a result, our electric sales to Other Power Suppliers and our purchases to supply our retail and wholesale load are made in thea competitive market.
Franchises
Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 91 cities. The remaining cities, villages and towns served by Minnesota Power do not require a franchise to operate. SWL&P serves customers under electric, natural gas or water franchises in 1 city and 14 villages or towns.
ENERGY INFRASTRUCTURE AND RELATED SERVICES
ALLETE Clean EnergyCLEAN ENERGY
ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in fourfive states, approximately 535660 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 380 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – ALLETE Clean Energy.)
ALLETE Clean Energy believes the market for renewable energy in North America is robust, driven by several factors including environmental regulation, tax incentives, societal expectations and continual technology advances. State renewable portfolio standards and state or federal regulations to limit GHG emissions are examples of environmental regulation or public policy that we believe will drive renewable energy development.
ALLETE Clean Energy’s strategy includes the safe, reliable, optimal and profitable operation of its existing facilities. This includes a strong safety culture, the continuous pursuit of operational efficiencies at existing facilities and cost controls. ALLETE Clean Energy generally acquires facilities in liquid power markets and its strategy includes the exploration of PSA extensions upon expiration of existing contracts.
ALLETE Clean Energy will pursue growth through acquisitions or project development for others. ALLETE Clean Energy is targeting acquisitions of existing facilities up to 200 MW each, which have long-term PSAs in place for the facilities’ output. At this time, ALLETE Clean Energy expects acquisitions will be primarily wind or solar facilities in North America. ALLETE Clean Energy is also targeting the development of new facilities up to 200 MW each, which will have long-term PSAs in place for the output or may be sold upon completion.
Federalcontracts and production tax credit qualification is important to development project economics, and ALLETE Clean Energy invested in equipment in late 2016 and late 2017 to meet production tax credit safe harbor provisions which provides an opportunity to seek developmentrequalification of up to approximately 1,500 MW of qualified wind projects through 2021. ALLETE Clean Energy will also invest approximately $80 million through 2020 to requalify up to 385 WTGs at its Storm Lake I, Storm Lake II and Lake Benton wind energy facilities for production tax credits.existing facilities.
ALLETE CLEAN ENERGY INFRASTRUCTURE AND RELATED SERVICES (Continued)
ALLETE Clean Energy (Continued)
On January 3, 2017, ALLETE Clean Energy announced that it will develop a wind energy facility of up to 50 MW after securing a 25-year PSA with Montana-Dakota Utilities, which includes an option to purchase the facility upon completion. We expect Montana-Dakota Utilities to exercise the option in the first quarter of 2018; construction and sale is expected to be completed in December 2018. ALLETE Clean Energy constructed and sold a 107 MW wind energy facility to Montana-Dakota Utilities in 2015. On March 16, 2017, ALLETE Clean Energy announced it will build, own and operate a separate 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction is expected to begin in late 2018.
ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current operating portfolio of approximately 535660 MW is subject to typical variations in seasonal wind with higher wind resources typically available in the winter months. The majority of its planned maintenance leverages this seasonality and is performed during lower wind periods. The current mix of PSA expiration and geographic location for existing facilities is as follows:
| | | Wind Energy Facility | Location | Capacity MW | PSA MW | PSA Expiration | Region | Capacity MW | PSA MW | PSA Expiration |
| Armenia Mountain | Pennsylvania | 100.5 | 100% | 2024 | East | 101 | 100% | 2024 |
| Chanarambie/Viking | Minnesota | 97.5 | | Midwest | 98 | |
| PSA 1 | | 12% | 2018 | |
PSA 1 (a) | | | 12% | 2023 |
| PSA 2 | | 88% | 2023 | | 88% | 2023 |
| Condon | Oregon | 50 | 100% | 2022 | West | 50 | 100% | 2022 |
| Glen Ullin | | West | 106 | 100% | 2039 |
| Lake Benton | Minnesota | 104 | 100% | 2028 | Midwest | 104 | 100% | 2028 |
| Storm Lake I | Iowa | 108 | 100% | 2019 | Midwest | 108 | 100% | 2027 |
| Storm Lake II | Iowa | 77 | | Midwest | 77 | |
| PSA 1 | | 90% | 2019 | | 90% | 2020 |
| PSA 2 | | 10% | 2032 | | 10% | 2032 |
| Other | | Midwest | 17 | 100% | 2028 |
| |
| (a) | The PSA expiration assumes the exercise of four one-year renewal options that ALLETE Clean Energy has the sole right to exercise. |
The majority of ALLETE Clean Energy’s wind operations are located on real property owned by others with appropriate easementseasement rights or necessary consents of governmental authorities. TwoOne of ALLETE Clean Energy’s wind energy facilities areis encumbered by liens against theirits assets securing financing. ALLETE Clean Energy’s Glen Ullin wind energy facility is owned through a tax equity financing structure. (See Note 1. Operations and Significant Accounting Policies.)
U.S. Water ServicesWATER SERVICES
U.S. Water Services providesprovided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency.
On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services is locatedto a subsidiary of Kurita Water Industries Ltd. On March 26, 2019, ALLETE completed the sale, and received approximately $270 million in 49 statescash, net of transaction costs and Canada and has an established basecash retained. The Company recognized a gain on the sale of approximately 4,900 customers. U.S. Water Services differentiates itselfof $13.2 million after-tax in 2019. ALLETE used the proceeds from the competition by developing synergies between established solutions in engineering, equipment and chemical water treatment, and helping customers achieve efficient and sustainable usesale of their water and energy systems. U.S. Water Services is a leading provider to the biofuels industry,reinvest in growth initiatives at our Regulated Operations and also serves the commercial and institutional markets, food and beverage, light manufacturing, power generation, and midstream oil and gas industries, among others. U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. U.S. Water Services sells certain products which are seasonal in nature, with higher demand typically realized in warmer months; generally, lower sales occur in the first quarter of each year.ALLETE Clean Energy.
Our strategy is to grow U.S. Water Services’ presence in North America by adding customers, products, markets and new geographies. We believe water scarcity and a growing emphasis on conservation will continue to drive significant growth in the industrial, commercial and governmental sectors leading to organic revenue growth for U.S. Water Services. U.S. Water Services also expects to pursue periodic strategic tuck-in acquisitions with a purchase price in the $10 million to $50 million range. Priority will be given to acquisitions which expand its geographic reach, add new technology or deepen its capabilities to serve its expanding customer base.
On September 1, 2017, U.S. Water Services acquired Tonka Water for total consideration of $19.2 million. Tonka Water is a supplier of municipal and industrial water treatment systems that will expand U.S. Water Services’ geographic and customer markets.
U.S. Water Services leases an office and production facility at its headquarters in Minnesota as well as various office, warehouse and production facilities across the United States.
CORPORATE AND OTHER
BNI Energy
BNI Energy is a supplier of lignite coal in North Dakota, producing approximately 4 million tons annually and has an estimated 650 million tons of lignite coal reserves. Two electric generating cooperatives, Minnkota Power and Square Butte, consume virtually all of BNI Energy’s production of lignite under cost-plus fixed fee coal supply agreements extending through December 31, 2037. (See Item 1. Business – Regulated Operations – Power Supply – Long-Term Purchased Power and Note 11.9. Commitments, Guarantees and Contingencies.) The mining process disturbs and reclaims between 200 and 250 acres per year. Laws require that the reclaimed land be at least as productive as it was prior to mining. As of December 31, 2017,2019, BNI Energy had a $25.0$43.4 million asset reclamation obligation ($23.526.5 million as of December 31, 2016)2018) included in Other Non-Current Liabilities on the Consolidated Balance Sheet. These costs are included in the cost-plus fixed fee contract, for which an asset reclamation cost receivable was included in Other Non-Current Assets on the Consolidated Balance Sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of credit. (See Note 11.9. Commitments, Guarantees and Contingencies.)
CORPORATE AND OTHER (Continued)
Investment in Nobles 2
In December 2018, our wholly-owned subsidiary, ALLETE South Wind, entered into an agreement with Tenaska to purchase a 49 percent equity interest in Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. The wind energy facility will be built in Nobles County, Minnesota and is expected to be completed in late 2020, with an estimated total project cost of approximately $350 million to $400 million. In the fourth quarter of 2019, we entered into a tax equity funding agreement to finance up to $125 million of the project costs. We account for our investment in Nobles 2 under the equity method of accounting. As of December 31, 2019, our equity investment in Nobles 2 was $56.0 million ($33.0 million at December 31, 2018). We expect to invest approximately $115 million in 2020. (See Note 5. Equity Investments.)
ALLETE Properties
ALLETE Properties represents our legacy Florida real estate investment. Market conditions can impact land sales and could result in our inability to cover our cost basis, operating expenses or fixed carrying costs such as community development district assessments and property taxes.
ALLETE Properties’ major projectsproject in Florida areis Town Center at Palm Coast and Palm Coast Park.Coast.
|
| | | | | | | | | |
| Summary of Projects | | | | Residential | | Non-residential |
| As of December 31, 2017 | | Acres (a) | | Units (b) | | Sq. Ft. (b)(c) |
| Projects | | | | | | |
| Town Center at Palm Coast | | 971 |
| | 2,419 |
| | 2,178,700 |
|
| Palm Coast Park | | 1,025 |
| | 830 |
| | 2,143,000 |
|
| Total Projects | | 1,996 |
| | 3,249 |
| | 4,321,700 |
|
|
| | | | | | | | | |
| Summary of Project | | | | Residential | | Non-residential |
| As of December 31, 2019 | | Acres (a) | | Units (b) | | Sq. Ft. (b)(c) |
| Project | | | | | | |
| Town Center at Palm Coast | | 807 |
| | 1,739 |
| | 1,872,700 |
|
| |
| (a) | Acreage amounts areis approximate and shown on a gross basis, including wetlands. |
| |
| (b) | Units and square footage are estimated. Density at build out may differ from these estimates. |
| |
| (c) | Includes retail and non-retail commercial, office, industrial, warehouse, storage and institutional square footage. |
In addition to the two projects,Town Center at Palm Coast project, ALLETE Properties has approximately 800600 acres of other land available for sale. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook – Corporate and Other – ALLETE Properties.)
In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In 2015, the Company reevaluated its strategy related to the real estate assets of ALLETE Properties in response to market conditions and transaction activity. The revised strategy incorporated the possibility of a bulk sale of its entire portfolio. Proceeds from a bulk sale would be strategically deployed to support growth in ALLETE Clean Energy and U.S. Water Services, collectively our Energy Infrastructure and Related Services businesses. ALLETE Properties also continues to pursue sales of individual parcels over time. ALLETE Properties will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.
In connection with implementing the revised strategy, management evaluated its impairment analysis for its real estate assets using updated assumptions to determine estimated future net cash flows on an undiscounted basis. Estimated fair values were based upon current market data and pricing for individual parcels. Our impairment analysis incorporates a probability-weighted approach considering the alternative courses of sales noted above.
Based on the results of the 2015 undiscounted cash flow analysis, the undiscounted future net cash flows were not adequate to recover the carrying value of the real estate assets leading to an adjustment of carrying value to estimated fair value. Estimated fair value was derived using Level 3 inputs, including current market interest in the property for a bulk sale of its entire portfolio, and discounted cash flow analysis of estimated selling price for sales over time. As a result, a non-cash impairment charge of $36.3 million was recorded in 2015 to reduce the carrying value of the real estate to its estimated fair value.
In 2017 and 2016, our qualitative assessments indicated that the cash flows were adequate to recover the carrying value of ALLETE Properties real estate assets. As a result, no impairment was recorded in 2017 or 2016.
CORPORATE AND OTHER (Continued)
ALLETE Properties (Continued)
Seller Financing. ALLETE Properties occasionally provides seller financing to certain qualified buyers. As of December 31, 2017,2019, outstanding finance receivables were $15.5$5.6 million, net of reserves, with maturities through 2022.2024. These finance receivables accrue interest at market-based rates and are collateralized by the financed properties.
Regulation. A substantial portion of our development properties in Florida are subject to federal, state and local regulations, and restrictions that may impose significant costs or limitations on our ability to develop the properties. Much of our property is vacant land and some is located in areas where development may affect the natural habitats of various protected wildlife species or in sensitive environmental areas such as wetlands.
Non-Rate Base Generation and Miscellaneous
Corporate and Other also includes other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,0004,000 acres of land in Minnesota, and earnings on cash and investments.
As of December 31, 20172019, non-rate base generationconsists of 29 MW of natural gas and hydro generation at Rapids Energy Center.Center in Grand Rapids, Minnesota. In 20172019, we sold less than 0.1 million MWh of non-rate base generation (0.1 million MWh in 20162018 and in 20152017). Net generation is primarily dedicated to the needs of one customer, UPM Blandin.
|
| | | | |
| Non-Rate Base Power Supply | Unit No. | Year Installed | Year Acquired | Net Capability (MW) |
Rapids Energy Center (a) | | | | |
| in Grand Rapids, MN | | | | |
Steam – Biomass (b) | 6 & 7 | 1969, 1980 | 2000 | 27 |
| Hydro | 4 & 5 | 1917, 1948 | 2000 | 2 |
| |
(a) | The net generation is primarily dedicated to the needs of one customer, UPM Blandin in Grand Rapids, Minnesota. (See Item 7. Management’s Discussion and Analysis – Outlook – Industrial Customers and Prospective Additional Load.) |
| |
(b) | Rapids Energy Center’s fuel supply is supplemented by coal. |
ENVIRONMENTAL MATTERS
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities.authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.
We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.
We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. (See Note 11.9. Commitments, Guarantees and Contingencies.)
EMPLOYEES
As of December 31, 20172019, ALLETE had 2,0171,339 employees, of which 1,9721,316 were full-time.
Minnesota Power and SWL&P have an aggregate of 517465 employees who are members of the International Brotherhood of Electrical Workers (IBEW) Local 31. The current labor agreements with IBEW Local 31 expiredexpire on January 31, 2018. Negotiations are proceeding and we believe ratified agreements will be agreed upon in the first quarter of 2018.April 30, 2020, for Minnesota Power SWL&P and IBEW Local 31 are operating under the expired labor agreements until new contracts are agreed upon.February 1, 2021, for SWL&P.
BNI Energy has 179 employees, of which 136133 are members of IBEW Local 1593. The current labor agreement with IBEW Local 1593 expires on March 31, 2019.2023.
AVAILABILITY OF INFORMATION
ALLETE makes its SEC filings, including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(e) or 15(d) of the Securities Exchange Act of 1934, available free of charge on ALLETE’s website, www.allete.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANT
As of February 15, 2018,13, 2020, these are the executive officers of ALLETE:
|
| |
| Executive Officers | Initial Effective Date |
| | |
Alan R. Hodnik, Age 5860 | |
Executive Chairman (a) | February 3, 2020 |
| Chairman and Chief Executive Officer | January 31, 2019 |
| Chairman, President and Chief Executive Officer | May 10, 2011 |
| |
| Bethany M. Owen, Age 54 | |
President and Chief Executive Officer(a) | May 1, 2010February 3, 2020 |
| President | January 31, 2019 |
| Senior Vice President and Chief Legal and Administrative Officer | November 26, 2016 |
| | |
Robert J. Adams, Age 5557 | |
| Senior Vice President and Chief Financial Officer | March 4, 2017 |
| Senior Vice President – Energy-Centric Businesses and Chief Risk Officer | November 14, 2015 |
| Vice President – Energy-Centric Businesses and Chief Risk Officer | June 23, 2014 |
Vice President – Business Development and Chief Risk Officer | May 13, 2008 |
| |
Deborah A. Amberg, Age 52 | |
Senior Vice President, Chief Strategy Officer – Regulated Operations and President – SWL&P | November 26, 2016 |
Senior Vice President, General Counsel and Secretary | January 1, 2006 |
| | |
Patrick L. Cutshall, Age 5254 | |
| Vice President and Corporate Treasurer | December 18, 2017 |
| Treasurer | January 1, 2016 |
| | |
| Nicole R. Johnson, Age 45 | |
| Vice President and Chief Administrative Officer | June 28, 2019 |
| |
Steven W. Morris, Age 5658 | |
| Vice President, Controller and Chief Accounting Officer | December 24, 2016 |
| Controller | March 3, 2014 |
| | |
Patrick K. Mullen,Margaret A. Thickens, Age 5753 | |
Senior Vice President, – External AffairsChief Legal Officer and Corporate Secretary | April 10, 2017February 13, 2019 |
| |
| (a) | |
Bradley W. Oachs, Age 60 | |
Senior Vice President and President – Regulated Operations | November 26, 2016 |
| |
On January 30, 2020, the Board of Directors of ALLETE elected Bethany M. Owen Age 52 | |
Senior Vice President andas Chief Legal and AdministrativeExecutive Officer | November 26, 2016 of ALLETE effective February 3, 2020, after Alan R. Hodnik informed the Board of Directors on January 30, 2020, that he will retire in May 2021. As part of an orderly transition, Mr. Hodnik will continue as Executive Chairman until May 2021. |
All of the executive officers have been employed by us for more than five years in executive or management positions. Prior to election to the position listed above, the following executives held other positions with the Company during the past five years.
Mr. Morris was Director – Accounting.
Mr. Cutshall was Director – Investments and Tax;Tax.
Ms. Johnson was Vice President – Human Resources; Director – Investments.Compensation and Benefits.
Mr. Oachs was Chief Operating Officer – Minnesota Power.
Ms. Owen was Vice President – Information Technology Solutions and President – SWL&P.
Mr. MullenMs. Thickens was Vice PresidentGeneral Counsel and Director of Compliance – MarketingALLETE Clean Energy; General Counsel and Corporate Communications.Secretary – ALLETE Clean Energy; Senior Attorney.
There are no family relationships between any of the executive officers. All officers and directors are elected or appointed annually.
The present term of office of the executive officers listed in the preceding table extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 8, 2018.12, 2020.
Item 1A. Risk Factors
The risks and uncertainties discussed below could materially affect our business operations, financial position, results of operations and cash flows, and should be carefully considered by stakeholders. The risks and uncertainties in this section are not the only ones we face; additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations, financial position, results of operations and cash flows. Accordingly, the risks described below should be carefully considered together with other information set forth in this report and in future reports that we file with the SEC.
Entity-wide Risks
We rely on access to financing sources and capital markets. If we do not have access to capital on acceptable terms or are unable to obtain capital when needed, our ability to execute our business plans, make capital expenditures or pursue other strategic actions that we may otherwise rely on for future growth would be adversely affected.
We rely on access to financing sources and the capital markets, on acceptable terms and at reasonable costs, as sources of liquidity for capital requirements not satisfied by our cash flows from operations. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access and financing costsfinance in the capital markets.markets or to access other financing sources. Such disruptions or causes of a downgrade could include but are not limited to: the effects of the TCJA on the Company’s cash flow metrics; a loss of, or a reduction in sales to, Large Power Customersour taconite, paper and pipeline customers if we are unable to offset the related lost margins; weaker operating performance; adverse regulatory outcomes; disproportionate increase in the contribution to net income from ALLETE Clean Energy and our Energy InfrastructureCorporate and Related ServicesOther businesses as compared to that from our Regulated Operations; deteriorating economic or capital market conditions; or volatility in commodity prices.
If we are not able to access capital on acceptable terms in sufficient amounts and when needed, or at all, the ability to maintain our businesses or to implement our business plans would be adversely affected.
Recent U.S. tax legislation could adversely impact our financial position, results of operations and cash flows.
On December 22, 2017, the TCJA was enacted into law. The TCJA has significantly changed the U.S. Internal Revenue Code and the taxation of corporations. The TCJA is unclear in certain respects and will require interpretations and the promulgation of regulations by the Internal Revenue Service, as well as state tax authorities and it could be subject to potential amendments and technical corrections. The regulatory treatment of the impacts of the TCJA will be subject to the discretion of the FERC and state regulatory authorities.
On February 6, 2018, Standard & Poor’s downgraded its ratings outlook for ALLETE to negative from stable as a result, among other reasons, of the potential negative impact of the TCJA on certain financial metrics used by credit rating agencies to rate us. It is unclear when or how the capital markets and the credit rating agencies will ultimately respond. Further, there may be other adverse effects resulting from the TCJA or regulatory agency responses to the TCJA that we have not yet identified. We are still quantifying the impacts of the TCJA on our businesses, and have reflected estimates for the impacts in our Consolidated Financial Statements as of December 31, 2017, which may be adjusted in future periods as more information becomes available. The reduction in the federal corporate income tax rate required us to remeasure our existing deferred income tax balances as of the date of enactment, resulting in a non‑cash benefit to earnings in our ALLETE Clean Energy and U.S. Water Services segments as well as a non-cash expense at our Corporate and Other businesses. The remeasurement of the existing deferred income tax assets and liabilities for our Regulated Operations segment was recorded as regulatory assets, regulatory liabilities, and a change to our investment in ATC resulting in no material impact on the 2017 results of operations for this segment. The benefits of the TCJA for customers of Minnesota Power and SWL&P are expected to be passed back to those customers over time primarily based upon the normalization provisions of the U.S. Internal Revenue Code over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. The decrease in our investment in ATC is expected to be amortized into earnings over time. The final amount and timing over which the benefits of the TCJA will be passed back to customers has not been determined, and therefore, the full cash flow impacts are still uncertain.
Item 1A. Risk Factors (Continued)
Entity-wide Risks (Continued)
A deterioration in general economic conditions may have adverse impacts on our financial position, results of operations and cash flows.
If economic conditions deteriorate on a national or regional level, it may have a negative impact on the Company’s financial position, results of operations and cash flows as well as on our customers. This impact may include volatility and unpredictability in the demand for the products and services offered by our businesses, the loss of existing customers, tempered growth strategies, customer production cutbacks or customer bankruptcies. An uncertain economy could also adversely affect expenses including pension costs, interest costs, and uncollectible accounts, or lead to reductions in the value of certain real estate and other investments.
We are subject to extensive state and federal legislation and regulation, compliance with which could have an adverse effect on our businesses.
We are subject to, and affected by, extensive state and federal legislation and regulation. If it was determined that our businesses failed to comply with applicable laws and regulations, we could become subject to fines or penalties or be required to implement additional compliance measures or actions, the cost of which could be material. Adoption of new laws, rules, regulations, principles, or practices by federal and state agencies, or changes to or a failure to comply with current laws, rules, regulations, principles, or practices and their interpretations, could have an adverse effect on our financial position, results of operations and cash flows.
The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on our operations.
The success of our business heavily depends on the leadership of our executive officers and key employees to implement our business strategy. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. Personnel costs may increase due to competitive pressures or terms of collective bargaining agreements with union employees.
Item 1A. Risk Factors (Continued)
Entity-wide Risks (Continued)
Market performance and other changes could decrease the value of pension and other postretirement benefit plan assets, which may result in significant additional funding requirements and increased annual expenses.
The performance of the capital markets impacts the values of the assets that are held in trust to satisfy future obligations under our pension and other postretirement benefit plans. We have significant obligations to these plans and the trusts hold significant assets. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected rates of return. A decline in the market value of the pension and other postretirement benefit plan assets would increase the funding requirements under our benefit plans if asset returns do not recover. Additionally, our pension and other postretirement benefit plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit expense and funding requirements. Our pension and other postretirement benefit plan costs are generally recoverable in our electric rates as allowed by our regulators or through our cost-plus fixed fee coal supply agreements at BNI Energy; however, there is no certainty that regulators will continue to allow recovery of these rising costs in the future.
We are exposed to significant reputational risk.
The Company could suffer negative impacts to its reputation as a result of operational incidents, violations of corporate compliance policies, regulatory violations, or other events which may result in negative customer perception and increased regulatory oversight, each of which could have an adverse effect on our financial position, results of operations and cash flows.
Catastrophic events, such as natural disasters and acts of war, may adversely affect our operations.
Catastrophic events such as fires, including wildfires, earthquakes, explosions, and floods, severe weather, such as ice storms, hailstorms, or tornadoes or similar occurrences, as well as acts of war, could adversely affect the Company’s facilities, operations, financial position, results of operations and cash flows. Although the Company has contingency plans and employs crisis management to respond and recover operations in the event of a severe disruption resulting from such events,a catastrophic event, these measures may not be successful. Furthermore, despite these measures, if such an occurrencea catastrophic event were to occur, our financial position, results of operations and cash flows could be adversely affected.
Item 1A. Risk Factors (Continued)
Entity-wide Risks (Continued)
We are vulnerable to acts of terrorism or cybersecurity attacks.
Our operations may be targets of terrorist activities includingor cybersecurity attacks, which could disrupt our ability to produceprovide utility service at our regulated utilities, develop or distribute some portionoperate our renewable energy projects at ALLETE Clean Energy, or operate our other businesses. The impacts may also impair the fulfillment of critical business functions, negatively impact our products. reputation, subject us to litigation or increased regulation, or compromise sensitive, confidential and other data.
There have been cyber securitycybersecurity attacks on U.S. energy infrastructure in the past and there may be such attacks in the future. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or otherwise be materially adversely affected by such activities. ComputerHacking, computer viruses, terrorism, theft and sabotage could impact our systems and facilities, or those of third parties on which we rely, which may disrupt our operations and adversely impactour results of operations.
Our businesses require the continued operation of sophisticated custom-developed, purchased, and leased information technology systems and network infrastructure. Ourinfrastructure as well as the collection and retention of personally identifiable information of our customers, shareholders and employees. Although we maintain security measures designed to prevent cybersecurity incidents and protect our information technology and control systems, network infrastructure and other assets, our technology systems, or those of third parties on which we rely, may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism andas well as other causes. If those technology systems fail or are breached and not recovered in a timely manner, we may be unable to perform critical business functions including effectively maintaining certain internal controls over financial reporting, our reputation may be negatively impacted, we may become subject to litigation or increased regulation, and sensitive, confidential and other data could be compromised, whichcompromised. If our business were impacted by terrorist activities or cybersecurity attacks, such impacts could have an adverse effect on our financial position, results of operations and cash flows.
Item 1A. Risk Factors (Continued)
Entity-wide Risks (Continued)
We maintain insurance against some, but not all, of the risks and uncertainties we face.
We maintain insurance against some, but not all, of the risks and uncertainties we face. The occurrence of these risks and uncertainties, if not fully covered by insurance, could have a material effect on our financial position, results of operations and cash flows.
Government challenges to our tax positions, as well as tax law changes and the inherent difficulty in quantifying potential tax effects of our operations and business decisions, could adversely affect our results of operations and liquidity.
We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations in order to estimate federal and state tax obligations. These judgments include reserves for potential adverse outcomes for tax positions that may be challenged by taxour obligations to taxing authorities. The obligations, which include income taxes and taxes other than income taxes, involve complex matters that ultimately could be litigated. We also estimate our ability to use tax benefits, including those in the form of carryforwards and tax credits that are recorded as deferred tax assets on our Consolidated Balance Sheet. A disallowance of these tax benefits could have an adverse impact on our financial position, results of operations and cash flows.
We are currently utilizing, and plan to utilize in the future, our carryforwards and tax credits in the future to reduce our income tax obligations. If we cannot generate enough taxable income in the future to utilize all of our carryforwards and tax credits before they expire, we may incur adverse charges to earnings. If federal or state tax authorities disagree with thedeny any deductions resulting from ouror tax planning strategies,credits, our financial position, results of operations and cash flows may be adversely impacted.
Regulated Operations Risks
Our results of operations could be negatively impacted if our Large Power Customerstaconite, paper and pipeline customers experience an economic downturn,incurwork stoppages, fail to compete effectively, experience decreased demand, fail to economically obtain raw materials, fail to renew or obtain necessary permits, or experience a decline in prices for their product.
Minnesota Power’s nineeight Large Power Customers accounted for 2528 percent of our 20172019 consolidated operating revenue (22(24 percent in 20162018 and 25 percent in 2015)2017), of which one of these customers accounted for approximately 1012 percent of consolidated revenue in 2017 (82019 (10 percent in 20162018 and in 2015)2017). These customers are involved in cyclical industries that by their nature are adversely impacted by economic downturns and are subject to strong competition in the marketplace. Additionally, the North American paper and pulp industry also faces declining demand due to the impact of electronic substitution for print and changing customer needs. As a result, certain paper and pulp customers have reduced their existing operations in recent years and have pursued or are pursuing product changes in response to declining demand.
Accordingly, if our industrial customers experience an economic downturn, incur a work stoppage (including strikes, lock-outs or other events), fail to compete effectively, experience decreased demand, fail to economically obtain raw materials, fail to renew or obtain necessary permits, or experience a decline in prices for their product, there could be adverse effects on their operations and, consequently, this could have a negative impact on our results of operations if we are unable to remarket at similar prices the energy that would otherwise have been sold to such Large Power Customers.customers.
Item 1A. Risk Factors (Continued)
Regulated Operations Risks (Continued)
Our utility operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.
We are subject to an extensive legal and regulatory framework imposed under federal and state law including regulations administered by the FERC, MPUC, MPCA, PSCW, NDPSC and EPA as well as regulations administered by other organizations including the NERC. These laws and regulations relate to allowed rates of return, capital structure, financings, rate and cost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and distribution facilities (including the ongoing maintenance and reliable operation of such facilities), recovery of purchased power costs and capital investments, approval of integrated resource plans and present or prospective wholesale and retail competition, renewable portfolio standards that require utilities to obtain specified percentages of electric supply from eligible renewable generation sources, among other things. Energy policy initiatives at the state or federal level could increase renewable portfolio standards or incentives for distributed generation, municipal utility ownership, or local initiatives could introduce generation or distribution requirements that could change the current integrated utility model. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. Compliance with these standards may lead to increased operating costs and capital expenditures.expenditures which are subject to regulatory approval for recovery. If it was determined that we were not in compliance with these mandatory reliability standards or other statutes, rules and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations.
These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary permits, licenses, approvals and certificates for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations, or the adoption of new regulations or the expansion of jurisdiction by these agencies and other organizations could have an adverse impact on our business and results of operations.
Our ability to obtain rate adjustments to maintain reasonable rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or reasonable authorized rates of return on capital will be earned. Minnesota Power and SWL&P, from time to time, file general rate cases with, or otherwise seek cost recovery authorization from, federal and state regulatory authorities. If Minnesota Power and SWL&P do not receive an adequate amount of rate relief in general rate cases, including if rates are reduced, if increased rates are not approved on a timely basis, if cost recovery is not granted at the requested level, or costs are otherwise unable to be recovered through rates, or if cost recovery is not granted at the requested level, we may experience an adverse impact on our financial position, results of operations and cash flows. We are unable to predict the impact on our business and results of operations from future legislation or regulatory activities of any of these agencies or organizations.
Our regulated operations present certain environmental risks that could adversely affect our financial position and results of operations, including effects of environmental laws and regulations, physical risks associated with climate change and initiatives designed to reduce the impact of GHG emissions.
We are subject to extensive environmental laws and regulations affecting many aspects of our past, present and future operations, including air quality, water quality and usage, waste management, reclamation, hazardous wastes, avian mortality and natural resources. These laws and regulations can result in increased capital expenditures environmental emission allowance trading,and increased operating and other costs as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions, coal ash and water discharge and wind energyat generating facilities.
These laws and regulations could restrict the output of some existing facilities, limit the use of some fuels in the production of electricity, require the installation of additional pollution control equipment, require participation in environmental emission allowance trading, and lead to other environmental considerations and costs, which could have an adverse impact on our business, operations and results of operations.
These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Violations of these laws and regulations could expose us to regulatory and legal proceedings, disputes with, and legal challenges by, governmental authorities and private parties, as well as potential significant civil fines criminal penalties and other sanctions.
Item 1A. Risk Factors (Continued)
Regulated Operations Risks (Continued)
Existing environmental regulations may be revised and new environmental regulations may be adopted or become applicable to us. Revised or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have an adverse effect on our results of operations.
Item 1A. Risk Factors (Continued)
Regulated Operations Risks (Continued)
The scientific community generally accepts that emissions of GHG are linked to global climate change. Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. Severe weather or other natural disasters could be destructive, which could result in increased costs. An extreme weather event within our utility service areas can also directly affect our capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. These all have the potential to adversely affect our business and operations.
There is significant uncertainty regarding if and when new laws or regulations will be adopted to reduce GHGsor limit GHG and the impact any such laws or regulations would have on us. In 2017,2019, coal was the primary fuel source for 7064 percent of the energy produced by our generating facilities. Any future limits on GHG emissions would likelyat the federal or state level, or action taken by regulators, may require us to incur significant capital expenditures and increases in operating costs, which if significant,or could result in the closure of certain coal-fired energy centers,generating facilities, an impairment of assets, or otherwise adversely affect our results of operations, particularly if suchresulting expenditures and costs are not fully recoverable from customers.
We cannot predict the amount or timing of all future expenditures related to environmental matters because of uncertainty as to applicable regulations or requirements. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Violations of certain environmental statutes, rules and regulations could expose ALLETE to third party disputes and potentially significant monetary penalties, as well as other sanctions for non‑compliance.
The operation and maintenance of our regulated electric generation and transmission facilities are subject to operational risks that could adversely affect our financial position, results of operations and cash flows.
The operation of generating facilities involves many risks, including start-up operationsoperational risks, breakdown or failure of facilities, the dependence on a specific fuel source, inadequatefuel supply, availability of fuel transportation, orand the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. A significant portion of our facilities contain older generating equipment, which, even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. Generation and transmission facilities and equipment are also likely to require periodic upgrades and improvements due to changing environmental standards and technological advances. We could be subject to costs associated with any unexpected failure to produce or deliver power, including failure caused by breakdown or forced outage, as well as repairing damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events.
Our ability to successfully and timely complete capital improvements to existing regulated facilities or other capital projects is contingent upon many variables.
We expect to incur significant capital expenditures in making capital improvements to our existing electric generation and transmission facilities and in the development and construction of new electric generation and transmission facilities. Should any such efforts be unsuccessful or not completed in a timely manner, we could be subject to additional costs or impairments which could have an adverse impact on our financial position, and results of operation.operation and cash flows.
Our regulated electric generating operations may not have access to adequate and reliable transmission and distribution facilities necessary to deliver electricity to our customers.
We depend on our own transmission and distribution facilities, as well as facilities owned by other utilities, to deliver the electricity produced and sold to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be limited. We may have to forgo sales or may have to buy more expensive wholesale electricity that is available in the capacity-constrained area. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact the satisfaction of our customers, which could have an adverse impact on our business and results of operations.
Item 1A. Risk Factors (Continued)
Regulated Operations Risks (Continued)
Our results of operations could be impacted by declining wholesale power prices.
Wholesale prices for electricity have declined in recent years primarily due to low natural gas prices. If there are reductions in demand from customers or if we lose customers, we will market any available power to Other Power Suppliers in an effort to mitigate any earnings impact. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. Due to the low wholesale prices for electricity, we can make no assurancesdo not expect that our power marketing efforts would fully offset anythe reduction in earnings resulting from the lower demand from existing customers or the loss of customers. (See Item 1. Business – Regulated Operations – Electric Sales / Customers.)
The price of electricity and fuel may be volatile.
Volatility in market prices for electricity and fuel could adversely impact our financial position and results of operations and may result from:
severe or unexpected weather conditions and natural disasters;
seasonality;
changes in electricity usage;
transmission or transportation constraints, inoperability or inefficiencies;
availability of competitively priced alternative energy sources;
changes in supply and demand for energy;
changes in power production capacity;
outages at our generating facilities or those of our competitors;
availability of fuel transportation;
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
wars, sabotage, terrorist acts or other catastrophic events; and
federal, state, local and foreign energy, environmental, or other regulation and legislation.
Fluctuations in our fuel and purchased power costs related to our retail and municipal customers are passed on to customers through the fuel adjustment clause. Volatility in market prices for our fuel and purchase power costs primarily impacts our sales to Other Power Suppliers.
Demand for energy may decrease.
Our results of operations are impacted by the demand for energy in our service territories.territories, our municipal customers and other power suppliers. There could be lower demand for energy due to a loss of customers as a result of economic conditions, customers constructing or installing their own generation facilities, higher costs and rates charged to customers, eligible municipal and other power suppliers choosing an alternative energy provider, or loss of service territory or franchises. Further, energy conservation and technological advances that increased energy efficiency may temporarily or permanently reduce the demand for energy products. In addition, we are impacted by state and federal regulations requiring mandatory conservation measures, which would reduce the demand for energy products. Continuing technology improvements and regulatory developments may make customer and third party-owned generation technologies such as rooftop solar systems, WTGs, microturbines and battery storage systems more cost effective and feasible for more of our customers. If more customers utilize their own generation, demand for energy from us would decline. There may not be future economic growth opportunities that would enable us to replace the lost energy demand from these customers. Therefore, a decrease in demand for energy could adversely impact our financial position, results of operations and cash flows.
We may not be able to successfully implement our strategic objectives of growing load at our utilities if current or potential industrial or municipal customers are unable to successfully implement expansion plans, including the inability to obtain necessary governmental permits.
As part of our long-term strategy, we pursue new wholesale and retail loads in and around our service territories. Currently, there are several companies in northeastern Minnesota that are in the process of developing natural resource-based projects that represent long-term growth potential and load diversity for our Regulated Operations businesses. These projects may include construction of new facilities and restarts of old facilities, both of which require permitting and approvals to be obtained before the projects can be successfully implemented. If a project does not obtain any necessary governmental (including environmental) permits and approvals or if these customers are unable to successfully implement expansion plans, our long-term strategy and thus our results of operations could be adversely impacted.
Item 1A. Risk Factors (Continued)
ALLETE Clean Energy Infrastructure/ Corporate and Related ServicesOther Risks
The inability to successfully manage and grow ALLETE Clean Energy and our Energy InfrastructureCorporate and Related ServicesOther businesses could adversely affect our results of operations.
Our Energy Infrastructure and Related Services businesses consist of ALLETE Clean Energy and U.S. Water Services. The Company's strategy for these businessesALLETE Clean Energy includes adding customers, products, and new geographies, project development for others and growth through acquisitions. This strategy depends, in part, on the Company’s ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on acceptable terms. The Company may compete with other companies for these acquisition opportunities, which may increase the Company’s cost of making acquisitions and the Company may be unsuccessful in pursuing these acquisition opportunities. TheseOther companies may be able to pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets than the Company’s financial or human resources permit. Additionally, tax law changes may adversely impact the economic characteristics of potential acquisitions or investments. If the Company is unable to execute its strategy of growth through acquisitions, project development for others, or the addition of new customers products and geographies, it may impede our long-term objectives and business strategy.
Acquisitions are subject to uncertainties. If we are unable to successfully integrate and manage future acquisitions or strategic investments, this could have an adverse impact on our results of operations. Our actual results may also differ from our expectations due to factors such as the ability to obtain timely regulatory or governmental approvals, integration and operational issues and the ability to retain management and other key personnel.
U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. Some of these customers can be adversely affected by low commodity prices such as those for ethanol and oil which may cause these customers to purchase less of U.S. Water Services’ products and services. If U.S. Water Services is unable to retain its existing customers, add new customers, or if it experiences reduced demand for its products and services, adverse impacts on our results of operations could occur that would prevent us from achieving our future growth expectations.
The generation of electricity from ALLETE Clean Energy’sour wind energy facilities depends heavily on suitable meteorological conditions.
ALLETE Clean Energy’sAlthough our wind energy facilities are geographically diverse; however, iflocated in diverse geographic regions to reduce the potential impact that may be caused by unfavorable weather in a particular region, suitable meteorological conditions are variable and difficult to predict. If wind conditions are unfavorable ALLETE Clean Energy’sor meteorological conditions are unsuitable, our electricity generation and revenue from its wind energy facilities may be substantially below itsour expectations. The electricity produced, production tax credits received, and revenues generated by a wind energy facility are highly dependent on suitable wind conditions and associated weather conditions, which are variable and beyond ALLETE Clean Energy’sour control. We base our decisions about which wind projects to build or acquire as well as our electricity generation estimates, in part, on the findings of long-term wind and other meteorological studies conducted on the project site and its region; however, the unpredictable nature of wind conditions, weather and meteorological conditions can result in material deviations from these studies and our expectations. Furthermore, components of itsour systems could be damaged by severe weather, such as hailstorms, lightning or tornadoes. In addition, replacement and spare parts for key components of ALLETE Clean Energy’sour diverse turbine portfolio may be difficult or costly to acquire or may be unavailable. Unfavorable wind conditions, weather and atmospheric conditionsor changes to meteorological patterns could impair the effectiveness of ALLETE Clean Energy’sour wind energy facility assets, or reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of itsour wind energy facilities.
The construction, operation and maintenance of ALLETE Clean Energy’sour electric generation facilities or investment in facilities are subject to operational risks that could adversely affect our financial position, results of operations and cash flows.
The construction and operation of generating facilities involves many risks, including the performance by key contracted suppliers and maintenance providers, start-up operations risks, breakdown or failure of facilities, the dependence on the availability of wind resources, or the impact of unusual, adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. A portionSome of our facilities contain older generating equipment, which even if maintained in accordance with good engineering practices, may require significant capital expenditures to continue operating at peak efficiency. We could be subject to costs associated with any unexpected failure to produce and deliver power, including failure caused by breakdown or forced outage, as well as repairing damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events.
Item 1A. Risk Factors (Continued)
Energy Infrastructure and Related Services Risks (Continued)
As contracts with its counterparties expire, ALLETE Clean Energywe may not be able to replace them with agreements on similar terms.
ALLETE Clean Energy is party to PSAs which expire in various years between 20182020 and 2032.2039. These PSA expirations are prior to the end of the estimated useful lives of the respective wind energy facilities. If, for any reason, ALLETE Clean Energy is unable to enter into new agreements with existing or new counterparties on similar terms once the current agreements expire, or sell energy in the wholesale market resulting in similar revenue, our financial position, results of operations and cash flows could be adversely affected.affected, which includes potential impairment of property, plant and equipment.
Item 1A. Risk Factors (Continued)
ALLETE Clean Energy / Corporate and Other Risks (Continued)
Counterparties to ALLETE Clean Energy’s offtaketurbine supply, service and maintenance, or power sale agreements may not fulfill their obligations.
ALLETE Clean Energy is party to turbine supply agreements, service and maintenance agreements, and PSAs under various durations with a limited number of creditworthy counterparties. If, for any reason, any of the counterparties under these agreements do not fulfill their related contractual obligations, and ALLETE Clean Energy is unable to mitigate non-performance by a key supplier or maintenance provider or remarket thePSA energy resulting in similar revenue, our financial position, results of operations and cash flows could be adversely affected.
ALLETE has a significant amount of goodwill and intangible assets. A determination that goodwill or intangible assets have been impaired could result in a significant non-cash charge to earnings.
We had approximately $226 million of goodwill and intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2017, relating to our initial acquisition of U.S. Water Services in 2015 as well as U.S. Water Services’ subsequent acquisitions. If we change our business strategy, fail to deliver on our projected results or if market or other conditions adversely affect the operations of U.S. Water Services, we may be required to record an impairment charge. Declines in projected operating cash flows at U.S. Water Services could also result in an impairment charge. An impairment charge would result in a non-cash charge to earnings that could have an adverse effect on our results of operations.
Corporate and Other Risks
BNI Energy may be adversely impacted by its exposure to customer concentration, and environmental laws and regulations.
BNI Energy sells lignite coal to two electric generating cooperatives, Minnkota Power and Square Butte, and could be adversely impacted if these customers were unable or unwilling to fulfill their related contractual obligations. In addition, BNI Energy and its customers may be adversely impacted by environmental laws and regulations which could have an adverse effect on our financial position, results of operations and cash flows. In addition, insurance companies have decreased the available coverage for policy holders in the mining industry, impacting the availability of coverage, and leading to higher deductibles and premiums.
Real estate market conditions where our legacy Florida real estate investment is located may not improve.
The Company’s strategy related to the real estate assets of ALLETE Properties incorporates the possibility of a bulk sale of its entire portfolio, in addition to sales over time, however, continued adverse market conditions could impact the timing of land sales, which could result in little to no sales, while still incurring operating expenses such as community development district assessments and property taxes, resulting in net operating losses at ALLETE Properties. Furthermore, weak market conditions could put the properties at risk for an impairment charge. An impairment charge would result in a non-cash charge to earnings that could have an adverse effect on our results of operations.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
A discussion of our properties is included in Item 1. Business and is incorporated by reference herein.
Item 3. Legal Proceedings
Discussions of material regulatory and environmental proceedings are included in Note 4. Regulatory Matters and Note 11.9. Commitments, Guarantees and Contingencies, and are incorporated by reference herein.
We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.
Item 4. Mine Safety Disclosures
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act). Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and this Item are included in Exhibit 95 to this Form 10-K.
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the NYSE under the symbol ALE. We have paid dividends, without interruption, on our common stock since 1948. A quarterly dividend of $0.56$0.6175 per share on our common stock is payable on March 1, 2018,2020, to the shareholders of record on February 15, 2018.14, 2020. The timing and amount of future dividends will depend upon earnings, cash requirements, the financial condition of the Company, applicable government regulations and other factors deemed relevant by the ALLETE Board of Directors.
The following table shows dividends declared per share, and the high and low prices of our common stock for the periods indicated as reported by the NYSE:
|
| | | | | | | | | | |
| | | 2017 | | | 2016 | |
| | Price Range | Dividends | Price Range | Dividends |
| Quarter | High | Low | Declared | High | Low | Declared |
| First | $68.38 | $61.64 |
| $0.535 |
| $58.34 | $48.26 |
| $0.52 |
|
| Second | $74.59 | $66.81 | 0.535 |
| $64.69 | $53.47 | 0.52 |
|
| Third | $79.61 | $69.79 | 0.535 |
| $65.41 | $52.50 | 0.52 |
|
| Fourth | $81.24 | $72.96 | 0.535 |
| $66.92 | $56.48 | 0.52 |
|
| Annual Total | | |
| $2.14 |
| | |
| $2.08 |
|
As of February 1, 2018,2020, there were approximately 23,00021,000 common stock shareholders of record.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (Continued)
Performance Graph.
The following graph compares ALLETE’s cumulative Total Shareholder Return on its common stock with the cumulative return of the S&P 500 Index and the Philadelphia Utility Index. The S&P 500 Index is a capitalization-weighted index of 500 stocks designed to measure performance of the broad domestic economy through changes in the aggregate market value of 500 stocks representing all major industries. Because this composite index has a broad industry base, its performance may not closely track that of a composite index comprised solely of electric utilities. The Philadelphia Utility Index is a capitalization-weighted index of 20 utility companies involved in the generation of electricity.
The calculations assume a $100 investment on December 31, 2012,2014, and reinvestment of dividends.
| | | | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 |
| ALLETE | $100 | $127 | $146 | $140 | $183 | $218 | $100 | $96 | $126 | $150 | $158 | $174 |
| S&P 500 Index | $100 | $132 | $150 | $153 | $171 | $208 | $100 | $101 | $113 | $138 | $132 | $174 |
| Philadelphia Utility Index | $100 | $111 | $143 | $152 | $178 | $201 | $100 | $94 | $110 | $124 | $129 | $163 |
Item 6. Selected Financial Data
| | | | 2017 |
| 2016 |
| 2015 |
| 2014 |
| 2013 |
| 2019 |
| 2018 |
| 2017 |
| 2016 |
| 2015 |
|
| Millions Except Per Share Amounts | | |
Operating Revenue (a)(b) |
| $1,419.3 |
|
| $1,339.7 |
|
| $1,486.4 |
|
| $1,136.8 |
|
| $1,018.4 |
|
| $1,240.5 |
|
| $1,498.6 |
|
| $1,419.3 |
|
| $1,339.7 |
|
| $1,486.4 |
|
Operating Expenses (a)(b) |
| $1,189.5 |
|
| $1,116.2 |
|
| $1,275.7 |
|
| $948.0 |
|
| $864.3 |
|
| $1,060.7 |
|
| $1,297.4 |
|
| $1,193.4 |
|
| $1,122.7 |
|
| $1,274.7 |
|
Net Income (b)(c) |
| $172.2 |
|
| $155.8 |
|
| $141.5 |
|
| $125.5 |
|
| $104.7 |
|
| $185.5 |
|
| $174.1 |
|
| $172.2 |
|
| $155.8 |
|
| $141.5 |
|
Less: Non-Controlling Interest in Subsidiaries (c) | — |
| 0.5 |
| 0.4 |
| 0.7 |
| — |
| $(0.1) | — |
| — |
|
| $0.5 |
|
| $0.4 |
|
Net Income Attributable to ALLETE (b)(c) |
| $172.2 |
|
| $155.3 |
|
| $141.1 |
|
| $124.8 |
|
| $104.7 |
|
| $185.6 |
|
| $174.1 |
|
| $172.2 |
|
| $155.3 |
|
| $141.1 |
|
| Common Stock Dividends | 108.7 |
| 102.7 |
| 97.9 |
| 83.8 |
| 75.2 |
|
| $121.4 |
|
| $115.0 |
|
| $108.7 |
|
| $102.7 |
|
| $97.9 |
|
Earnings Retained in Business (b)(c) |
| $63.5 |
|
| $52.6 |
|
| $43.2 |
|
| $41.0 |
|
| $29.5 |
|
| $64.2 |
|
| $59.1 |
|
| $63.5 |
|
| $52.6 |
|
| $43.2 |
|
| Shares Outstanding | | |
| Year-End | 51.1 |
| 49.6 |
| 49.1 |
| 45.9 |
| 41.4 |
| 51.7 |
| 51.5 |
| 51.1 |
| 49.6 |
| 49.1 |
|
Average (d) | | | | |
| Basic | 50.8 |
| 49.3 |
| 48.3 |
| 42.9 |
| 39.7 |
| 51.6 |
| 51.3 |
| 50.8 |
| 49.3 |
| 48.3 |
|
| Diluted | 51.0 |
| 49.5 |
| 48.4 |
| 43.1 |
| 39.8 |
| 51.7 |
| 51.5 |
| 51.0 |
| 49.5 |
| 48.4 |
|
Diluted Earnings Per Share (b)(c) |
| $3.38 |
|
| $3.14 |
|
| $2.92 |
|
| $2.90 |
|
| $2.63 |
|
| $3.59 |
|
| $3.38 |
|
| $3.38 |
|
| $3.14 |
|
| $2.92 |
|
Total Assets (e) |
| $5,080.0 |
|
| $4,876.9 |
|
| $4,864.4 |
|
| $4,329.1 |
|
| $3,458.6 |
|
| $5,482.8 |
|
| $5,165.0 |
|
| $5,080.0 |
|
| $4,876.9 |
|
| $4,864.4 |
|
| Long-Term Debt |
| $1,439.2 |
|
| $1,370.4 |
|
| $1,556.7 |
|
| $1,263.2 |
|
| $1,074.9 |
|
| $1,400.9 |
|
| $1,428.5 |
|
| $1,439.2 |
|
| $1,370.4 |
|
| $1,556.7 |
|
Return on Common Equity (b)(c) | 8.6 | % | 8.4 | % | 8.0 | % | 8.6 | % | 8.3 | % | 8.4 | % | 8.3 | % | 8.6 | % | 8.4 | % | 8.0 | % |
| Common Equity Ratio | 58 | % | 55 | % | 53 | % | 54 | % | 55 | % | 56 | % | 59 | % | 58 | % | 55 | % | 53 | % |
| Dividends Declared per Common Share |
| $2.14 |
|
| $2.08 |
|
| $2.02 |
|
| $1.96 |
|
| $1.90 |
|
| $2.35 |
|
| $2.24 |
|
| $2.14 |
|
| $2.08 |
|
| $2.02 |
|
Dividend Payout Ratio (b)(c) | 63 | % | 66 | % | 69 | % | 68 | % | 72 | % | 65 | % | 66 | % | 63 | % | 66 | % | 69 | % |
| Book Value Per Share at Year-End |
| $40.46 |
|
| $38.17 |
|
| $37.18 |
|
| $35.04 |
|
| $32.43 |
|
| $43.19 |
|
| $41.85 |
|
| $40.46 |
|
| $38.17 |
|
| $37.18 |
|
| Capital Expenditures by Segment | | | | |
| Regulated Operations |
| $177.1 |
|
| $121.8 |
|
| $224.4 |
|
| $583.5 |
|
| $326.3 |
|
| $230.9 |
|
| $211.9 |
|
| $177.1 |
|
| $121.8 |
|
| $224.4 |
|
| ALLETE Clean Energy | 56.1 |
| 106.9 |
| 8.6 |
| 4.2 |
| — |
| 385.6 |
| 89.7 |
| 56.1 |
| 106.9 |
| 8.6 |
|
U.S. Water Services | 4.4 |
| 3.7 |
| 2.9 |
| — |
| — |
| — |
| 5.0 |
| 4.4 |
| 3.7 |
| 2.9 |
|
| Corporate and Other | 28.9 |
| 15.4 |
| 15.9 |
| 16.6 |
| 13.2 |
| 10.1 |
| 12.0 |
| 28.9 |
| 15.4 |
| 15.9 |
|
| Total Capital Expenditures |
| $266.5 |
|
| $247.8 |
|
| $251.8 |
|
| $604.3 |
|
| $339.5 |
|
| $626.6 |
|
| $318.6 |
|
| $266.5 |
|
| $247.8 |
|
| $251.8 |
|
| |
| (a) | In 2015, operating revenue and operating expenses included $197.7 million and $162.9 million, respectively, for the construction and sale of a wind energy facility fromby ALLETE Clean Energy to Montana-Dakota Utilities for $197.7Utilities. In 2018, operating revenue and operating expenses included $81.1 million and $162.9$67.4 million, respectively.respectively, for the sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities. |
| |
| (b) | In 2019, ALLETE sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. |
| |
| (c) | The year ended December 31, 2017 includesincluded the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.) |
| |
(c) | The non-controlling interest related to ALLETE Clean Energy’s Condon wind energy facility was acquired in April 2016. (See Note 6. Acquisitions.) |
| |
(d) | Excludes unallocated ESOP shares in 2013 and 2014. |
| |
(e) | During the first quarter of 2017, the Company identified an error related to the deferred income tax treatment associated with its Wholesale and Retail Contra AFUDC Regulatory Liability resulting in a decrease in Regulatory Assets and Deferred11. Income Taxes. The periods presented have been revised for the correction of the error. (See Note 1. Operations and Significant Accounting Policies.Tax Expense.) |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with our Consolidated Financial Statements and notes to those statements and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-K contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-K under the headings: “Forward‑Looking Statements” located on page 6 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the risks are realized.
Overview
Basis of Presentation. We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 145,000 retail customers. Minnesota Power also has 1615 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 4. Regulatory Matters.)
ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in fourfive states, approximately 535660 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 380 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.
U.S. Water Services providesprovided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. On March 26, 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.
Corporate and Otheris comprised of BNI Energy, our coal mining operations in North Dakota, our investment in Nobles 2, a 49 percent equity interest in the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota, ALLETE Properties, our legacy Florida real estate investment, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,0004,000 acres of land in Minnesota, and earnings on cash and investments.
ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2017,2019, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.
20172019 Financial Overview
The following net income discussion summarizes a comparison of the year ended December 31, 2017,2019, to the year ended December 31, 2016.2018.
Net income attributable to ALLETE in 20172019 was $172.2$185.6 million, or $3.59 per diluted share, compared to $174.1 million, or $3.38 per diluted share, compared to $155.3 million, or $3.14 per diluted share, in 2016.2018. Net income in 20172019 included the favorable impactsgain on sale of $13.0U.S. Water Services of $13.2 million after-tax, or $0.25$0.26 per share, and U.S. Water Services results of operations amounted to a net loss of $1.1 million after-tax, or $0.02 per share. Net income in 2018 included $10.2 million after-tax, or $0.20 per share, for the remeasurementsale of deferreda wind energy facility to Montana-Dakota Utilities, $3.2 million after-tax, or $0.06 per share, from U.S. Water Services and a $2.0 million after-tax, or $0.04 per share, benefit for the change in fair value of the contingent consideration liability. Earnings per share dilution in 2019 was $0.01 due to additional shares of common stock outstanding as of December 31, 2019.
Regulated Operations net income attributable to ALLETE was $154.4 million in 2019, compared to $131.0 million in 2018. Net income at Minnesota Power was higher than 2018 primarily due to lower operating and maintenance and property tax assetsexpenses, increased cost recovery rider revenue, higher transmission margins and liabilitieshigher fuel adjustment clause recoveries. These increases were partially offset by lower kWh sales. Net income at SWL&P was higher than 2018 primarily due to higher rates resulting from the TCJAimplementation of new rates on January 1, 2019. Our after-tax equity earnings in ATC were higher than 2018 primarily due to additional investments and period over period changes in ATC’s estimate of a refund liability related to the FERC decision on MISO return on equity complaints. (See Note 5. Equity Investments.)
2019 Financial Overview (Continued)
ALLETE Clean Energy net income attributable to ALLETE was $12.4 million in 2019 compared to $33.7 million in 2018. Net income in 2018 included $10.2 million after-tax for the sale of a wind energy facility to Montana-Dakota Utilities and $3.0 million of production tax credits that resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017. Net income in 2019 included lower revenue resulting from lower non-cash amortization related to the expiration of power sales agreements as well as lower wind resources and availability, and higher depreciation expense. These decreases were partially offset by $5.3 million of additional production tax credits generated in 2019 compared to production tax credits generated in 2018 as ALLETE Clean Energy continues to execute its refurbishment strategy.
U.S. Water Services net loss attributable to ALLETE was $1.1 million in 2019, compared to net income of $3.2 million in 2018. ALLETE completed the sale of U.S. Water Services in the first quarter of 2019.
Corporate and Other net income attributable to ALLETE was $19.9 million in 2019 compared to $6.2 million in 2018. Net income in 2019 included the gain on sale of U.S. Water Services of $13.2 million after-tax, of which $2.1 million after-tax was recognized in the fourth quarter of 2019 for the favorable settlement of a U.S. Water Services patent infringement case. Net income in 2019 also included higher earnings on cash and investments. Net income in 2018 included a $2.0 million after-tax benefit for the change in fair value of the contingent consideration liability.
2019 Compared to 2018
(See Note 14. Business Segments for financial results by segment.)
Regulated Operations
|
| | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Operating Revenue – Utility |
| $1,042.4 |
|
| $1,059.5 |
|
| Fuel, Purchased Power and Gas – Utility | 390.7 |
| 407.5 |
|
| Transmission Services – Utility | 69.8 |
| 69.9 |
|
| Operating and Maintenance | 201.9 |
| 220.1 |
|
| Depreciation and Amortization | 159.4 |
| 158.0 |
|
| Taxes Other than Income Taxes | 48.4 |
| 52.5 |
|
| Operating Income | 172.2 |
| 151.5 |
|
| Interest Expense | (58.9 | ) | (60.2 | ) |
| Equity Earnings in ATC | 21.7 |
| 17.5 |
|
| Other Income | 12.3 |
| 6.7 |
|
| Income Before Income Taxes | 147.3 |
| 115.5 |
|
| Income Tax Expense (Benefit) | (7.1 | ) | (15.5 | ) |
| Net Income Attributable to ALLETE | $154.4 |
| $131.0 |
|
Operating Revenue – Utility decreased $17.1 million from 2018 primarily due to lower revenue from kWh sales and conservation improvement recoveries, partially offset by increased cost recovery rider revenue, higher fuel adjustment clause recoveries and higher FERC formula-based rates.
Revenue from kWh sales decreased $43.3 million from 2018 reflecting lower sales to residential, commercial and municipal customers as well as lower sales to other power suppliers. Sales to residential and commercial customers decreased from 2018 primarily due to milder weather conditions in 2019. Sales to industrial customers in 2019 were similar to 2018 reflecting higher sales to Silver Bay Power as it ceased self-generation in the third quarter of 2019, partially offset by lower sales to Husky Energy due to an April 2018 fire at its refinery in Superior, Wisconsin. Sales to municipal customers decreased from 2018 as a result of additional customer self-generation in 2019 and the expiration of a contract with a municipal customer on June 30, 2019. Sales to other power suppliers decreased in 2019 primarily due to fewer market sales and sales under PSAs as a result of less generation available for sale, partially offset by the commencement of Minnesota Power’s PSA with Oconto Electric Cooperative in January 2019. Sales to other power suppliers are sold at market-based prices into the MISO market on a daily basis or through PSAs of various durations.
2019 Compared to 2018 (Continued)
Regulated Operations (Continued)
|
| | | | | | | | |
Kilowatt-hours Sold | 2019 |
| 2018 |
| Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipal | | | | |
| Residential | 1,130 |
| 1,140 |
| (10 | ) | (0.9 | ) |
| Commercial | 1,390 |
| 1,426 |
| (36 | ) | (2.5 | ) |
| Industrial | 7,277 |
| 7,261 |
| 16 |
| 0.2 |
|
| Municipal | 672 |
| 798 |
| (126 | ) | (15.8 | ) |
| Total Retail and Municipal | 10,469 |
| 10,625 |
| (156 | ) | (1.5 | ) |
| Other Power Suppliers | 3,185 |
| 3,953 |
| (768 | ) | (19.4 | ) |
| Total Regulated Utility Kilowatt-hours Sold | 13,654 |
| 14,578 |
| (924 | ) | (6.3 | ) |
Revenue from electric sales to taconite customers accounted for 25 percent of consolidated operating revenue in 2019 (21 percent in 2018). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 6 percent of consolidated operating revenue in 2019 (4 percent in 2018). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2019 (6 percent in 2018).
Conservation improvement program recoveries decreased $5.9 million from 2018 primarily due to a decrease in related expenditures.
Cost recovery rider revenue contributed an incremental $14.0 million over current base rates compared to 2018 (see Note 4. Regulatory Matters) primarily due to higher expenditures related to the construction of the GNTL and lower transmission margins related to our portion of CapX2020 transmission lines. Transmission margins for CapX2020 transmission lines recognized below those assumed in Minnesota Power base rates result in increased cost recovery rider revenue to offset the impact of the lower margins.
Fuel adjustment clause revenue increased $13.1 million due to period over period timing of recoveries for fuel and purchased power costs attributable to retail and municipal customers. Beginning in 2020, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. (See Note 4. Regulatory Matters.)
Revenue from wholesale customers under FERC formula-based rates increased $3.3 million from 2018 primarily due to higher rates.
Transmission revenue was similar to 2018 reflecting a $4.4 million out-of-period adjustment in 2018 for an estimated true-up of MISO rates that were billed in 2017 and credited to customers in 2019, mostly offset by lower MISO-related revenue in 2019.
Operating Expenses decreased $37.8 million, or 4 percent, from 2018.
Fuel, Purchased Power and Gas – Utility expense decreased $16.8 million, or 4 percent, from 2018 primarily due to lower kWh sales, purchased power prices and fuel costs, partially offset by higher costs of purchased power from Square Butte. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.
Operating and Maintenance expense decreased $18.2 million, or 8 percent, from 2018 primarily due to lower salary and benefit expenses, maintenance contract expenses and materials purchased for generation facilities as well as a decrease in severance expense of $2.3 million in 2019.
Taxes Other than Income Taxes decreased $4.1 million, or 8 percent, from 2018 primarily due to lower property tax expenses resulting from lower estimated taxable market values.
2019 Compared to 2018 (Continued)
Regulated Operations (Continued)
Interest Expense decreased $1.3 million, or 2 percent, from 2018 primarily due to lower average long-term debt balances for our Regulated Operations and interest on Minnesota Power’s reserve for interim rate refunds. We record interest expense for Regulated Operations primarily based on rate base and authorized capital structure, and allocate the balance to Corporate and Other.
Equity Earnings in ATC increased $4.2 million, or 24 percent, from2018 primarily due to additional investments and period over period changes in ATC’s estimate of a refund liability related to the FERC decision on MISO return on equity complaints. (See Note 5. Equity Investments.)
Other Income increased $5.6 million from2018 reflecting higher AFUDC – Equity and lower pension and other postretirement benefit plan non-service costs. (See Note 12. Pension and Other Postretirement Benefit Plans.)
Income Tax Benefit was $7.1 million in 2019 compared to income tax benefit of $15.5 million in 2018. The income tax benefit in 2019 reflects higher pre-tax income, partially offset by higher production tax credits.
ALLETE Clean Energy
|
| | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Operating Revenue | | |
Contracts with Customers – Non-utility (a) |
| $48.0 |
|
| $136.3 |
|
Other – Non-utility (b) | 11.6 |
| 23.6 |
|
Cost of Sales – Non-utility (a) | — |
| 67.4 |
|
| Operating and Maintenance | 29.5 |
| 29.9 |
|
| Depreciation and Amortization | 26.8 |
| 24.4 |
|
| Taxes Other than Income Taxes | 2.1 |
| 2.1 |
|
| Operating Income | 1.2 |
| 36.1 |
|
| Interest Expense | (2.8 | ) | (3.6 | ) |
| Other Income | 2.0 |
| 0.2 |
|
| Income Before Income Taxes | 0.4 |
| 32.7 |
|
| Income Tax Expense (Benefit) | (11.9 | ) | (1.0 | ) |
| Net Income | 12.3 |
| 33.7 |
|
Less: Non-Controlling Interest in Subsidiaries (c) | (0.1 | ) | — |
|
Net Income Attributable to ALLETE (a) | $12.4 |
| $33.7 |
|
| |
| (a) | In 2018, operating revenue and operating expenses included $81.1 million and $67.4 million, respectively, for the sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities. |
| |
| (b) | Represents non-cash amortization of differences between contract prices and estimated market prices on assumed PSAs. |
| |
| (c) | See Note 1. Operations and Significant Accounting Policies. |
Operating Revenue decreased $100.3 million from 2018 primarily due to the sale of a wind energy facility to Montana-Dakota Utilities in 2018 and lower kWh sales resulting from lower wind resources and availability. In addition, revenue decreased $12.0 million due to lower non-cash amortization related to the expiration of power sales agreements. In 2019, two PSAs expired and the related non-cash revenue was fully amortized. (See Note 1. Operations and Significant Accounting Policies)Policies – Revenue – ALLETE Clean Energy – Other and $7.9Item 7. Management’s Discussion and Analysis – Outlook – ALLETE Clean Energy.)
2019 Compared to 2018 (Continued)
ALLETE Clean Energy (Continued)
|
| | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | 2018 |
| Production and Operating Revenue | kWh | Revenue | kWh | Revenue |
| Millions | | | | |
| Wind Energy Regions | | | | |
| East | 232.9 |
|
| $21.0 |
| 264.5 |
|
| $24.1 |
|
| Midwest | 805.8 |
| 32.4 |
| 791.6 |
| 46.6 |
|
| West | 87.8 |
| 6.2 |
| 99.6 |
| 8.1 |
|
| Total Wind Energy Facilities | 1,126.5 |
| 59.6 |
| 1,155.7 |
| 78.8 |
|
| Sale of Wind Energy Facility | — |
| — |
| — |
| 81.1 |
|
| Total Production and Operating Revenue | 1,126.5 |
| $59.6 | 1,155.7 |
|
| $159.9 |
|
Cost of Sales decreased $67.4 million from 2018 due to the sale of a wind energy facility to Montana-Dakota Utilities in 2018.
Depreciation and Amortizationexpense increased $2.4 million, or 10 percent, from 2018 primarily due to additional property, plant and equipment in service.
Other Incomeincreased $1.8 million from 2018 reflecting various individually immaterial items.
Income Tax Benefit increased $10.9 million from 2018 primarily due to additional production tax credits generated in 2019 and lower pre-tax income. The income tax benefit reflected production tax credits generated of $10.9 million in 2019 and $5.6 million in 2018. The income tax benefit in 2018 also reflected $3.0 million of production tax credits that resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017.
U.S. Water Services
|
| | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Operating Revenue |
| $33.4 |
|
| $172.1 |
|
| Net Income (Loss) Attributable to ALLETE | $(1.1) |
| $3.2 |
|
Operating Revenue decreased $138.7 million from 2018. ALLETE sold U.S. Water Services in the first quarter of 2019. (See Note 1. Operations and Significant Accounting Policies.)
Corporate and Other
Operating Revenue decreased $2.0 million, or 2 percent, from 2018 primarily due to lower revenue from non-rate base generation and lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses and fewer tons sold in 2019 compared to 2018. These increases were partially offset by higher land sales at ALLETE Properties.
Net Income Attributable to ALLETE was $19.9 million in 2019 compared to $6.2 million in 2018. Net income in 2019 included the gain on sale of U.S. Water Services of $13.2 million after-tax, or $0.16 per share,of which $2.1 million after-tax was recognized in the fourth quarter of 2019 for the favorable settlement of a U.S. Water Services patent infringement case. Net income in 2019 also included higher earnings on cash and investments. Net income in 2018 included a $2.0 million after-tax benefit for the change in fair value of the contingent consideration liability. Net income at BNI Energy was $7.4 million in 2019 compared to $6.8 million in 2018, reflecting higher earnings from investments in 2019. Net income at ALLETE Properties was $0.3 million in 2019 compared to a net loss of $0.5 million in 2018 reflecting higher land sales in 2019.
Income Taxes – Consolidated
For the year ended December 31, 2019, the effective tax rate was a benefit of 3.7 percent (benefit of 9.8 percent for the year ended December 31, 2018). The effective tax rate for 2019 was a lower benefit primarily due to higher pre-tax income resulting from the gain on sale of U.S. Water Services and a higher effective tax rate on the gain, partially offset by higher production tax credits. (See Note 11. Income Tax Expense.)
2018 Compared to 2017
(See Note 14. Business Segments for financial results by segment.)
Regulated Operations
|
| | | | | | |
| Year Ended December 31 | 2018 |
| 2017 |
|
| Millions | | |
| Operating Revenue – Utility |
| $1,059.5 |
|
| $1,063.8 |
|
| Fuel, Purchased Power and Gas – Utility | 407.5 |
| 396.9 |
|
| Transmission Services – Utility | 69.9 |
| 71.2 |
|
| Operating and Maintenance | 220.1 |
| 227.3 |
|
| Depreciation and Amortization | 158.0 |
| 132.6 |
|
| Taxes Other than Income Taxes | 52.5 |
| 51.1 |
|
| Operating Income | 151.5 |
| 184.7 |
|
| Interest Expense | (60.2 | ) | (57.0 | ) |
| Equity Earnings in ATC | 17.5 |
| 22.5 |
|
| Other Income | 6.7 |
| 5.4 |
|
| Income Before Income Taxes | 115.5 |
| 155.6 |
|
| Income Tax Expense (Benefit) | (15.5 | ) | 27.2 |
|
| Net Income Attributable to ALLETE | $131.0 | $128.4 |
Operating Revenue – Utility decreased $4.3 million from 2017 primarily due to lower transmission revenue, the impact of a regulatory outcome in 2017 related to the allocation of North Dakota investment tax credits, provision for tax reform refund related to income tax changes resulting from the TCJA, and lower financial incentives under the Minnesota conservation improvement program, partially offset by higher revenue from kWh sales, cost recovery rider revenue, fuel clause adjustment recoveries, and conservation improvement program recoveries.
Transmission revenue decreased $15.0 million primarily due to lower MISO-related revenue and a $4.4 million out-of-period adjustment for an estimated true-up of MISO rates that were billed in 2017 and credited to customers in 2019.
Revenue decreased $14.0 million due to the impact of a regulatory outcome of the MPUC’s modification of its November 2016 order onin 2017 related to the allocation of North Dakota investment tax credits. NetThis decrease in revenue was offset by the income tax impacts of the regulatory outcome resulting in no impact to net income for Regulated Operations. (See Note 4. Regulatory Matters and Income Tax Benefit.)
Revenue decreased $11.9 million from 2017 reflecting income tax changes resulting from the TCJA primarily related to a provision for tax reform refund for the benefit of excess deferred income taxes in 2018. We have recorded the benefit of these excess deferred income taxes for Minnesota Power and SWL&P as regulatory liabilities. (See Note 4. Regulatory Matters.)
Financial incentives under the Minnesota conservation improvement program were lower by $2.5 million from 2017 as a result of MPUC-approved modifications to the mechanism for calculating the financial incentives.
Interim retail rates of $29.5 million collected in 2018 were fully offset by the recognition of a corresponding reserve throughout the year. In the fourth quarter of 2017, Minnesota Power recognized interim retail rate refund reserves of $31.6 million to fully offset interim retail rates collected throughout the year in 2017 also included a non‑cash $11.4 million after-tax charge, or $0.22 per share, fordue to the regulatory outcome of the MPUC’s decision in Minnesota Power’s 2016 general rate case at a hearing on January 18, 2018.
Revenue increased $13.5 million from 2017 reflecting higher kWh sales to Residential and Commercial customers, and higher pricing on sales to Other Power Suppliers. Sales to Residential and Commercial customers increased in 2018 primarily due to more favorable weather conditions in 2018 compared to 2017. Sales to Industrial customers decreased 0.9 percent reflecting lower sales to UPM Blandin as a result of the closure of the smaller of its two paper machines in the fourth quarter of 2017 and Husky Energy due to an April 2018 fire at its refinery in Superior, Wisconsin, partially offset by increased taconite production. Revenue from Other Power Suppliers increased due to higher pricing on sales, partially offset by a 2.1 percent decrease in kWh sales from 2017. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through PSAs of various durations.
2018 Compared to 2017 (Continued)
Regulated Operations (Continued)
|
| | | | | | | | |
Kilowatt-hours Sold | 2018 |
| 2017 |
| Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipal | | | | |
| Residential | 1,140 |
| 1,096 |
| 44 |
| 4.0 |
|
| Commercial | 1,426 |
| 1,420 |
| 6 |
| 0.4 |
|
| Industrial | 7,261 |
| 7,327 |
| (66 | ) | (0.9 | ) |
| Municipal | 798 |
| 799 |
| (1 | ) | (0.1 | ) |
| Total Retail and Municipal | 10,625 |
| 10,642 |
| (17 | ) | (0.2 | ) |
| Other Power Suppliers | 3,953 |
| 4,039 |
| (86 | ) | (2.1 | ) |
| Total Regulated Utility Kilowatt-hours Sold | 14,578 |
| 14,681 |
| (103 | ) | (0.7 | ) |
Revenue from electric sales to taconite customers accounted for 21 percent of consolidated operating revenue in 2018 (22 percent in 2017). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 4 percent of consolidated operating revenue in 2018 (5 percent in 2017). Revenue from electric sales to pipelines and other industrial customers accounted for 6 percent of consolidated operating revenue in 2018 (7 percent in 2017).
Cost recovery rider revenue increased $13.0 million primarily due to higher expenditures related to the construction of the GNTL and fewer production tax credits recognized by Minnesota Power. If production tax credits are recognized at a level below those assumed in Minnesota Power’s base rates, an increase in cost recovery rider revenue is recognized to offset the impact of lower production tax credits on income tax expense.
Fuel adjustment clause recoveries increased $7.9 million due to higher fuel and purchased power costs attributable to retail and municipal customers.
Conservation improvement program recoveries increased $3.5 million from 2017 primarily due to an increase in related expenditures. (See Operating Expenses - Operating and Maintenance.)
Operating Expenses increased $28.9 million, or 3 percent, from 2017.
Fuel, Purchased Power and Gas – Utility expense increased $10.6 million, or 3 percent, from 2017 primarily due to higher purchased power prices and higher fuel costs, partially offset by a $19.5 million expense in 2017 for the MPUC’s decision disallowing recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs. At a hearing on January 18, 2018, the MPUC disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology. (See Note 4. Regulatory Matters.) Net incomemethodology resulting in 2016 included the favorable impact related to the change in fair value of the contingent consideration liability of $13.6 million after-tax, or $0.28 per share. Net income in 2016 also included an adverse impact of $8.8 million after‑tax, or $0.18 per share, for the regulatory outcome of the November 2016 MPUC order on the allocation of North Dakota investment tax credits, a $3.3 million after‑tax, or $0.07 per share, goodwill impairment charge and a $0.9 million after-tax expense, or $0.02 per share, related to the repayment of long-term debt at ALLETE Clean Energy. Earnings per share dilution in 2017 was $0.11 due to additional shares of common stock outstanding as of December 31, 2017.
2017 Financial Overview (Continued)
Regulated Operations net income attributable to ALLETE was $128.4 million in 2017, compared to $135.5 million in 2016. Net income in 2017 at Minnesota Power decreased $9.8 million after-tax reflecting a non-cash $11.4 million after-tax charge for the MPUC’s decision disallowing the recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology. In addition, net income decreased due to lower kWh sales to other power suppliers as a result of higher industrial sales coupled with lower market prices, higher interest and taxes other than income taxes, and lower kWh sales to residential, commercial and municipal customers due to milder temperatures in 2017. These decreases were partially offset by lower depreciation expense of $14.6 million after-tax resulting from the MPUC’s decision to modify the depreciable lives at Boswell, and higher industrial kWh sales. Interim retail rate refund reserves fully offset the interim retail rates recognized during 2017 due to the regulatory outcome of the MPUC’s decisions in Minnesota Power’s 2016 general rate case on January 18, 2018. Our equity earnings in ATC for 2017 increased $2.6 million after‑tax primarily due to additional investments in ATC and period over period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints.
ALLETE Clean Energy net income attributable to ALLETE was $41.5 million in 2017 compared to $13.4 million in 2016. Net income in 2017 reflected a $23.6 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, increased production tax credits due to the requalification of WTGs for production tax credits at its Storm Lake I, Storm Lake II and Lake Benton wind energy facilities, lower operating and maintenance expenses, and lower interest expense compared to 2016. Net income in 2016 included a $3.3 million after-tax goodwill impairment charge and a $0.9 million after-tax expense related to the repayment of long-term debt. Net income in 2016 also included an allocation of earnings to a non‑controlling interest in the limited liability company that owns the Condon wind energy facility, which was acquired by ALLETE Clean Energy in April 2016. (See Note 6. Acquisitions.)
U.S. Water Services net income attributable to ALLETE was $10.7 million in 2017, compared to $1.5 million in 2016. Net income in 2017 reflected a $9.2 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, and higher operating revenue, partially offset by increased operating expenses as a result of investments for future growth in waste treatment and water safety applications. Net income in 2017 also included a net loss of $0.8 million primarily for transaction fees and amortization expense of the Tonka Water acquisition on September 1, 2017. (See Note 6. Acquisitions.)
Corporate and Other net loss attributable to ALLETE was $8.4 million in 2017, compared to net income of $4.9 million in 2016. The net loss in 2017 included additional income tax expense of $19.8 million after-tax for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. The net loss in 2017 also included a $7.9 million after‑tax favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits, lower accretion expense relating to the contingent consideration liability, and lower interest expense. Net income in 2016 included an after-tax gain of $13.6 million related to the change in fair value of the contingent consideration liability, partially offset by an $8.8 million after-tax adverse impact for the regulatory outcome of the November 2016 MPUC order.
2017 Compared to 2016
(See Note 17. Business Segments for financial results by segment.)
Regulated Operations
|
| | | | | | |
| Year Ended December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Operating Revenue – Utility |
| $1,063.8 |
|
| $1,000.7 |
|
| Fuel, Purchased Power and Gas – Utility | 396.9 |
| 339.9 |
|
| Transmission Services – Utility | 71.2 |
| 65.2 |
|
| Operating and Maintenance | 223.1 |
| 220.7 |
|
| Depreciation and Amortization | 132.6 |
| 154.3 |
|
| Taxes Other than Income Taxes | 51.1 |
| 47.7 |
|
| Operating Income | 188.9 |
| 172.9 |
|
| Interest Expense | (57.0 | ) | (52.1 | ) |
| Equity Earnings in ATC | 22.5 |
| 18.5 |
|
| Other Income | 1.2 |
| 2.1 |
|
| Income Before Income Taxes | 155.6 |
| 141.4 |
|
| Income Tax Expense | 27.2 |
| 5.9 |
|
| Net Income Attributable to ALLETE | $128.4 |
| $135.5 |
|
Operating Revenue – Utility increased $63.1 million, or 6 percent, from 2016 primarily due to the period over period impact of the regulatory outcomes related to the allocation of North Dakota investment tax credits, as well as higher fuel adjustment clause recoveries, conservation improvement program recoveries and revenue from kWh sales, partially offset by lower FERC formula-based rates, financial incentives under the conservation improvement program and transmission revenue. Interim retail rate refund reserves fully offset the interim retail rates recognized during 2017.
Revenue increased $29.3 million due to the period over period impact of the regulatory outcomes related to the allocation of North Dakota investment tax credits. As a result of the favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits, operating revenue increased approximately $14 million in 2017. In 2016, operating revenue decreased approximately $15 million as a result of the adverse impact for the regulatory outcome of the November 2016 MPUC order. (See Note 4. Regulatory Matters.)
Fuel adjustment clause recoveries increased $24.4 million due to higher fuel and purchased power costs attributable to retail and municipal customers. (See Operating Expenses - Fuel, Purchased Power and Gas – Utility.)
Conservation improvement program recoveries increased $7.2 million from 2016 primarily due to an increase in related expenditures. (See Operating Expenses - Operating and Maintenance.)
Revenue from kWh sales increased $3.9 million from 2016 primarily due to higher sales to Industrial customers. Sales to Industrial customers increased 13.5 percent primarily due to increased taconite production and the commencement of a long‑term PSA with Silver Bay Power in June 2016. Sales to Other Power Suppliers decreased 6.4 percent from 2016 as a result of increased sales to Industrial customers. Sales to Other Power Suppliers are sold at market‑based prices into the MISO market on a daily basis or through bilateral agreements of various durations; market prices were lower in 2017 compared to 2016. Sales to Residential, Commercial and Municipal customers decreased primarily due to milder temperatures in 2017.
2017 Compared to 2016 (Continued)
Regulated Operations (Continued)
|
| | | | | | | | |
Kilowatt-hours Sold | 2017 |
| 2016 |
| Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipal | | | | |
| Residential | 1,096 |
| 1,102 |
| (6 | ) | (0.5 | ) |
| Commercial | 1,420 |
| 1,442 |
| (22 | ) | (1.5 | ) |
| Industrial | 7,327 |
| 6,456 |
| 871 |
| 13.5 |
|
| Municipal | 799 |
| 816 |
| (17 | ) | (2.1 | ) |
| Total Retail and Municipal | 10,642 |
| 9,816 |
| 826 |
| 8.4 |
|
| Other Power Suppliers | 4,039 |
| 4,316 |
| (277 | ) | (6.4 | ) |
| Total Regulated Utility Kilowatt-hours Sold | 14,681 |
| 14,132 |
| 549 |
| 3.9 |
|
Revenue from electric sales to taconite and iron concentrate customers accounted for 22 percent of consolidated operating revenue in 2017 (18 percent in 2016). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of consolidated operating revenue in 2017 (6 percent in 2016). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2017 (7 percent in 2016).
Interim retail rates for Minnesota Power were approved by the MPUC and became effective January 1, 2017. Interim retail rate refund reserves of $31.6 million fully offset the interim retail rates recognized during 2017 due to the regulatory outcome of the MPUC’s decision in Minnesota Power’s 2016 general rate case on January 18, 2018. (See Note 4. Regulatory Matters.)
Revenue from wholesale customers under FERC formula-based rates decreased $4.9 million from 2016 primarily due to lower rates.
Financial incentives under the conservation improvement program decreased $1.9 million from 2016.
Transmission revenue decreased $1.7 million primarily due to lower MISO-related revenue, partially offset by period over period changes in the estimate of a refund liability related to MISO return on equity complaints. (See Operating Expenses - Transmission Services – Utility.)
Operating Expenses increased $47.1 million, or 6 percent, from 2016.
Fuel, Purchased Power and Gas – Utility expense increased $57.0 million, or 17 percent, from 2016 primarily due to increased kWh sales, higher fuel costs and a $19.5 million expense forcharge in the MPUC’s decision disallowing recoveryfourth quarter of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs at a hearing on January 18, 2018, due to the anticipated adoption of a forward-looking fuel adjustment clause methodology. These increases were partially offset by lower purchased power prices.2017. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause. (See Operating Revenue – Utility.Utility.)
Transmission Services – Utility Operating and Maintenanceexpense increased $6.0decreased $7.2 million, or 93 percent, from 20162017 primarily due to higher MISO-related expense. (See Operating Revenue – Utility.)
Operatinglower salary and Maintenance expense increased $2.4 million, or 1 percent, from 2016 primarily due tobenefit expenses, and lower materials purchased for generation facilities, partially offset by a $7.2$3.5 million increase in conservation improvement program expenses and additional severance expense of $1.9 million in 2017. Conservation improvement program expenses are recovered from certain retail customers.2018. (SeeOperating Revenue – Utility.) This increase was partially offset by lower materials purchased for generation facilities. Operating and Maintenance expense in 2016 included a $3.6 million sales tax refund, partially offset by higher storm restoration costs of $2.9 million related to severe wind storms across Minnesota Power’s service territory in July 2016.
2017 Compared to 2016 (Continued)
Regulated Operations (Continued)
Depreciation and Amortization expense decreased $21.7increased $25.4 million, or 1419 percent, from 20162017 primarily due to modifications of the depreciable lives for Boswell partially offset byand additional property, plant and equipment in service. At a hearing on January 18, 2018,As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC decided to extendextended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050, and shortenshortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million in 2017. Subsequently, as part of the reconsideration of its decision in Minnesota Power’s 2016 general rate case, the MPUC reduced the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035, resulting in higher depreciation expense in 2018. The increase in depreciation expense in 2018 was offset mostly by the benefits of the lower federal income tax rate enacted as part of the TCJA. (See Note 4. Regulatory Matters and Income Tax Benefit.)
Taxes Other than Income Taxes
2018 Compared to 2017 (Continued)
Regulated Operations (Continued)
Interest Expenseincreased $3.4$3.2 million, or 76 percent, from 2016 primarily due to higher property tax expenses resulting from higher taxable plant.
Interest Expense increased $4.9 million, or 9 percent, from 20162017 primarily due to higher average long-term debt balances, higher interest rates.rates and $0.5 million of interest on Minnesota Power’s reserve for interim rate refunds. We record interest expense for Regulated Operations primarily based on rate base and authorized capital structure, and allocate the balance to Corporate and Other.
Equity Earnings in ATC increased $4.0decreased $5.0 million, or 22 percent, from2016 primarily due to additional investments in ATC and period over period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints. (See Note 5. Investment in ATC.)
Income Tax Expense increased $21.3 million from 20162017 primarily due to the period over periodfederal income tax rate change enacted as part of the TCJA, partially offset by additional investments in ATC. (See Note 5. Equity Investments.)
Income Tax Benefit was $15.5 million in 2018 compared to income tax expense of $27.2 million in 2017. The income tax benefit in 2018 reflects the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, the amortization of excess deferred income tax benefit resulting from the TCJA and lower pre-tax income. Income tax expense in 2017 included the impact of thea regulatory outcomesoutcome in 2017 related to the allocation of North Dakota investment tax credits and higher pre-tax income. The TCJA did not have an impact on income tax expense for our Regulated Operations as the remeasurement of deferred income tax assets and liabilities primarily resulted in the recording of regulatory assets and liabilities.credits.
In 2017, as a result of the favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits, Regulated Operations increased operating revenue and reduced the corresponding regulatory liability by approximately $14$14.0 million resulting in an income tax expense of $6.1 million. In addition, Regulated Operations recorded an income tax expense of $7.9 million for North Dakota investment tax credits transferred to Corporate and Other, resulting in no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax benefit of $7.9 million for the North Dakota investment tax credits transferred from Regulated Operations.
In 2016, as a result of the adverse impact for the regulatory outcome of the November 2016 MPUC order, Regulated Operations reduced operating revenue and recorded a corresponding regulatory liability for approximately $15 million resulting in an income tax benefit of $6.2 million. In addition, Regulated Operations recorded an income tax benefit of $8.8 million for North Dakota investment tax credits transferred from Corporate and Other, resulting in no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax expense of $8.8 million for the North Dakota investment tax credits transferred to Regulated Operations.
ALLETE Clean Energy
| | | Year Ended December 31 | 2017 |
| 2016 |
| 2018 |
| 2017 |
|
| Millions | | |
| Operating Revenue |
| $80.5 |
|
| $80.5 |
| |
Net Income Attributable to ALLETE (a) | $41.5 |
| $13.4 |
| |
Contracts with Customers – Non-utility (a) | |
| $136.3 |
|
| $56.9 |
|
Other – Non-utility (b) | | 23.6 |
| 23.6 |
|
Cost of Sales – Non-utility (a) | | 67.4 |
| — |
|
| Operating and Maintenance | | 29.9 |
| 23.5 |
|
| Depreciation and Amortization | | 24.4 |
| 23.4 |
|
| Taxes Other than Income Taxes | | 2.1 |
| 2.2 |
|
| Operating Income | | 36.1 |
| 31.4 |
|
| Interest Expense | | (3.6 | ) | (4.2 | ) |
| Other Income | | 0.2 |
| 0.1 |
|
| Income Before Income Taxes | | 32.7 |
| 27.3 |
|
Income Tax Expense (Benefit) (c) | | (1.0 | ) | (14.2 | ) |
| Net Income Attributable to ALLETE | | $33.7 |
| $41.5 |
|
| |
| (a) | ResultsIn 2018, operating revenue and operating expenses included $81.1 million and $67.4 million, respectively, for the sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities. |
| |
| (b) | Represents non-cash amortization of differences between contract prices and estimated market prices on assumed PSAs. (See Note 1. Operations and Significant Accounting Policies.) |
| |
| (c) | Income Tax Benefit in 2017 include a $23.6 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. |
Operating Revenueis consistent with 2016 as lower kWh sales at increased $79.4 million from 2017 due to the sale of a wind energy facilities resulting from lower wind resources were offset by higher amortization of PSAs. (See Note 1. Operations and Significant Accounting Policies.)facility to Montana-Dakota Utilities in 2018.
20172018 Compared to 20162017 (Continued)
ALLETE Clean Energy (Continued)
|
| | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | 2016 |
| Production and Operating Revenue | kWh | Revenue | kWh | Revenue |
| Millions | | | | |
| Wind Energy Facility | | | | |
| Lake Benton | 241.8 |
|
| $12.3 |
| 254.7 |
|
| $12.8 |
|
| Storm Lake II | 152.6 |
| 10.0 |
| 154.8 |
| 10.1 |
|
| Condon | 90.7 |
| 7.5 |
| 96.9 |
| 8.2 |
|
| Storm Lake I | 215.6 |
| 12.4 |
| 222.3 |
| 11.6 |
|
| Chanarambie/Viking | 263.5 |
| 13.9 |
| 278.8 |
| 13.4 |
|
| Armenia Mountain | 267.4 |
| 24.4 |
| 268.2 |
| 24.4 |
|
| Total Production and Operating Revenue | 1,231.6 |
| $80.5 | 1,275.7 |
|
| $80.5 |
|
|
| | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | 2017 |
| Production and Operating Revenue | kWh | Revenue | kWh | Revenue |
| Millions | | | | |
| Wind Energy Regions | | | | |
| East | 264.5 |
|
| $24.1 |
| 267.4 |
|
| $24.4 |
|
| Midwest | 791.6 |
| 46.6 |
| 873.5 |
| 48.6 |
|
| West | 99.6 |
| 8.1 |
| 90.7 |
| 7.5 |
|
| Total Wind Energy Facilities | 1,155.7 |
| 78.8 |
| 1,231.6 |
| 80.5 |
|
| Sale of Wind Energy Facility | — |
| 81.1 |
| — |
| — |
|
| Total Production and Operating Revenue | 1,155.7 |
| $159.9 | 1,231.6 |
|
| $80.5 |
|
Net Income Attributable to ALLETE Cost of Salesincreased $28.1$67.4 million from 2016. Net income2017 due to the sale of a wind energy facility to Montana-Dakota Utilities in 2018.
Operating and Maintenanceexpense increased $6.4 million, or 27 percent, from 2017 primarily due higher professional services and routine maintenance costs.
Income Tax Benefit decreased $13.2 million from 2017. Income tax benefit in 2017 included a $23.6 million after‑taxafter-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, increasedTCJA. The income tax benefit in 2018 reflected production tax credits due togenerated of $5.6 million, $3.0 million of production tax credits that resulted from the requalificationretrospective qualification of WTGs at ALLETE Clean Energy’s Storm Lake I, Storm Lake II and Lake Bentonadditional wind energy facilities, lower operating and maintenance expense, and lower interest expense compared to 2016. Net incometurbine generators in 2016 included a $3.3 million after-tax goodwill impairment charge and a $0.9 million after-tax expense related to the repayment of long-term debt. Net income in 2016 also included an allocation of earnings to a non-controlling interest in the limited liability company that owns the Condon wind energy facility, which was acquired by ALLETE Clean Energy in April 2016. (See Note 6. Acquisitions.)2017, and higher pre-tax income.
U.S. Water Services
| | | Year Ended December 31 | 2017 |
| 2016 |
| 2018 |
| 2017 |
|
| Millions | | | | |
| Operating Revenue |
| $151.8 |
|
| $137.5 |
|
| $172.1 |
|
| $151.8 |
|
Net Income Attributable to ALLETE (a) | $10.7 |
| $1.5 |
| $3.2 |
| $10.7 |
|
| |
| (a) | Results in 2017 include a $9.2 million after-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. |
Operating Revenue increased $14.3$20.3 million from 2016 primarily due to the acquisitions of WEST in October 2016 and Tonka Water in September 2017. (See Note 6. Acquisitions.) Revenue from chemical sales and related services was $116.0$138.6 million in 20172018 compared to $110.5$132.0 million in 2016.2017. Revenue from equipment salescapital projects was $35.8$33.5 million for 20172018 compared to $27.0$19.8 million in 2016; equipment2017. Revenue in 2018 reflected a full year of sales can significantly fluctuate from period to period.Tonka Water, which was acquired in September 2017.
Net Income Attributable to ALLETE increased$9.2decreased $7.5 million from 2016.2017. Net income in 2017 included a $9.2 million after‑taxafter-tax benefit due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA,TCJA. Net income in 2018 included increased revenue primarily due to higher capital project sales and higher operating revenue,sales of chemicals and related services, partially offset by increasedhigher operating expenses as a result of investments for future growth in waste treatment and water safety applications.expenses. Net income in 2017 also2018 included a net loss$0.6 million of $0.8 million primarilyafter-tax expense recognized as cost of sales related to purchase accounting for transaction fees and amortization expense of the Tonka Water acquisition on September 1, 2017. (See Note 6. Acquisitions.)sales backlog.
Cash flow from operations for U.S. Water Services was approximately $12 million in 2017 compared to approximately $11 million in 2016.
Corporate and Other
Operating Revenue increased $2.2 decreased $16.1 million, or 213 percent, from 20162017 primarily due to an increasea decrease in land sales at ALLETE Properties and lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of higherlower expenses and record coal salesfewer tons sold in 2017, partially offset by a decrease in land sales at ALLETE Properties. Operating revenue in 2016 included the sale of ALLETE Properties’ Ormond Crossings project and Lake Swamp wetland mitigation bank for approximately $21 million.2018 compared to 2017.
2017 Compared to 2016 (Continued)
Corporate and Other (Continued)
Net LossIncome Attributable to ALLETEwas $8.4$6.2 million in 20172018 compared to a net incomeloss of $4.9$8.4 million in 2016.2017. The net loss in 2017 included aadditional income tax expense of $19.8 million after-tax expense due tofor the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. The net loss in 2017 also includedTCJA and a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits, lower accretion expense relating to the contingent consideration liability, and lower interest expense.credits. Net income in 20162018 included an after‑tax gain of $13.6 million related toincrease for the change in fair value of the contingent consideration liability partially offset by an $8.8of $1.3 million after-tax adverse impact for the regulatory outcome of the November 2016 MPUC order.after-tax.
2018 Compared to 2017 (Continued)
Corporate and Other (Continued)
Net income at BNI Energy was $6.8 million in 2018 compared to $4.5 million in 2017. Net income in 2017 which included a $3.1 million after-tax expense due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, partially offset by more tons sold; net income in 2016 was $6.8 million.TCJA. The net loss at ALLETE Properties was $0.5 million in 2018 compared to a net loss of $8.8 million in 2017. The net loss in 2017 which included a $7.8 million after-tax expense for the remeasurement of deferred income tax assets and liabilities resulting from the TCJA; net income in 2016 was $0.7 million.TCJA.
Income Taxes – Consolidated
For the year ended December 31, 2017,2018, the effective tax rate was 7.9a benefit of 9.8 percent (11.3(expense of 7.9 percent for the year ended December 31, 2016)2017). The decrease from 20162017 was primarily due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, the amortization of excess deferred income tax benefit resulting from the TCJA and lower pre-tax income in 2018, partially offset by the remeasurement of deferred income tax assets and liabilities resulting from the TCJA and increased production tax credits, partially offset by higher pre-tax income. (See Regulated Operations - Income Tax Expense.)in 2017. The effective rate deviated from the combined statutory rate of approximately 41 percent primarily due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, and production tax credits. (See Note 13. Income Tax Expense.)
2016 Compared to 2015
(See Note 17. Business Segments for financial results by segment.)
Regulated Operations
|
| | | | | | |
| Year Ended December 31 | 2016 |
| 2015 |
|
| Millions | | |
| Operating Revenue – Utility |
| $1,000.7 |
|
| $991.2 |
|
| Fuel, Purchased Power and Gas – Utility | 339.9 |
| 336.0 |
|
| Transmission Services – Utility | 65.2 |
| 54.1 |
|
| Operating and Maintenance | 220.7 |
| 229.6 |
|
| Depreciation and Amortization | 154.3 |
| 135.1 |
|
| Taxes Other than Income Taxes | 47.7 |
| 46.2 |
|
| Operating Income | 172.9 |
| 190.2 |
|
| Interest Expense | (52.1 | ) | (53.9 | ) |
| Equity Earnings in ATC | 18.5 |
| 16.3 |
|
| Other Income | 2.1 |
| 3.4 |
|
| Income Before Income Taxes | 141.4 |
| 156.0 |
|
| Income Tax Expense | 5.9 |
| 24.4 |
|
| Net Income Attributable to ALLETE | $135.5 | $131.6 |
Operating Revenue – Utility increased $9.5 million, or 1 percent, from 2015 primarily due to higher transmission revenue, cost recovery rider revenue, pricing on PSAs with Other Power Suppliers and FERC formula-based rates, partially offset by the adverse impact for the regulatory outcome of the November 2016 MPUC order related to the allocation of North Dakota investment tax credits as well as lower conservation improvement program recoveries.
Transmission revenue increased $9.7 million primarily due to period over period changes in our estimate of a refund liability related to MISO return on equity complaints and higher MISO-related revenue. (See Operating Expenses - Transmission Services – Utility.)
2016 Compared to 2015 (Continued)
Regulated Operations (Continued)
Cost recovery rider revenue increased $7.5 million primarily due to the completion of the Boswell Unit 4 environmental upgrade in the fourth quarter of 2015.
Despite lower kWh sales, revenue increased $4.9 million from 2015 primarily due to higher pricing on PSAs with Other Power Suppliers in 2016. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. Sales to industrial customers decreased 2.7 percent primarily due to reduced taconite production. In addition, demand revenue from industrial customers was down in 2016 as a result of lower demand nominations.
|
| | | | | | | | |
Kilowatt-hours Sold | 2016 |
| 2015 |
| Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipal | | | | |
| Residential | 1,102 |
| 1,113 |
| (11 | ) | (1.0 | ) |
| Commercial | 1,442 |
| 1,462 |
| (20 | ) | (1.4 | ) |
| Industrial | 6,456 |
| 6,635 |
| (179 | ) | (2.7 | ) |
| Municipal | 816 |
| 833 |
| (17 | ) | (2.0 | ) |
| Total Retail and Municipal | 9,816 |
| 10,043 |
| (227 | ) | (2.3 | ) |
| Other Power Suppliers | 4,316 |
| 4,310 |
| 6 |
| 0.1 |
|
| Total Regulated Utility Kilowatt-hours Sold | 14,132 |
| 14,353 |
| (221 | ) | (1.5 | ) |
Revenue from electric sales to taconite and iron concentrate customers accounted for 18 percent of consolidated operating revenue in 2016(17 percent in 2015). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 6 percent of consolidated operating revenue in 2016 (6 percent in 2015). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2016 (6 percent in 2015).
Revenue from wholesale customers under FERC formula-based rates increased $3.8 million primarily due to additional environmental and other investments.
Revenue decreased $15.0 million due to the adverse impact for the regulatory outcome of the November 2016 MPUC order related to the allocation of North Dakota investment tax credits. (See Note 4. Regulatory Matters.)
Conservation improvement program recoveries decreased $4.1 million from 2015 primarily due to a reduction in related expenditures. (See Operating Expenses - Operating and Maintenance Expense.)
Operating Expenses increased $26.8 million, or 3 percent, from 2015.
Fuel, Purchased Power and Gas – Utility expense increased $3.9 million, or 1 percent, from 2015 primarily due to higher fuel and purchased power prices in 2016 compared to 2015, partially offset by lower kWh sales in 2016. Fuel and purchased power expense related to retail and municipal customers is recovered through the fuel adjustment clause.
Transmission Services – Utility expense increased $11.1 million, or 21 percent, from 2015 primarily due to higher MISO‑related expense and period over period changes in our estimate of a refund for MISO transmission expense related to MISO return on equity complaints. (See Operating Revenue and Note 4. Regulatory Matters.)
Operating and Maintenance expense decreased $8.9 million, or 4 percent, from 2015, primarily due to lower pension and other postretirement benefit expenses (see Note 15. Pension and Other Postretirement Benefit Plans), a $3.6 million sales tax refund received in 2016 and a $4.1 million decrease in conservation improvement program expenses. Conservation improvement program expenses are recovered from certain retail customers. (See Operating Revenue.) Operating and Maintenance expense included higher storm restoration costs of $2.9 million related to severe wind storms across Minnesota Power’s service territory in July 2016.
2016 Compared to 2015 (Continued)
Regulated Operations (Continued)
Depreciation and Amortization expense increased $19.2 million, or 14 percent, from 2015 primarily due to additional property, plant and equipment in service.
Taxes Other than Income Taxes increased $1.5 million, or 3 percent, from 2015 primarily due to higher property tax expenses resulting from higher taxable plant.
Interest Expense decreased $1.8 million, or 3 percent, from 2015 primarily due to lower average interest rates. We record interest expense for Regulated Operations based on Minnesota Power’s rate base and authorized capital structure, and allocate the balance to Corporate and Other.
Equity Earnings in ATC increased $2.2 million, or 13 percent, from2015 primarily due to additional investments in ATC and period over period changes in ATC’s estimate of a refund liability related to MISO return on equity complaints.
Other Income decreased $1.3 million, or 38 percent, from 2015 primarily due to lower AFUDC–Equity.
Income Tax Expense decreased $18.5 million, or 76 percent, from 2015 due to lower pre-tax income, higher production tax credits and the adverse impact for the regulatory outcome of the November 2016 MPUC order related to the allocation of North Dakota investment tax credits. (See Note 4. Regulatory Matters.)
As a result of the adverse impact for the regulatory outcome of the November 2016 MPUC order, Regulated Operations reduced operating revenue and recorded a corresponding regulatory liability for approximately $15 million resulting in an income tax benefit of $6.2 million in 2016. In addition, Regulated Operations recorded an income tax benefit of $8.8 million for North Dakota investment tax credits transferred from Corporate and Other, resulting in no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax expense of $8.8 million for the North Dakota investment tax credits transferred to Regulated Operations.
ALLETE Clean Energy
|
| | | | | | |
| Year Ended December 31, | 2016 |
| 2015 |
|
| Millions | | |
| Operating Revenue |
| $80.5 |
|
| $262.1 |
|
| Net Income Attributable to ALLETE | $13.4 | $29.9 |
Operating Revenue decreased $181.6 million from 2015. Operating revenue in 2015 included the recognition of $197.7 million in revenue for the construction of a wind energy facility sold to Montana-Dakota Utilities in 2015. Operating revenue in 2016 was positively impacted by additional revenue generated from the operations of wind energy facilities acquired in April and July 2015.
|
| | | | | | | | | | |
| | Year Ended December 31, |
| | 2016 | 2015 |
| Production and Operating Revenue | kWh | Revenue | kWh | Revenue |
| Millions | | | | |
| Wind Energy Facility | | | | |
| Lake Benton | 254.7 |
|
| $12.8 |
| 265.1 |
|
| $13.5 |
|
| Storm Lake II | 154.8 |
| 10.1 |
| 186.4 |
| 11.7 |
|
| Condon | 96.9 |
| 8.2 |
| 84.1 |
| 7.8 |
|
| Storm Lake I | 222.3 |
| 11.6 |
| 230.7 |
| 12.1 |
|
| Chanarambie/Viking | 278.8 |
| 13.4 |
| 199.1 |
| 9.8 |
|
| Armenia Mountain | 268.2 |
| 24.4 |
| 111.6 |
| 9.5 |
|
| Total Wind Energy Facilities | 1,275.7 |
| 80.5 |
| 1,077.0 |
| 64.4 |
|
Development Fee (a) | — |
| — |
| — |
| 197.7 |
|
| Total Production and Operating Revenue | 1,275.7 |
| $80.5 | 1,077.0 |
|
| $262.1 |
|
(a) 2015 included the recognition of $162.9 million of cost of sales.
2016 Compared to 2015 (Continued)
ALLETE Clean Energy (Continued)
Net Income Attributable to ALLETE decreased $16.5 million from 2015. Net income for 2015 included the recognition of profit of $20.4 million after-tax for the construction of a wind energy facility sold to Montana-Dakota Utilities. In 2015, net income also included $1.8 million after-tax expense in acquisition costs related to the Chanarambie/Viking and Armenia Mountain wind energy facilities. Net income in 2016 included a $3.3 million after-tax non-cash goodwill impairment charge (see Note 1. Operations and Significant Accounting Policies) and a $0.9 million after-tax expense related to the repayment of long-term debt. Earnings in 2016 were positively impacted by income generated from the operations of wind energy facilities acquired in April and July 2015.
U.S. Water Services
|
| | | | | | |
| | Year Ended |
| Period February 10, 2015 |
|
| | December 31, 2016 |
| Through December 31, 2015 |
|
| Millions | | |
| Operating Revenue |
| $137.5 |
|
| $119.8 |
|
| Net Income Attributable to ALLETE | $1.5 |
| $0.9 |
|
Operating Revenue increased $17.7 million in 2016 compared to the period from February 10, 2015, to December 31, 2015. The results for 2015 reflect operations from the date of acquisition, February 10, 2015, through December 31, 2015, and therefore, do not reflect a full year. Revenue from chemical sales and related services was $110.5 million in 2016 compared to $92.5 million in 2015. Revenue from equipment sales was $27.0 million for 2016 compared to $27.3 million in 2015; equipment sales can significantly fluctuate from period to period.
Net Income Attributable to ALLETE increased $0.6 million in 2016 compared to the period from February 10, 2015, to December 31, 2015. The results for 2015 reflect operations from the date of acquisition, February 10, 2015, through December 31, 2015, and therefore do not reflect a full year. Net income in 2015 included an additional $1.9 million of after‑tax expense recognized as cost of sales related to purchase accounting for inventories and sales backlog which have been fully recognized as of December 31, 2016. Earnings in 2016 reflected increased investments in back office systems and support at U.S. Water Services as we create a platform for future growth.
Corporate and Other
Operating Revenue increased $7.7 million, or 7 percent, from 2015 primarily due to an increase in land sales at ALLETE Properties, which sold its Ormond Crossings project and Lake Swamp wetland mitigation bank in 2016. The increase was partially offset by a decrease in revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses and fewer tons sold in 2016 compared to 2015.
Net Income Attributable to ALLETE increased $26.2 million from 2015. Net income in 2016 included an after-tax gain of $13.6 million related to the change in fair value of the U.S. Water Services contingent consideration liability and increased land sales at ALLETE Properties, partially offset by an adverse impact of $8.8 million after-tax for the regulatory outcome of the November 2016 MPUC order. (Regulated Operations - Income Tax Expense.) In 2015, the net loss included a $22.3 million after-tax non-cash impairment charge relating to the real estate assets of ALLETE Properties and $3.0 million after-tax expense in acquisition costs related to U.S. Water Services. Net income at BNI Energy increased to $6.8 million in 2016 compared to $6.7 million in 2015, and net income at ALLETE Properties increased to $0.7 million in 2016 compared to a net loss of $23.3 million in 2015.
Income Taxes – Consolidated
For the year ended December 31, 2016, the effective tax rate was 15.2 percent (22.6 percent for the year ended December 31, 2015). The decrease from the year ended December 31, 2015, was primarily due to increased production tax credits in 2016 related to additional wind energy generation. The effective rate deviated from the combined statutory rate of approximately 4128 percent primarily due to production tax credits. (See Note 13.11. Income Tax Expense.)
Critical Accounting Policies
The preparation of financial statements and related disclosures in conformity with GAAP requires management to make various estimates and assumptions that affect amounts reported in the Consolidated Financial Statements. These estimates and assumptions may be revised, which may have a material effect on the Consolidated Financial Statements. Actual results may differ from these estimates and assumptions. These policies are discussed with the Audit Committee of our Board of Directors on a regular basis. We believe the following policies are most critical to our business and the understanding of our results of operations.
Regulatory Accounting. Our regulated utility operations are accounted for in accordance with the accounting standards for the effects of certain types of regulation. These standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income. (See Note 4. Regulatory Matters.)
Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and other postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of several important assumptions, including the expected long-term rate of return on plan assets, the discount rate and mortality assumptions, among others, in determining our obligations and the annual cost of our pension and other postretirement benefits. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class and adjust these for current economic conditions while utilizing the target allocation of our plan assets to forecast the expected long-term rate of return. Our pension asset allocation as of December 31, 2017,2019, was approximately 5334 percent equity securities, 3862 percent debt, 5fixed income, 1 percent private equity and 43 percent real estate. Our postretirement health and life asset allocation as of December 31, 2017,2019, was approximately 6466 percent equity securities, 3133 percent debtfixed income and 51 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2017,2019, we used expected long-term rates of return of 7.507.25 percent in our actuarial determination of our pension expense and 6.005.80 percent to 7.507.25 percent in our actuarial determination of our other postretirement expense. The actuarial determination uses an asset smoothing methodology for actual returns to reduce the volatility of varying investment performance over time. We review our expected long-term rate of return assumption annually and will adjust it to respond to changing market conditions. A one‑quarter percent decrease in the expected long-term rate of return would increase the annual expense for pension and other postretirement benefits by approximately $1.8$1.9 million, pre-tax.
Critical Accounting Policies (Continued)
Pension and Postretirement Health and Life Actuarial Assumptions (Continued)
The discount rate is computed using a bond matching study which utilizes a portfolio of high quality bonds that produce cash flows similar to the projected costs of our pension and other postretirement plans. In 20172019, we used discount rates of 4.39 percent to 4.53 percent and 4.574.47 percent in our actuarial determination of our pension and other postretirement expense, respectively. We review our discount rates annually and will adjust them to respond to changing market conditions. A one-quarter percent decrease in the discount rate would increase the annual expense for pension and other postretirement benefits by approximately $1.1$0.9 million, pre‑tax.
The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2017,2019, considered a modified RP-2014PRI-2012 mortality table and mortality projection scale. (See Note 15.12. Pension and Other Postretirement Benefit Plans.)
Impairment of Long-Lived Assets. We review our long-lived assets, which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis.
In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our long‑lived assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to maintain the operations.
Critical Accounting Policies (Continued)
Taxation. We are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income taxes and taxes other than income taxes. Judgments related to income taxes require the recognition in our financial statements of the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit. Tax positions that do not meet the “more-likely-than-not” criteria are reflected as a tax liability in accordance with the accounting standards for uncertainty in income taxes. We record a valuation allowance against our deferred tax assets to the extent it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.
We are subject to income taxes in various jurisdictions. We make assumptions and judgments each reporting period to estimate our income tax assets, liabilities, benefits and expenses. Judgments and assumptions are supported by historical data and reasonable projections. Our assumptions and judgments include the application of tax statutes and regulations, and projections of future federal taxable income, state taxable income, and state apportionment to determine our ability to utilize NOL and credit carryforwards prior to their expiration. Significant changes in assumptions regarding future federal and state taxable income or a change in tax rates could require new or increased valuation allowances which could result in a material impact on our results of operations.
Valuation of Goodwill and Intangible Assets. When we acquire a business, the assets acquired and liabilities assumed are recorded at their respective fair values as of the acquisition date. Determining the fair value of intangible assets acquired as part of a business combination requires us to make significant estimates. These estimates include the amount and timing of projected future cash flows, the discount rate used to discount those cash flows to present value, the assessment of the asset’s life cycle, and the consideration of legal, technical, regulatory, economic and competitive risks. The fair value assigned to intangible assets is determined by estimating the future cash flows of each project and discounting the net cash flows back to their present values. The discount rate used is determined at the time of measurement in accordance with accepted valuation standards.
Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. The Company assesses whether there has been an impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. Our estimates associated with the goodwill impairment test are considered critical due to the amount of goodwill recorded on our Consolidated Balance Sheet and the judgment required in determining fair value, including projected future cash flows. The results of our annual impairment test are discussed in Note 1. Operations and Significant Accounting Policies and Note 9. Fair Value in this Form 10-K. Goodwill was $148.3 million and $131.2 million as of December 31, 2017, and December 31, 2016, respectively.
Intangible Assets.Intangible assets include customer relationships, patents, non-compete agreements, land easements, trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents, non-compete agreements, land easements and certain trade names, which are amortized on a straight-line basis with estimated useful lives ranging from approximately 1 year to approximately 20 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite-lived intangible assets consist of trademarks and certain trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Our impairment reviews are based on an estimated future cash flow approach that requires significant judgment with respect to future revenue and expense growth rates, selection of an appropriate discount rate, and other assumptions and estimates. We use estimates that are consistent with our business plans and a market participant view of the assets being evaluated. The results of our annual impairment test are discussed in Note 9. Fair Value in this Form 10-K. Intangible assets, net of accumulated amortization, were $77.6 million and $82.2 million as of December 31, 2017, and December 31, 2016, respectively.
Outlook
ALLETE is an energy company committed to earning a financial return that rewards our shareholders, allows for reinvestment in our businesses and sustains growth. The Company has long-term objectives of achieving average annual earnings per share growth of 5 percent to 7 percent, and providing a dividend payout competitive with our industry. Regulated Operations is projected to have average annual earnings growth of 4 percent to 5 percent. ALLETE Clean Energy and our Corporate and Other businesses are projected to have average annual earnings growth of at least 15 percent over the long-term.
ALLETE is predominately a regulated utility through Minnesota Power, SWL&P and an investment in ATC. ALLETE’s strategy is to remain predominately a regulated utility while investing in itsALLETE Clean Energy Infrastructure and Related Servicesour Corporate and Other businesses to complement its regulated businesses, balance exposure to the utility’s industrial customers and provide potential long-term earnings growth. ALLETE expects net income from Regulated Operations to be approximately 80 percent of total consolidated net income in 2018.2020. Over the next several years, the contribution of theALLETE Clean Energy Infrastructure and Related Servicesour Corporate and Other businesses to net income is expected to increase as ALLETE grows these operations. ALLETE expects its businesses to provide regulated, contracted or recurring revenues, and to support sustained growth in net income and cash flow.
On March 26, 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.
Outlook (Continued)
Regulated Operations. Minnesota Power’s long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable energy requirements. Keeping the cost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain customer viability. As part of maintaining cost competitiveness, Minnesota Power intends to reduce its exposure to possible future carbon and GHG legislation by reshaping its generation portfolio, over time, to reduce its reliance on coal. (See EnergyForward.) We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approvals for transmission, renewable and environmental investments, as well as work with regulators to earn a fair rate of return.
Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, FERC, PSCW and NDPSC. See Note 4. Regulatory Matters for discussion of regulatory matters within these jurisdictions.
2016 Minnesota General Rate Case. In The MPUC issued a March 2018 order in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect in December 2018.
2020 Minnesota General Rate Case. On November 2016,1, 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 910.6 percent for retail customers. The rate filing soughtseeks a return on equity of 10.2510.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generatedgenerate approximately $55$66 million in additional revenue. In orders dated December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders,23, 2019, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7$36.1 million beginning January 1, 2017.2020.
On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. 2018 Wisconsin General Rate Case. In ana December 2018 order, dated April 13, 2017, the MPUCPSCW approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately $49 million on an annualized basis. At a hearing on January 18, 2018, the MPUC made determinations regarding Minnesota Power’s general rate casefor SWL&P including allowing a return on common equity of 9.2510.4 percent and a 53.8155.0 percent equity ratio. Upon commencement of finalFinal rates we expectwent into effect January 1, 2019, which resulted in additional revenue of approximately $13 million on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which will be fully offset by the recognition of$3 million. SWL&P anticipates filing a corresponding reserve. As a result of the MPUC’s decisions on January 18, 2018, Minnesota Power has recorded a reserve for an interim rate refund of approximately $32 million as of December 31, 2017. The MPUC also disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. An order from the MPUC setting forth the effective date of final rates is expected by March 12, 2018. Minnesota Power will review this order for potential reconsideration of certain issues at that time.
As part of its decision in Minnesota Power’s 2016 general rate case in the MPUC extended the depreciable livessecond quarter of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a decrease to depreciation expense of approximately $25 million pre-tax in 2017.2020.
Outlook (Continued)
Regulatory Matters (Continued)
Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 which established that it is the energy policy of Minnesota to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued on October 13, 2017, that modified the order dated April 20, 2017. During 2017, Minnesota Power provided discounts of $8.6 million which were recorded as a receivable. On September 29, 2017, Minnesota Power informed its EITE customers that it had suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately $15 million annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, EITE discounts will offset interim rate refund reserves for non-EITE customers.
2016 Wisconsin General Rate Case.SWL&P’s current retail rates are based on a 2017 PSCW retail rate order effective August 14, 2017, that allows for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 14, 2017, were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity. The 2017 PSCW retail rate order authorizes SWL&P to collect on average a 2.9 percent increase in rates for retail customers (3.8 percent increase in electric rates; 4.8 percent decrease in natural gas rates; and 9.8 percent increase in water rates). On an annualized basis, SWL&P expects to collect additional revenue of $2.5 million.
Industrial Customers and Prospective Additional Load
Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and secondary wood products, pipeline and other industries. Approximately 5054 percent of our regulated utility kWh sales in 2017 (452019 (50 percent in 20162018 and 46 percent in 2015)2017) were made to our industrial customers. We expect industrial sales of approximately 7.0 million to 7.5 million MWh in 20182020 (7.3 million MWh in 2017; 6.5 million MWh2019 and in 2016)2018). (See Item 1. Business – Regulated Operations – Electric Sales / Customers.)
Taconite and Iron Concentrate. Minnesota Power’s taconite customers are capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five10 percent of Minnesota taconite production has been exported outside of North America. Minnesota Power also provides electric service to three iron concentrate facilities capable of producing up to approximately 4 million tons of iron concentrate per year. Iron concentrate is used in the production of taconite pellets. These iron concentrate facilities are owned in whole, or in part, by ERP Iron Ore and are currently idled. (See ERP Iron Ore /Magnetation.)
There has been a general historical correlation between U.S. steel production and Minnesota taconite production. The American Iron and Steel Institute, an association of North American steel producers, reported that U.S. raw steel production operated at approximately 7480 percent of capacity in 2017 (712019 (78 percent in 20162018 and 74 percent in 2015)2017). The World Steel Association, an association of over 160 steel producers, national and regional steel industry associations, and steel research institutes representing approximately 85 percent of world steel production, projected U.S. steel consumption in 20182020 will increase by approximately 1one percent compared to 2017.2019.
Minnesota Power’s taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in Minnesota Power’s taconite customers’ production would impact our annual earnings per share by approximately $0.04, net of expected power marketing sales at current prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Minnesota Power proactively sells power in the wholesale power markets that is temporarily not required by industrial customers to optimize the value of its generating facilities. Long-term reductions in taconite production or a permanent shut down of a taconite customer may lead Minnesota Power to file a general rate case to recover lost revenue.
Outlook (Continued)
Industrial Customers and Prospective Additional Load (Continued)
USS Corporation. In 2015,On October 17, 2019, USS Corporation temporarilyannounced that it had idled one of its Minnesota Ore Operations - Keetac plant in Keewatin, Minnesota, and a portion ofpellet production lines at its Minnesota Ore Operations - Minntac plant in Mountain Iron, Minnesota. These actions were dueMinnesota, citing changing market conditions and the need to high inventory levels and ongoing adjustment ofadjust its steel producing operations throughout North America. Global influences in the market, including a higher level of imports, unfairly traded products and reduced steel prices, were cited as having an impact.raw materials accordingly. USS Corporation returned its Minntac plantalso noted it plans to full productionperform additional maintenance during this time in 2015,preparation for improved market conditions and in the first quarter of 2017, USS Corporation restarted its Keetac plant. USS Corporation has the capability to produce approximately 5 million tons and 15 million tons of taconite annually at its Keetac and Minntac plants, respectively.does not anticipate any employment impacts.
United Taconite. On May 16, 2017, Cliffs announced that production of a fully fluxed taconite pellet has started at its United Taconite facility. The product replaces a flux pellet previously made at Cliffs’ indefinitely idled Empire operation in Michigan. United Taconite has the capability to produce approximately 5 million tons of taconite annually.
Northshore Mining. Cliffs has announced that it is investing furtherhas made an approximately $90 million investment in its Minnesota ore operations specifically it plans to invest approximately $75 million through 2020 to expand capacity for producing direct reduced-grade pellets at Northshore Mining. The additional direct reduced-grade pellets could be sold commercially or used to supply Cliff’s plannedCliffs is currently constructing a hot briquetted iron production plant in Toledo, Ohio.Ohio, and has begun shipping direct reduced-grade pellets to the Toledo plant in anticipation of the planned start of operations in mid-2020. Minnesota Power has a long-term PSA through 2031 with Silver Bay Power, which provides the majority of the electric service requirements for Northshore Mining. (See Silver Bay Power.)
Silver Bay Power. In 2016, Minnesota Power and Silver Bay Power entered into a long-term PSA through 2031. Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which hashad previously been served predominately through self-generation by Silver Bay Power. In the yearsStarting in 2016, through 2019, Minnesota Power is supplyingsupplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power hashad the option to purchase additional energy from Minnesota Power as it transitionstransitioned away from self-generation. On December 31,In the third quarter of 2019, Silver Bay Power will ceaseceased self-generation and Minnesota Power will supplybegan supplying the full energy requirements for Silver Bay Power.
ERP Iron Ore / Magnetation. In 2015, Magnetation announced that it had filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Minnesota, citing the significant decrease in global iron ore prices and its existing capital structure. In January 2016, Magnetation idled its Plant 2 facility in Bovey, Minnesota. In October 2016, the bankruptcy court approved plans to idle Magnetation’s Plant 4 facility near Grand Rapids, Minnesota, and its pellet plant in Reynolds, Indiana, as well as terminate Magnetation’s pellet purchase agreement with AK Steel Corporation. The company subsequently idled the facilities and stated it was preserving the plants and their value for a potential buyer. On January 30, 2017, ERP Iron Ore purchased substantially all of Magnetation’s assets pursuant to an asset purchase agreement approved by the bankruptcy court. Although we cannot predict whether the facilities will be restarted, Minnesota Power would serve the Plant 2 and Plant 4 facilities through ERP Iron Ore’s assumption of the existing electric service agreement.
Paper, Pulp and Secondary Wood Products. Minnesota Power servesThe North American paper and pulp industry faces declining demand due to the impact of electronic substitution for print and changing customer needs. As a number ofresult, certain paper and pulp customers have reduced their existing operations in recent years and have pursued or are pursuing product changes in response to the paper, pulp and secondary wood products industry. Thedeclining demand. We expect operating levels in 2020 at the four major paper and pulp mills we serve reportedto be similar to 2019.
Pipeline and Other Industries.
Husky Energy.In April 2018, a fire at Husky Energy’s refinery in Superior, Wisconsin, disrupted operations at the facility. Under normal operating at, or near, full capacityconditions, SWL&P provides approximately 14 MW of average monthly demand to Husky Energy in 2017. Lower levels of production are expected in 2018 as a result of the closure of the smaller of the two paper machines located at UPM Blandin in the fourth quarter of 2017. (See UPM Blandin.)
UPM Blandin.addition to water service. On October 24, 2017, UPM-Kymmene CorporationSeptember 30, 2019, Husky Energy announced that in light ofit had received the global market situation for graphic papers,required permit approvals to begin reconstruction. The facility remains at minimal operations, and the refinery is not expected to sustain its competitiveness and leading position in the market, it planned to permanently close the smaller of UPM Blandin’s two paper machines located in Grand Rapids, Minnesota; the closure was completed in the fourth quarter of 2017. Paper production related to the other paper machine is planned to continue at UPM Blandin. Minnesota Power provides electric and steam service to UPM Blandin.resume normal operations until 2021.
Prospective Additional Load.Minnesota Power is pursuing new wholesale and retail loads in and around its service territory. Currently, several companies in northeastern Minnesota continue to progress in the development of natural resource-based projects that represent long-term growth potential and load diversity for Minnesota Power. We cannot predict the outcome of these projects.
Nashwauk Public Utilities Commission. Mesabi Metallics is a retail customer of the Nashwauk Public Utilities Commission, and Minnesota Power has a wholesale electric contract with the Nashwauk Public Utilities Commission for electric service through at least December 2032. Mesabi Metallics filed for bankruptcy protection in July 2016, under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. On June 13, 2017, the bankruptcy court approved a settlement plan for a consortium led by Chippewa Capital Partners LLC to take control of the project, subject to certain stipulations. On December 22, 2017, Mesabi Metallics emerged from bankruptcy under the ownership of Chippewa Capital Partners LLC.
Outlook (Continued)
Industrial Customers and Prospective Additional Load (Continued)
PolyMet. PolyMet is planning to start a new copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. In 2015, PolyMet announced the completion of the final EIS by state and federal agencies, which was subsequently published in the Federal Register and Minnesota Environmental Quality Board Monitor. The Minnesota Department of Natural Resources (DNR) and the U.S. Army Corps of Engineers have both issued its Recordfinal Records of Decision, in March 2016, finding the final EIS adequate.
In July 2016, PolyMet submitted applications for water-related permits with the State of Minnesota,DNR and in August 2016, an application forMPCA, an air quality permit was submitted towith the MPCA. In November 2016, PolyMet submittedMPCA, and a state permit to mine application towith the DNR detailing its operational plans for the mine. On January 5,In June 2018, the DNR released PolyMet’s draft permit to mine and opened a public comment period through March 6, 2018. Public hearings were held in February 2018 to review the draft permit to mine, as well as the MPCA’s recently released draft water quality permit, draft air quality permit and draft water quality certification. The final EIS also requires Records of Decision by the federal agencies, which are expected in 2018, before final action can be taken on the required federal permits to construct and operate the mining operation. On January 9, 2017, the U.S. Forest Service signed the Final Record of Decision authorizingand PolyMet closed on a land exchange, with PolyMet, which upon completion of title transfer will resultresulted in PolyMet obtaining surface rights to land needed to develop its mining operation. In November 2018, the DNR issued PolyMet’s permit to mine and certain water-related permits. In December 2018, the MPCA issued PolyMet’s final state water and air quality permits. On March 21, 2019, the U.S. Army Corps of Engineers issued PolyMet’s final federal permit. PolyMet was issued all necessary permits to construct and operate its new mining operation; however, on January 13, 2020, the Minnesota Court of Appeals reversed the DNR’s decisions granting PolyMet’s permit to mine and dam-safety permits, and remanded them back to the DNR to hold a contested-case hearing. On February 11, 2020, PolyMet announced it has filed a petition for further review with the Minnesota Supreme Court seeking to overturn the Minnesota Court of Appeals decision. Minnesota Power could supply between 45 MW and 50 MW of load under a ten-year10‑year power supply contract with PolyMet that would begin upon start-up of operations.
Outlook (Continued)
EnergyForward. Minnesota Power is executing EnergyForward, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes completed and planned investments in wind, solar, natural gas and hydroelectric power, construction of additional transmission capacity, the installation of emissions control technology and the idling of certain coal-fired generating facilities.
On July 28,In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of PPAsa PPA for the output of a 250 MW wind energy facility and a 10 MW solar energy facility(see Nobles 2 PPA) as well as approval of a 250 MW natural gas energy PPA. These agreements will becapacity dedication agreement. The natural gas capacity dedication agreement was subject to MPUC approval of the construction of NTEC, a 525 MW to 550625 MW combined-cycle natural gas-firedgas‑fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In an order dated September 19, 2017,January 24, 2019, the MPUC approved Minnesota Power’s request thatfor approval forof the NTEC natural gas energy PPAcapacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet including potential early retirement scenarios of Boswell Units 3 and 4, as well as a securitization plan. On December 23, 2019, the Minnesota Court of Appeals reversed and remanded the MPUC’s decision to approve certain affiliated-interest agreements. The MPUC was ordered to determine whether NTEC may have the potential for significant environmental effects and, if so, to prepare an environmental assessment worksheet before reassessing the agreements. On January 22, 2020, Minnesota Power filed a petition for further review with the Minnesota Supreme Court requesting that it review and overturn the Minnesota Court of Appeals decision. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW, which was approved by the PSCW at a hearing on January 16, 2020. Construction of NTEC is subject to obtaining additional permits from local, state and federal authorities. The total project cost is estimated to be decided through an administrative law judge process. The administrative law judgeapproximately $700 million, of which ALLETE’s portion is expected to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second halfbe approximately $350 million. ALLETE’s portion of 2018. The MPUC did not take any action regarding the wind and solar energy PPAs which will be refiled separately from the natural gas energy PPA.NTEC project costs incurred through December 31, 2019, is approximately $12 million.
Integrated Resource Plan. In 2015, Minnesota Power filed its 2015 IRP with the MPUC which contained steps in its EnergyForward strategic plan, and included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. In a July 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct requestrequests for proposalsproposal for additional wind, solar and demand response resource additions subject to further MPUC approvals. In October 2016,additions. Minnesota Power announced thatretired Boswell Units 1 and 2 will be retired in 2018 as partthe fourth quarter of its EnergyForward strategic plan. In an order dated September 19, 2017, the MPUC approved2018. Minnesota Power’s request to extend the next IRP filing deadline untilis due October 1, 2019.2020. (See Note 4. Regulatory Matters.)
Renewable Energy. Minnesota Power’s 2015 IRP includes an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. Minnesota Power continues to execute its renewable energy strategy through renewable projects that will ensure it meets the identified state mandate at the lowest cost for customers. Minnesota Power has exceeded the interim milestone requirements to date and expects 28between 25 percent and 30 percent of its applicable retail and municipal energy sales will be supplied by renewable energy sources in 2018.2020. (See Item 1. Business – Regulated Operations – Minnesota Legislation and EnergyForward.)
Outlook (Continued)
EnergyForward (Continued)
Minnesota Solar Energy Standard. Minnesota law requires at least 1.5Power continues to execute its renewable energy strategy and expects approximately 50 percent of total retail electric sales, excluding sales to certain customers, toits energy will be generatedsupplied by renewable energy sources by 2021.
Solar Energy. Minnesota Power’s solar energy by the endsupply consists of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved Camp Ripley, a 10 MW utility scale solar projectenergy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. Minnesota Power believes Camp Ripley and the community solar garden arrays will meet approximately one-third of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. The proposal to incentivize customer-sited solar installations and the community solar garden subscriptions is expected to meet a portion of the required small scale solar mandate.
Minnesota Power has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. Currently, there is no approved customer billing rate for solar costs.
Wind Energy. Minnesota Power’s wind energy facilities consist of Bison (497 MW) located in North Dakota, and Taconite Ridge (25 MW) located in northeastern Minnesota. Minnesota Power also has two long-term wind energy PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) located in North Dakota.
Outlook (Continued)
EnergyForward (Continued)
Minnesota Power uses the 465-mile, 250-kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota, to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity delivered to its system over this transmission line from Square Butte’s lignite coal-fired generating unit. TheMinnesota Power is currently pursuing a modernization and capacity upgrade of its DC transmission line capacity can be increased if renewable energy or transmission needs justify investmentssystem to upgrade the line.continue providing reliable operations and additional system capabilities.
Updated customer billing rates for the renewableMinnesota Power has an approved cost recovery rider which includesfor certain renewable investments and expenditures related to Bison, were approved by the MPUC in an order dated November 8, 2017, whichexpenditures. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested.
In Updated customer billing rates for the renewable cost recovery rider were provisionally approved by the MPUC in a November 2016 order,2018 order.
Nobles 2 PPA. In the MPUC directed Minnesota Power to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a resultthird quarter of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability, and a reduction in Operating Revenue of approximately $15 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income in 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order.
In an order dated December 7, 2017, the MPUC modified its November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in Operating Revenue of approximately $14 million in 2017. The North Dakota investment tax credits were reestablished as income tax credits in Corporate and Other, resulting in a $7.9 million increase to net income in 2017.
The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in Corporate and Other operations.
Outlook (Continued)
EnergyForward (Continued)
Tenaska PPA. On May 10, 2017,2018, Minnesota Power and Nobles 2 signed an affiliate of Tenaska signed aamended long-term PPA that provides for Minnesota Power to purchase the energy and associated capacity from a 250 MW wind energy facility in southwestsouthwestern Minnesota for a 20-year period beginning in 2020. The agreement provides for the purchase of output from the facility at fixed energy prices. There are no fixed capacity charges, and Minnesota Power will only pay for energy as it is delivered. This agreement is subject to MPUC approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE, and construction of the wind energy facility. (See Note 4. Regulatory Matters.5. Equity Investments.)
Manitoba Hydro. Minnesota Power has five long-term PPAs with Manitoba Hydro. The first PPA expires in May 2020. Under this agreement, Minnesota Power is purchasing 50 MW of capacity and the energy associated with that capacity. Both the capacity price and the energy price are adjusted annually by the change in a governmental inflationary index. Under the second PPA, Minnesota Power is purchasing surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro’s system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement, Minnesota Power will purchase at least one million MWh of energy over the contract term.
The third PPA provides for Minnesota Power to purchase 250 MW of capacity and energy from Manitoba Hydro for 15 years beginning in 2020. The agreementPPA is subject to the construction of additional transmission capacity between Manitobathe GNTL and the U.S., along with construction of new hydroelectric generating capacity in Manitoba.MMTP. (See Item 1. Business – Regulated Operations – TransmissionNote 9. Commitments, Guarantees and Distribution – Great Northern Transmission Line.Contingencies.) The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.
The fourth PPA provides for Minnesota Power to purchase up to 133 MW of energy from Manitoba Hydro for 20 years beginning in 2020. The pricing under this PPA is based on forward market prices. The PPA is subject to the construction of the GNTL.GNTL and MMTP. (See Item 1. Business – Regulated Operations – TransmissionNote 9. Commitments, Guarantees and Distribution – Great Northern Transmission Line.Contingencies.)
The fifth PPA provides for Minnesota Power to purchase 50 MW of capacity from Manitoba Hydro at fixed prices. The PPA began in June 2017 and expires in May 2020.
Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. See also Item 1. Business – Regulated Operations.Operations and Note 9. Commitments, Guarantees and Contingencies.
Energy Infrastructure and Related Services.
ALLETE Clean Energy.
ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 535 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.
ALLETE Clean Energy believes the market for renewable energy in North America is robust, driven by several factors including environmental regulation, tax incentives, societal expectations and continual technology advances. State renewable portfolio standards, and state or federal regulations to limit GHG emissions are examples of environmental regulation or public policy that we believe will drive renewable energy development.
ALLETE Clean Energy’s strategy includes the safe, reliable, optimal and profitable operation of its existing facilities. This includes a strong safety culture, the continuous pursuit of operational efficiencies at existing facilities and cost controls. ALLETE Clean Energy generally acquires facilities in liquid power markets and its strategy includes the exploration of PSA extensions upon expiration of existing contracts.
Outlook (Continued)
ALLETE Clean Energy (Continued)
ALLETE Clean Energy will pursue growth through acquisitions or project development for others.development. ALLETE Clean Energy is targeting acquisitions of existing facilities up to 200 MW each, which have long-term PSAs in place for the facilities’ output. At this time, ALLETE Clean Energy expects acquisitions or development of new facilities will be primarily wind or solar facilities in North America. ALLETE Clean Energy is also targeting the development of new facilities up to 200 MW each, which will have long-termlong‑term PSAs in place for the output or may be sold upon completion.
Federal production tax credit qualification is important to the economics of project development, project economics, and in 2016, 2017 and 2018 ALLETE Clean Energy invested in equipment in late 2016 and late 2017 to meet production tax credit safe harbor provisions which provides an opportunity to seek development of up to approximately 1,500 MW of production tax credit qualified wind projects through 2021.2022. ALLETE Clean Energy will also invest approximately $80 million through 2020 to requalifyfor production tax credit requalification of up to 385approximately 500 WTGs at its Storm Lake I, Storm Lake II, and Lake Benton and Condon wind energy facilities for production tax credits.facilities. We anticipate annual production tax credits relating to these projects of approximately $5$20 million in 2018, $10 million in 2019, $152020, $17 million to $20$22 million annually in 20202021 through 2027 and decreasing thereafter through 2030.
On January 3, 2017, ALLETE Clean Energy announced that it will develop a wind energy facility of up to 50 MW after securing a 25-year PSA with Montana-Dakota Utilities, which includes an option to purchase the facility upon completion. We expect Montana-Dakota Utilities to exercise the option in the first quarter of 2018; construction and sale is expected to be completed in December 2018. Revenue is expected to be recognized upon completion; if the wind energy facility is not completed and sold in 2018, revenue and related margins would be recognized in 2019. ALLETE Clean Energy constructed and sold a 107 MW wind energy facility to Montana-Dakota Utilities in 2015. On March 16,In 2017, ALLETE Clean Energy announced it will build, own and operate a separate 100 MW wind energy facility pursuant to a 20-year PSA with Northern States Power; construction was completed and tax equity funding was received in the fourth quarter of 2019. In March 2018, ALLETE Clean Energy announced that it will build, own and operate an 80 MW wind energy facility pursuant to a 15-year PSA with NorthWestern Corporation; construction is expected to beginbe completed in the first quarter of 2020.
On May 3, 2019, ALLETE Clean Energy acquired the Diamond Spring wind project in Oklahoma from Apex Clean Energy. ALLETE Clean Energy will build, own and operate the approximately 300 MW wind energy facility. The Diamond Spring wind project is fully contracted to sell wind power under long-term power sales agreements. Construction is expected to be completed in late 2018.2020.
ALLETE Clean Energy manages risk by having a diverse portfolio of assets, which includes PSA expiration, technology and geographic diversity. The current operating portfolio of approximately 535660 MW is subject to typical variations in seasonal wind with higher wind resources typically available in the winter months. The majority of its planned maintenance leverages this seasonality and is performed during lower wind periods. The current mix of PSA expiration and geographic location for existing facilities is as follows:
| | | Wind Energy Facility | Location | Capacity MW | PSA MW | PSA Expiration | Location | Capacity MW | PSA MW | PSA Expiration |
| Armenia Mountain | Pennsylvania | 100.5 | 100% | 2024 | East | 101 | 100% | 2024 |
| Chanarambie/Viking | Minnesota | 97.5 | | Midwest | 98 | |
| PSA 1 | | 12% | 2018 | |
PSA 1 (a) | | | 12% | 2023 |
| PSA 2 | | 88% | 2023 | | 88% | 2023 |
| Condon | Oregon | 50 | 100% | 2022 | West | 50 | 100% | 2022 |
| Glen Ullin | | West | 106 | 100% | 2039 |
| Lake Benton | Minnesota | 104 | 100% | 2028 | Midwest | 104 | 100% | 2028 |
| Storm Lake I | Iowa | 108 | 100% | 2019 | Midwest | 108 | 100% | 2027 |
| Storm Lake II | Iowa | 77 | | Midwest | 77 | |
| PSA 1 | | 90% | 2019 | | 90% | 2020 |
| PSA 2 | | 10% | 2032 | | 10% | 2032 |
| Other | | Midwest | 17 | 100% | 2028 |
| |
| (a) | The PSA expiration assumes the exercise of four one-year renewal options that ALLETE Clean Energy has the sole right to exercise. |
Non-cash amortization to revenue recognized by ALLETE Clean Energy relates to the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of wind energy facility acquisitions, ALLETE Clean Energy assumed various PSAs that were above or below estimated market prices at the time of acquisition; the resulting differences between contract prices and estimated market prices are amortized to revenue over the remaining PSA term. Non-cash amortization is expected to be approximately $11.5 million annually in 2020 through 2023, $5.5 million annually in 2024 through 2027, and decreasing thereafter through 2032.
U.S. Water Services provides integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage and improve efficiency. U.S. Water Services is located in 49 states and Canada, and has an established base of approximately 4,900 customers. U.S. Water Services differentiates itself from the competition by developing synergies between established solutions in engineering, equipment and chemical water treatment, and helping customers achieve efficient and sustainable use of their water and energy systems. U.S. Water Services is a leading provider to the biofuels industry, and also serves the commercial and institutional markets, food and beverage, light manufacturing, power generation, and midstream oil and gas industries, among others. U.S. Water Services principally relies upon recurring revenues from a diverse mix of industrial customers. U.S. Water Services sells certain products which are seasonal in nature, with higher demand typically realized in warmer months; generally, lower sales occur in the first quarter of each year.
Outlook (Continued)
U.S. Water Services (Continued)
Our strategy is to grow U.S. Water Services’ presence in North America by adding customers, products, markets and new geographies. We believe water scarcity and a growing emphasis on conservation will continue to drive significant growth in the industrial, commercial and governmental sectors leading to organic revenue growth for U.S. Water Services. U.S. Water Services also expects to pursue periodic strategic tuck-in acquisitions with a purchase price in the $10 million to $50 million range. Priority will be given to acquisitions which expand its geographic reach, add new technology, or deepen its capabilities to serve its expanding customer base.
On September 1, 2017, U.S. Water Services acquired Tonka Water for total consideration of $19.2 million. Tonka Water is a supplier of municipal and industrial water treatment systems that will expand U.S. Water Services’ geographic and customer markets.
U.S. Water Services expects cash flow from operations of approximately $15 million in 2018 ($12 million in 2017).
Corporate and Other.
BNI Energy.In 2017,2019, BNI Energy sold a record 4.74.1 million tons of coal (3.8(4.3 million tons in 2016)2018) and anticipates 20182020 sales will be lowerhigher than 2017 primarily due to an expected outage for one of its customers.2019 reflecting no major planned customer outages anticipated in 2020. BNI Energy operates under cost-plus fixed fee agreements extending through December 31, 2037.
Investment in Nobles 2.In December 2018, our wholly-owned subsidiary, ALLETE South Wind, entered into an agreement with Tenaska to purchase a 49 percent equity interest in Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. The wind energy facility will be built in Nobles County, Minnesota and is expected to be completed in late 2020, with an estimated total project cost of approximately $350 million to $400 million. In the fourth quarter of 2019, we entered into a tax equity funding agreement to finance up to $125 million of the project costs. We account for our investment in Nobles 2 under the equity method of accounting. (See Note 5. Equity Investments.)
ALLETE Properties.Our strategy incorporates the possibility of a bulk sale of the entire ALLETE Properties representsportfolio. Proceeds from a bulk sale would be strategically deployed to support growth initiatives at our legacy Florida real estate investment.Regulated Operations and ALLETE Clean Energy. ALLETE Properties also continues to pursue sales of individual parcels over time and will continue to maintain key entitlements and infrastructure. Market conditions can impact land sales and could result in our inability to cover our cost basis and operating expenses orincluding fixed carrying costs such as community development district assessments and property taxes. ALLETE Properties’ major projects in Florida are Town Center at Palm Coast and Palm Coast Park, with approximately 2,000 acres combined of land available for sale. (See Item 1. Business – Corporate and Other – ALLETE Properties.) In addition to these two projects, ALLETE Properties has approximately 800 acres of other land available for sale.
In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In 2015, the Company reevaluated its strategy related to the real estate assets of ALLETE Properties in response to market conditions and transaction activity. The revised strategy incorporated the possibility of a bulk sale of its entire portfolio. Proceeds from a bulk sale would be strategically deployed to support growth in ALLETE Clean Energy and U.S. Water Services, collectively our Energy Infrastructure and Related Services businesses. ALLETE Properties also continues to pursue sales of individual parcels over time. ALLETE Properties will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.
Income Taxes
ALLETE’s aggregate federal and multi-state statutory tax rate is approximately 4128 percent for 2017. On an ongoing basis, ALLETE’s statutory tax rate will be reduced to approximately 28 percent as a result of the federal income tax rate change of the TCJA.2019. ALLETE also has tax credits and other tax adjustments that reduce the combined statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, production tax credits, AFUDC‑Equity, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income before income taxes, state and federal tax law changes that become effective during the year, business combinations, tax planning initiatives and resolution of prior years’ tax matters. We expect our effective tax rate to be a benefit of approximately negative 1015 percent to 20 percent for 20182020 primarily due to a lower statutory tax rate resulting from the TCJA, and federal production tax credits as a result of wind energy generation. We also expect that our effective tax rate will be lower than the combined statutory rate over the next 1211 years due to production tax credits attributable to our wind energy generation.
We expect the federal income tax rate change of the TCJA to result in lower income tax expense on an ongoing basis for our Regulated Operations, ALLETE Clean Energy and U.S. Water Services segments as well as our Corporate and Other businesses. The lower income tax expense for our Regulated Operations segment is expected to be mostly offset by lower revenue as most of the benefit is expected to be passed back to customers through lower rates. We do not expect a material impact on the Company’s ability to utilize its federal and state NOL and tax credit carryforwards due to the TCJA.
Liquidity and Capital Resources
Liquidity Position. ALLETE is well-positioned to meet its liquidity needs. As of December 31, 2017,2019, we had cash and cash equivalents of $98.9$69.3 million, $395.1$345.0 million in available consolidated lines of credit and a debt-to-capital ratio of 4241 percent.
On March 26, 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.
Capital Structure. ALLETE’s capital structure for each of the last three years is as follows:
| | | As of December 31 | 2017 |
| % | 2016 |
| % | 2015 |
| % | 2019 |
| % | 2018 |
| % | 2017 |
| % |
| Millions | | | | | | | | | | | | |
| ALLETE Equity |
| $2,068.2 |
| 58 |
| $1,893.0 |
| 55 |
| $1,820.2 |
| 53 |
| $2,231.9 |
| 56 |
| $2,155.8 |
| 59 |
| $2,068.2 |
| 58 |
| Non-Controlling Interest | — |
| — | — |
| — | 2.2 |
| — | 103.7 |
| 3 | — |
| — | — |
| — |
| Long-Term Debt (Including Current Maturities) | 1,513.3 |
| 42 | 1,569.1 |
| 45 | 1,605.0 |
| 47 | |
| Notes Payable | — |
| — | — |
| — | 1.6 |
| — | |
| Long-Term Debt (Including Long-Term Debt Due Within One Year) | | 1,622.6 |
| 41 | 1,495.2 |
| 41 | 1,513.3 |
| 42 |
| |
| $3,581.5 |
| 100 |
| $3,462.1 |
| 100 |
| $3,429.0 |
| 100 |
| $3,958.2 |
| 100 |
| $3,651.0 |
| 100 |
| $3,581.5 |
| 100 |
Liquidity and Capital Resources (Continued)
Cash Flows. Selected information from ALLETE’s Consolidated Statement of Cash Flows is as follows:
| | | Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
| 2019 |
| 2018 |
| 2017 |
|
| Millions | | | | |
| Cash and Cash Equivalents at Beginning of Period |
| $27.5 |
|
| $97.0 |
|
| $145.8 |
| |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | |
| $79.0 |
|
| $110.1 |
|
| $38.3 |
|
| Cash Flows from (used for) | | | | |
| Operating Activities | 402.9 |
| 332.0 |
| 340.1 |
| 249.5 |
| 433.1 |
| 402.9 |
|
| Investing Activities | (229.0 | ) | (276.2 | ) | (618.8 | ) | (345.3 | ) | (349.0 | ) | (229.0 | ) |
| Financing Activities | (102.5 | ) | (125.3 | ) | 229.9 |
| 109.3 |
| (115.2 | ) | (102.1 | ) |
| Change in Cash and Cash Equivalents | 71.4 |
| (69.5 | ) | (48.8 | ) | |
| Cash and Cash Equivalents at End of Period |
| $98.9 |
|
| $27.5 |
|
| $97.0 |
| |
| Change in Cash, Cash Equivalents and Restricted Cash | | 13.5 |
| (31.1 | ) | 71.8 |
|
| Cash, Cash Equivalents and Restricted Cash at End of Period | |
| $92.5 |
|
| $79.0 |
|
| $110.1 |
|
Operating Activities. Cash from operating activities was lower in 2019 compared to 2018 primarily due to the refund of Minnesota Power’s provisions for tax reform and interim rates to customers, fewer customer deposits received and lower recoveries from customers under cost recovery riders in 2019. These decreases were partially offset by the timing of collections of accounts receivable.
Cash from operating activities was higher in 20172018 compared to 20162017 primarily due to a payment of $31.0 million made in 2016 as partthe sale of a long-term PSA between Minnesota Powerwind energy facility to Montana-Dakota Utilities in 2018 and Silver Bay Power, as well as higherthe timing of accounts payable, partially offset by lower recoveries of ourfrom customers under cost recovery riders net income and non-cash items in 2017, partially offset by an increase in customer receivables and higher payments on accounts payable in 2017.
Cash from operating activities was lower in 2016 compared to 2015 primarily due to a payment of $31.0 million made as part of a long-term PSA between Minnesota Power and Silver Bay Power, cash contributions to ourthe defined benefit pension plan and non-cash items, partiallyplans in 2018.
Investing Activities. Cash used for investing activities in 2019 was similar to 2018 reflecting proceeds received from the sale of U.S. Water Services, mostly offset by higher net income, lower fuel inventoryadditions to property, plant and increased recoveries through our cost recovery riders.equipment.
Investing Activities.Cash used for investing activities was lowerhigher in 20172018 compared to 20162017 primarily due to lower payments forhigher capital expenditures and additional contributions to equity method investments in 2017,2018. (See Note 5. Equity Investments.) These increases in cash used for investing activities were partially offset by the acquisition of Tonka Water and additional investments in ATC in 2017.
Financing Activities.Cash used for investingfrom financing activities was lowerhigher in 2016 compared to 20152019 primarily due to higher proceeds from the issuance of long-term debt and proceeds from a decreasetax equity financing (non-controlling interest in cash used for the acquisitions of subsidiaries, as well as fewer capital expenditures in 2016. In 2015, we acquired U.S. Water Services, and ALLETE Clean Energy acquired the Chanarambie/Viking and Armenia Mountain wind energy facilities. (See Note 6. Acquisitions.)subsidiaries), partially offset by higher dividends on common stock.
Financing Activities.Cash used for financing activities was lowerhigher in 2018 compared to 2017 primarily due to higher dividends on common stock as well as lower proceeds received from the issuance of common stock of $86.0 million compared to $30.9 millionand long-term debt in 2016,2018, partially offset by higher contingent consideration payments in 2017 andlower repayments of long-term debt of $189.6 million in 2017, net of long-term debt issuances of $131.5 million in 2017. Additionally, in 2016 the Company paid $8.0 million to acquire the non-controlling interest of the limited liability company that owns the Condon wind energy facility. (See Securities and Note 6. Acquisitions.)2018.
Cash used for financing activities decreased in 2016 compared to 2015 primarily due to lower proceeds from the issuance of long‑term debt and common stock.
Liquidity and Capital Resources (Continued)
Working Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit and the issuance of securities, including long-term debt, common stock and commercial paper. As of December 31, 2017,2019, we had consolidated bank lines of credit aggregating $407.0 million ($409.0407.0 million as of December 31, 2016)2018), the majoritymost of which expire in October 2020.January 2024. We had $11.9$62.0 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of December 31, 20172019 ($11.118.4 million in standby letters of credit and no outstanding draws as of December 31, 2016)2018). In addition, as of December 31, 2017,2019, we had 3.23.7 million original issue shares of our common stock available for issuance through Invest Direct and 2.9 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, Inc. (See Securities.) The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.
On January 10, 2019, ALLETE entered into an amended and restated $400 million credit agreement (Credit Agreement). The remeasurementCredit Agreement amended and restated ALLETE’s $400 million credit facility, which was scheduled to expire in October 2020. The Credit Agreement is unsecured, has a variable interest rate and will expire in January 2024. At ALLETE’s request and subject to certain conditions, the Credit Agreement may be increased by up to $150 million and ALLETE may make two requests to extend the maturity date, each for a one‑year extension. Advances may be used by ALLETE for general corporate purposes, to provide liquidity in support of deferred income tax assetsALLETE's commercial paper program and liabilities resulting from the TCJA for Minnesota Power and SWL&P were recorded as regulatory assets and liabilities. The net regulatory liabilities for Minnesota Power and SWL&P are expected to be passed backissue up to customers over time primarily based upon the normalization provisions$100 million in letters of the U.S. Internal Revenue Code over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. The final amount and timing over which the benefits of the TCJA will be passed back to customers has not been determined, and therefore, the full cash flow impacts are still uncertain. (See Note 4. Regulatory Matters.)credit.
Liquidity and Capital Resources (Continued)
Securities. We entered into a distribution agreement with Lampert Capital Markets, Inc., in 2008, as amended most recently in August 2016, with respect to the issuance and sale of up to an aggregate of 13.6 million shares of our common stock, without par value, of which 2.9 million shares remain available for issuance as of December 31, 2017.2019. For the year ended December 31, 2017, 1.0 million2019, no shares of common stock were issued under this agreement resulting(none in net proceeds of $65.7 million (0.12018; 1 million shares for net proceeds of $8.0$65.7 million in 2016; 1.3 million shares for net proceeds of $69.9 million in 2015)2017). The shares issued in 2017 and 2016 were offered and sold pursuant to Registration Statement No. 333-212794,333-212794. On July 31, 2019, we filed Registration Statement No. 333-232905, pursuant to which the remaining shares will continue to be offered for sale, from time to time. The shares issued in 2015 were offered and sold pursuant to Registration Statement No. 333-190335.
During the year ended December 31, 2017,2019, we issued 0.30.2 million shares of common stock through Invest Direct, the Employee Stock Purchase Plan, and the Retirement Savings and Stock Ownership Plan, resulting in net proceeds of $20.3$1.9 million (0.4 million shares for net proceeds of $22.9$20.3 million in 2016; 0.42018; 0.3 million shares for net proceeds of $25.9$20.3 million in 2015)2017). These shares of common stock were registered under Registration Statement Nos. 333-231030, 333-211075, 333-188315, 333-183051 and 333-162890. See Note 10. Common Stock and Earnings Per Share for additional detail regarding ALLETE’s equity securities.
On JuneMarch 1, 2017,2019, ALLETE issued $80 millionand sold the following First Mortgage Bonds (the Bonds):
|
| | |
| Maturity Date | Principal Amount | Interest Rate |
| March 1, 2029 | $70 Million | 4.08% |
| March 1, 2049 | $30 Million | 4.47% |
ALLETE has the option to prepay all or a portion of the Bonds at its senior unsecured notes (the Notes)discretion, subject to certain institutional buyers ina make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. ALLETE used the private placement market.proceeds from the sale of the Bonds to fund utility capital investment and for general corporate purposes. The NotesBonds were issuedsold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes bear interest at 3.11 percent and mature on June 1, 2027. (See Note 10. Short-Term and Long-Term Debt.)
On August 25, 2017,14, 2019, ALLETE entered into a $40$110.0 million term loan agreement (Term Loan). The Term Loan is an unsecured, single draw loan that is due on August 25, 2020, and may be prepaid at any time subject to a make-whole provision. The interest rateInterest on the Term Loan is payable monthly at a rate per annum equal to LIBOR plus 1.025 percent. (See Note 10. Short-Term and Long-Term Debt.)Proceeds from the Term Loan were used for general corporate purposes.
On November 2, 2017,January 10, 2020, ALLETE entered into a bond purchase$200 million term loan agreement providing(Term Loan) and borrowed $60 million upon execution. The unsecured Term Loan provides for the issuanceability to borrow up to an additional $140 million, is due on February 10, 2021, and sale of $60 million of its First Mortgage Bonds (the Bonds) that bear interestmay be repaid at 4.07any time. Interest is payable monthly at a rate per annum equal to LIBOR plus 0.55 percent. The BondsProceeds from the Term Loan will be issued on or about April 1, 2018, and will mature in April 2048. (Seeused for construction-related expenditures. See Note 10.8. Short-Term and Long-Term Debt.)Debt for additional detail regarding ALLETE’s debt securities.
Financial Covenants. See Note 10.8. Short-Term and Long-Term Debt for information regarding our financial covenants.
Pension and Other Postretirement Benefit Plans. Management considers various factors when making funding decisions, such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the defined benefit pension plans. For the year ended December 31, 2017,2019, we contributed $1.7$10.4 million in cash and 0.2 million shares of ALLETE common stock, which had an aggregate value of $13.5 million when contributed, to the defined benefit pension plans. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended. On January 8, 2018,15, 2020, we contributed $15.0$10.7 million in cash to the defined benefit pension plans. We do not expect to make any additional contributions to our defined benefit pension plans in 2018,2020, and we do not expect to make any contributions to our other postretirement benefit plans in 2018.2020. (See Note 12.10. Common Stock and Earnings Per Share and Note 15.12. Pension and Other Postretirement Benefit Plans.)
Liquidity and Capital Resources (Continued)
Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 11.9. Commitments, Guarantees and Contingencies.
Liquidity and Capital Resources (Continued)
Contractual Obligations and Commercial Commitments. ALLETE has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following table summarizes contractual obligations and other commercial commitments as of December 31, 2017:2019:
| | | | Payments Due by Period | Payments Due by Period |
| | | Less than | 1 to 3 | 4 to 5 | After | | Less than | 1 to 3 | 4 to 5 | After |
Contractual Obligations (a) | Total | 1 Year | Years | 5 Years | Total | 1 Year | Years | 5 Years |
| Millions | | |
| Long-Term Debt |
| $2,255.4 |
|
| $126.1 |
|
| $313.6 |
|
| $284.8 |
|
| $1,530.9 |
|
| $2,396.7 |
|
| $277.0 |
|
| $301.2 |
|
| $259.2 |
|
| $1,559.3 |
|
Pension (b)(a) | 458.0 |
| 46.3 |
| 92.1 |
| 91.6 |
| 228.0 |
| 490.7 |
| 51.2 |
| 100.8 |
| 99.4 |
| 239.3 |
|
Other Postretirement Benefit Plans (b)(a) | 97.2 |
| 9.2 |
| 19.1 |
| 19.2 |
| 49.7 |
| 81.3 |
| 8.6 |
| 16.6 |
| 16.0 |
| 40.1 |
|
| Capital Purchase Obligations | | 292.7 |
| 292.7 |
| — |
| — |
| — |
|
| Easement Obligations | | 197.1 |
| 5.0 |
| 10.7 |
| 11.0 |
| 170.4 |
|
| Operating Lease Obligations | 79.9 |
| 14.2 |
| 22.3 |
| 13.4 |
| 30.0 |
| 35.2 |
| 6.6 |
| 11.0 |
| 6.1 |
| 11.5 |
|
PPA Obligations (c) | 2,283.1 |
| 104.5 |
| 222.1 |
| 289.5 |
| 1,667.0 |
| |
PPA Obligations (b) | | 2,051.8 |
| 113.0 |
| 268.0 |
| 284.1 |
| 1,386.7 |
|
| Other Purchase Obligations | 56.5 |
| 40.5 |
| 3.5 |
| 1.4 |
| 11.1 |
| 32.5 |
| 22.8 |
| 9.6 |
| — |
| 0.1 |
|
| Total Contractual Obligations |
| $5,230.1 |
|
| $340.8 |
|
| $672.7 |
|
| $699.9 |
|
| $3,516.7 |
|
| $5,578.0 |
|
| $776.9 |
|
| $717.9 |
|
| $675.8 |
|
| $3,407.4 |
|
| |
| (a) | Does not include $1.7 million of non-current unrecognized tax benefits due to uncertainty regarding the timing of future cash payments related to uncertain tax positions. (See Note 13. Income Tax Expense.) |
| |
(b) | Represents the estimated future benefit payments for our defined benefit pension and other postretirement plans through 2027.2029. |
| |
(c)(b) | Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with TenaskaNobles 2 commencing in 2020 as it is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas‑firedwind energy facility. (See Note 11.9. Commitments, Guarantees and Contingencies.) |
Long-Term Debt. Our long-term debt obligations, including long-term debt due within one year, represent the principal amount of bonds, notes and loans which are recorded on the Consolidated Balance Sheet, plus interest. The table above assumes that the interest rates in effect at December 31, 20172019, remain constant through the remaining term. (See Note 10.8. Short-Term and Long‑Term Debt.)
Pension and Other Postretirement Benefit Plans. Our pension and other postretirement benefit plan obligations represent our current estimate of future benefit payments through 2027.2029. Pension contributions will be dependent on several factors including realized asset performance, future discount rate and other actuarial assumptions, Internal Revenue Service and other regulatory requirements, and contributions required to avoid benefit restrictions for the pension plans. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements. These amounts are estimates and will change based on actual market performance, changes in interest rates and any changes in governmental regulations. (See Note 15.12. Pension and Other Postretirement Benefit Plans.)
Easement Obligations. Easement obligations represent the minimum payments for our land easement agreements at our wind energy facilities.
PPA Obligations. PPA obligations represent our Square Butte, Manitoba Hydro, Minnkota Power and other PPA’s.PPAs. (See Note 11.9. Commitments, Guarantees and Contingencies.)
Other Purchase Obligations. Other purchase obligations represents our minimum purchase commitments under coal and rail contracts, purchase obligations for certain capital expenditure projects, and long-term service agreements for wind energy facilities. (See Note 11.9. Commitments, Guarantees and Contingencies.)
Liquidity and Capital Resources (Continued)
Credit Ratings. Access to reasonably priced capital markets is dependent in part on credit and ratings. Our securities have been rated by Standard & Poor’sS&P and by Moody’s. Rating agencies use both quantitative and qualitative measures in determining a company’s credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective. Our current credit ratings are listed in the following table:
Liquidity and Capital Resources (Continued)
Credit Ratings (Continued)
|
| | |
| Credit Ratings | Standard & Poor’sS&P | Moody’s |
| Issuer Credit Rating | BBB+ | A3Baa1 |
| Commercial Paper | A-2 | P-2 |
| First Mortgage Bonds | (a) | A1A2 |
| |
| (a) | Not rated by Standard & Poor’s.S&P. |
The disclosure of these credit ratings is not a recommendation to buy, sell or hold our securities. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.
On February 6, 2018, Standard & Poor’s revisedMarch 26, 2019, Moody’s downgraded the long-term ratings of ALLETE, including its issuer rating to Baa1 from A3, and changed its credit rating outlook on ALLETE to negativestable from stable, while affirming its issuer and commercial paper ratings on ALLETE. Standard & Poor’s citednegative. Moody’s noted the potential effectcombined impact of the TCJA on the Company’s cash flows and Standard & Poor’s assessment of the Company’s regulatory risk following Minnesota Power’s recent2018 adverse general rate case outcome at Minnesota Power as well as its debt coverage ratios going forward as its rationale for issuing the negative outlook.downgrade.
On February 8, 2018, Moody’s issued a report on ALLETE noting that Minnesota Power’s general rate case was credit negative. With respect to Minnesota Power’s general rate case outcome, Moody’s noted a lower return on equity, disallowance of various expenses, including a decision to disallow recovery of the prepaid pension asset, and a ruling against Minnesota Power’s request to adopt an annual rate review mechanism. In addition, Moody’s noted the potential negative impact of the TCJA on certain financial metrics used by Moody’s.
The Company believes it is well-positioned to meet its liquidity needs. As of December 31, 2017,2019, we had cash and cash equivalents of $98.9$69.3 million, $395.1$345.0 million in available consolidated lines of credit and a debt-to-equitydebt-to-capital ratio of 4241 percent. Our cash from operating activities for the year ended December 31, 20172019 was $402.9$249.5 million. In addition, as of December 31, 2017,2019, we had 3.23.7 million original issue shares of our common stock available for issuance through Invest Direct and 2.9 million original issue shares of common stock available for issuance through a distribution agreement with Lampert Capital Markets, Inc.
Common Stock Dividends. ALLETE is committed to providing a competitive dividend to its shareholders while at the same time funding its growth. The Company’sALLETE’s long-term objective is to maintain a dividend payout ratio similar to our peers and provide for future dividend increases. Our targeted payout range is between 60 percent and 65 percent. In 2017,2019, we paid out 6365 percent (66 percent in 2016; 692018; 63 percent in 2015)2017) of our per share earnings in dividends. On January 23, 2018,30, 2020, our Board of Directors declared a dividend of $0.56$0.6175 per share, which is payable on March 1, 2018,2020, to shareholders of record at the close of business on February 15, 2018.14, 2020.
Capital Requirements
ALLETE’s projected capital expenditures for the years 20182020 through 20222024 are presented in the following table. Actual capital expenditures may vary from the estimatesprojections due to changes in forecasted plant maintenance, regulatory decisions or approvals, future environmental requirements, base load growth, capital market conditions or executions of new business strategies.
Capital Requirements (Continued)
| | | Capital Expenditures | Capital Expenditures | 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022 |
| Total |
| Capital Expenditures | 2020 |
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| Total |
|
| Millions | Millions | | Millions | |
| Regulated Operations | Regulated Operations | | Regulated Operations | |
| | Base and Other |
| $130 |
|
| $190 |
|
| $130 |
|
| $170 |
|
| $170 |
|
| $790 |
| Base and Other |
| $145 |
|
| $245 |
|
| $300 |
|
| $235 |
|
| $130 |
|
| $1,055 |
|
| | Transmission Cost Recovery (a) | 110 |
| 85 |
| 50 |
| — |
| — |
| 245 |
| Transmission Cost Recovery (a) | 25 |
| — |
| — |
| — |
| — |
| 25 |
|
| | | Nemadji Trail Energy Center (b) | 10 |
| 65 |
| 70 |
| 165 |
| 25 |
| 335 |
|
| Regulated Operations Capital Expenditures | Regulated Operations Capital Expenditures | 240 |
| 275 |
| 180 |
| 170 |
| 170 |
| 1,035 |
| Regulated Operations Capital Expenditures | 180 |
| 310 |
| 370 |
| 400 |
| 155 |
| 1,415 |
|
| ALLETE Clean Energy | 65 |
| 65 |
| 25 |
| 5 |
| 5 |
| 165 |
| |
| U.S. Water Services | 5 |
| 5 |
| 5 |
| 10 |
| 10 |
| 35 |
| |
ALLETE Clean Energy (c) | | ALLETE Clean Energy (c) | 340 |
| 10 |
| 5 |
| 5 |
| 10 |
| 370 |
|
Corporate and Other (b) | Corporate and Other (b) | 15 |
| 15 |
| 35 |
| 60 |
| 170 |
| 295 |
| Corporate and Other (b) | 15 |
| 15 |
| 25 |
| 30 |
| 15 |
| 100 |
|
| Total Capital Expenditures | Total Capital Expenditures |
| $325 |
|
| $360 |
|
| $245 |
|
| $245 |
|
| $355 |
|
| $1,530 |
| Total Capital Expenditures |
| $535 |
|
| $335 |
|
| $400 |
|
| $435 |
|
| $180 |
|
| $1,885 |
|
| |
| (a) | Estimated capital expenditures eligible for cost recovery outside of a general rate case. Ourcase, including our portion of transmission capital expenditures related to construction of the GNTL is estimated at approximately $245 million through 2020.GNTL. (See Item 1. Business – Regulated Operations – Transmission and Distribution.) |
| |
| (b) | Our portion of estimated capital expenditures related tofor construction of NTEC, a 525 MW to 550625 MW combined-cycle natural gas-fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. |
| |
| (c) | Capital expenditures in 2020 include construction of an 80 MW wind energy facility and a 300 MW wind energy facility that ALLETE is estimated at approximately $200 million through 2022, subject to regulatory approval.Clean Energy will build, own and operate. These capital expenditures do not include the cost of safe harbor turbines purchased previously. (See Item 7. Management’s Discussion and Analysis – Outlook – EnergyForward.ALLETE Clean Energy.) |
We are well positioned to meet our financing needs due to adequate operating cash flows, available additional working capital and access to capital markets. We will finance capital expenditures from a combination of internally generated funds, debt and equity issuance proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Capital Structure.)
Environmental and Other Matters
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities.authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation. (See Note 11.9. Commitments, Guarantees and Contingencies.)
Market Risk
Securities Investments.
Available-for-Sale Securities. As of December 31, 20172019, our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits. (See Note 8. Investments.)
Market Risk (Continued)
INTEREST RATE RISK
We are exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. The following table presents the long-term debt obligations and the corresponding weighted average interest rate as of December 31, 20172019:
| | | | Expected Maturity Date | Expected Maturity Date |
Interest Rate Sensitive Financial Instruments | 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022 |
| Thereafter |
| Total |
| Fair Value | 2020 |
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| Thereafter |
| Total |
| Fair Value |
| Long-Term Debt | | | | |
| Fixed Rate – Millions |
| $63.4 |
|
| $56.2 |
|
| $89.0 |
|
| $97.8 |
|
| $88.0 |
|
| $1,034.5 |
|
| $1,428.9 |
|
| $1,543.2 |
|
| $89.8 |
|
| $98.6 |
|
| $88.8 |
|
| $88.8 |
|
| $73.5 |
|
| $1,031.8 |
|
| $1,471.3 |
|
| $1,640.5 |
|
| Average Interest Rate – % | 2.8 |
| 7.6 |
| 4.2 |
| 3.8 |
| 3.7 |
| 4.4 |
| 4.4 |
| | 4.2 |
| 3.9 |
| 3.7 |
| 5.9 |
| 3.9 |
| 4.4 |
| 4.4 |
| |
| | | |
| Variable Rate – Millions |
| $1.2 |
|
| $1.4 |
|
| $54.0 |
| — |
| — |
|
| $27.8 |
|
| $84.4 |
|
| $84.4 |
|
| $123.5 |
| — |
| — |
| — |
| — |
|
| $27.8 |
|
| $151.3 |
|
| $151.3 |
|
| Average Interest Rate – % | 5.4 |
| 5.4 |
| 2.1 |
| — |
| — |
| 0.7 |
| 1.8 |
| | 2.7 |
| — |
| — |
| — |
| — |
| 1.7 |
| 2.5 |
| |
Interest rates on variable rate long-term debt are reset on a periodic basis reflecting prevailing market conditions. Based on the variable rate debt outstanding as of December 31, 20172019, an increase of 100 basis points in interest rates would impact the amount of pre-tax interest expense by $0.8$1.5 million. This amount was determined by considering the impact of a hypothetical 100 basis point increase to the average variable interest rate on the variable rate debt outstanding as of December 31, 20172019.
COMMODITY PRICE RISK
Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota, and power and natural gas purchased for resale in our regulated service territory in Wisconsin. Minnesota Power’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates or distribution of savings in fuel costs to ratepayers. SWL&P’s exposure to price risk for natural gas is significantly mitigated by the current ratemaking process and regulatory framework, which allows the commodity cost to be passed through to customers. We seek to prudently manage our customers’ exposure to price risk by entering into contracts of various durations and terms for the purchase of power and coal and related transportation costs (Minnesota Power) and natural gas (SWL&P).
Market Risk (Continued)
POWER MARKETING
Minnesota Power’s power marketing activities consist of: (1) purchasing energy in the wholesale market to serve its regulated service territory when energy requirements exceed generation output; and (2) selling excess available energy and purchased power. From time to time, Minnesota Power may have excess energy that is temporarily not required by retail and municipal customers in our regulated service territory. Minnesota Power actively sells any excess energy to the wholesale market to optimize the value of its generating facilities.
We are exposed to credit risk primarily through our power marketing activities. We use credit policies to manage credit risk, which includes utilizing an established credit approval process and monitoring counterparty limits.
Recently Adopted Accounting Standards.Pronouncements.
New accounting standardspronouncements are discussed in Note 1. Operations and Significant Accounting Policies of this Form 10-K.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk for information related to quantitative and qualitative disclosure about market risk.
Item 8. Financial Statements and Supplementary Data
See our Consolidated Financial Statements as of December 31, 20172019 and 2016,2018, and for the years ended December 31, 2017, 20162019, 2018 and 2015,2017, and supplementary data, which are indexed in Item 15(a).
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 20172019, evaluations were performed, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, on the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in ALLETE’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control – Integrated Framework (framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.2019.
Item 9A. Controls and Procedures (Continued)
The effectiveness of the Company’s internal control over financial reporting as of December 31, 20172019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Controls
There has been no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Not applicable.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Unless otherwise stated, the information required by this Item is incorporated by reference herein from our Proxy Statement for the 20182020 Annual Meeting of Shareholders (20182020 Proxy Statement) under the following headings:
| |
| • | Directors. The information regarding directors will be included in the “Election of Directors” section; |
| |
| • | Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Corporate Governance” section and the “Audit Committee Report” section; |
| |
| • | Audit Committee Members. The identity of the Audit Committee members will be included in the “Corporate Governance” section and the “Audit Committee Report” section; |
| |
| • | Executive Officers. The information regarding executive officers is included in Part I of this Form 10-K; and |
| |
| • | Section 16(a) Delinquency. If applicable, information regarding Section 16(a) delinquencies will be included in a “Delinquent Section 16(a) Reports” section. |
Directors. The information regarding directors will be included in the “Election of Directors” section;
Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Corporate Governance” section and the “Audit Committee Report” section;
Audit Committee Members. The identity of the Audit Committee members will be included in the “Corporate Governance” section and the “Audit Committee Report” section;
Executive Officers. The information regarding executive officers is included in Part I of this Form 10-K; and
Section 16(a) Compliance. The information regarding Section 16(a) compliance will be included in the “Ownership of ALLETE Common Stock – Section 16(a) Beneficial Ownership Reporting Compliance” section.
Our 20182020 Proxy Statement will be filed with the SEC within 120 days after the end of our 20172019 fiscal year.
Code of Ethics. We have adopted a written Code of Ethics that applies to all of our employees, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. A copy of our Code of Ethics is available on our website at www.allete.com and print copies are available without charge upon request to ALLETE, Inc., Attention: Secretary, 30 West Superior St., Duluth, Minnesota 55802. Any amendment to the Code of Ethics or any waiver of the Code of Ethics will be disclosed on our website at www.allete.com promptly following the date of such amendment or waiver.
Corporate Governance. The following documents are available on our website at www.allete.com and print copies are available upon request:
Corporate Governance Guidelines;
Audit Committee Charter;
Executive Compensation Committee Charter; and
Corporate Governance and Nominating Committee Charter.
Any amendment to these documents will be disclosed on our website at www.allete.com promptly following the date of such amendment.
Item 11. Executive Compensation
The information required forby this Item is incorporated by reference herein from the “Compensation Discussion and Analysis,” the “Compensation of Executive Officers,” the “Compensation Committee Report” and the “Director Compensation” sections in our 20182020 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required forby this Item is incorporated by reference herein from the “Ownership of ALLETE Common Stock – Securities Owned by Certain Beneficial Owners” and the “Ownership of ALLETE Common Stock – Securities Owned by Directors and Management” sections in our 20182020 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth the shares of ALLETE common stock available for issuance under the Company's equity compensation plans as of December 31, 2017:2019:
|
| | | | | | |
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (a)
|
| | | |
Equity Compensation Plans Approved by Security Holders | — |
| — |
| 1,266,716 |
|
Equity Compensation Plans Not Approved by Security Holders | — |
| N/A |
| — |
|
Total | — |
| — |
| 1,266,716 |
|
|
| | | | | | |
| Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a) | Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights (b) | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (c) |
| | | | |
| Equity Compensation Plans Approved by Security Holders | 150,181 |
| — |
| 857,656 |
|
| Equity Compensation Plans Not Approved by Security Holders | — |
| — |
| — |
|
| Total | 150,181 |
| — |
| 857,656 |
|
| |
| (a) | Includes the following: (i) 25,196 securities representing the performance shares (including accrued dividends) granted under the executive long-term incentive compensation plan that vested but were not paid as of December 31, 2019; (ii) 60,656 securities representing the target number of performance share awards (including accrued dividends) granted under the executive long-term incentive compensation plan that were unvested as of December 31, 2019; and (iii) 64,329 director deferred stock units (including accrued dividends) under the non-employee director compensation deferral plan as of December 31, 2019. With respect to unvested performance share awards, the actual number of shares to be issued will vary from 0 percent to 200 percent of the target level depending upon the achievement of total shareholder return objectives established for such awards. For additional information about the performance shares, including payout calculations, see our 2020 Proxy Statement. |
| |
| (b) | Earned performance share awards are paid in shares of ALLETE common stock on a one-for-one basis. Accordingly, these awards do not have a weighted-average exercise price. |
| |
| (c) | Excludes the number of securities shown in the first column as to be issued upon exercise of outstanding options, warrants, and rights. The amount shown is comprised of: (i) 1,005,861707,353 shares available for issuance under the executive long-term incentive compensation plan in the form of options, rights, restricted stock units, performance share awards, and other grants as approved by the Executive Compensation Committee of the Company’s Board of Directors; (ii) 136,17845,379 shares available for issuance under the Non-Employee Director Stock Plan as payment for a portion of the annual retainer payable to non-employee Directors; and (iii) 124,677104,925 shares available for issuance under the ALLETE and Affiliated Companies Employee Stock Purchase Plan. |
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required forby this Item is incorporated by reference herein from the “Corporate Governance” section in our 20182020 Proxy Statement.
We have adopted a Related Person Transaction Policy which is available on our website at www.allete.com. Print copies are available without charge, upon request. Any amendment to this policy will be disclosed on our website at www.allete.com promptly following the date of such amendment.
Item 14. Principal Accounting Fees and Services
The information required forby this Item is incorporated by reference herein from the “Audit Committee Report” section in our 20182020 Proxy Statement.
Part IV
Item 15. Exhibits and Financial Statement Schedules
|
| | | | |
| (a) | Certain Documents Filed as Part of this Form 10-K. | |
| (1) | Financial Statements | Page |
| | ALLETE | |
| | | |
| | | |
| | For the Years Ended December 31, 2017, 20162019, 2018 and 20152017 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| (2) | Financial Statement Schedules | |
| | | |
| | All other schedules have been omitted either because the information is not required to be reported by ALLETE or because the information is included in the Consolidated Financial Statements or the notes. |
| (3) | Exhibits including those incorporated by reference. | |
| Exhibit Number |
| | | | | | |
| — | |
| — | |
| — | |
| — | |
| — | |
| — | |
| — | |
| *4(a)1 | — | Mortgage and Deed of Trust, dated as of September 1, 1945, between Minnesota Power & Light Company (now ALLETE) and The Bank of New York Mellon (formerly Irving Trust Company) and Andres Serrano (successor to Richard H. West), Trustees (filed as Exhibit 7(c), File No. 2-5865). |
| *4(a)2 | — | Supplemental Indentures to ALLETE’s Mortgage and Deed of Trust: |
| | | Number | Dated as of | Reference File | Exhibit |
| | | First | March 1, 1949 | 2-7826 | 7(b) |
| | | Second | July 1, 1951 | 2-9036 | 7(c) |
| | | Third | March 1, 1957 | 2-13075 | 2(c) |
| | | Fourth | January 1, 1968 | 2-27794 | 2(c) |
| | | Fifth | April 1, 1971 | 2-39537 | 2(c) |
| | | Sixth | August 1, 1975 | 2-54116 | 2(c) |
| | | Seventh | September 1, 1976 | 2-57014 | 2(c) |
| | | Eighth | September 1, 1977 | 2-59690 | 2(c) |
| | | Ninth | April 1, 1978 | 2-60866 | 2(c) |
| | | Tenth | August 1, 1978 | 2-62852 | 2(d)2 |
| | | Eleventh | December 1, 1982 | 2-56649 | 4(a)3 |
| | | Twelfth | April 1, 1987 | 33-30224 | 4(a)3 |
| | | Thirteenth | March 1, 1992 | 33-47438 | 4(b) |
| | | Fourteenth | June 1, 1992 | 33-55240 | 4(b) |
| | | Fifteenth | July 1, 1992 | 33-55240 | 4(c) |
| | | Sixteenth | July 1, 1992 | 33-55240 | 4(d) |
| | | Seventeenth | February 1, 1993 | 33-50143 | 4(b) |
| | | Eighteenth | July 1, 1993 | 33-50143 | 4(c) |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
| | | | | |
| | | | | |
| Exhibit Number |
| | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| *4(b)1 | — |
| Mortgage and Deed of Trust, dated as of March 1, 1943, between Superior Water, Light and Power Company and Chemical Bank & Trust Company and Howard B. Smith, as Trustees, both succeeded by U.S. Bank National Association, as Trustee (filed as Exhibit 7(c), File No. 2-8668). |
| *4(b)2 | — |
| Supplemental Indentures to Superior Water, Light and Power Company’s Mortgage and Deed of Trust: |
| | | Number | Dated as of | Reference File | Exhibit |
| | | First | March 1, 1951 | 2-59690 | 2(d)(1) |
| | | Second | March 1, 1962 | 2-27794 | 2(d)1 |
| | | Third | July 1, 1976 | 2-57478 | 2(e)1 |
| | | Fourth | March 1, 1985 | 2-78641 | 4(b) |
| | | Fifth | December 1, 1992 | 1-3548 (1992 Form 10-K) | 4(b)1 |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
| — |
| |
| — |
| Term Loan Agreement dated as of August 25, 2015, among ALLETE, as Borrower, the Lenders party hereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities LLC, as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 4 to the August 28, 2015, Form 8-K, File No. 1-3548). |
| — |
| |
| — |
| |
| — |
| Term Loan Agreement dated as of August 25, 2017, among ALLETE, as Borrower, the Lenders party hereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and JPMorgan Chase Bank, N.A., as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 4 to the September 30, 2017, Form 10-Q, File No. 1-3548). |
| — |
| Amended and Restated Term Loan Agreement dated as of August 14, 2019 among ALLETE, Inc., as Borrower, the Lenders Party Hereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A., as Syndication Agent and JPMorgan Chase Bank, N.A., as Sole Lead Arranger and Sole Bookrunner (filed as Exhibit 4 to the September 30, 2019, Form 10-Q, File No. 1-3548) |
| — |
| |
| — |
| |
| — |
| |
| — |
| Amended and Restated Credit Agreement dated as of November 4, 2013January 10, 2019 among ALLETE, as Borrower, the lenders party thereto,hereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities LLC,Chase Bank, N.A., as Sole Lead Arranger and Sole Book Runner (filed as Exhibit 1010(b)2 to the November 4, 2013,2018 Form 8-K,10-K, File No. 1-3548). |
| — |
| First Amendment to Credit Agreement dated May 15, 2019, among ALLETE, as Borrower, the Lenders party hereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the June 30, 2019, Form 10-Q, File No. 1-3548). |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
Exhibit Number |
| | | | | | |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| Exhibit Number |
| | | | | | |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
Exhibit Number |
| | | | | | |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| — |
| |
| 101.INS | — |
| XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| 101.SCH | — |
| XBRL Schema |
| 101.CAL | — |
| XBRL Calculation |
| 101.DEF | — |
| XBRL Definition |
| 101.LAB | — |
| XBRL Label |
| 101.PRE | — |
| XBRL Presentation |
| 104 | — |
| Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
Exhibits (Continued)
ALLETE or its subsidiaries are obligors under various long-term debt instruments including, but not limited to, the following:
$38,995,000 original principal amount, of City of Cohasset, Minnesota, Variable Rate Demand Revenue Refunding Bonds (ALLETE, formerly Minnesota Power & Light Company, Project) Series 1997A ($13,500,000 remaining principal balance);
$27,800,000 of Collier County Industrial Development Authority, Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006;
$6,370,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Refunding Bonds Series 2007A; and
$6,130,000 of City of Superior, Wisconsin, Collateralized Utility Revenue Bonds Series 2007B.
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, these and other long-term debt instruments are not filed as exhibits because the total amount of debt authorized under each of these omitted instrumentsinstrument does not exceed 10 percent of our total consolidated assets. We will furnish copies of these instruments to the SEC upon its request.
|
| |
| * | Incorporated herein by reference as indicated. |
| + | Management contract or compensatory plan or arrangement pursuant to Item 15(b). |
Item 16. Form 10-K Summary
None.
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.
|
| | | |
| | | ALLETE, Inc. |
| | |
| | |
| Dated: | February 15, 201813, 2020 | By | /s/ Alan R. Hodnik |
| | | Alan R. Hodnik |
| | | Executive Chairman President, Chief Executive Officerand Director |
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.
|
| | | | |
| Signature | | Title | | Date |
| | | | | |
/s/ Alan R. HodnikBethany M. Owen | | Chairman, President, Chief Executive Officer and Director | | February 15, 201813, 2020 |
Alan R. HodnikBethany M. Owen | | (Principal Executive Officer) | | |
| | | | | |
| /s/ Robert J. Adams | | Senior Vice President and Chief Financial Officer | | February 15, 201813, 2020 |
| Robert J. Adams | | (Principal Financial Officer) | | |
| | | | | |
| /s/ Steven W. Morris | | Vice President, Controller and Chief Accounting Officer | | February 15, 201813, 2020 |
| Steven W. Morris | | (Principal Accounting Officer) | | |
Signatures (Continued)
|
| | | | |
| Signature | | Title | | Date |
| | | | | |
| /s/ Kathryn W. Dindo | | Director | | February 15, 201813, 2020 |
| Kathryn W. Dindo | | | | |
| | | | |
/s/ Sidney W. Emery, Jr. | | Director | | February 15, 2018 |
Sidney W. Emery, Jr. | | | | |
| | | | | |
| /s/ George G. Goldfarb | | Director | | February 15, 201813, 2020 |
| George G. Goldfarb | | | | |
| | | | |
/s/ James S. Haines, Jr. | | Director | | February 15, 2018 |
James S. Haines, Jr. | | | | |
| | | | | |
| /s/ James J. Hoolihan | | Director | | February 15, 201813, 2020 |
| James J. Hoolihan | | | | |
| | | | | |
| /s/ Heidi E. Jimmerson | | Director | | February 15, 201813, 2020 |
| Heidi E. Jimmerson | | | | |
| | | | | |
| /s/ Madeleine W. Ludlow | | Director | | February 15, 201813, 2020 |
| Madeleine W. Ludlow | | | | |
| | | | | |
| /s/ Susan K. Nestegard | | Director | | February 15, 201813, 2020 |
| Susan K. Nestegard | | | | |
| | | | | |
| /s/ Douglas C. Neve | | Director | | February 15, 201813, 2020 |
| Douglas C. Neve | | | | |
| | | | | |
| /s/ Robert P. Powers | | Director | | February 15, 201813, 2020 |
| Robert P. Powers | | | | |
| | | | |
/s/ Leonard C. Rodman | | Director | | February 15, 2018 |
Leonard C. Rodman | | | | |
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Shareholders of ALLETE, Inc.:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheetssheet of ALLETE, Inc. and its subsidiaries (the Company) as of December 31, 20172019 and 2016,2018, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2017,2019, including the related notes and financial statement schedule of valuation and qualifying accounts and reserveslisted in the index appearing under Item 15(a)(2) for each of the three years in the period ended December 31, 2017 appearing under Item 15(a)(2)2019 (collectively referred to as the “consolidatedconsolidated financial statements”)statements). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management'sManagement’s Report on Internal Control overOver Financial Reporting.Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Report of Independent Registered Public Accounting Firm (Continued)
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.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulatory Matters
As described in Notes 1 and 4 to the consolidated financial statements, the Company’s regulated utility operations are subject to accounting standards for the effects of certain types of regulation. As of December 31, 2019, there was $421 million of regulatory assets and $562 million of regulatory liabilities recorded. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. Management assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. As disclosed by management, these standards require the Company to reflect the effect of regulatory decisions in its financial statements. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income.
The principal consideration for our determination that performing procedures relating to the Company’s accounting for the effects of regulatory matters is a critical audit matter are there was significant judgment by management in determining the recoverability of costs. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence obtained related to the recoverability of costs.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation of new regulatory orders, changes to existing regulatory orders, and assessing the recoverability of costs. These procedures also included, among others, evaluating (i) the reasonableness of management’s assessment of impacts arising from correspondence with regulators and changes in laws and regulations, (ii) management’s judgments related to the recoverability of regulatory assets and the establishment of regulatory liabilities, and (iii) the sufficiency of the disclosures in the consolidated financial statements. Testing the regulatory assets and liabilities involved considering the provisions and formulas outlined in rate orders, other regulatory correspondence, and application of relevant regulatory precedents.
/s/ PricewaterhouseCoopers LLP
Minneapolis, Minnesota
February 15, 201813, 2020
We have served as the Company’s auditor since 1963.
CONSOLIDATED FINANCIAL STATEMENTS
ALLETE Consolidated Balance Sheet
| | | As of December 31 | 2017 |
| 2016 |
| 2019 |
| 2018 |
|
| Millions | | |
| Assets | | |
| Current Assets | | |
| Cash and Cash Equivalents |
| $98.9 |
|
| $27.5 |
|
| $69.3 |
|
| $69.1 |
|
| Accounts Receivable (Less Allowance of $2.1 and $3.1) | 135.1 |
| 122.5 |
| |
| Accounts Receivable (Less Allowance of $0.9 and $1.7) | | 96.4 |
| 144.4 |
|
| Inventories – Net | 95.9 |
| 104.2 |
| 72.8 |
| 86.7 |
|
| Prepayments and Other | 37.6 |
| 40.3 |
| 31.0 |
| 34.1 |
|
| Total Current Assets | 367.5 |
| 294.5 |
| 269.5 |
| 334.3 |
|
| Property, Plant and Equipment – Net | 3,822.4 |
| 3,741.2 |
| 4,377.0 |
| 3,904.4 |
|
| Regulatory Assets | 384.7 |
| 330.1 |
| 420.5 |
| 389.5 |
|
| Investment in ATC | 118.7 |
| 135.6 |
| |
| Other Investments | 53.1 |
| 55.6 |
| |
| Equity Investments | | 197.6 |
| 161.1 |
|
| Goodwill and Intangible Assets – Net | 225.9 |
| 213.4 |
| 1.0 |
| 223.3 |
|
| Other Non-Current Assets | 107.7 |
| 106.5 |
| 217.2 |
| 152.4 |
|
| Total Assets |
| $5,080.0 |
|
| $4,876.9 |
|
| $5,482.8 |
|
| $5,165.0 |
|
| Liabilities and Shareholders’ Equity | | |
| Liabilities and Equity | | |
| Liabilities | | |
| Current Liabilities | | |
| Accounts Payable |
| $136.3 |
|
| $74.0 |
|
| $165.2 |
|
| $149.8 |
|
| Accrued Taxes | 50.0 |
| 46.5 |
| 50.8 |
| 51.4 |
|
| Accrued Interest | 17.6 |
| 17.6 |
| 18.1 |
| 17.9 |
|
| Long-Term Debt Due Within One Year | 64.1 |
| 187.7 |
| 212.9 |
| 57.5 |
|
| Other | 83.2 |
| 73.7 |
| 60.4 |
| 128.5 |
|
| Total Current Liabilities | 351.2 |
| 399.5 |
| 507.4 |
| 405.1 |
|
| Long-Term Debt | 1,439.2 |
| 1,370.4 |
| 1,400.9 |
| 1,428.5 |
|
| Deferred Income Taxes | 230.5 |
| 554.6 |
| 212.8 |
| 223.6 |
|
| Regulatory Liabilities | 532.0 |
| 125.8 |
| 560.3 |
| 512.1 |
|
| Defined Benefit Pension and Other Postretirement Benefit Plans | 191.8 |
| 210.9 |
| 172.8 |
| 177.3 |
|
| Other Non-Current Liabilities | 267.1 |
| 322.7 |
| 293.0 |
| 262.6 |
|
| Total Liabilities | 3,011.8 |
| 2,983.9 |
| 3,147.2 |
| 3,009.2 |
|
| Commitments, Guarantees and Contingencies (Note 11) |
| |
| Shareholders’ Equity | | |
| Common Stock Without Par Value, 80.0 Shares Authorized, 51.1 and 49.6 Shares Issued and Outstanding | 1,401.4 |
| 1,295.3 |
| |
| Commitments, Guarantees and Contingencies (Note 9) | |
|
| Equity | | |
| ALLETE’s Equity | | |
| Common Stock Without Par Value, 80.0 Shares Authorized, 51.7 and 51.5 Shares Issued and Outstanding | | 1,436.7 |
| 1,428.5 |
|
| Accumulated Other Comprehensive Loss | (22.6 | ) | (28.2 | ) | (23.6 | ) | (27.3 | ) |
| Retained Earnings | 689.4 |
| 625.9 |
| 818.8 |
| 754.6 |
|
| Total Shareholders’ Equity | 2,068.2 |
| 1,893.0 |
| |
| Total Liabilities and Shareholders’ Equity |
| $5,080.0 |
|
| $4,876.9 |
| |
| Total ALLETE Equity | | 2,231.9 |
| 2,155.8 |
|
| Non-Controlling Interest in Subsidiaries | | 103.7 |
| — |
|
| Total Equity | | 2,335.6 |
| 2,155.8 |
|
| Total Liabilities and Equity | |
| $5,482.8 |
|
| $5,165.0 |
|
The accompanying notes are an integral part of these statements.
ALLETE Consolidated Statement of Income
|
| | | | | | | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions Except Per Share Amounts | | | |
| Operating Revenue | | | |
| Utility |
| $1,063.8 |
|
| $1,000.7 |
|
| $991.2 |
|
| Non-utility | 355.5 |
| 339.0 |
| 495.2 |
|
| Total Operating Revenue | 1,419.3 |
| 1,339.7 |
| 1,486.4 |
|
| Operating Expenses | | | |
| Fuel, Purchased Power and Gas – Utility | 396.9 |
| 339.9 |
| 336.0 |
|
| Transmission Services – Utility | 71.2 |
| 65.2 |
| 54.1 |
|
| Cost of Sales – Non-utility | 147.8 |
| 137.7 |
| 294.4 |
|
| Operating and Maintenance | 339.9 |
| 334.1 |
| 333.5 |
|
| Depreciation and Amortization | 177.5 |
| 195.8 |
| 170.0 |
|
| Taxes Other than Income Taxes | 56.9 |
| 53.8 |
| 51.4 |
|
| Other | (0.7 | ) | (10.3 | ) | 36.3 |
|
| Total Operating Expenses | 1,189.5 |
| 1,116.2 |
| 1,275.7 |
|
| Operating Income | 229.8 |
| 223.5 |
| 210.7 |
|
| Other Income (Expense) | | | |
| Interest Expense | (67.8 | ) | (70.3 | ) | (64.9 | ) |
| Equity Earnings in ATC | 22.5 |
| 18.5 |
| 16.3 |
|
| Other | 2.4 |
| 3.9 |
| 4.7 |
|
| Total Other Expense | (42.9 | ) | (47.9 | ) | (43.9 | ) |
| Income Before Non-Controlling Interest and Income Taxes | 186.9 |
| 175.6 |
| 166.8 |
|
| Income Tax Expense | 14.7 |
| 19.8 |
| 25.3 |
|
| Net Income | 172.2 |
| 155.8 |
| 141.5 |
|
| Less: Non-Controlling Interest in Subsidiaries | — |
| 0.5 |
| 0.4 |
|
| Net Income Attributable to ALLETE |
| $172.2 |
|
| $155.3 |
|
| $141.1 |
|
| Average Shares of Common Stock | | | |
| Basic | 50.8 |
| 49.3 |
| 48.3 |
|
| Diluted | 51.0 |
| 49.5 |
| 48.4 |
|
| Basic Earnings Per Share of Common Stock |
| $3.39 |
|
| $3.15 |
|
| $2.92 |
|
| Diluted Earnings Per Share of Common Stock |
| $3.38 |
|
| $3.14 |
|
| $2.92 |
|
| Dividends Per Share of Common Stock |
| $2.14 |
|
| $2.08 |
|
| $2.02 |
|
The accompanying notes are an integral part of these statements.
ALLETE Consolidated Statement of Comprehensive Income
|
| | | | | | | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Net Income |
| $172.2 |
|
| $155.8 |
|
| $141.5 |
|
| Other Comprehensive Income (Loss) | | | |
| Unrealized Gain (Loss) on Securities | | | |
| Net of Income Tax Expense (Benefit) of $0.7, $(0.2) and $(0.3) | 0.9 |
| (0.2 | ) | (0.5 | ) |
| Unrealized Gain on Derivatives | | | |
| Net of Income Tax Expense of $–, $– and $0.1 | — |
| — |
| 0.1 |
|
| Defined Benefit Pension and Other Postretirement Benefit Plans | | | |
| Net of Income Tax Expense (Benefit) of $2.2, $(2.4) and $(2.2) | 4.7 |
| (3.5 | ) | (3.0 | ) |
| Total Other Comprehensive Income (Loss) | 5.6 |
| (3.7 | ) | (3.4 | ) |
| Total Comprehensive Income | 177.8 |
| 152.1 |
| 138.1 |
|
| Less: Non-Controlling Interest in Subsidiaries | — |
| 0.5 |
| 0.4 |
|
| Total Comprehensive Income Attributable to ALLETE |
| $177.8 |
|
| $151.6 |
|
| $137.7 |
|
|
| | | | | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions Except Per Share Amounts | | | |
| Operating Revenue | | | |
| Contracts with Customers – Utility |
| $1,042.4 |
|
| $1,059.5 |
|
| $1,063.8 |
|
| Contracts with Customers – Non-utility | 186.5 |
| 415.5 |
| 331.9 |
|
| Other – Non-utility | 11.6 |
| 23.6 |
| 23.6 |
|
| Total Operating Revenue | 1,240.5 |
| 1,498.6 |
| 1,419.3 |
|
| Operating Expenses | | | |
| Fuel, Purchased Power and Gas – Utility | 390.7 |
| 407.5 |
| 396.9 |
|
| Transmission Services – Utility | 69.8 |
| 69.9 |
| 71.2 |
|
| Cost of Sales – Non-utility | 80.6 |
| 218.0 |
| 147.5 |
|
| Operating and Maintenance | 264.3 |
| 340.5 |
| 344.1 |
|
| Depreciation and Amortization | 202.0 |
| 205.6 |
| 177.5 |
|
| Taxes Other than Income Taxes | 53.3 |
| 57.9 |
| 56.9 |
|
| Other | — |
| (2.0 | ) | (0.7 | ) |
| Total Operating Expenses | 1,060.7 |
| 1,297.4 |
| 1,193.4 |
|
| Operating Income | 179.8 |
| 201.2 |
| 225.9 |
|
| Other Income (Expense) | | | |
| Interest Expense | (64.9 | ) | (67.9 | ) | (67.8 | ) |
| Equity Earnings | 21.7 |
| 17.5 |
| 22.5 |
|
| Gain on Sale of U.S. Water Services | 23.6 |
| — |
| — |
|
| Other | 18.7 |
| 7.8 |
| 6.3 |
|
| Total Other Expense | (0.9 | ) | (42.6 | ) | (39.0 | ) |
| Income Before Non-Controlling Interest and Income Taxes | 178.9 |
| 158.6 |
| 186.9 |
|
| Income Tax Expense (Benefit) | (6.6 | ) | (15.5 | ) | 14.7 |
|
| Net Income | 185.5 |
| 174.1 |
| 172.2 |
|
| Less: Non-Controlling Interest in Subsidiaries | (0.1 | ) | — |
| — |
|
| Net Income Attributable to ALLETE |
| $185.6 |
|
| $174.1 |
|
| $172.2 |
|
| Average Shares of Common Stock | | | |
| Basic | 51.6 |
| 51.3 |
| 50.8 |
|
| Diluted | 51.7 |
| 51.5 |
| 51.0 |
|
| Basic Earnings Per Share of Common Stock |
| $3.59 |
|
| $3.39 |
|
| $3.39 |
|
| Diluted Earnings Per Share of Common Stock |
| $3.59 |
|
| $3.38 |
|
| $3.38 |
|
The accompanying notes are an integral part of these statements.
ALLETE Consolidated Statement of Cash FlowsComprehensive Income
|
| | | | | | | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Operating Activities | | | |
| Net Income |
| $172.2 |
|
| $155.8 |
|
| $141.5 |
|
| AFUDC – Equity | (1.2 | ) | (2.1 | ) | (3.3 | ) |
| Income from Equity Investments – Net of Dividends | (3.2 | ) | (5.7 | ) | (1.8 | ) |
| Impairment of Real Estate | — |
| — |
| 36.3 |
|
| Impairment of Goodwill | — |
| 3.3 |
| — |
|
| Change in Fair Value of Contingent Consideration | (0.7 | ) | (13.6 | ) | — |
|
| Deferred Fuel Adjustment Clause Charge | 19.5 |
| — |
| — |
|
| Loss (Gain) on Sales of Investments and Property, Plant and Equipment | 0.4 |
| (6.0 | ) | (0.2 | ) |
| Depreciation Expense | 171.9 |
| 190.6 |
| 165.9 |
|
| Amortization of PSAs | (23.6 | ) | (22.3 | ) | (23.2 | ) |
| Amortization of Other Intangible Assets and Other Assets | 10.2 |
| 10.3 |
| 5.6 |
|
| Deferred Income Tax Expense | 14.4 |
| 19.4 |
| 25.1 |
|
| Share-Based and ESOP Compensation Expense | 6.6 |
| 5.1 |
| 11.6 |
|
| Defined Benefit Pension and Other Postretirement Benefit Expense | 10.1 |
| 4.6 |
| 15.4 |
|
| Bad Debt Expense | 0.8 |
| 4.1 |
| 1.6 |
|
| Provision for Interim Rate Refund | 32.3 |
| — |
| — |
|
| Changes in Operating Assets and Liabilities | | | |
| Accounts Receivable | (8.0 | ) | (4.7 | ) | 1.1 |
|
| Inventories | 11.9 |
| 13.3 |
| (22.1 | ) |
| Prepayments and Other | (5.3 | ) | (6.9 | ) | 3.7 |
|
| Accounts Payable | (7.5 | ) | 6.5 |
| (19.3 | ) |
| Other Current Liabilities | 1.8 |
| (13.8 | ) | 5.1 |
|
| Cash Contributions to Defined Benefit Pension Plans | (1.7 | ) | (6.3 | ) | — |
|
| Changes in Regulatory and Other Non-Current Assets | 33.7 |
| (10.7 | ) | 0.6 |
|
| Changes in Regulatory and Other Non-Current Liabilities | (31.7 | ) | 11.1 |
| (3.5 | ) |
| Cash from Operating Activities | 402.9 |
| 332.0 |
| 340.1 |
|
| Investing Activities | | | |
| Proceeds from Sale of Available-for-sale Securities | 10.1 |
| 9.0 |
| 1.7 |
|
| Payments for Purchase of Available-for-sale Securities | (8.6 | ) | (9.4 | ) | (2.3 | ) |
| Acquisitions of Subsidiaries – Net of Cash Acquired | (18.5 | ) | (5.9 | ) | (333.3 | ) |
| Investment in ATC | (7.8 | ) | (5.4 | ) | (1.6 | ) |
| Changes to Other Investments | 3.0 |
| 4.4 |
| 3.1 |
|
| Additions to Property, Plant and Equipment | (208.5 | ) | (265.6 | ) | (286.8 | ) |
| Proceeds from Sale of Property, Plant and Equipment | 1.3 |
| 0.7 |
| 0.4 |
|
| Changes in Restricted Cash | — |
| (4.0 | ) | — |
|
| Cash for Investing Activities | (229.0 | ) | (276.2 | ) | (618.8 | ) |
| Financing Activities | | | |
| Proceeds from Issuance of Common Stock | 86.0 |
| 30.9 |
| 161.2 |
|
| Proceeds from Issuance of Long-Term Debt | 131.5 |
| 4.8 |
| 324.5 |
|
| Changes in Restricted Cash | (0.4 | ) | 7.0 |
| 8.5 |
|
| Changes in Notes Payable | — |
| (1.6 | ) | (2.1 | ) |
| Repayments of Long-Term Debt | (189.6 | ) | (54.8 | ) | (160.2 | ) |
| Acquisition of Non-Controlling Interest | — |
| (8.0 | ) | — |
|
| Acquisition-Related Contingent Consideration Payments | (19.7 | ) | (0.9 | ) | — |
|
| Dividends on Common Stock | (108.7 | ) | (102.7 | ) | (97.9 | ) |
| Other Financing Activities | (1.6 | ) | — |
| (4.1 | ) |
| Cash from (for) Financing Activities | (102.5 | ) | (125.3 | ) | 229.9 |
|
| Change in Cash and Cash Equivalents | 71.4 |
| (69.5 | ) | (48.8 | ) |
| Cash and Cash Equivalents at Beginning of Period | 27.5 |
| 97.0 |
| 145.8 |
|
| Cash and Cash Equivalents at End of Period |
| $98.9 |
|
| $27.5 |
|
| $97.0 |
|
|
| | | | | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Net Income |
| $185.5 |
|
| $174.1 |
|
| $172.2 |
|
| Other Comprehensive Income (Loss) | | | |
| Unrealized Gain (Loss) on Securities | | | |
| Net of Income Tax Expense of $0.1, $– and $0.7 | 0.2 |
| (0.1 | ) | 0.9 |
|
| Defined Benefit Pension and Other Postretirement Benefit Plans | | | |
| Net of Income Tax Expense of $1.4, $0.3 and $2.2 | 3.5 |
| 1.0 |
| 4.7 |
|
| Total Other Comprehensive Income | 3.7 |
| 0.9 |
| 5.6 |
|
| Total Comprehensive Income | 189.2 |
| 175.0 |
| 177.8 |
|
| Less: Non-Controlling Interest in Subsidiaries | (0.1 | ) | — |
| — |
|
| Total Comprehensive Income Attributable to ALLETE |
| $189.3 |
|
| $175.0 |
|
| $177.8 |
|
The accompanying notes are an integral part of these statements.
ALLETE Consolidated Statement of EquityCash Flows
|
| | | | | | | | | | | | | | | | |
| | Total Equity | Retained Earnings | Accumulated Other Comprehensive Loss | Unearned ESOP Shares | Common Stock | Non-Controlling Interest in Subsidiaries |
| Millions | | | | | | |
| Balance as of December 31, 2014 |
| $1,611.2 |
|
| $530.1 |
| $(21.1) | $(7.2) |
| $1,107.6 |
|
| $1.8 |
|
| Comprehensive Income | | | | | | |
| Net Income | 141.5 |
| 141.1 |
| — |
| — |
| — |
| 0.4 |
|
| Other Comprehensive Income – Net of Tax | | | | | | |
| Unrealized Loss on Securities | (0.5 | ) | — |
| (0.5 | ) | — |
| — |
| — |
|
| Unrealized Gain on Derivatives | 0.1 |
| — |
| 0.1 |
| — |
| — |
| — |
|
| Defined Benefit Pension and Other Postretirement Plans | (3.0 | ) | — |
| (3.0 | ) | — |
| — |
| — |
|
| Total Comprehensive Income | 138.1 |
| | | | | |
| Common Stock Issued | 163.8 |
| — |
| — |
| — |
| 163.8 |
| — |
|
| Dividends Declared | (97.9 | ) | (97.9 | ) | — |
| — |
| — |
| — |
|
| ESOP Shares Earned | 7.2 |
| — |
| — |
| 7.2 |
| — |
| — |
|
| Balance as of December 31, 2015 | 1,822.4 |
| 573.3 |
| (24.5 | ) | — |
| 1,271.4 |
| 2.2 |
|
| Comprehensive Income | | | | | | |
| Net Income | 155.8 |
| 155.3 |
| — |
| — |
| — |
| 0.5 |
|
| Other Comprehensive Income – Net of Tax | | | | | | |
| Unrealized Loss on Securities | (0.2 | ) | — |
| (0.2 | ) | — |
| — |
| — |
|
| Defined Benefit Pension and Other Postretirement Plans | (3.5 | ) | — |
| (3.5 | ) | — |
| — |
| — |
|
| Total Comprehensive Income | 152.1 |
| | | | | |
| Common Stock Issued | 35.9 |
| — |
| — |
| — |
| 35.9 |
| — |
|
| Common Stock Retired | (8.0 | ) | — |
| — |
| — |
| (8.0 | ) | — |
|
| Dividends Declared | (102.7 | ) | (102.7 | ) | — |
| — |
| — |
| — |
|
| Acquisition of Non-Controlling Interest | (6.7 | ) | — |
| — |
| — |
| (4.0 | ) | (2.7 | ) |
| Balance as of December 31, 2016 | 1,893.0 |
| 625.9 |
| (28.2 | ) | — |
| 1,295.3 |
| — |
|
| Comprehensive Income | | | | | | |
| Net Income | 172.2 |
| 172.2 |
| — |
| — |
| — |
| — |
|
| Other Comprehensive Income – Net of Tax | | | | | | |
| Unrealized Gain on Securities | 0.9 |
| — |
| 0.9 |
| — |
| — |
| — |
|
| Defined Benefit Pension and Other Postretirement Plans | 4.7 |
| — |
| 4.7 |
| — |
| — |
| — |
|
| Total Comprehensive Income | 177.8 |
| | | | | |
| Common Stock Issued | 106.1 |
| — |
| — |
| — |
| 106.1 |
| — |
|
| Dividends Declared | (108.7 | ) | (108.7 | ) | — |
| — |
| — |
| — |
|
| Balance as of December 31, 2017 |
| $2,068.2 |
|
| $689.4 |
| $(22.6) | — |
|
| $1,401.4 |
| — |
|
|
| | | | | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Operating Activities | | | |
| Net Income |
| $185.5 |
|
| $174.1 |
|
| $172.2 |
|
| AFUDC – Equity | (2.3 | ) | (1.2 | ) | (1.2 | ) |
| Income from Equity Investments – Net of Dividends | (5.6 | ) | (2.3 | ) | (3.2 | ) |
| Change in Fair Value of Contingent Consideration | — |
| (2.0 | ) | (0.7 | ) |
| Deferred Fuel Adjustment Clause Charge | — |
| — |
| 19.5 |
|
| Loss (Gain) on Sales of Investments and Property, Plant and Equipment | (1.7 | ) | 1.0 |
| 0.4 |
|
| Depreciation Expense | 200.6 |
| 200.1 |
| 171.9 |
|
| Amortization of PSAs | (11.6 | ) | (23.6 | ) | (23.6 | ) |
| Amortization of Other Intangible Assets and Other Assets | 13.0 |
| 10.4 |
| 10.2 |
|
| Deferred Income Tax Expense (Benefit) | (6.7 | ) | (15.8 | ) | 14.4 |
|
| Share-Based and ESOP Compensation Expense | 6.3 |
| 6.8 |
| 6.6 |
|
| Defined Benefit Pension and Other Postretirement Benefit Expense | 1.2 |
| 8.6 |
| 10.1 |
|
| Bad Debt Expense | (0.1 | ) | 1.1 |
| 0.8 |
|
| Provision (Payments) for Interim Rate Refund | (40.0 | ) | 16.3 |
| 32.3 |
|
| Provision (Payments) for Tax Reform Refund | (10.4 | ) | 10.7 |
| — |
|
| Gain on Sale of U.S. Water Services | (23.6 | ) | — |
| — |
|
| Changes in Operating Assets and Liabilities | | | |
| Accounts Receivable | 22.6 |
| (10.7 | ) | (8.0 | ) |
| Inventories | (4.1 | ) | 55.5 |
| 11.9 |
|
| Prepayments and Other | 0.3 |
| (4.0 | ) | (5.3 | ) |
| Accounts Payable | (8.8 | ) | 13.6 |
| (7.5 | ) |
| Other Current Liabilities | (13.7 | ) | 6.7 |
| 1.8 |
|
| Cash Contributions to Defined Benefit Pension Plans | (10.4 | ) | (15.0 | ) | (1.7 | ) |
| Changes in Regulatory and Other Non-Current Assets | (25.1 | ) | 6.7 |
| 33.7 |
|
| Changes in Regulatory and Other Non-Current Liabilities | (15.9 | ) | (3.9 | ) | (31.7 | ) |
| Cash from Operating Activities | 249.5 |
| 433.1 |
| 402.9 |
|
| Investing Activities | | | |
| Proceeds from Sale of Available-for-sale Securities | 12.1 |
| 10.2 |
| 10.1 |
|
| Payments for Purchase of Available-for-sale Securities | (12.2 | ) | (13.3 | ) | (8.6 | ) |
| Acquisitions of Subsidiaries – Net of Cash and Restricted Cash Acquired | — |
| — |
| (18.5 | ) |
| Equity Investments | (37.9 | ) | (39.2 | ) | (7.8 | ) |
| Return of Capital from Equity Investments | 8.3 |
| — |
| — |
|
| Additions to Property, Plant and Equipment | (597.1 | ) | (312.4 | ) | (208.5 | ) |
| Proceeds from Sale of U.S. Water Services – Net of Transaction Costs and Cash Retained | 268.6 |
| — |
| — |
|
| Other Investing Activities | 12.9 |
| 5.7 |
| 4.3 |
|
| Cash for Investing Activities | (345.3 | ) | (349.0 | ) | (229.0 | ) |
| Financing Activities | | | |
| Proceeds from Issuance of Common Stock | 1.9 |
| 20.3 |
| 86.0 |
|
| Proceeds from Issuance of Long-Term Debt | 201.9 |
| 75.6 |
| 131.5 |
|
| Repayments of Long-Term Debt | (72.2 | ) | (95.5 | ) | (189.6 | ) |
| Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs | 103.8 |
| — |
| — |
|
| Acquisition-Related Contingent Consideration Payments | (3.8 | ) | — |
| (19.7 | ) |
| Dividends on Common Stock | (121.4 | ) | (115.0 | ) | (108.7 | ) |
| Other Financing Activities | (0.9 | ) | (0.6 | ) | (1.6 | ) |
| Cash (for) from Financing Activities | 109.3 |
| (115.2 | ) | (102.1 | ) |
| Change in Cash, Cash Equivalents and Restricted Cash | 13.5 |
| (31.1 | ) | 71.8 |
|
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 79.0 |
| 110.1 |
| 38.3 |
|
| Cash, Cash Equivalents and Restricted Cash at End of Period |
| $92.5 |
|
| $79.0 |
|
| $110.1 |
|
The accompanying notes are an integral part of these statements.
ALLETE Consolidated Statement of Equity
|
| | | | | | | | | |
| | 2019 |
| 2018 |
| 2017 |
|
| Millions Except Per Share Amounts | | | |
| Common Stock | | | |
| Balance, Beginning of Period |
| $1,428.5 |
|
| $1,401.4 |
|
| $1,295.3 |
|
| Common Stock Issued | 8.2 |
| 27.1 |
| 106.1 |
|
| Balance, End of Period | 1,436.7 |
| 1,428.5 |
| 1,401.4 |
|
| | | | |
| Accumulated Other Comprehensive Loss | | | |
| Balance, Beginning of Period | (27.3 | ) | (22.6 | ) | (28.2 | ) |
Adjustments to Opening Balance – Net of Income Taxes (a) | — |
| (5.6 | ) | — |
|
| Other Comprehensive Income – Net of Income Taxes |
|
|
|
| Unrealized Gain (Loss) on Debt Securities | 0.2 |
| (0.1 | ) | 0.9 |
|
| Defined Benefit Pension and Other Postretirement Plans | 3.5 |
| 1.0 |
| 4.7 |
|
| Balance, End of Period | (23.6 | ) | (27.3 | ) | (22.6 | ) |
| | | | |
| Retained Earnings | | | |
| Balance, Beginning of Period | 754.6 |
| 689.4 |
| 625.9 |
|
Adjustments to Opening Balance – Net of Income Taxes (a) | — |
| 6.1 |
| — |
|
| Net Income | 185.6 |
| 174.1 |
| 172.2 |
|
| Common Stock Dividends | (121.4 | ) | (115.0 | ) | (108.7 | ) |
| Balance, End of Period | 818.8 |
| 754.6 |
| 689.4 |
|
| | | | |
| Non-Controlling Interest in Subsidiaries | | | |
| Balance, Beginning of Period | — |
| — |
| — |
|
| Proceeds from Non-Controlling Interest in Subsidiaries – Net of Issuance Costs | 103.8 |
| — |
| — |
|
| Net Loss | (0.1 | ) | — |
| — |
|
| Balance, End of Period | 103.7 |
| — |
| — |
|
| | | | |
| Total Equity |
| $2,335.6 |
|
| $2,155.8 |
|
| $2,068.2 |
|
| | | | |
| Dividends Per share of Common Stock |
| $2.35 |
|
| $2.24 |
|
| $2.14 |
|
| |
| (a) | Reflects the impacts associated with the adoption of accounting standards concerning Financial Instruments, Revenue from Contracts with Customers and the Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. (See Note 1. Operations and Significant Accounting Policies.) |
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
Financial Statement Preparation. References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with GAAP. These principles require management to make informed judgments, best estimates, and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. Actual results could differ from those estimates.
Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the time of the financial statements issuance.
Principles of Consolidation. Our Consolidated Financial Statements include the accounts of ALLETE and, all of our majority‑owned subsidiary companies.companies and variable interest entities of which ALLETE is the primary beneficiary. All material intercompany balances and transactions have been eliminated in consolidation.
Variable Interest Entities. The accounting guidance for “Variable Interest Entities” (VIE) is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether ALLETE is the primary beneficiary of a VIE, management considers whether ALLETE has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. The accounting guidance for VIEs applies to certain ALLETE Clean Energy wind energy facilities. (See Tax Equity Financing.)
Business Segments. We present three3 reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. Our segments were determined in accordance with the guidance on segment reporting. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 145,000 retail customers. Minnesota Power also has 1615 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities.
ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in fourfive states, approximately 535660 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. In addition, ALLETE Clean Energy currently has approximately 380 MW of wind energy facilities under construction that it will own and operate with long-term PSAs in place. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.
U.S. Water Services providesprovided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. On March 26, 2019, the Company sold U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. pursuant to a stock purchase agreement for approximately $270 million in cash, net of transaction costs and cash retained.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Corporate and Otheris comprised of BNI Energy, our investment in Nobles 2, ALLETE Properties, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,0004,000 acres of land in Minnesota, and earnings on cash and investments.
BNI Energy mines and sells lignite coal to two2 North Dakota mine-mouth generating units, one1 of which is Square Butte. In 20172019, Square Butte supplied 50 percent (227.5 MW) of its output to Minnesota Power under long-term contracts. (See Note 11.9. Commitments, Guarantees and Contingencies.)
Our investment in Nobles 2 represents a 49 percent equity interest in Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power.
ALLETE Properties represents our legacy Florida real estate investment. Our strategy related to the real estate assets of ALLETE Properties is to sell individual parcels over time, but incorporates the possibility of a bulk sale of ourthe entire real estateALLETE Properties portfolio. Proceeds from a bulk sale would be strategically deployed to support growth inat our Regulated Operations and ALLETE Clean Energy and U.S. Water Services, collectively our energy infrastructure and related services businesses.Energy. ALLETE Properties continues to pursue sales of individual parcels over time and will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions. (See Note 8. Investments.)infrastructure.
Cash, Cash Equivalents and Cash Equivalents.Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. As of December 31, 2019, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement. In prior periods presented, the amounts also include U.S. Water Services' standby letters of credit. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under an ALLETE Clean Energy loan agreement, PSAs and a tax equity financing agreement. In prior periods presented, the amounts also include deposits from a SWL&P customer in aid of future capital expenditures. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amounts presented in the Consolidated Statement of Cash Flows.
|
| | | | | | | | | | | |
| Cash, Cash Equivalents and Restricted Cash | December 31,
2019 |
| | December 31,
2018 |
| | December 31,
2017 |
|
| Millions | | | | | |
| Cash and Cash Equivalents |
| $69.3 |
| |
| $69.1 |
| |
| $98.9 |
|
| Restricted Cash included in Prepayments and Other | 2.8 |
| | 1.3 |
| | 2.6 |
|
| Restricted Cash included in Other Non-Current Assets | 20.4 |
| | 8.6 |
| | 8.6 |
|
| Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows |
| $92.5 |
| |
| $79.0 |
| |
| $110.1 |
|
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Supplemental Statement of Cash Flow Information.
|
| | | | | | | | | |
| Consolidated Statement of Cash Flows | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Cash Paid During the Period for Interest – Net of Amounts Capitalized |
| $63.5 |
|
| $66.0 |
|
| $64.5 |
|
Recognition of Right-of-use Assets and Lease Liabilities (a) |
| $28.7 |
| — |
| — |
|
| Remeasurement of Deferred Income Taxes Resulting from the TCJA | | | |
| Increase in Regulatory Assets | — |
| — |
|
| $80.9 |
|
| Decrease in Investment in ATC | — |
| — |
| $(27.9) |
| Decrease in Deferred Income Taxes | — |
| — |
| $(353.6) |
| Increase in Regulatory Liabilities | — |
| — |
|
| $393.6 |
|
| Noncash Investing and Financing Activities | | | |
| Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment | $33.9 | $(0.1) | $67.2 |
Reclassification of Property, Plant and Equipment to Inventory (b) | — |
|
| $46.3 |
| — |
|
| Capitalized Asset Retirement Costs | $20.7 | $14.2 | $(15.6) |
| AFUDC–Equity |
| $2.3 |
|
| $1.2 |
|
| $1.2 |
|
| ALLETE Common Stock Contributed to Pension Plans | — |
| — |
|
| $13.5 |
|
| |
| (b) | In February 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification from Property, Plant and Equipment – Net to Inventories – Net for project costs incurred in the prior year. On the Consolidated Statement of Cash Flows, the sale of the wind energy facility in the fourth quarter of 2018 resulted in Operating Activities – Inventories increasing by $46.3 million in 2018 due to the project costs incurred in the prior year. |
|
| | | | | | | | | |
| Consolidated Statement of Cash Flows | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Cash Paid During the Period for Interest – Net of Amounts Capitalized |
| $64.5 |
|
| $68.2 |
|
| $59.0 |
|
| Cash Paid During the Period for Income Taxes |
| $0.4 |
|
| $0.5 |
|
| $0.4 |
|
| Remeasurement of Deferred Income Taxes Resulting from the TCJA | | | |
| Increase in Regulatory Assets |
| $80.9 |
| — |
| — |
|
| Decrease in Investment in ATC | $(27.9) | — |
| — |
|
| Decrease in Deferred Income Taxes | $(353.6) | — |
| — |
|
| Increase in Regulatory Liabilities |
| $393.6 |
| — |
| — |
|
| Noncash Investing and Financing Activities | | | |
| Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment | $67.2 | $(22.0) | $(40.6) |
| Capitalized Asset Retirement Costs | $(15.6) |
| $3.7 |
| $12.4 |
| Camp Ripley Solar Financing | — |
| $15.0 | — |
|
| AFUDC–Equity |
| $1.2 |
|
| $2.1 |
|
| $3.3 |
|
| ALLETE Common Stock Contributed to Pension Plans |
| $13.5 |
| — |
| — |
|
| Contingent Consideration | — |
| — |
|
| $35.7 |
|
| ALLETE Common Stock Received for Land Inventory | — |
|
| $8.0 |
| — |
|
| Long-Term Finance Receivable for Land Inventory | — |
|
| $12.0 |
| — |
|
Accounts Receivable. Accounts receivable are reported on the Consolidated Balance Sheet net of an allowance for doubtful accounts. The allowance is based on our evaluation of the receivable portfolio under current conditions, overall portfolio quality, review of specific situations and such other factors that, in our judgment, deserve recognition in estimating losses.
|
| | | | | | | |
| Accounts Receivable | | | |
| As of December 31 | 2019 |
| | 2018 |
|
| Millions | | | |
Trade Accounts Receivable (a) | | | |
| Billed |
| $77.2 |
| |
| $121.7 |
|
| Unbilled | 20.1 |
| | 24.4 |
|
| Less: Allowance for Doubtful Accounts | 0.9 |
| | 1.7 |
|
| Total Accounts Receivable |
| $96.4 |
| |
| $144.4 |
|
| |
| (a) | On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related accounts receivable from the Consolidated Balance Sheet. |
|
| | | | | | | |
| Accounts Receivable | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
| Trade Accounts Receivable | | | |
| Billed |
| $112.6 |
| |
| $106.5 |
|
| Unbilled | 24.6 |
| | 19.1 |
|
| Less: Allowance for Doubtful Accounts | 2.1 |
| | 3.1 |
|
| Total Accounts Receivable |
| $135.1 |
| |
| $122.5 |
|
Concentration of Credit Risk. We are subject to concentration of credit risk primarily as a result of accounts receivable. Minnesota Power sells electricity to nine8 Large Power Customers. Receivables from these customers totaled $13.8$7.8 million as of December 31, 20172019 ($9.511.7 million as of December 31, 2016)2018). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, Minnesota Power, as permitted by the MPUC, requires its taconite-producing Large Power Customers to pay weekly for electric usage based on monthly energy usage estimates, which allows us to closely manage collection of amounts due. One of these customers accounted for 1012 percent of consolidated operating revenue in 2017 (82019 (10 percent in 20162018 and in 2015)2017).
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Long-Term Finance Receivables. Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Available-for-Sale Securities. Available-for-sale debt and equity securities are recorded at fair value with unrealizedvalue. Unrealized gains and losses on available-for-sale debt securities are included in accumulated other comprehensive income (loss), net of tax. Unrealized gains and losses that are other than temporaryon available-for-sale equity securities are recognized in earnings. We use the specific identification method as the basis for determining the cost of securities sold. Our policy is to review available-for-sale securities for other than temporary impairment on a quarterly basis by assessing such factors as share price trends and the impact of overall market conditions. (See New Accounting Pronouncements and Note 8. Investments.)
Inventories – Net. Inventories are stated at the lower of cost or net realizable value. Inventories in our Regulated Operations and ALLETE Clean Energy segmentssegment are carried at an average cost or first-in, first-out basis. Inventories in our U.S. Water ServicesALLETE Clean Energy segment and Corporate and Other operationsbusinesses are carried at an average cost, first-in, first-out or specific identification basis.
|
| | | | | | | |
| Inventories – Net | | | |
| As of December 31 | 2019 |
| | 2018 |
|
| Millions | | | |
Fuel (a) |
| $25.9 |
| |
| $26.0 |
|
| Materials and Supplies | 46.9 |
| | 44.2 |
|
Raw Materials (b) | — |
| | 2.8 |
|
Work in Progress (b) | — |
| | 6.1 |
|
Finished Goods (b) | — |
| | 8.4 |
|
Reserve for Obsolescence (b) | — |
| | (0.8 | ) |
| Total Inventories – Net |
| $72.8 |
| |
| $86.7 |
|
|
| | | | | | | |
| Inventories – Net | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
Fuel (a) |
| $34.8 |
| |
| $43.9 |
|
| Materials and Supplies | 46.5 |
| | 48.7 |
|
| Raw Materials | 2.8 |
| | 2.9 |
|
| Work in Progress | 4.2 |
| | 1.0 |
|
| Finished Goods | 8.3 |
| | 8.6 |
|
| Reserve for Obsolescence | (0.7 | ) | | (0.9 | ) |
| Total Inventories – Net |
| $95.9 |
| |
| $104.2 |
|
| |
| (a) | Fuel consists primarily of coal inventory at Minnesota Power. |
(b) On March 26, 2019, ALLETE sold U.S. Water Services which resulted in the removal of the related inventory items from the Consolidated Balance Sheet. |
| | | | | | | |
| Prepayments and Other Current Assets | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
Deferred Fuel Adjustment Clause (a) | — |
| |
| $18.6 |
|
Restricted Cash (b) |
| $2.6 |
| | 2.2 |
|
| Other | 35.0 |
| | 19.5 |
|
| Total Prepayments and Other Current Assets |
| $37.6 |
| |
| $40.3 |
|
| |
(a) | At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. |
| |
(b) | Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreement and collateral deposits required for U.S. Water Services’ standby letters of credit. |
Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the Consolidated Balance Sheet net of accumulated depreciation. Expenditures for additions, significant replacements, improvements and major plant overhauls are capitalized; maintenance and repair costs are expensed as incurred. Gains or losses on property, plant and equipment in our U.S. Water Services segment andfor Corporate and Other operations are recognized when they are retired or otherwise disposed. When property, plant and equipment in our Regulated Operations and ALLETE Clean Energy segments are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for component depreciation except for certain circumstances where the retirement is unforeseen or unexpected. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during construction periods. AFUDC amounts capitalized are included in rate base and are recovered from customers as the related property is depreciated. Upon MPUC approval of cost recovery, the recognition of AFUDC ceases. (See Note 2. Property, Plant and Equipment.)
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Property, Plant and Equipment (Continued)
We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. In 2015, Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to operate on natural gas which were actions included in Minnesota Power’s MPUC-approved 2013 IRP. In a July 2016 order, the MPUC approvedgas. Minnesota Power’s 2015 IRP with modifications. The 2015 IRP containscontained steps in Minnesota Power’s EnergyForward plan including the economic idling of Taconite Harbor Units 1 and 2 in September 2016, and the ceasing of coal-fired operations at Taconite Harbor in 2020. (See Note 4. Regulatory Matters.) The MPUC order for the 2015 IRP also directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022. In October 2016, Minnesota Power announced thatretired Boswell Units 1 and 2 will be retired in the fourth quarter of 2018. As part of the 2016 general retail rate case, the MPUC allowed recovery of the remaining book value of Boswell Units 1 and 2 through 2022. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2 or the conversion of Laskin to operate on natural gas. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
ALLETE Clean Energy Asset Acquisition. On May 3, 2019, ALLETE Clean Energy acquired the Diamond Spring wind project in Oklahoma from Apex Clean Energy. ALLETE Clean Energy will build, own and operate the approximately 300 MW wind energy facility. The Diamond Spring wind project is fully contracted to sell wind power under long-term power sales agreements. Construction is expected to be completed in late 2020.
Impairment of Long-Lived Assets. We review our long-lived assets which include the legacy real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. This includes our property, plant and equipment (see Property, Plant and Equipment) and land inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value.
In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our long‑lived assets for recoverability by comparing the carrying amount of the asset to the undiscounted future net cash flows expected to be generated by the asset. Cash flows are assessed at the lowest level of identifiable cash flows. The undiscounted future net cash flows are impacted by trends and factors known to us at the time they are calculated and our expectations related to: management’s best estimate of future use; sales prices; holding period and timing of sales; method of disposition; and future expenditures necessary to maintain the operations.
Real Estate Assets. In recent years, market conditions for real estate in Florida have required us to review our land inventories for impairment. In 2015, the Company reevaluated its strategy related to the real estate assets of ALLETE Properties in response to market conditions and transaction activity. The revised strategy incorporated the possibility of a bulk sale of its entire portfolio. Proceeds from a bulk sale would be strategically deployed to support growth in ALLETE Clean Energy and U.S. Water Services, collectively our Energy Infrastructure and Related Services businesses. ALLETE Properties also continues to pursue sales of individual parcels over time. ALLETE Properties will continue to maintain key entitlements and infrastructure without making additional investments or acquisitions.
In connection with implementing the revised strategy, management evaluated its2019, 2018, and 2017, there were no indicators of impairment analysis for its real estate assets using updated assumptions to determine estimated future net cash flows on an undiscounted basis. Estimated fair values were based upon current market dataour property, plant, and pricing for individual parcels. Our impairment analysis incorporates a probability-weighted approach considering the alternative courses of sales noted above.
Based on the results of the 2015 undiscounted cash flow analysis, the undiscounted future net cash flows were not adequate to recover the carrying value of the real estate assets leading to an adjustment of carrying value to estimated fair value. Estimated fair value was derived using Level 3 inputs, including current market interest in the property for a bulk sale of its entire portfolio, and discounted cash flow analysis of estimated selling price for sales over time.equipment or land inventory. As a result, a non-cash impairment charge of $36.3 million was recorded in 2015 to reduce the carrying value of the real estate to its estimated fair value.
In 2017 and 2016, our qualitative assessments indicated that the cash flows were adequate to recover the carrying value of ALLETE Properties real estate assets. As a result, no0 impairment was recorded in 20172019, 2018 or 2016.2017.
Derivatives. ALLETE is exposed to certain risks relating to its business operations that can be managed through the use of derivative instruments. ALLETE may enter into derivative instruments to manage those risks including interest rate risk related to certain variable-rate borrowings.
Accounting for Stock-Based Compensation. We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 16.13. Employee Stock and Incentive Plans.)
|
| | | | | | | |
| Other Non-Current Assets | | | |
| As of December 31 | 2019 |
| | 2018 |
|
| Millions | | | |
Contract Assets (a) |
| $28.0 |
| |
| $30.7 |
|
Finance Receivable (b) | — |
| | 10.4 |
|
Operating Lease Right-of-use Assets (c) | 28.6 |
| | — |
|
| ALLETE Properties | 21.9 |
| | 24.4 |
|
| Restricted Cash | 20.4 |
| | 8.6 |
|
| Other Postretirement Benefit Plans | 37.5 |
| | 0.4 |
|
| Other | 80.8 |
| | 77.9 |
|
| Total Other Non-Current Assets |
| $217.2 |
| |
| $152.4 |
|
| |
| (a) | Contract Assets include payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue. |
| |
| (b) | Finance Receivable related to the 2016 sale of Ormond Crossings and Lake Swamp, which was collected in the second quarter of 2019. |
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Goodwill and Intangible Assets.
Goodwill. Goodwill is the excess of the purchase price (consideration transferred) over the estimated fair value of net assets of acquired businesses. In accordance with GAAP, goodwill is not amortized. Goodwill is assessed annually in the fourth quarter for impairment and whenever an event occurs or circumstances change that would indicate the carrying amount may be impaired. Impairment testing for goodwill is done at the reporting unit level.
As part of the 2016 annual impairment analysis, the Company recognized a non-cash impairment charge of $3.3 million for ALLETE Clean Energy’s goodwill primarily related to the acquisition of Storm Lake II in 2014. The charge, which is presented within Operating Expenses – Other in the Consolidated Statement of Income, eliminated all recognized goodwill for the ALLETE Clean Energy reporting unit.
As of the date of our annual goodwill impairment testing in 2017, the U.S. Water Services reporting unit had positive equity and the Company elected to bypass the qualitative assessment of goodwill for impairment, proceeding directly to the two-step impairment test. In performing Step 1 of the impairment test, we compared the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2 of the impairment test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.
U.S. Water Services.For Step 1 of the impairment test, we estimated the reporting unit's fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes a growth rate on debt-free cash flows. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. Our annual impairment test in 2017 indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and therefore no impairment existed (none in 2016 or in 2015). The fair value of the reporting unit was determined using a discounted cash flow model, using significant assumptions which included a discount rate of 10.75 percent, cash flow forecasts through 2022, annual revenue growth rates ranging from 7 percent to 9 percent, excluding 13 percent of revenue growth in 2018 related to the year over year impact of the acquisition of Tonka Water, and a terminal growth rate of 4.0 percent. Forecasted annual revenue growth assumes an increase in market share and growth in the industry.
Intangible Assets.Intangible assets include customer relationships, patents, non-compete agreements, land easements, trademarks and trade names. Intangible assets with definite lives consist of customer relationships, which are amortized using an attrition model, and patents, non-compete agreements, land easements and certain trade names, which are amortized on a straight-line basis with estimated remaining useful lives ranging from approximately 1 year to approximately 20 years. We review definite-lived intangible assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Indefinite‑lived intangible assets consist of trademarks and certain trade names, which are tested for impairment annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. Impairment is calculated as the excess of the asset’s carrying amount over its fair value. Fair value is generally determined using a discounted cash flow analysis. Our annual impairment test in 2017 indicated that the estimated fair value of trademarks and trade names exceeded the asset carrying values. As a result, no impairment existed in 2017 (none in 2016 or in 2015).
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
|
| | | | | | | |
| Other Current Liabilities | | | |
| As of December 31 | 2019 |
| | 2018 |
|
| Millions | | | |
Provision for Interim Rate Refund (a) | — |
| |
| $40.0 |
|
| PSAs |
| $12.3 |
| | 12.6 |
|
Contract Liabilities (b) | — |
| | 7.6 |
|
Provision for Tax Reform Refund (c) | 0.2 |
| | 10.7 |
|
Contingent Consideration (d) | — |
| | 3.8 |
|
Operating Lease Liabilities (e) | 6.9 |
| | — |
|
| Other | 41.0 |
| | 53.8 |
|
| Total Other Current Liabilities |
| $60.4 |
| |
| $128.5 |
|
|
| | | | | | | |
| Other Non-Current Assets | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
Contract Payment (a) |
| $27.5 |
| |
| $29.6 |
|
Finance Receivable (b) | 11.0 |
| | 11.5 |
|
Restricted Cash (c) | 8.6 |
| | 8.6 |
|
| Other | 60.6 |
| | 56.8 |
|
| Total Other Non-Current Assets |
| $107.7 |
| |
| $106.5 |
|
| |
(a) | Contract Payment includes a payment made to Cliffs as part of a long-term PSA between Minnesota Power and Silver Bay Power. The contract payment is being amortized over the term of the PSA. (See Note 11. Commitments, Guarantees and Contingencies.) |
| |
| (b) | In 2016, ALLETE Properties sold its Ormond Crossings project and Lake Swamp wetland mitigation bank for considerationContract Liabilities consist of approximately $21 million. The consideration includeddeposits received as a down payment in the formresult of 0.1 million shares of ALLETE common stockentering into contracts with a value of $8.0 million. The remaining purchase price will be paid under the terms of a finance receivable due over a five-year period which bears interest at market rates and is collateralized by the property sold.our customers prior to completing our performance obligations. |
| |
| (c) | Restricted Cash includes collateral deposits required under an ALLETE Clean Energy loan agreementProvision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and PSAs, and deposits fromis being returned to SWL&P customers in aid of future capital expenditures.through 2020. |
|
| | | | | | | |
| Other Current Liabilities | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
| PSAs |
| $24.5 |
| |
| $24.6 |
|
| Other | 58.7 |
| | 49.1 |
|
| Total Other Current Liabilities |
| $83.2 |
| |
| $73.7 |
|
|
| | | | | | | |
| Other Non-Current Liabilities | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
| Asset Retirement Obligation |
| $122.7 |
| |
| $136.6 |
|
| PSAs | 89.5 |
| | 113.8 |
|
Contingent Consideration (a) | 5.4 |
| | 25.0 |
|
| Other | 49.5 |
| | 47.3 |
|
| Total Other Non-Current Liabilities |
| $267.1 |
| |
| $322.7 |
|
| |
(a)(d) | Contingent Consideration relatesrelated to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 6. Acquisitions and Note 9. Fair Value.)acquisition was paid in the first quarter of 2019. |
|
| | | | | | | |
| Other Non-Current Liabilities | | | |
| As of December 31 | 2019 |
| | 2018 |
|
| Millions | | | |
| Asset Retirement Obligation |
| $160.3 |
| |
| $138.6 |
|
| PSAs | 64.6 |
| | 76.9 |
|
Operating Lease Liabilities (a) | 21.8 |
| | — |
|
| Other | 46.3 |
| | 47.1 |
|
| Total Other Non-Current Liabilities |
| $293.0 |
| |
| $262.6 |
|
Leases.
We determine if a contract is, or contains, a lease at inception and recognize a right-of-use asset and lease liability for all leases with a term greater than 12 months. Our right-of-use assets and lease liabilities for operating leases are included in Other Non-Current Assets, Other Current Liabilities and Other Non-Current Liabilities, respectively, in our Consolidated Balance Sheet. We currently do not have any finance leases.
Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and lease liabilities are recognized at the commencement date based on the estimated present value of lease payments over the lease term. As our leases do not provide an explicit rate, we determine the present value of future lease payments based on our estimated incremental borrowing rate using information available at the lease commencement date. The operating lease right-of-use asset includes lease payments to be made during the lease term and any lease incentives, as applicable.
Our leases may include options to extend or buy out the lease at certain points throughout the term, and if it is reasonably certain that we will exercise that option at lease commencement, we include those rental payments in our calculation of the right-of-use asset and lease liability. Lease and rent expense is recognized on a straight-line basis over the lease term. Leases with a term of 12 months or less are not recognized on the Consolidated Balance Sheet.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Leases (Continued)
The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the dragline at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $3 million and is included in our calculation of the right-of-use asset and lease liability recorded. None of our other leases contain residual value guarantees.
Additional information on the components of lease cost and presentation of cash flows were as follows:
|
| | | |
| December 31, 2019 |
|
| Millions | |
| Operating Lease Cost |
| $9.4 |
|
| |
| Other Information: | |
| Operating Cash Flows From Operating Leases |
| $9.4 |
|
Additional information related to leases was as follows: |
| | | |
| December 31, 2019 |
|
| Millions | |
| Balance Sheet Information Related to Leases: | |
| Other Non-Current Assets |
| $28.6 |
|
| Total Operating Lease Right-of-use Assets |
| $28.6 |
|
| |
| Other Current Liabilities |
| $6.9 |
|
| Other Non-Current Liabilities | 21.8 |
|
| Total Operating Lease Liabilities |
| $28.7 |
|
| |
| Weighted Average Remaining Lease Term (Years): | |
| Operating Leases - Vehicles and Equipment | 4 |
|
| Operating Leases - Land and Other | 28 |
|
| |
| Weighted Average Discount Rate: | |
| Operating Leases - Vehicles and Equipment | 3.7 | % |
| Operating Leases - Land and Other | 4.1 | % |
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Leases (Continued)
Maturities of lease liabilities were as follows:
|
| | | |
| | December 31, 2019 |
|
| Millions | |
| 2020 |
| $6.6 |
|
| 2021 | 6.0 |
|
| 2022 | 5.0 |
|
| 2023 | 3.2 |
|
| 2024 | 2.9 |
|
| Thereafter | 11.5 |
|
| Total Lease Payments Due | 35.2 |
|
| Less: Imputed Interest | 6.5 |
|
| Total Lease Obligations | 28.7 |
|
| Less: Current Lease Obligations | 6.9 |
|
| Total Long-term Lease Obligations |
| $21.8 |
|
Environmental Liabilities. We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers. (See Note 11.9. Commitments, Guarantees and Contingencies.)
Revenue.
Contracts with Customers – Utility includes sales from our regulated operations for generation, transmission and distribution of electric service, and distribution of water and gas services to our customers. Also included is an immaterial amount of regulated steam generation that is used by customers in the production of paper and pulp.
Contracts with Customers – Non-utility includes sales of goods and services to customers from ALLETE Clean Energy, U.S. Water Services and our Corporate and Other businesses.
Other – Non-utility is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices for PSAs that were assumed during the acquisition of various wind energy facilities.
Revenue Recognition
Revenue is recognized upon transfer of control of promised goods or services to our customers in an amount that reflects the consideration we expect to receive in exchange for those products or services. Revenue is recognized net of allowance for returns and any taxes collected from customers, which are subsequently remitted to the appropriate governmental authorities. We account for shipping and handling activities that occur after the customer obtains control of goods as a cost rather than an additional performance obligation thereby recognizing revenue at time of shipment and accruing shipping and handling costs when control transfers to our customers. We have a right to consideration from our customers in an amount that corresponds directly with the value to the customer for our performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue (Continued)
Nature of Revenue Recognition.Streams
Regulated Operations Utility
Residential and Commercial includes sales for electric, gas or water service to customers, who have implied contracts with the utility, under rates are undergoverned by the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities.MPUC, PSCW or FERC. Customers are billed on a monthly cycle basis.basis and revenue is recognized for electric, gas or water service delivered during the billing period. Revenue is accrued for servicesservice provided but not yet billed. Regulatedbilled at period end. Performance obligations with these customers are satisfied at time of delivery to customer meters and simultaneously consumed.
Municipal includes sales to 15 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. All wholesale electric contracts include a termination clause requiring a three-year notice to terminate. These contracts have termination dates ranging through at least 2032, with a majority of contracts effective through at least 2024. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon municipal substation or meter.
Industrial includes sales recognized from contracts with customers in the taconite mining, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 54 percent of total regulated utility electric rates include adjustment clauses that: (1) bill or credit customers for fuel and purchased energy costs above or below the base levels in rate schedules; (2) bill retail customerskWh sales for the recoveryyear ended December 31, 2019. Within industrial revenue, Minnesota Power has 8 Large Power Customer contracts, each serving requirements of conservation improvement program expenditures10 MW or more of customer load. These contracts automatically renew past the contract term unless a four-year advanced written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2023 through 2029. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not collected in base rates; and (3) billyet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the recoveryfixed contract components of certain transmission, renewable,approximately $55 million per annum in 2020 through 2023, $20 million in 2024, and environmental improvement expenditures. Previously, fuel and purchased power expense was deferred to match$65 million in total thereafter, which reflects the termination notice period in whichthese contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts.
Other Power Suppliers includes the sale of energy under long-term PSAs with 2 customers as well as MISO market and liquidation sales. Expiration dates of these PSAs range from 2020 through 2028. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon delivery point defined in the contract (generally the MISO pricing node). Based on current contracts with 2 customers, we expect to recognize minimum revenue for fuelfixed contract components of approximately $3 million in 2020. Other power supplier contracts that extend beyond 2020 contain variable pricing components that prevent us from estimating future minimum revenue, and purchased power expense was billedtherefore are not included.
Other Revenue includes all remaining individually immaterial revenue streams for Minnesota Power and SWL&P, and is comprised of steam sales to paper and pulp mills, wheeling revenue and other sources. Revenue for steam sales to customers withis recognized at the deferred fuel coststime steam is delivered and simultaneously consumed. Revenue is recognized as a regulatory asset. At a hearing on January 18, 2018,at the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. Astime each performance obligation is satisfied.
CIP Financial Incentive reflects certain revenue that is a result of the MPUC hearing, fuel and purchased power costs above or below the base levels in rate schedules are no longer deferred.
Revenue from cost recovery riders (transmission, renewable and environmental improvement)achievement of certain objectives for our CIP financial incentives. This revenue is accounted for in accordance with GAAPthe accounting standards for alternative revenue programs. These standardsprograms which allow for recognizingthe recognition of revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory authority,commission, the order allows for automatic adjustment of future rates, the amount of the revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. RevenueCIP financial incentives are recognized usingin the alternative revenue program guidanceperiod in which the MPUC approves the filing, which is included in Operating Revenue – Utility on the Consolidated Statement of Income and Regulatory Assets on the Consolidated Balance Sheet until it is subsequently collected from customers.typically mid-year.
Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue – Utility and net purchases in Fuel, Purchased Power and Gas – Utility expense on the Consolidated Statement of Income.(Continued)
Non-utility
ALLETE Clean Energy recognizes
Long-term PSA revenue includes all sales recognized under long-term contracts for production, curtailment, capacity and associated renewable energy credits from ALLETE Clean Energy wind energy facilities. Expiration dates of these PSAs range from 2020 through 2039. Performance obligations for these contracts are satisfied at the sale oftime energy from PSAs under various durations. Revenue is recognized when delivered to an agreed upon point, or production is curtailed at the request of its customersthe customer, at specified prices. Revenue from the sale of renewable energy credits is recognized at the same time the related energy is delivered to the customer when sold to the same party.
Sale of Wind Energy Facility includes revenue recognized for the design, development, construction, and sale of a wind energy facility to a customer. Performance obligations for these types of agreements are satisfied at the time the completed project is transferred to the customer at the commercial operation date. Revenue from the sale of a wind energy facility is recognized at the time of asset transfer.
Other is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of its acquisitions of wind energy facilities,facility acquisitions, ALLETE Clean Energy has assumed various PSAs that were above or below estimated market prices at the time of acquisition and amortizesacquisition; the resulting differences between contract prices and estimated market prices are amortized to Operating Revenue – Non-utilityrevenue over the remaining PSA term.
U.S. Water Services
Point-in-time revenue is recognized for purchases by customers for chemicals, consumable equipment (e.g., filters, pumps and valves) or related maintenance and repair services as the customer’s usage and needs change over time. These goods and services are purchased on an as-needed basis by customers and therefore revenue can be variable. Products are shipped to customers in accordance with the Consolidated Statementterms of Income. In 2017, we recognized $23.6 million of non-cash revenue amortization relating to the difference between contract priceseach purchase order, and estimated market prices as an increase in Operating Revenue – Non-utility ($22.3 million in 2016; $23.2 million in 2015). Revenue from the construction and sale of wind energy facilities to others will be recognized at a point in time, or over time, as performance obligations are satisfied at the time of shipment of goods or when services are rendered to the customer.
Contract includes monthly revenue from contracts with customers to provide chemicals, consumable equipment and services to meet customer needs during the contract period. As agreed with the customer, a fixed amount is invoiced based on the termsgoods and services to be provided under the contract. The duration of each specific agreement.
U.S. Water Services recognizes revenuethese contracts generally range in length from three months to five years and automatically renew. A 30-day notice is required to terminate such contracts without penalty. Performance obligations are satisfied during the sale of products when the earnings process is complete. This generally occurs when productsperiod as goods and service are shipped to the customerdelivered in accordance with the terms of the contract.
Capital Project includes the sale of equipment and other components assembled to create a water treatment system for a customer. These projects are provided under contracts at an agreed upon price to meet a customer's specifications and typically take less than one year to complete. In general, progress payments are received throughout the project period and are recorded as contract or purchase order, ownershipliabilities until performance obligations are satisfied at the time the equipment and risk of loss have passedother components are delivered to the customer, collectibility is reasonably assured, and pricing is fixed and determinable. Revenue from services is recognized as the services are performed.customer’s site.
Corporate and Other
BNI Energy recognizesLong-term Contract encompasses the sale and delivery of coal sales when deliveredto customer generation facilities. Revenue is recognized on a monthly basis at the cost of production plus a specified profit per ton of coal delivered.delivered to the customer. Coal sales are secured under long-term coal supply agreements extending through 2037. Performance obligations are satisfied during the period as coal is delivered to customer generation facilities.
ALLETE Properties records full profit recognition on salesOther primarily includes revenue from BNI Energy unrelated to coal, the sale of real estate upon closing, providedfrom ALLETE Properties, and non‑rate base steam generation that cash collectionsis sold for use during production of paper and pulp. Performance obligations are at least 20 percent ofsatisfied when control transfers to the contract price and the other requirements under the guidance for sales of real estate are met. Certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.customer.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
|
| | | | | | | | |
| Operating Expenses – Other | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
Impairment of Real Estate (a) | — |
| — |
|
| $36.3 |
|
Impairment of Goodwill (b) | — |
|
| $3.3 |
| — |
|
Change in Fair Value of Contingent Consideration (c) | $(0.7) | (13.6 | ) | — |
|
| Total Operating Expenses – Other | $(0.7) | $(10.3) |
| $36.3 |
|
Payment Terms
Payment terms and conditions vary across our businesses. Aside from taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered or goods provided. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customers’ energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite-producing Large Power Customers have generally predictable energy usage on a weekly basis and any differences that occur are trued-up the following month. Due to the timing difference of revenue recognition from the timing of invoicing and payment, the customer receives credit for the time value of money; however, we have determined that our contracts do not include a significant financing component as the period between when we transfer the service to the customer and when they pay for such service is minimal.
Assets Recognized From the Costs to Obtain a Contract with a Customer
We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of December 31, 2019, we have $28.0 million of assets recognized for costs incurred to obtain contracts with our customers ($30.7 million as of December 31, 2018). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. We recognized $2.6 million of non-cash amortization for the years ended December 31, 2019 and 2018.
|
| | | |
| Operating Expenses – Other | | | |
| Year Ended December 31 | 2019 | 2018 | 2017 |
| Millions | | | |
Change in Fair Value of Contingent Consideration (a) | — | $(2.0) | $(0.7) |
| Total Operating Expenses – Other | — | $(2.0) | $(0.7) |
| |
| (a) | See ImpairmentContingent Consideration related to the earnings-based payment resulting from the U.S. Water Services acquisition was paid in the first quarter of Long-Lived Assets. |
| |
(b) | See Goodwill and Intangible Assets. |
| |
(c) | See2019. (See Note 9.7. Fair Value.) |
Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using a method which approximates the effective interest method.
Tax Equity Financings. In the fourth quarter of 2019, certain subsidiaries of ALLETE entered into tax equity financings that include forming limited liability companies (LLC) with third-party investors for certain wind projects. Tax equity financings have specific terms that dictate distributions of cash and the allocation of tax attributes among the partners, who are divided into two categories: the sponsor and third-party investor. ALLETE subsidiaries are the sponsors in these tax equity financings. The distributions of cash and allocation of tax attributes in these financings are generally different than the underlying percentage ownership interests in the related LLC. A disproportionate share of tax attributes (including accelerated depreciation and production tax credits) are allocated to third-party investors in order to achieve targeted after-tax rates of return, or target yield, from project operations, while a disproportionate share of cash distributions are made to the sponsor.
The target yield and terms vary by financing agreement, by third-party investor, and sponsor project. Once the third-party investor’s target yield has been achieved, a “flip point” is recognized. Prior to the flip point, tax attributes are disproportionately allocated to the third-party investor with cash distributions disproportionately made to the sponsor. In addition, cash distributions can be temporarily increased to the third-party investors in order to meet cumulative distribution thresholds. After the flip point, tax attributes and cash distributions are both typically disproportionately allocated to the sponsor.
Tax equity financings impose a range of affirmative and negative covenants that are similar to what a project lender would require, such as financial reporting, insurance, maintenance and prudent operator standards. Most of these restrictions end once the flip point occurs and any other obligations of the third-party investor have been eliminated.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Tax Equity Financings (Continued)
The third-party investor’s portion of equity ownership in tax equity LLC is recorded as non-controlling interest in subsidiaries on the Consolidated Balance Sheet.
Non-Controlling Interest in Subsidiaries. Non-controlling interest in subsidiaries represents the portion of equity ownership, net income (loss), and comprehensive income (loss) in subsidiaries that is not attributable to equity holders of ALLETE.
For those wind projects with tax equity financing structures where the economic benefits are not allocated based on the underlying ownership percentage interests, we have determined that the appropriate methodology for calculating the non-controlling interest in subsidiaries balance is the hypothetical liquidation at book value (HLBV) method. The HLBV method is a balance sheet approach which reflects the substantive economic arrangements in the tax equity financing structures.
Under the HLBV method, amounts reported as non-controlling interest in subsidiaries on the Consolidated Balance Sheet represent the amounts the third-party investors would hypothetically receive at each balance sheet reporting date under the liquidation provisions of the LLC operating agreements, assuming the net assets of the wind projects were liquidated at amounts determined in accordance with GAAP and distributed to the third-party investor and sponsor. The resulting non-controlling interest in subsidiaries balance in these projects is reported as a component of equity on the Consolidated Balance Sheet.
The results of operations for these projects attributable to non-controlling interests under the HLBV method is determined as the difference in non-controlling interest in subsidiaries on the Consolidated Balance Sheet at the start and end of each reporting period, after taking into account any capital transactions between the projects and the third-party investors.
Factors used in the HLBV calculation include GAAP income, taxable income (loss), tax attributes such as accelerated depreciation and production tax credits, capital contributions, cash distributions, and the stipulated third-party investor target after-tax return specified in the tax equity LLC operating agreements. Changes in these factors could have a significant impact on the amounts that third-party investors and sponsors would receive upon a hypothetical liquidation. The use of the HLBV method to allocate income to the non-controlling interest in subsidiaries may create variability in our results of operations as the application of the HLBV method can drive variability in net income or loss attributable to non-controlling interest in subsidiaries from period to period.
|
| | | | | | | | | |
| Other Income (Expense) - Other | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
Pension and Other Postretirement Benefit Plan Non-Service Credit (a) |
| $7.7 |
|
| $4.6 |
|
| $3.9 |
|
| Interest and Investment Earnings | 4.4 |
| 0.5 |
| 1.8 |
|
| AFUDC - Equity | 2.3 |
| 1.2 |
| 1.2 |
|
| Gain (Loss) on Land Sales | 2.1 |
| 0.9 |
| (0.5 | ) |
| Other | 2.2 |
| 0.6 |
| (0.1 | ) |
| Total Other Income (Expense) - Other |
| $18.7 |
|
| $7.8 |
|
| $6.3 |
|
| |
| (a) | These are components of net periodic pension and other postretirement benefit cost other than service cost. (See Note 12. Pension and Other Postretirement Benefit Plans.) |
Income Taxes. ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns. We account for income taxes using the liability method in accordance with GAAP for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable.
Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with GAAP for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more‑likely‑than‑not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more‑likely‑than‑not” means more than 50 percent likely. (See Note 13.11. Income Tax Expense.)
Tax Cuts and Jobs Act of 2017. On December 22, 2017, the TCJA was enacted into law. The TCJA has significantly changed the U.S. Internal Revenue Code (IRC) and the taxation of corporations. The more significant provisions that impact our Company include a reduction in the corporate federal income tax rate from 35 percent to 21 percent, and provisions related to our regulated utilities which generally allow for the continued deductibility of interest expense, the elimination of full expensing for property acquired after September 27, 2017, and the continuation of normalization requirements for accelerated tax depreciation taken by regulated utilities. The TCJA allows for full expensing for property and imposes an interest expense limitation on non‑regulated operations. The interest expense limitation is not expected to have a material impact on the Company.
Under ASC 740, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. ASC 740 requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, as of the date of enactment, the Company’s deferred income tax assets and liabilities were remeasured based upon the new tax rate. For our Regulated Operations segment, the change in deferred income taxes was recorded as regulatory assets, regulatory liabilities and a change to our investment in ATC. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the IRC over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. The decrease in our investment in ATC is expected to be amortized into earnings over time. For our ALLETE Clean Energy and U.S. Water Services segments as well as our Corporate and Other businesses, the change in deferred income taxes is recorded in income tax expense on the Consolidated Statement of Income.
On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118) which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete, and provides for up to a one year period in which to complete the required analyses and accounting (the measurement period). SAB 118 describes three scenarios associated with a company’s status of accounting for the TCJA: (1) a company is complete with its accounting for certain effects, (2) a company is able to determine a reasonable estimate for certain effects and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Income Taxes (Continued)
The Company has made a provisional estimate for the measurement and accounting of the effects of the TCJA, which have been reflected in the Consolidated Financial Statements as of December 31, 2017. The measurement and accounting of the effects of the TCJA resulted in a decrease to Income Tax Expense of $13.0 million for the year ended December 31, 2017, as well as a decrease to Deferred Income Taxes of $353.6 million, a decrease to Investment in ATC of $27.9 million, an increase to Regulatory Assets of $80.9 million and an increase to Regulatory Liabilities of $393.6 million as of December 31, 2017. The provisional amounts incorporate assumptions made based upon the Company’s current interpretation of the TCJA, and may change as the Company receives additional clarification and implementation guidance. Any adjustments recorded to the provisional amounts in 2018 will be included in income from operations as an adjustment to income tax expense.
As provided for under SAB 118, the Company has not estimated the impact for items for which it cannot predict, such as guidance that has not yet been provided, or for which federal or state regulatory treatment is still uncertain. The determination of the impact of the income tax effects of these types of items will occur when more information is available to the Company.
Excise Taxes. We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.
Purchase Accounting. In accordance with the authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the Consolidated Balance Sheet if it exceeds the estimated fair value and as a bargain purchase gain on the Consolidated Income Statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts as well as the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. (See Note 6. Acquisitions.)
New Accounting Pronouncements.
Recently Adopted Pronouncements
SimplifyingDisclosure Update and Simplification. In November 2018, the Measurement of Inventory. In 2015,SEC adopted amendments to certain disclosure requirements. The amendments adopted include requirements that interim financial statements should include comparative statements for the FASB issued an accounting standards update which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling pricesame period in the ordinary courseprior financial year, except that the requirement for comparative balance sheet information may be satisfied by presenting the year-end balance sheet. It further includes a requirement analyzing the changes in each caption of business less reasonably predictable costsshareholders’ equity either separately in a note or on the face of completion, disposal and transportation. This accounting guidance was adoptedthe financial statement. These amendments were effective for ALLETE in the first quarter of 2017 and did not2019. We have a material impact on our Consolidated Financial Statements.
Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued guidance to simplify the accounting for share-based payment transactions by requiring all excess tax benefits and deficiencies to be recognized in income tax expense or benefit in earnings, thus eliminating the requirement to classify the excess tax benefit and deficiencies as additional paid-in capital. Under the new guidance, an entity makes an accounting policy election to either estimate the expected forfeiture awards or account for forfeitures as they occur. This accounting guidance was adopted in the first quarter of 2017. The adoption of this guidance is expected to result in a less than $1 million impact to income tax expense (benefit) annually.
Clarifying the Definition of a Business. In January 2017, the FASB issued clarifying guidance on the definition of a business and provided additional guidance to assist with evaluating whether transactions are to be accounted for as an acquisition or disposal of a group of assets or a business. The clarifying guidance will also impact other areas including the accounting for goodwill and consolidation. This accounting guidance was adopted in the first quarter of 2017 and did not have an impact on our Consolidated Financial Statements.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements (Continued)
Stock Compensation: Scope of Modification Accounting. In May 2017, the FASB issued additional clarifying guidance regarding circumstances where changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting under ASC 718. The guidance provides specific situations that would be excluded from effects of a modification including if the fair value, vesting conditions, and classification are the same before and after modification. The amendments in this update will be applied prospectively to awards modified on or after adoption. This accounting guidance was adopted by the Company in the second quarter of 2017 and did not have an impact on our Consolidated Financial Statements.
Recently Issued Pronouncements
Simplifying the Test for Goodwill Impairment. In January 2017, the FASB issued updated guidance which simplifies the measurement of goodwill impairment by removing step two of the goodwill impairment test that requires the determination of the fair value of individual assets and liabilities of a reporting unit. The updated guidance requires goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued guidance to improveincluded the presentation of net periodic pension and postretirement benefit costs. Under the revised guidanceour Statement of ASC 715, an entity shall present the service cost component of the net periodic benefit cost in the same income statement line as other employee compensation costs arising from services rendered during the period. The guidance also allows only the service cost component of the periodic cost to be eligible for capitalization. The standard will be applied retrospectively for income statement presentation, and prospectively for capitalization of service cost components. We do not expect there to be a material impact on the Consolidated Financial Statements with the adoption of the updated guidance which is effective for the Company beginning in the first quarter of 2018.
Revenue from Contracts with Customers. In 2014, the FASB issued amended revenue recognition guidance that clarifies the principles for recognizing revenue from contracts with customers by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The guidance requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. As of December 31, 2017, the Company has reviewed all of its revenue streams and contracts for its regulated, energy infrastructure and related services, and corporate and other businesses, completing the evaluations of the impact of this new guidance. Based on these evaluations, the Company has determined the new guidance does not materially alter the amount or timing of revenue recognition from the current methodology nor does it have a material transition adjustment upon adoption. Additionally, management does not expect the recognition of any assets from the costs to obtain a contract. Management continues to draft and refine the additional disclosures neededShareholders’ Equity to meet the requirements of the new standard following adoption. The Company will adopt and implement the new guidance on a modified retrospective basis which requires application of standards to all contracts with customers effective January 1, 2018, with the cumulative impact on contracts with performance obligations not yet satisfied as of December 31, 2017, recognized as an adjustment to Retained Earnings on the Consolidated Balance Sheet.these requirements.
Leases. In February 2016, the FASB issued an accounting standard update which revisesrevised the existing guidance for leases. Under the revised guidance, lessees will beare required to recognize a “right-of-use” assetright-of-use assets and a lease liabilityliabilities on the Consolidated Balance Sheet for all leases with a termterms greater than 12 months. The new standard also requires additional quantitativequalitative and qualitativequantitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement and presentation of expenses and cash flows from leases areis not expected to significantly change as a result of the new guidance. As of December 31, 2017, ALLETE expects to make $79.9 million in minimum lease payments due in future years (undiscounted). The revisedCompany adopted this guidance is effective for the Company beginning in the first quarter of 2019 with earlyusing the optional transition method and the package of practical expedients, which allowed for the adoption permitted. We are currently evaluating the impact of the revised lease guidance on our Consolidated Financial Statements.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements (Continued)
Financial Instruments. Instandard as of January 2016,1, 2019, without restating previously disclosed information. Management elected the FASB issued an accounting standard update which requires entitiesoptional transition method of adoption due to measure their investments at fair value and recognize any changes in fair value in net income unless the investments qualify foroverall immateriality of the practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The updated guidance is effective for the Company beginningbalance sheet gross up in the first quarterperiod of 2018 and will result in a cumulative-effect adjustmentadoption. The package of practical expedients allowed management to Retained Earnings onnot reassess the Consolidated Balance Sheet inlease classification for leases, including those that had expired during the fiscal yearperiods presented or that still existed at the time of adoption. We have performed a preliminary evaluation ofincluded additional disclosures in the impact of this update, and based on that evaluation, we do not expect the adoption of the update to have a material impact on our Consolidated Financial Statements.
Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standard update which addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero‑coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relationnotes to the effective interest rate of the borrowing; 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 (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. This accounting guidance is effective for the Company beginning in the first quarter of 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.
Statement of Cash Flows: Restricted Cash. In November 2016, the FASB issued an accounting standard update related to the presentation of restricted cash in the Company’s Consolidated Statement of Cash Flows. The update requires that the Consolidated Statement of Cash Flows explain the change during the period in cash, cash equivalents, and restricted cash. Restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. This accounting guidance is effective for the Company beginning in the first quarter of 2018 and will be applied retrospectively to all periods presented. The guidance will result in changes to the Company’s Consolidated Statement of Cash Flows such that restricted cash amounts will be included in the beginning-of-period and end‑of‑period cash and cash equivalents totals when adopted for our fiscal year beginning January 1, 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.
Revision of Prior Balance Sheet. During the first quarter of 2017, the Company identified an error related to the deferred income tax treatment associated with its Wholesale and Retail Contra AFUDC Regulatory Liability. The Company evaluated the materiality of the error and concluded that it was not material to any previously issued historicalconsolidated financial statements. The Company has revised its Consolidated Balance Sheet as of December 31, 2016, by decreasing Regulatory Assets and Deferred Income Taxes by $29.5 million. The correction had no impact on our Consolidated Statement of Income.
Reclassification of Prior Income Statement. Beginning with the second quarter of 2017, the Company enhanced its presentation of Operating Revenue and certain Operating Expenses on the Consolidated Statement of Income by presenting the caption Operating Revenue separately as Operating Revenue – Utility and Operating Revenue – Non-utility. In conformity with the current presentation, we now present $1,007.7 million and $991.2 million of Operating Revenue as Operating Revenue – Utility for the years ended December 31, 2016, and 2015, respectively, as it is generated from our regulated utility operations. Non-utility revenue of $339.0 million and $495.2 million for the years ended December 31, 2016, and 2015 respectively, is now presented as Operating Revenue – Non-utility. In addition, the captions Fuel and Purchased Power and Cost of Sales have been updated to Fuel, Purchased Power and Gas – Utility and Cost of Sales – Non-utility. As a result, we have reclassified $7.0 million relating to the cost of gas sales at SWL&P from the historic caption Cost of Sales to Fuel, Purchased Power and Gas – Utility for the year ended December 31, 2016, and $7.9 million for the year ended December 31, 2015.
NOTE 2. PROPERTY, PLANT AND EQUIPMENT |
| | | | | | | |
| Property, Plant and Equipment | | | |
| As of December 31 | 2019 |
| | 2018 |
|
| Millions | | | |
| Regulated Operations | | | |
| Property, Plant and Equipment in Service |
| $4,555.8 |
| |
| $4,490.6 |
|
| Construction Work in Progress | 383.6 |
| | 251.1 |
|
| Accumulated Depreciation | (1,635.3 | ) | | (1,549.6 | ) |
| Regulated Operations – Net | 3,304.1 |
| | 3,192.1 |
|
| ALLETE Clean Energy | | | |
| Property, Plant and Equipment in Service | 686.0 |
| | 488.4 |
|
| Construction Work in Progress | 351.3 |
| | 164.5 |
|
| Accumulated Depreciation | (86.8 | ) | | (73.0 | ) |
| ALLETE Clean Energy – Net | 950.5 |
| | 579.9 |
|
U.S. Water Services (a) | | | |
| Property, Plant and Equipment in Service | — |
| | 30.1 |
|
| Accumulated Depreciation | — |
| | (14.0 | ) |
| U.S. Water Services – Net | — |
| | 16.1 |
|
Corporate and Other (b) | | | |
| Property, Plant and Equipment in Service | 231.9 |
| | 214.3 |
|
| Construction Work in Progress | 3.8 |
| | 6.6 |
|
| Accumulated Depreciation | (113.3 | ) | | (104.6 | ) |
| Corporate and Other – Net | 122.4 |
| | 116.3 |
|
| Property, Plant and Equipment – Net |
| $4,377.0 |
| |
| $3,904.4 |
|
|
| | | | | | | |
| Property, Plant and Equipment | | | |
| As of December 31 | 2017 |
| | 2016 |
|
| Millions | | | |
| Regulated Operations | | | |
| Property, Plant and Equipment in Service |
| $4,523.7 |
| |
| $4,437.0 |
|
| Construction Work in Progress | 121.6 |
| | 84.2 |
|
| Accumulated Depreciation | (1,520.5 | ) | | (1,426.1 | ) |
| Regulated Operations – Net | 3,124.8 |
| | 3,095.1 |
|
| ALLETE Clean Energy | | | |
| Property, Plant and Equipment in Service | 482.5 |
| | 472.3 |
|
| Construction Work in Progress | 144.9 |
| | 101.0 |
|
| Accumulated Depreciation | (60.8 | ) | | (41.0 | ) |
| ALLETE Clean Energy – Net | 566.6 |
| | 532.3 |
|
| U.S. Water Services | | | |
| Property, Plant and Equipment in Service | 24.8 |
| | 19.5 |
|
| Accumulated Depreciation | (10.4 | ) | | (6.9 | ) |
| U.S. Water Services – Net | 14.4 |
| | 12.6 |
|
Corporate and Other (a) | | | |
| Property, Plant and Equipment in Service | 204.7 |
| | 179.8 |
|
| Construction Work in Progress | 5.0 |
| | 2.8 |
|
| Accumulated Depreciation | (93.1 | ) | | (81.4 | ) |
| Corporate and Other – Net | 116.6 |
| | 101.2 |
|
| Property, Plant and Equipment – Net |
| $3,822.4 |
| |
| $3,741.2 |
|
| |
| (a) | On March 26, 2019, ALLETE completed the sale of U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.) |
| |
| (b) | Primarily includes BNI Energy and a small amount of non-rate base generation. |
Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.
|
| | | | |
| Estimated Useful Lives of Property, Plant and Equipment (Years) |
| Regulated Operations | | | ALLETE Clean Energy (a)
| 5 to 35 years |
| Generation | 54 to 50 years | | U.S. Water ServicesALLETE Clean Energy | 35 to 39 years35 |
| Transmission | 4452 to 67 years71 | | Corporate and Other | 3 to 50 years |
| Distribution | 1819 to 65 years68 | | | |
| |
(a) | ALLETE Clean Energy’s Property, Plant and Equipment consists primarily of WTGs with estimated useful lives ranging from 30 years to 35 years. |
Asset Retirement Obligations. We recognize, at fair value, obligations associated with the retirement of certain tangible, long‑lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (AROs) relate primarily to the decommissioning of our coal-fired and wind energy facilities, and land reclamation at BNI Energy. AROs are included in Other Non-Current Liabilities on the Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.
Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, the period of remediation is indeterminable and removal liabilities have not been recognized because they are considered immaterial to our Consolidated Financial Statements.recognized.
Long-standing ratemaking practices approved by applicable state and federal regulatory authorities have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-AROs. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with GAAP for AROs. (See Note 4. Regulatory Matters.)
NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)
|
| | | | |
| Asset Retirement Obligations | | |
| Millions | | |
Obligation as of December 31, 20152017 | |
| $131.4122.7 |
|
| Accretion | | 8.07.0 |
|
| Liabilities Settled | | (6.55.3 | ) |
| Revisions in Estimated Cash Flows | | 3.714.2 |
|
Obligation as of December 31, 20162018 | | 136.6138.6 |
|
| Accretion | | 7.67.2 |
|
| Liabilities Recognized | | 1.4 |
|
| Liabilities Settled | | (5.94.6 | ) |
| Revisions in Estimated Cash Flows | | (15.617.7 | )
|
Obligation as of December 31, 20172019 | |
| $122.7160.3 |
|
NOTE 3. JOINTLY-OWNED FACILITIES AND PROJECTSASSETS
Boswell Unit 4. Minnesota Power owns 80 percent of the 585 MW Boswell Unit 4. While Minnesota Power operates the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which it and WPPI Energy, the owner of the remaining 20 percent,, have equal representation and voting rights. Each owner must provide its own financing and is obligated to its ownership share of operating costs. Minnesota Power’s share of operating expenses for Boswell Unit 4 is included in Operating Expenses on the Consolidated Statement of Income.
CapX2020. Minnesota Power was a participant in the CapX2020 initiative which represented an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consisted of electric cooperatives and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, assessed the transmission system and projected growth in customer demand for electricity through 2020. Minnesota Power participated in threecertain CapX2020 projects which were completed and placed in service in 2011, 2012 andby 2015.
Minnesota Power’s investments in jointly-owned facilities and projectsassets and the related ownership percentages are as follows:
|
| | | | | | | | | | |
| Regulated Utility Plant | Plant in Service | Accumulated Depreciation | Construction Work in Progress | % Ownership |
| Millions | | | | |
| As of December 31, 2019 | | | | |
| Boswell Unit 4 |
| $662.7 |
|
| $258.9 |
|
| $5.7 |
| 80 |
| CapX2020 | 101.0 |
| 13.5 |
| — |
| 9.3 - 14.7 |
| Total |
| $763.7 |
|
| $272.4 |
|
| $5.7 |
| |
| As of December 31, 2018 | | | | |
| Boswell Unit 4 |
| $650.1 |
|
| $229.9 |
|
| $6.4 |
| 80 |
| CapX2020 | 101.0 |
| 11.0 |
| — |
| 9.3 - 14.7 |
| Total |
| $751.1 |
|
| $240.9 |
|
| $6.4 |
| |
|
| | | | | | | | | | |
| Regulated Utility Plant | Plant in Service | Accumulated Depreciation | Construction Work in Progress | % Ownership |
| Millions | | | | |
| As of December 31, 2017 | | | | |
| Boswell Unit 4 |
| $668.2 |
|
| $222.8 |
|
| $8.2 |
| 80 |
| CapX2020 Projects | 101.0 |
| 8.4 |
| — |
| 9.3 - 14.7 |
| Total |
| $769.2 |
|
| $231.2 |
|
| $8.2 |
| |
| As of December 31, 2016 | | | | |
| Boswell Unit 4 |
| $668.1 |
|
| $211.2 |
|
| $8.1 |
| 80 |
| CapX2020 Projects | 101.2 |
| 5.9 |
| — |
| 9.3 - 14.7 |
| Total |
| $769.3 |
|
| $217.1 |
|
| $8.1 |
| |
NOTE 4. REGULATORY MATTERS
Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See Transmission Cost Recovery Rider, Renewable Cost Recovery Rider and Environmental Improvement Rider.) Revenue from cost recovery riders was $31.8 million in 2019 ($103.8 million in 2018; $96.9 million in 2017 ($97.1 million2017). With the implementation of final rates in 2016; $89.6 million in 2015)Minnesota Power’s general rate case, certain revenue previously recognized under cost recovery riders was incorporated into base rates. (See 2016 Minnesota General Rate Case.)
NOTE 4. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
2016 Minnesota General Rate Case. In The MPUC issued a March 2018 order in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which results in additional revenue of approximately $13 million on an annualized basis.
2020 Minnesota General Rate Case. On November 2016,1, 2019, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately 910.6 percent for retail customers. The rate filing soughtseeks a return on equity of 10.2510.05 percent and a 53.81 percent equity ratio. On an annualized basis, the requested final rate increase would have generatedgenerate approximately $55$66 million in additional revenue. In orders dated December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to $34.7 million from the original request of approximately $49 million due to a change in its electric sales forecast. In December 2016 orders,23, 2019, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of $34.7$36.1 million beginning January 1, 2017.2020.
On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to $32.2 million beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately $49 million on an annualized basis. At a hearing on January 18, 2018, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of 9.25 percent and a 53.81 percent equity ratio. Upon commencement of final rates, we expect additional revenue of approximately $13 million on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which will be fully offset by the recognition of a corresponding reserve. As a result of the MPUC’s decisions on January 18, 2018, FERC-Approved Wholesale Rates. Minnesota Power has recorded a reserve for an interim rate refund of approximately $32 million as of December 31, 2017. The MPUC also disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. An order from the MPUC setting forth the effective date of final rates is expected by March 12, 2018. Minnesota Power will review this order for potential reconsideration of certain issues at that time.
As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately $25 million pre-tax in 2017.
Energy-Intensive Trade-Exposed Customer Rates. An EITE customer ratemaking law was enacted in 2015 which established that it is the energy policy of Minnesota to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued on October 13, 2017, that modified the order dated April 20, 2017. During 2017, Minnesota Power provided discounts of $8.6 million which were recorded as a receivable. On September 29, 2017, Minnesota Power informed its EITE customers that it has suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately $15 million annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, EITE discounts will offset interim rate refund reserves for non-EITE customers.
FERC-Approved Wholesale Rates. Minnesota Power has 1615 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All wholesale contracts include a termination clause requiring a three-year3-year notice to terminate.
NOTE 4. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through at least December 31, 2032. No termination notice may be given for this contract prior to July 1, 2029. The wholesale electric service contractscontract with SWL&P and another municipal customer areis effective through at least February 28, 2021, and through June 30, 2019, respectively.2023. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided a contract termination notice in June 2016. Minnesota Power currently provides approximately 29 MW of average monthly demand to this customer. The rates included in these three2 contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.
Minnesota Power’s wholesale electric contracts with 14 municipal customers are effective through at least December 31, 2024.varying dates ranging from 2024 through 2029. No termination notices may be given prior to three years before maturity. These contracts includehad fixed capacity charges through 2018; beginning in 2019, the capacity charge will beis determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term will beis set each January 1, subject to monthly adjustment, and will also beis determined using a cost-based formula methodology.
The contract with another municipal customer expired on June 30, 2019. Minnesota Power historically provided approximately 29 MW of average monthly demand to this customer.
Transmission Cost Recovery Rider.Rider. Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In a February 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates which allowsallowing Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. AsOn July 9, 2019, Minnesota Power filed a result of thepetition seeking MPUC approval ofto update the certificate of needcustomer billing factor to include investments made for the GNTL in 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see Great Northern Transmission Line),GNTL. (See Note 9. Commitments, Guarantees and anticipates including its portion of the investments and expenditures for the GNTL in future transmission bill factor filings.Contingencies.)
Renewable Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place for certain renewable investments and expenditures related to Bison, and the restoration and repair of Thomson.expenditures. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested. UpdatedCurrent customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated November 8, 2017.
In a November 2016 order, the MPUC directed2018 order. On August 15, 2019, Minnesota Power filed a petition seeking MPUC approval to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a result ofupdate the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in Operating Revenue of approximately $15 million in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an $8.8 million charge to net income in 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order.customer billing factor.
In an order dated December 7, 2017, the MPUC modified its November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in Operating Revenue of approximately $14 million in 2017. The North Dakota investment tax credits were reestablished as income tax credits in Corporate and Other, resulting in a $7.9 million increase to net income in 2017.
The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in Corporate and Other operations.
Minnesota Power also has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See Minnesota Solar Energy Standard.) Currently, there is no approved customer billing rate for solar costs.
NOTE 4. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
Environmental Improvement Rider. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a December 2016 order; however, in an order dated March 22, 2017, the MPUC approved a request by Minnesota Power to delay implementation of the updated rates until resolution of its 2016 general rate case. (See 2016 Minnesota General Rate Case.)November 2018 order.
Fuel Adjustment Clause Reform Pilot. In ana 2017 order, dated December 19, 2017, the MPUC adopted a three-year pilot program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. TheWith this order, changes the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forwarded-lookingforward-looking FAC with an annual prudence review and true-up to actual allowed costs. The MPUC is seeking input from Minnesota electric utilities and other stakeholders on the implementation and transition accounting needed to adopt the change. The three-year pilot program is expected to begin in 2019. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of the forward-looking fuel adjustment clause methodology in this proceeding resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017.
Tax Cuts and Jobs Act of 2017. On December 29, 2017, the MPUC opened a docket to review the effects of the TCJA on electric and natural gas rates and services in Minnesota, including the legislation’s impact on tax rates and utilities’ deferred income tax assets and liabilities. On January 19, 2018, the MPUC issued a notice of request for information and established comment periods with an initial filing required by March 2, 2018. On January 10, 2018, the PSCW also opened a docket to review the effects of this legislation and directed Wisconsin utilities to defer its impacts until further direction is provided by the PSCW. We have recorded the impact of the remeasurement of deferred income tax assets and liabilities resulting from the federal income tax rate change of the TCJA for Minnesota Power and SWL&P as regulatory assets and liabilities as the benefits of the TCJA are expected to be passed back to our customers over time. (See Regulatory Assets and Liabilities.) The final amount and timing over which the benefits of the TCJA will be passed back to customers is expected to be determined in these dockets; however, we are unable to predict the outcome of these regulatory proceedings.
2016 Wisconsin General Rate Case. SWL&P’s current retail rates are based on a 2017 PSCW retail rate order effective August 14, 2017, that allows for a 10.5 percent return on common equity and a 55 percent equity ratio. SWL&P’s retail rates prior to August 14, 2017, were based on a 2012 PSCW retail rate order that provided for a 10.9 percent return on equity. The 2017 PSCW retail rate order authorizes SWL&P to collect on average a 2.9 percent increase in rates for retail customers (3.8 percent increase in electric rates; 4.8 percent decrease in natural gas rates; and 9.8 percent increase in water rates). On an annualized basis, SWL&P expects to collect additional revenue of $2.5 million.
Integrated Resource Plan.In 2015,May 1, 2019, Minnesota Power filed its 2015 IRP withfuel adjustment forecast for 2020, which was accepted by the MPUC which includedin an analysisorder dated November 14, 2019, for purposes of setting fuel adjustment clause rates for 2020, subject to a varietytrue-up filing in 2021.
2018 Wisconsin General Rate Case. In a December 2018 order, the PSCW approved a rate increase for SWL&P including a return on equity of existing and future energy resource alternatives10.4 percent and a projection55.0 percent equity ratio. Final rates went into effect January 1, 2019, which resulted in additional revenue of customer cost impact by class. The 2015 IRP also contained steps in Minnesota Power’s EnergyForward strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in September 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between 200 MW and 300 MW of natural gas-fired generation in the next decade. approximately $3 million.
Integrated Resource Plan.In a July 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of Taconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct requestrequests for proposalsproposal for additional wind, solar and demand response resource additions subject to further MPUC approvals. In October 2016,additions. Minnesota Power announcedretired Boswell Units 1 and 2 will be retired in the fourth quarter of 2018. Minnesota Power’s next IRP filing is due October 1, 2020.
On July 28,In 2017, Minnesota Power submitted a resource package to the MPUC which included requesting approval of PPAsa PPA for the output of a 250 MW wind energy facility and a 10 MW solar energy facility as well as approval of a 250 MW natural gas energy PPA. These agreements will becapacity dedication agreement. The natural gas capacity dedication agreement was subject to MPUC approval of the construction of NTEC, a 525 MW to 550625 MW combined-cycle natural gas-firedgas‑fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately 50 percent of the facility's output starting in 2025. In an order dated September 19, 2017,January 24, 2019, the MPUC approved Minnesota Power’s request to extendfor approval of the NTEC natural gas capacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing deadline until October 1,analyzing its existing fleet, including potential early retirement scenarios of Boswell Units 3 and 4, as well as a securitization plan. On December 23, 2019, the Minnesota Court of Appeals reversed and Minnesota Power’s request that approval forremanded the natural gas energy PPA be decided through an administrative law judge process. The administrative law judge is expectedMPUC’s decision to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second half of 2018. approve certain affiliated-interest agreements. The MPUC did not take any action regardingwas ordered to determine whether NTEC may have the windpotential for significant environmental effects and, solar energy PPAs which will be refiled separately fromif so, to prepare an environmental assessment worksheet before reassessing the natural gas energy PPA.
NOTE 4. REGULATORY MATTERS (Continued)
Great Northern Transmission Line.agreements. On January 22, 2020, Minnesota Power filed a petition for further review with the Minnesota Supreme Court requesting that it review and Manitoba Hydro have proposed constructionoverturn the Minnesota Court of the GNTL,Appeals decision. On January 8, 2019, an approximately 220-mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range. In 2015,application for a certificate of needpublic convenience and necessity for NTEC was submitted to the PSCW, which was approved by the MPUC. BasedPSCW at a hearing on this approval, Minnesota Power’s portionJanuary 16, 2020. Construction of the investmentsNTEC is subject to obtaining additional permits from local, state and expenditures for thefederal authorities. The total project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Transmission Cost Recovery Rider.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between $560 million and $710approximately $700 million, of which Minnesota Power’sALLETE’s portion is expected to be between $300 million andapproximately $350 million; the difference will be recovered from a subsidiarymillion. ALLETE’s portion of Manitoba Hydro as contributions in aid of construction. TotalNTEC project costs of $152.4 million have been incurred through December 31, 2017,2019, is approximately $12 million.
In August 2018, Minnesota Power filed a separate petition for approval of which $67.6 million has been recovered from a subsidiary of Manitoba Hydro.
Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EISan amended PPA for the transmission line in Canada tooutput of the Manitoba Conservation and Water Stewardship for regulatory approval. In December 2016, Manitoba Hydro filed an application with the National Energy Board in Canada requesting authorization to construct and operate an international transmission line. Both provincial and federal approvals are pending. Construction of Manitoba Hydro’s hydroelectric generation250 MW wind energy facility commenced in 2014 and is anticipated to be located in service by early 2021.southwestern Minnesota which was approved in an order dated January 23, 2019. (See Note 5. Equity Investments.)
Conservation Improvement Program. Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on energy CIPs each year and establish an annual energy-savings goal of 1.5 percent of annual retail energy sales. These investments are recovered from certain retail customers through a combination of the conservation cost recovery charge included in retail base rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge on the deferred account balance. Minnesota Power refers to its conservation programs collectively as the “Power of One”. On November 16,year. In 2017, the Minnesota Department of Commerce approved Minnesota Power’s modified CIP triennial filing for 2017 through 2019, which outlinesoutlined Minnesota Power’s CIP spending and energy-saving goals for 2017 through 2019.those years. Minnesota Power’s CIP investment goal was $10.3$10.5 million for 20172019 ($7.310.3 million for 2016; $7.1 million for 2015)2018 and 2017), with actual spending of $8.3 million in 2019 ($9.0 million in 2018; $8.1 million in 2017 ($7.4 million in 2016; $6.6 million in 2015)2017). The investment goalsgoal for 2018 and 2019 are $10.3 million and2020 is $10.5 million respectively.based on approval of an extension for Minnesota Power’s next CIP triennial filing by the Minnesota Department of Commerce on November 26, 2019.
NOTE 4. REGULATORY MATTERS (Continued)
Conservation Improvement Program (Continued)
On April 3, 2017,1, 2019, Minnesota Power submitted its 2016 CIP2018 consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $5.5$2.8 million based upon MPUC procedures. Inprocedures, which was approved by the MPUC in an order dated June 22, 2017,July 19, 2019. In 2018, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive whichof $3.0 million was recorded as revenue and as a regulatory assetrecognized in 2017. The approved financial incentive will be recovered through customer billing rates inthe third quarter upon approval by the MPUC of Minnesota Power’s 2017 and 2018. In 2016 and 2015, the CIP financial incentives recognized were $7.5 million and $6.2 million, respectively.consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing.
MISO Return on Equity Complaints. In 2013, several customer groups located within the MISO service area filed complaints with the FERC requesting, among other things, a reduction in the base return on equity used by Complaint. MISO transmission owners, including ALLETE and ATC, to 9.15 percent. In 2015, a federal administrative law judge ruled on the complaint proposing a reduction in the basehave an authorized return on equity to 10.32of 9.88 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. In September 2016, the FERC issued an order affirming the administrative law judge’s recommendation.
In 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to 8.67 percent. In June 2016, a federal administrative law judge ruled on the additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.2010.38 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision frombased on a November 2019 FERC order. In this order, the FERC reduced the base return on theequity for regional transmission organizations as recommended by an administrative law judge’s recommendation is pending,judge with refunds ordered for prior periods, which is not expectedare immaterial to ALLETE. Multiple parties to the complaint have a material impact on our Consolidated Financial Statements.appealed the FERC order.
NOTE 4. REGULATORY MATTERS (Continued)
Minnesota Solar Energy Standard. Minnesota law requires at least 1.5 percent of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least 10 percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40kW40 kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved
Minnesota Power’s solar energy supply consists of Camp Ripley, a 10 MW utility scale solar projectenergy facility at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a 1 MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. Minnesota Power believesexpects that Camp Ripley, and the community solar garden arrays, and an increase in solar rebates will allow Minnesota Power to meet approximately one‑thirdboth parts of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. The proposal to incentivize customer‑sited solar installations and the community solar garden subscriptions is expected to meet a portion of the required small scale solar mandate.
Regulatory Assets and Liabilities. Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. NoWith the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets or liabilities are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.
NOTE 4. REGULATORY MATTERS (Continued)
|
| | | | | | |
| Regulatory Assets and Liabilities | | |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Non-Current Regulatory Assets | | |
Defined Benefit Pension and Other Postretirement Benefit Plans (a) |
| $212.9 |
|
| $218.5 |
|
Income Taxes (b) | 123.4 |
| 105.5 |
|
Asset Retirement Obligations (c) | 32.0 |
| 32.6 |
|
Cost Recovery Riders (d) | 24.7 |
| — |
|
Boswell 1 & 2 Net Plant and Equipment (e) | 10.7 |
| 16.3 |
|
Manufactured Gas Plant (f) | 8.2 |
| 8.0 |
|
| PPACA Income Tax Deferral | 4.8 |
| 5.0 |
|
| Other | 3.8 |
| 3.6 |
|
| Total Non-Current Regulatory Assets |
| $420.5 |
|
| $389.5 |
|
Current Regulatory Liabilities (g) | | |
Provision for Interim Rate Refund (h) | — |
|
| $40.0 |
|
Provision for Tax Reform Refund (i) |
| $0.2 |
| 10.7 |
|
| Transmission Formula Rates | 1.7 |
| 4.4 |
|
| Total Current Regulatory Liabilities | 1.9 |
| 55.1 |
|
| Non-Current Regulatory Liabilities | | |
Income Taxes (b) | 407.2 |
| 396.4 |
|
Wholesale and Retail Contra AFUDC (j) | 79.3 |
| 64.4 |
|
Plant Removal Obligations (k) | 35.5 |
| 25.1 |
|
Defined Benefit Pension and Other Postretirement Benefit Plans (a) | 17.0 |
| — |
|
North Dakota Investment Tax Credits (l) | 12.3 |
| 14.7 |
|
Conservation Improvement Program (m) | 5.4 |
| 1.5 |
|
Cost Recovery Riders (d) | — |
| 6.9 |
|
| Transmission Formula Rates | — |
| 1.6 |
|
| Other | 3.6 |
| 1.5 |
|
| Total Non-Current Regulatory Liabilities | 560.3 |
| 512.1 |
|
| Total Regulatory Liabilities |
| $562.2 |
|
| $567.2 |
|
|
| | | | | | |
| Regulatory Assets and Liabilities | | |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
Current Regulatory Assets (a) | | |
| Deferred Fuel Adjustment Clause | — |
|
| $18.6 |
|
| Non-Current Regulatory Assets | | |
Defined Benefit Pension and Other Postretirement Benefit Plans (b) | $220.3 | 226.1 |
|
Income Taxes (c)(d) | 112.8 |
| 33.8 |
|
Asset Retirement Obligations (e) | 29.6 |
| 26.0 |
|
Manufactured Gas Plant (f) | 8.1 |
| 1.0 |
|
| PPACA Income Tax Deferral | 5.0 |
| 5.0 |
|
Conservation Improvement Program (g) | 3.3 |
| 4.0 |
|
Cost Recovery Riders (h) | — |
| 30.5 |
|
| Other | 5.6 |
| 3.7 |
|
| Total Non-Current Regulatory Assets | 384.7 |
| 330.1 |
|
| Total Regulatory Assets |
| $384.7 |
|
| $348.7 |
|
| Non-Current Regulatory Liabilities | | |
Income Taxes (d) |
| $411.2 |
|
| $19.1 |
|
Wholesale and Retail Contra AFUDC (i) | 57.9 |
| 56.8 |
|
Provision for Interim Rate Refund (j) | 23.7 |
| — |
|
| Plant Removal Obligations | 20.3 |
| 19.1 |
|
North Dakota Investment Tax Credits (k) | 14.1 |
| 28.2 |
|
Cost Recovery Riders (h) | 2.2 |
| — |
|
| Other | 2.6 |
| 2.6 |
|
| Total Non-Current Regulatory Liabilities |
| $532.0 |
|
| $125.8 |
|
| |
| (a) | Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a $19.5 million pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. (See 2016 Minnesota General Rate Case.) |
| |
(b) | Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 15.12. Pension and Other Postretirement Benefit Plans.) |
| |
(c) | See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet. |
| |
(d)(b) | These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The increase in 2017 isbalances will primarily due to the remeasurement of deferred income tax assets and liabilities for our Regulated Operations resulting from the TCJA. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the U.S. Internal Revenue Code over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. (See Note 1. Operations and Significant Accounting Policies, and Tax Cuts and Jobs Act of 2017.) The balances not related to remeasurement will decrease over the remaining life of the related temporary differences and flow through current income taxes.differences. |
| |
(e)(c) | Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations. |
| |
| (d) | The cost recovery rider regulatory assets and liabilities are revenue not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL. The cost recovery rider regulatory assets as of December 31, 2019, will be recovered within the next two years. |
| |
| (e) | In December 2018, Minnesota Power retired Boswell Units 1 and 2 and reclassified the remaining net book value from property, plant and equipment to a regulatory asset on the Consolidated Balance Sheet. The remaining net book value is currently included in Minnesota Power’s rate base and Minnesota Power is earning a return on the outstanding balance. |
| |
| (f) | The manufactured gas plant regulatory asset represents costs of remediation for a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. We expect recovery of these remediation costs to be allowed by the PSCW in rates over time. |
| |
| (g) | The conservation improvement programCurrent regulatory asset represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future cost recovery overliabilities are presented within Other Current Liabilities on the next year following MPUC approval.Consolidated Balance Sheet. |
| |
| (h) | The cost recovery rider regulatory assets and liabilities are revenues not yet collected from our customers and cash collections from ourThis amount was refunded to Minnesota Power’s regulated retail customers in excessthe second quarter of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL, and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets and liabilities as of December 31, 2017, will be recovered or returned within the next two years.2019. |
| |
| (i) | Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and is being returned to SWL&P customers through 2020. |
| |
| (j) | Wholesale and Retail Contraretail contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset. |
| |
(j)(k) | This amount is expected to be refunded to Minnesota Power’s regulatedNon-legal plant removal obligations included in retail customers in the first quarter of 2019 and includes $8.6 million of EITE discountscustomer rates that will be offset against interim rate refunds. (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)have not yet been incurred. |
| |
(k)(l) | North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers through future renewable cost recovery rider fillingsfilings as the tax credits are utilized. |
| |
| (m) | The conservation improvement program regulatory liability represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future refund over the next year following MPUC approval. |
NOTE 5. INVESTMENT IN ATCEQUITY INVESTMENTS
Investment in ATC. Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As ofFor the year ended December 31, 2017, our equity investment2019, we invested $6.6 million in ATC was $118.7 million ($135.6 million as of December 31, 2016). Onand on January 31, 2018,2020, we invested an additional $1.6$0.4 million in ATC. In total, we expect to invest approximately $6$2.7 million throughout 2018.in 2020.
|
| | | | | | |
| ALLETE’s Investment in ATC | | |
| Year Ended December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Equity Investment Beginning Balance |
| $128.1 |
|
| $118.7 |
|
| Cash Investments | 6.6 |
| 6.2 |
|
| Equity in ATC Earnings | 21.7 |
| 17.5 |
|
| Distributed ATC Earnings | (16.1 | ) | (15.2 | ) |
| Amortization of the Remeasurement of Deferred Income Taxes | 1.3 |
| 0.9 |
|
| Equity Investment Ending Balance |
| $141.6 |
|
| $128.1 |
|
|
| | | | | | |
| ALLETE’s Investment in ATC | | |
| Year Ended December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Equity Investment Beginning Balance |
| $135.6 |
|
| $124.5 |
|
| Cash Investments | 7.8 |
| 5.4 |
|
| Equity in ATC Earnings | 22.5 |
| 18.5 |
|
| Distributed ATC Earnings | (19.3 | ) | (12.8 | ) |
Remeasurement of Deferred Income Taxes (a) | (27.9 | ) | — |
|
| Equity Investment Ending Balance |
| $118.7 |
|
| $135.6 |
|
| |
(a) | Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.) |
|
| | | | | | |
| ATC Summarized Financial Data | | |
| Balance Sheet Data | | |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Current Assets |
| $87.7 |
|
| $75.8 |
|
| Non-Current Assets | 4,598.9 |
| 4,312.9 |
|
| Total Assets |
| $4,686.6 |
|
| $4,388.7 |
|
| Current Liabilities |
| $767.2 |
|
| $495.1 |
|
| Long-Term Debt | 1,790.6 |
| 1,865.3 |
|
| Other Non-Current Liabilities | 240.3 |
| 271.5 |
|
| Members’ Equity | 1,888.5 |
| 1,756.8 |
|
| Total Liabilities and Members’ Equity |
| $4,686.6 |
|
| $4,388.7 |
|
|
| | | | | | |
| ATC Summarized Financial Data | | |
| Balance Sheet Data | | |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Current Assets |
| $84.6 |
|
| $87.2 |
|
| Non-Current Assets | 5,244.3 |
| 4,928.8 |
|
| Total Assets |
| $5,328.9 |
|
| $5,016.0 |
|
| Current Liabilities |
| $502.6 |
|
| $640.0 |
|
| Long-Term Debt | 2,312.8 |
| 2,014.0 |
|
| Other Non-Current Liabilities | 298.9 |
| 295.3 |
|
| Members’ Equity | 2,214.6 |
| 2,066.7 |
|
| Total Liabilities and Members’ Equity |
| $5,328.9 |
|
| $5,016.0 |
|
| | | Income Statement Data | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
| 2019 |
| 2018 |
| 2017 |
|
| Millions | | |
| Revenue |
| $721.6 |
|
| $650.8 |
|
| $615.8 |
|
| $744.4 |
|
| $690.5 |
|
| $721.6 |
|
| Operating Expense | 344.9 |
| 322.5 |
| 319.3 |
| 373.5 |
| 358.7 |
| 344.9 |
|
| Other Expense | 104.1 |
| 95.5 |
| 96.1 |
| 110.5 |
| 108.3 |
| 104.1 |
|
| Net Income |
| $272.6 |
|
| $232.8 |
|
| $200.4 |
|
| $260.4 |
|
| $223.5 |
|
| $272.6 |
|
| ALLETE’s Equity in Net Income |
| $22.5 |
|
| $18.5 |
|
| $16.3 |
|
| $21.7 |
|
| $17.5 |
|
| $22.5 |
|
In September 2016, the FERC issued an order reducing ATC’s authorized return on equity to 10.32is 9.88 percent, or 10.82 percent including an incentive adder for participation in a regional transmission organization. Prior to this order, ATC had been allowed a return on equity of 12.2 percent which had been impacted by reductions for estimated refunds related to complaints filed with the FERC by several customers located within the MISO service area.
In June 2016, a federal administrative law judge ruled on an additional complaint proposing a further reduction in the base return on equity to 9.70 percent, or 10.2010.38 percent including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from thebased on a November 2019 FERC on the administrative law judge’s recommendation is pending.order. (See Note 4. Regulatory Matters.)
NOTE 6. ACQUISITIONS5. EQUITY INVESTMENTS (Continued)
Investment in Nobles 2. In December 2018, our wholly-owned subsidiary, ALLETE South Wind, entered into an agreement with Tenaska to purchase a 49 percent equity interest in Nobles 2, the entity that will own and operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. The following acquisitions are consistentwind energy facility will be built in Nobles County, Minnesota and is expected to be completed in late 2020, with ALLETE’s stated strategyan estimated total project cost of investing in energy infrastructure and related services businessesapproximately $350 million to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth. The pro forma impact of the following acquisitions was not significant, either individually or in the aggregate, to the results of the Company for the years ended December 31, 2017, 2016 and 2015.
2017 Activity.
Tonka Water.On September 1, 2017, U.S. Water Services acquired 100 percent of Tonka Water. Total consideration for the transaction was $19.2 million, including a working capital adjustment. Consideration of $19.0 million was paid in cash on the acquisition date and a working capital adjustment of $0.2 million was paid in$400 million. In the fourth quarter of 2017. Tonka Water is2019, we entered into a supplier of municipal and industrial water treatment systems and will expand U.S. Water Services’ geographic and customer markets.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair valuestax equity funding agreement to finance up to $125 million of the assets acquired andproject costs. We account for our investment in Nobles 2 under the liabilities assumedequity method of accounting. As of December 31, 2019, our equity investment in Nobles 2 was $56.0 million ($33.0 million at the date of acquisition. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to income tax liabilities; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.
|
| | | |
Millions | |
Assets Acquired | |
Accounts Receivable | $5.1 |
Other Current Assets | 5.1 |
|
Trade Names (a)
| 0.9 |
|
Goodwill (a)(b)
| 16.9 |
|
Other Non-Current Assets | 0.2 |
|
Total Assets Acquired |
| $28.2 |
|
Liabilities Assumed | |
Current Liabilities |
| $9.0 |
|
Total Liabilities Assumed |
| $9.0 |
|
Net Identifiable Assets Acquired |
| $19.2 |
|
(a) Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.) | |
(b) | Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in $4.1 million of deductible goodwill. |
Acquisition-related costs were immaterial, expensed as incurred during 2017 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
2016 Activity.
Acquisition of Non-Controlling Interest.December 31, 2018). In April 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns its Condon wind energy facility for $8.0 million. This transaction was accounted for as an equity transaction, and no gain or loss was recognized in net income or other comprehensive income. As a result of the acquisition, the Condon wind energy facility is now a wholly-owned subsidiary of ALLETE Clean Energy.
WEST. In October 2016, U.S. Water Services acquired 100 percent of Water & Energy Systems Technology of Nevada, Inc. (WEST). Total consideration for the transaction was $6.7 million. Consideration of $5.9 million was paid in cash on the acquisition date, working capital adjustments of $0.2 million were paid in the first six months of 2017 and a $0.6 million payment is due in April 2018. WEST is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southwestern United States.
NOTE 6. ACQUISITIONS (Continued)
2016 Activity (Continued)
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in the second quarter of 2017, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.
|
| | | |
Millions | |
Assets Acquired | |
Cash and Cash Equivalents |
| $0.1 |
|
Other Current Assets | 1.0 |
|
Customer Relationships (a)
| 2.8 |
|
Goodwill (a)(b)
| 4.2 |
|
Other Non-Current Assets | 0.1 |
|
Total Assets Acquired |
| $8.2 |
|
Liabilities Assumed | |
Current Liabilities |
| $0.3 |
|
Non-Current Liabilities | 1.2 |
|
Total Liabilities Assumed |
| $1.5 |
|
Net Identifiable Assets Acquired |
| $6.7 |
|
| |
(a) | Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.) |
| |
(b) | For tax purposes, the purchase price allocation resulted in no allocation to goodwill. |
Acquisition-related costs were immaterial, expensed as incurred during 2016 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
2015 Activity.
U.S. Water Services. In 2015, ALLETE acquired U.S. Water Services. Total consideration for the transaction was $202.3 million, which included payment of $166.6 million in cash and an estimated fair value of earnings-based contingent consideration of $35.7 million, as estimated at the date of acquisition, to be paid through 2019. The contingent consideration is presented within Other Non-Current Liabilities on the Consolidated Balance Sheet. The Consolidated Statement of Income reflects 100 percent of the results of operations for U.S. Water Services since the acquisition date as the Company has acquired 100 percent of U.S. Water Services.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
NOTE 6. ACQUISITIONS (Continued)
2015 Activity (Continued)
|
| | | |
Millions | |
Assets Acquired | |
Cash and Cash Equivalents |
| $0.9 |
|
Accounts Receivable | 16.8 |
|
Inventories (a)
| 13.4 |
|
Other Current Assets (b)
| 5.3 |
|
Property, Plant and Equipment | 10.6 |
|
Intangible Assets (c)
| 83.0 |
|
Goodwill (d)
| 122.9 |
|
Other Non-Current Assets | 0.2 |
|
Total Assets Acquired |
| $253.1 |
|
Liabilities Assumed | |
Current Liabilities |
| $19.2 |
|
Non-Current Liabilities | 31.6 |
|
Total Liabilities Assumed |
| $50.8 |
|
Net Identifiable Assets Acquired |
| $202.3 |
|
| |
(a) | Included in Inventories was $2.7 million of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of Sales within one year from the acquisition date. |
| |
(b) | Included in Other Current Assets was $1.6 million relating to the fair value of sales backlog. Sales backlog was recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of $2.1 million relating to cash pledged as collateral for standby letters of credit. |
| |
(c) | Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 7. Goodwill and Intangible Assets.) |
| |
(d) | For tax purposes, the purchase price allocation resulted in $2.9 million of deductible goodwill. |
Acquisition-related costs of $3.0 million after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
Chanarambie/Viking. In 2015, ALLETE Clean Energy acquired 100 percent of wind energy facilities in southern Minnesota (Chanarambie/Viking) from EDF Renewable Energy, Inc. for $48.0 million.
The facilities have a combined 97.5 MW of generating capability. The wind energy facilities began commercial operations in 2003 and have PSAs in place for their entire output, which expire in 2018 (12 MW) and 2023 (85.5 MW).
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
NOTE 6. ACQUISITIONS (Continued)
2015 Activity (Continued)
|
| | | |
Millions | |
Assets Acquired | |
Current Assets |
| $4.8 |
|
Property, Plant and Equipment | 103.0 |
|
Other Non-Current Assets (a)
| 1.0 |
|
Total Assets Acquired |
| $108.8 |
|
Liabilities Assumed | |
Current Liabilities (b)
|
| $6.7 |
|
PSAs | 49.0 |
|
Non-Current Liabilities | 5.1 |
|
Total Liabilities Assumed |
| $60.8 |
|
Net Identifiable Assets Acquired |
| $48.0 |
|
| |
(a) | Included in Other Non-Current Assets was $0.3 million of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill. |
| |
(b) | Current Liabilities included $5.9 million related to the current portion of PSAs. |
Acquisition-related costs of $0.2 million after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
Armenia Mountain. In 2015, ALLETE Clean Energy acquired 100 percent of a wind energy facility located near Troy, Pennsylvania (Armenia Mountain) from The AES Corporation and a minority shareholder for $111.1 million, plus the assumption of existing debt.
The facility has 100.5 MW of generating capability, began commercial operations in 2009, and has PSAs in place for its entire output, which expire in 2024.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
|
| | | |
Millions | |
Assets Acquired | |
Current Assets (a)
|
| $9.0 |
|
Property, Plant and Equipment | 156.2 |
|
Other Non-Current Assets (b)
| 14.4 |
|
Total Assets Acquired |
| $179.6 |
|
Liabilities Assumed | |
Current Liabilities |
| $2.9 |
|
Long-Term Debt Due Within One Year | 5.9 |
|
Long-Term Debt | 55.0 |
|
Other Non-Current Liabilities | 4.7 |
|
Total Liabilities Assumed |
| $68.5 |
|
Net Identifiable Assets Acquired |
| $111.1 |
|
| |
(a) | Included in Current Assets was $1.0 million related to the current portion of PSAs and $6.0 million of restricted cash related to collateral deposits required under its loan agreement. |
| |
(b) | Included in Other Non-Current Assets was $8.2 million related to the non-current portion of PSAs, $6.1 million of restricted cash related to collateral deposits required under its loan agreements and an immaterial amount of goodwill. For tax purposes, the purchase price allocation resulted in no allocation to goodwill. |
NOTE 6. ACQUISITIONS (Continued)
2015 Activity (Continued)
Acquisition-related costs of $1.6 million after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
A and W Technologies. In 2015, U.S. Water Services acquired 100 percent of A and W Technologies, Inc. (AWT). Total consideration for the transaction was $9.3 million, which included payment2019, Nobles 2 returned capital of $8.3 million in cash and a $1.0 million payment made in April 2017. AWT, similar to U.S. Water Services, is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southeastern United States.
The acquisition was accounted for as a business combination and the purchase price was allocated based on its cash needs. For the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalizedyear ended December 31, 2019, we invested $31.3 million in 2015, is reflectedNobles 2. We expect to invest approximately $115 million in the following table. Fair value measurements were valued primarily using the discounted cash flow method.2020.
|
| | | |
Millions | |
Assets Acquired | |
Current Assets |
| $1.0 |
|
Property, Plant and Equipment | 0.1 |
|
Intangible Assets (a)
| 3.9 |
|
Goodwill (b)
| 4.4 |
|
Total Assets Acquired |
| $9.4 |
|
Liabilities Assumed | |
Current Liabilities |
| $0.1 |
|
Total Liabilities Assumed |
| $0.1 |
|
Net Identifiable Assets Acquired |
| $9.3 |
|
| |
(a) | Intangible Assets include customer relationships and non-compete agreements. (See Note 7. Goodwill and Intangible Assets.) |
| |
(b) | For tax purposes, the purchase price allocation resulted in $4.4 million of deductible goodwill. |
Acquisition-related costs were immaterial, expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
NOTE 7.6. GOODWILL AND INTANGIBLE ASSETS
As a result of completing the sale of U.S. Water Services on March 26, 2019, there was 0 goodwill recorded as of December 31, 2019 ($148.5 million at December 31, 2018).
The following table summarizes changes to goodwill by reportable segment:
|
| | | | | | | | | | | |
| | ALLETE Clean Energy |
| | U.S. Water Services |
| | Total |
|
| Millions | | | | | |
| Balance as of December 31, 2015 |
| $3.3 |
| |
| $127.3 |
| |
| $130.6 |
|
Acquired Goodwill (a) | — |
| | 3.9 |
| | 3.9 |
|
Impairment Charge (b) | (3.3 | ) | | — |
| | (3.3 | ) |
| Balance as of December 31, 2016 | — |
| | 131.2 |
| | 131.2 |
|
Acquired Goodwill (a) | — |
| | 16.9 |
| | 16.9 |
|
Other Adjustments (c) | — |
| | 0.2 |
| | 0.2 |
|
| Balance as of December 31, 2017 | — |
| |
| $148.3 |
| |
| $148.3 |
|
| |
(a) | See Note 6. Acquisitions. |
| |
(b) | The facts and circumstances that led to an impairmentbalance of ALLETE Clean Energy’s goodwill primarily relate to lower estimated energy prices in periods not under PSAs. Impairment Charge is included in Operating Expenses – Other on the Consolidated Statement of Income. (See Note 1. Operations and Significant Accounting Policies.) ALLETE Clean Energy’s goodwill was primarily related to the acquisition of Storm Lake II in 2014. |
| |
(c) | Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition. |
The following table summarizes changes to intangible assets, net, for the year ended December 31, 2017:2019:
| | | | December 31,
2016 |
| | Additions (a) | | Amortization | | December 31,
2017 |
| December 31,
2018 |
| | Amortization | | Other (b) | | December 31,
2019 |
|
| Millions | | | | | | | | |
| Intangible Assets | | | | | | | | |
| Definite-Lived Intangible Assets | | | | | | | | |
| Customer Relationships |
| $59.3 |
| | — |
| | $(4.6) | |
| $54.7 |
|
| $50.7 |
| | $(1.1) | | $(49.6) | | — |
|
Developed Technology and Other (b)(a) | 6.3 |
| |
| $0.9 |
| | (0.9) | | 6.3 |
| 7.5 |
| | (0.4) | | (6.1) | |
| $1.0 |
|
| Total Definite-Lived Intangible Assets | 65.6 |
| | 0.9 |
| | (5.5) | | 61.0 |
| 58.2 |
| | (1.5) | | (55.7) | | 1.0 |
|
| Indefinite-Lived Intangible Assets | | | | | | | | |
| Trademarks and Trade Names | 16.6 |
| | — |
| | n/a | | 16.6 |
| 16.6 |
| | n/a | | (16.6) | | — |
|
| Total Intangible Assets |
| $82.2 |
| |
| $0.9 |
| | $(5.5) | |
| $77.6 |
|
| $74.8 |
| | $(1.5) | | $(72.3) | |
| $1.0 |
|
| |
| (a) | Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 6. Acquisitions.) |
| |
(b) | Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives. |
Customer relationships have a remaining useful life(b) On March 26, 2019, ALLETE completed the sale of approximately 20 years, and developed technology and other have remaining useful lives ranging from approximately 1 year to approximately 11 years (weighted averageU.S. Water Services which resulted in the removal of approximately 7 years). The weighted average remaining useful life of all definite-livedthe related intangible assets as of December 31, 2017, is approximately 19 years.from the Consolidated Balance Sheet.
Amortization expense offor intangible assets was $1.5 million for the year ended December 31, 2017, was $5.52019 ($5.6 million ($5.2 million in 2016; $4.0 million in 2015). Accumulated amortization was $14.8 million and $9.3 million as offor the year ended December 31, 2017, and December 31, 2016, respectively. Estimated amortization expense for2018). The remaining definite-lived intangible assets is $5.3 million in 2018, $5.0 million in 2019, $4.7 million in 2020, $4.6 million in 2021, $4.3 million in 2022 and $37.1 million thereafter.
NOTE 8. INVESTMENTS
Investments. As of December 31, 2017, the investment portfolio included the legacy real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans and other assets consisting primarily of land in Minnesota.
|
| | | | | | |
| Other Investments | | |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| ALLETE Properties |
| $26.4 |
|
| $31.7 |
|
Available-for-sale Securities (a) | 19.1 |
| 18.8 |
|
| Cash Equivalents | 3.8 |
| 1.3 |
|
| Other | 3.8 |
| 3.8 |
|
| Total Other Investments |
| $53.1 |
|
| $55.6 |
|
| |
(a) | As of December 31, 2017, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $0.7 million, in one year to less than three years was $3.2 million, in three years to less than five years was $3.6 million, and in five or more years was $1.4 million. |
Land Inventory. Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined notwill continue to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and no impairment was recorded in 2017 (none in 2016; $36.3 million in 2015). (See Note 1. Operations and Significant Accounting Policies.)amortized ratably through 2028.
Available-for-Sale Securities.We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.
Gross realized and unrealized gains and losses on our available-for-sale securities were immaterial in 2017, 2016 and 2015.
NOTE 9.7. FAIR VALUE
Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily equity securities.
NOTE 7. FAIR VALUE (Continued)
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. This category includes deferred compensation and fixed income securities.
Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includesincluded the U.S. Water Services contingent consideration liability.
NOTE 9. FAIR VALUE (Continued)
The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 20172019, and December 31, 2016.2018. Each asset and liability is classified 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, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.
|
| | | | | | | | | | | | | | |
| | Fair Value as of December 31, 2019 |
| Recurring Fair Value Measures | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
|
| Millions | | | | | | | |
| Assets: | | | | | | | |
Investments (a) | | | | | | | |
| Available-for-sale – Equity Securities |
| $11.1 |
| | — |
| | — |
| |
| $11.1 |
|
Available-for-sale – Corporate and Governmental Debt Securities (b) | — |
| |
| $9.7 |
| | — |
| | 9.7 |
|
| Cash Equivalents | 0.9 |
| | — |
| | — |
| | 0.9 |
|
| Total Fair Value of Assets |
| $12.0 |
| |
| $9.7 |
| | — |
| |
| $21.7 |
|
| | | | | | | | |
| Liabilities: | | | | | | | |
Deferred Compensation (c) | — |
| |
| $21.2 |
| | — |
| |
| $21.2 |
|
| Total Fair Value of Liabilities | — |
| |
| $21.2 |
| | — |
| |
| $21.2 |
|
| Total Net Fair Value of Assets (Liabilities) |
| $12.0 |
| | $(11.5) | | — |
| | $0.5 |
|
| | | | | | | | | | | | | | | |
| | Fair Value as of December 31, 2017 |
| Recurring Fair Value Measures | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
|
| Millions | | | | | | | |
| Assets: | | | | | | | |
Investments (a) | | | | | | | |
| Available-for-sale – Equity Securities |
| $10.2 |
| | — |
| | — |
| |
| $10.2 |
|
| Available-for-sale – Corporate and Governmental Debt Securities | — |
| |
| $8.9 |
| | — |
| | 8.9 |
|
| Cash Equivalents | 3.8 |
| | — |
| | — |
| | 3.8 |
|
| Total Fair Value of Assets |
| $14.0 |
| |
| $8.9 |
| | — |
| |
| $22.9 |
|
| | | | | | | | |
Liabilities: (b) | | | | | | | |
| Deferred Compensation | — |
| |
| $18.2 |
| | — |
| |
| $18.2 |
|
| U.S. Water Services Contingent Consideration | — |
| | — |
| |
| $5.4 |
| | 5.4 |
|
| Total Fair Value of Liabilities | — |
| |
| $18.2 |
| |
| $5.4 |
| |
| $23.6 |
|
| Total Net Fair Value of Assets (Liabilities) |
| $14.0 |
| | $(9.3) | | $(5.4) | | $(0.7) |
| |
| (a) | Included in Other InvestmentsNon-Current Assets on the Consolidated Balance Sheet. |
| |
| (b) | As of December 31, 2019, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $2.1 million, in one year to less than three years was $7.2 million, in three years to less than five years was 0 and in five or more years was $0.4 million. |
| |
| (c) | Included in Other Non-Current Liabilities on the Consolidated Balance Sheet. |
NOTE 7. FAIR VALUE (Continued)
|
| | | | | | | | | | | | | | | |
| | Fair Value as of December 31, 2018 |
| Recurring Fair Value Measures | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
|
| Millions | | | | | | | |
| Assets: | | | | | | | |
Investments (a) | | | | | | | |
| Available-for-sale – Equity Securities |
| $12.2 |
| | — |
| | — |
| |
| $12.2 |
|
| Available-for-sale – Corporate and Governmental Debt Securities | — |
| |
| $8.0 |
| | — |
| | 8.0 |
|
| Cash Equivalents | 1.0 |
| | — |
| | — |
| | 1.0 |
|
| Total Fair Value of Assets |
| $13.2 |
| |
| $8.0 |
| | — |
| |
| $21.2 |
|
| | | | | | | | |
Liabilities: (b) | | | | | | | |
| Deferred Compensation | — |
| |
| $19.8 |
| | — |
| |
| $19.8 |
|
| U.S. Water Services Contingent Consideration | — |
| | — |
| |
| $3.8 |
| | 3.8 |
|
| Total Fair Value of Liabilities | — |
| |
| $19.8 |
| |
| $3.8 |
| |
| $23.6 |
|
| Total Net Fair Value of Assets (Liabilities) |
| $13.2 |
| | $(11.8) | | $(3.8) | | $(2.4) |
| |
| (a) | Included in Other Non-Current Assets on the Consolidated Balance Sheet. |
| |
| (b) | Included in Other Non-Current Liabilities on the Consolidated Balance Sheet. |
|
| | | | | | | | | | | | | | | |
| | Fair Value as of December 31, 2016 |
| Recurring Fair Value Measures | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
|
| Millions | | | | | | | |
| Assets: | | | | | | | |
Investments (a) | | | | | | | |
| Available-for-sale – Equity Securities |
| $7.1 |
| | — |
| | — |
| |
| $7.1 |
|
| Available-for-sale – Corporate and Governmental Debt Securities | — |
| |
| $11.7 |
| | — |
| | 11.7 |
|
| Cash Equivalents | 1.3 |
| | — |
| | — |
| | 1.3 |
|
| Total Fair Value of Assets |
| $8.4 |
| |
| $11.7 |
| | — |
| |
| $20.1 |
|
| | | | | | | | |
Liabilities: (b) | | | | | | | |
| Deferred Compensation | — |
| |
| $16.0 |
| | — |
| |
| $16.0 |
|
| U.S. Water Services Contingent Consideration | — |
| | — |
| |
| $25.0 |
| | 25.0 |
|
| Total Fair Value of Liabilities | — |
| |
| $16.0 |
| |
| $25.0 |
| |
| $41.0 |
|
| Total Net Fair Value of Assets (Liabilities) |
| $8.4 |
| | $(4.3) | | $(25.0) | | $(20.9) |
| |
(a) | Included in Other Investments on the Consolidated Balance Sheet. |
| |
(b) | Included in Other Non-Current Liabilities on the Consolidated Balance Sheet. |
NOTE 9. FAIR VALUE (Continued)
The followingLevel 3 liability in the preceding table provides a reconciliationis related to the contingent consideration liability that resulted from the 2015 acquisition of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of December 31, 2017, and December 31, 2016. The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value was measured basedServices. Based on the consideration expected to be transferred, discounted to present value. The discount rate was determined at the time of measurement in accordance with generally accepted valuation methods. The fair valueterms and conditions of the acquisition contingent consideration is remeasured to arrive at estimated fair value each reporting period with the change in fair value recognized as income or expenseagreement, a final payout of $3.8 million was made in the Consolidated Statementfirst quarter of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, timing of milestones that trigger payments, and the timing and amount of earnings estimates. Using different valuation assumptions, including earnings projections or discount rates, may result in different fair value measurements and expense (or income) in future periods. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate. The acquisition contingent consideration was measured at $5.4 million as of December 31, 2017.2019.
|
| | | |
Recurring Fair Value Measures | |
Activity in Level 3 | |
Millions | |
Balance as of December 31, 2015 |
| $36.6 |
|
Accretion (a)
| 2.8 |
|
Payments | (0.8 | ) |
Changes in Cash Flow Projections (b)
| (13.6 | ) |
Balance as of December 31, 2016 |
| $25.0 |
|
Accretion (a)
| 0.8 |
|
Payments (c)
| (19.7 | ) |
Changes in Cash Flow Projections (c)
| (0.7 | ) |
Balance as of December 31, 2017 |
| $5.4 |
|
| |
(a) | Included in Interest Expense on the Consolidated Statement of Income. |
| |
(b) | During the fourth quarter of 2016, management assessed earnings estimates used in calculating the fair value of the U.S. Water Services contingent consideration liability and determined an adjustment was necessary to the liability’s carrying amount based on its assessment. As a result, we recorded a reduction of $13.6 million to the liability’s carrying amount which resulted in an after-tax gain of the same amount presented within Operating Expenses – Other in the Consolidated Statement of Income. |
| |
(c) | Payments and changes in cash flow projections reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, and were paid in the first half of 2017. |
The Company’s policy is to recognize transfers in and transfers out of Levels as of the actual date of the event or change in circumstances that caused the transfer. For the years ended December 31, 20172019 and 20162018, there were no0 transfers in or out of Levels 1, 2 or 3.
Fair Value of Financial Instruments. With the exception of the item listed in the following table, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed in the following table was based on quoted market prices for the same or similar instruments (Level 2).
|
| | | |
| Financial Instruments | Carrying Amount | | Fair Value |
| Millions | | | |
| Long-Term Debt, Including Long-Term Debt Due Within One Year | | | |
| December 31, 2019 | $1,622.6 | | $1,791.8 |
| December 31, 2018 | $1,495.2 | | $1,534.6 |
|
| | | |
| Financial Instruments | Carrying Amount | | Fair Value |
| Millions | | | |
| Long-Term Debt, Including Long-Term Debt Due Within One Year | | | |
| December 31, 2017 | $1,513.3 | | $1,627.6 |
| December 31, 2016 | $1,569.1 | | $1,653.8 |
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.
NOTE 9. FAIR VALUE (Continued)
Equity Method Investment. Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately 8 percent of ATC. (See Note 5. Investment in ATC.) Investments. The aggregate carrying amount of the investmentour equity investments was $118.7$197.6 million as of December 31, 20172019 ($135.6161.1 million as of December 31, 2016)2018). The Company assesses our investmentequity investments in ATC and Nobles 2 for impairment whenever events or changes in circumstances indicate that the carrying amount of our investment in ATCinvestments may not be recoverable. For the years ended December 31, 20172019 and 2016,2018, there were no0 indicators of impairment.
Goodwill. The Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. The Company’s goodwill is a result of the U.S. Water Services acquisition in 2015 as well as U.S. Water Services’ subsequent acquisitions. (See Note 6. Acquisitions.5. Equity Investments.) The aggregate carrying amount of goodwill was $148.3 million as of December 31, 2017, and $131.2 million as of December 31, 2016.
Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. The Company calculates the excess of the reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. Our annual impairment test for U.S. Water Services indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and no impairment existed for the year ended December 31, 2017 (none in 2016 and in 2015). As part of the 2016 annual impairment analysis, the Company recognized a non-cash impairment charge of $3.3 million for ALLETE Clean Energy’s goodwill primarily related to the acquisition of Storm Lake II in 2014. The charge, which is presented within Operating Expenses – Other in the Consolidated Statement of Income, eliminated all goodwill for the ALLETE Clean Energy reporting unit. (See Note 1. Operations and Significant Accounting Policies.)
Intangible Assets. The Company assesses indefinite-lived intangible assets for impairment annually in the fourth quarter. The Company also assesses indefinite-lived and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable. Substantially all of the Company’s intangible assets are a result of the U.S. Water Services acquisition in 2015 as well as U.S. Water Services’ subsequent acquisitions. The aggregate carrying amount of intangible assets was $77.6 million as of December 31, 2017 ($82.2 million as of December 31, 2016). When events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable, the Company calculates the excess of an intangible asset's carrying amount over its undiscounted future cash flows. If the carrying amount is not recoverable, an impairment loss is recorded based on the amount by which the carrying amount exceeds the fair value. The inputs used in the fair value analysis fall within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs to determine fair value. As of December 31, 2017, there have been no events or changes in circumstance which would indicate impairment of our intangible assets.
Property, Plant and Equipment. The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable. The impairment of ALLETE Clean Energy’s goodwill in 2016, primarily due to lower estimated energy prices in periods not under PSAs, caused management to review ALLETE Clean Energy’s WTGs for impairment. Based on the results of the undiscounted cash flow analysis, the undiscounted future cash flows were adequate to recover the carrying value of the WTGs. In 2015, the Company implemented a revised strategy for its real estate assets and recorded a non-cash impairment charge of $36.3 million for ALLETE Properties, reducing the carrying value of the real estate to its estimated fair value. (See Note 1. Operations and Significant Accounting Policies.) For the yearyears ended December 31, 2017,2019, and 2018, there were no indicatorswas 0 impairment of impairment.property, plant, and equipment.
NOTE 7. FAIR VALUE (Continued)
We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. In 2015, Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to operate on natural gas which were actions included in Minnesota Power’s MPUC-approved 2013 IRP. In a July 2016 order, the MPUC approvedaccepted Minnesota Power’s 2015 IRP with modifications. The 2015 IRP contains steps in Minnesota Power’s EnergyForward plan including the economic idling ofplans for Taconite Harbor, Units 1 and 2 in September 2016, and the ceasing of coal-fired operations at Taconite Harbor in 2020. (See Note 4. Regulatory Matters.) The MPUC order for the 2015 IRP also directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022. In October 2016,2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power announced thatto conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. Minnesota Power retired Boswell Units 1 and 2 will be retired in the fourth quarter of 2018. As part of the 2016 general retail rate case, the MPUC allowed recovery of the remaining book value of Boswell Units 1 and 2 through 2022. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2 or the conversion of Laskin to operate on natural gas. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives. (See Note 4. Regulatory Matters.)
NOTE 10.8. SHORT-TERM AND LONG-TERM DEBT
Short-Term Debt. As of December 31, 2017,2019, total short-term debt outstanding was $64.1$212.9 million ($187.757.5 million as of December 31, 2016)2018), consisted of long-term debt due within one year and included $0.5$0.4 million of unamortized debt issuance costs.
As of December 31, 2017,2019, we had consolidated bank lines of credit aggregating $407.0 million ($409.0407.0 million as of December 31, 2016)2018), the majoritymost of which expire in October 2020.January 2024. We had $11.9$62.0 million outstanding in standby letters of credit and no0 outstanding draws under our lines of credit as of December 31, 20172019 ($11.118.4 million in standby letters of credit and no0 outstanding draws as of December 31, 2016)2018).
On January 10, 2019, ALLETE entered into an amended and restated $400 million credit agreement (Credit Agreement). The Credit Agreement amended and restated ALLETE’s $400 million credit facility, which was scheduled to expire in October 2020. The Credit Agreement is unsecured, has a variable interest rate and will expire in January 2024. At ALLETE’s request and subject to certain conditions, the Credit Agreement may be increased by up to$150 million and ALLETE may make two requests to extend the maturity date, each for a one‑year extension. Advances may be used by ALLETE for general corporate purposes, to provide liquidity in support of ALLETE's commercial paper program and to issue up to $100 million in letters of credit.
Long-Term Debt. As of December 31, 2017,2019, total long-term debt outstanding was $1,439.2$1,400.9 million ($1,370.41,428.5 million as of December 31, 2016)2018) and included $9.5$8.4 million of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in 20182020 is $64.6$213.3 million; $57.6 million in 2019; $143.0 million in 2020; $97.8$98.6 million in 2021; $88.0$88.8 million in 2022; $88.8 million in 2023; $73.5 million in 2024; and $1,062.3$1,059.6 million thereafter. Substantially all of our regulated electric plant is subject to the lien of the mortgages collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.
Minnesota Power is obligated to make financing payments for the Camp Ripley solar array totaling $1.4 million annually during the financing term, which expires in 2027. Minnesota Power has the option at the end of the financing term to renew for a two‑2‑year term, or to purchase the solar array for approximately $4 million. Minnesota Power anticipates exercising the purchase option when the term expires.
On JuneMarch 1, 2017,2019, ALLETE issued $80.0 million of its senior unsecured notes (the Notes) to certain institutional buyers inand sold the private placement market. The Notes were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes bear interest at 3.11 percent and mature on June 1, 2027. Interest on the Notes is payable semi-annually in June and December of each year, commencing on December 1, 2017. ALLETE has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes were used to redeem debt, fund corporate growth opportunities and for general corporate purposes.
On August 25, 2017, ALLETE entered into a $40.0 million term loan agreement (Term Loan). The Term Loan is an unsecured, single draw loan that is due on August 25, 2020, and may be prepaid at any time subject to a make-whole provision. Interest on the Term Loan is payable quarterly at a rate per annum equal to LIBOR plus 1.025 percent. Proceeds from the Term Loan were used for general corporate purposes.
On November 2, 2017, ALLETE entered into a bond purchase agreement providing for the issuance and sale of $60.0 million of itsfollowing First Mortgage Bonds (the Bonds) that bear interest at 4.07 percent. The Bonds will be issued on or about April 1, 2018, and will mature in April 2048. Interest on the Bonds will be payable semi-annually in April and October of each year, commencing on October 16, 2018. :
|
| | |
| Maturity Date | Principal Amount | Interest Rate |
| March 1, 2029 | $70 Million | 4.08% |
| March 1, 2049 | $30 Million | 4.47% |
ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The company intends to useALLETE used the proceeds from the sale of the Bonds to fund utility capital expendituresinvestment and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.
NOTE 10.8. SHORT-TERM AND LONG-TERM DEBT (Continued)
Long-Term Debt (Continued)
|
| | | | | | |
| Long-Term Debt | | |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| First Mortgage Bonds | | |
| 1.83% Series Due 2018 |
| $50.0 |
|
| $50.0 |
|
| 8.17% Series Due 2019 | 42.0 |
| 42.0 |
|
| 5.28% Series Due 2020 | 35.0 |
| 35.0 |
|
| 2.80% Series Due 2020 | 40.0 |
| 40.0 |
|
| 4.85% Series Due 2021 | 15.0 |
| 15.0 |
|
| 3.02% Series Due 2021 | 60.0 |
| 60.0 |
|
| 3.40% Series Due 2022 | 75.0 |
| 75.0 |
|
| 6.02% Series Due 2023 | 75.0 |
| 75.0 |
|
| 3.69% Series Due 2024 | 60.0 |
| 60.0 |
|
| 4.90% Series Due 2025 | 30.0 |
| 30.0 |
|
| 5.10% Series Due 2025 | 30.0 |
| 30.0 |
|
| 3.20% Series Due 2026 | 75.0 |
| 75.0 |
|
| 5.99% Series Due 2027 | 60.0 |
| 60.0 |
|
| 3.30% Series Due 2028 | 40.0 |
| 40.0 |
|
| 3.74% Series Due 2029 | 50.0 |
| 50.0 |
|
| 3.86% Series Due 2030 | 60.0 |
| 60.0 |
|
| 5.69% Series Due 2036 | 50.0 |
| 50.0 |
|
| 6.00% Series Due 2040 | 35.0 |
| 35.0 |
|
| 5.82% Series Due 2040 | 45.0 |
| 45.0 |
|
| 4.08% Series Due 2042 | 85.0 |
| 85.0 |
|
| 4.21% Series Due 2043 | 60.0 |
| 60.0 |
|
| 4.95% Series Due 2044 | 40.0 |
| 40.0 |
|
| 5.05% Series Due 2044 | 40.0 |
| 40.0 |
|
| 4.39% Series Due 2044 | 50.0 |
| 50.0 |
|
| Unsecured Term Loan Variable Rate Due 2017 | — |
| 125.0 |
|
| Senior Unsecured Notes 5.99% Due 2017 | — |
| 50.0 |
|
| Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020 | 13.5 |
| 13.5 |
|
| Unsecured Term Loan Variable Rate Due 2020 | 40.0 |
| — |
|
| Armenia Mountain Senior Secured Notes 3.26% Due 2024 | 65.9 |
| 74.6 |
|
| Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025 | 27.8 |
| 27.8 |
|
| Senior Unsecured Notes 3.11% Due 2027 | 80.0 |
| — |
|
| SWL&P First Mortgage Bonds 4.15% Series Due 2028 | 15.0 |
| 15.0 |
|
| Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037 | 69.1 |
| 61.2 |
|
| Unamortized Debt Issuance Costs | (10.0 | ) | (11.0 | ) |
| Total Long-Term Debt | 1,503.3 |
| 1,558.1 |
|
| Less: Due Within One Year | 64.1 |
| 187.7 |
|
| Net Long-Term Debt |
| $1,439.2 |
|
| $1,370.4 |
|
|
| | | | | | |
| Long-Term Debt | | |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| First Mortgage Bonds | | |
| 8.17% Series Due 2019 | — |
|
| $42.0 |
|
| 5.28% Series Due 2020 |
| $35.0 |
| 35.0 |
|
| 2.80% Series Due 2020 | 40.0 |
| 40.0 |
|
| 4.85% Series Due 2021 | 15.0 |
| 15.0 |
|
| 3.02% Series Due 2021 | 60.0 |
| 60.0 |
|
| 3.40% Series Due 2022 | 75.0 |
| 75.0 |
|
| 6.02% Series Due 2023 | 75.0 |
| 75.0 |
|
| 3.69% Series Due 2024 | 60.0 |
| 60.0 |
|
| 4.90% Series Due 2025 | 30.0 |
| 30.0 |
|
| 5.10% Series Due 2025 | 30.0 |
| 30.0 |
|
| 3.20% Series Due 2026 | 75.0 |
| 75.0 |
|
| 5.99% Series Due 2027 | 60.0 |
| 60.0 |
|
| 3.30% Series Due 2028 | 40.0 |
| 40.0 |
|
| 4.08% Series Due 2029 | 70.0 |
| — |
|
| 3.74% Series Due 2029 | 50.0 |
| 50.0 |
|
| 3.86% Series Due 2030 | 60.0 |
| 60.0 |
|
| 5.69% Series Due 2036 | 50.0 |
| 50.0 |
|
| 6.00% Series Due 2040 | 35.0 |
| 35.0 |
|
| 5.82% Series Due 2040 | 45.0 |
| 45.0 |
|
| 4.08% Series Due 2042 | 85.0 |
| 85.0 |
|
| 4.21% Series Due 2043 | 60.0 |
| 60.0 |
|
| 4.95% Series Due 2044 | 40.0 |
| 40.0 |
|
| 5.05% Series Due 2044 | 40.0 |
| 40.0 |
|
| 4.39% Series Due 2044 | 50.0 |
| 50.0 |
|
| 4.07% Series Due 2048 | 60.0 |
| 60.0 |
|
| 4.47% Series Due 2049 | 30.0 |
| — |
|
| Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020 | 13.5 |
| 13.5 |
|
| Unsecured Term Loan Variable Rate Due 2020 | 110.0 |
| 10.0 |
|
| Armenia Mountain Senior Secured Notes 3.26% Due 2024 | 47.8 |
| 57.2 |
|
| Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025 | 27.8 |
| 27.8 |
|
| Senior Unsecured Notes 3.11% Due 2027 | 80.0 |
| 80.0 |
|
| SWL&P First Mortgage Bonds 4.15% Series Due 2028 | 15.0 |
| 15.0 |
|
| SWL&P First Mortgage Bonds 4.14% Series Due 2048 | 12.0 |
| 12.0 |
|
| Other Long-Term Debt, 3.11% – 5.75% Due 2020 – 2037 | 46.5 |
| 67.7 |
|
| Unamortized Debt Issuance Costs | (8.8 | ) | (9.2 | ) |
| Total Long-Term Debt | 1,613.8 |
| 1,486.0 |
|
| Less: Due Within One Year | 212.9 |
| 57.5 |
|
| Net Long-Term Debt |
| $1,400.9 |
|
| $1,428.5 |
|
NOTE 10.8. SHORT-TERM AND LONG-TERM DEBT (Continued)
Long-Term Debt (Continued)
On January 10, 2020, ALLETE entered into a $200 million term loan agreement (Term Loan) and borrowed $60 million upon execution. The unsecured Term Loan provides for the ability to borrow up to an additional $140 million, is due on February 10, 2021, and may be repaid at any time. Interest is payable monthly at a rate per annum equal to LIBOR plus 0.55 percent. Proceeds from the Term Loan will be used for construction-related expenditures.
Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to 0.65 to 1.00, measured quarterly. As of December 31, 2017,2019, our ratio was approximately 0.42 to 1.00. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of December 31, 20172019, ALLETE was in compliance with its financial covenants.
NOTE 11.9. COMMITMENTS, GUARANTEES AND CONTINGENCIES
The following table details the estimated minimum payments for certain long-term commitments:
|
| | | | | | | | | | | | | | | | | | |
| As of December 31, 2017 | | | | | | |
| Millions | 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022 |
| Thereafter |
|
| Coal, Rail and Shipping Contracts |
| $29.0 |
|
| $1.8 |
| — |
| — |
| — |
| — |
|
| Leasing Agreements |
| $14.2 |
|
| $12.8 |
|
| $9.5 |
|
| $7.3 |
|
| $6.1 |
|
| $30.0 |
|
Long-term Service Agreements (a) |
| $11.0 |
|
| $0.9 |
| — |
| — |
|
| $1.0 |
|
| $11.0 |
|
PPAs (b) |
| $104.5 |
|
| $107.1 |
|
| $115.0 |
|
| $144.8 |
|
| $144.7 |
|
| $1,667.0 |
|
|
| | | | | | | | | | | | | | | | | | |
| As of December 31, 2019 | | | | | | |
| Millions | 2020 |
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| Thereafter |
|
| Capital Purchase Obligations |
| $292.7 |
| — |
| — |
| — |
| — |
| — |
|
Easements (a) |
| $5.0 |
|
| $5.3 |
|
| $5.4 |
|
| $5.5 |
|
| $5.5 |
|
| $170.4 |
|
PPAs (b) |
| $113.0 |
|
| $122.5 |
|
| $145.5 |
|
| $145.6 |
|
| $138.5 |
|
| $1,386.7 |
|
Other Purchase Obligations (c) |
| $22.8 |
|
| $9.6 |
| — |
| — |
| — |
|
| $0.1 |
|
| |
| (a) | Consists of long-term serviceEasement obligations represent the minimum payments for our land easement agreements forat our wind energy facilities. |
| |
| (b) | Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with TenaskaNobles 2 commencing in 2020 as it is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-firedwind energy facility. (See Power Purchase Agreements.) |
| |
| (c) | Consists of long-term service agreements for wind energy facilities and minimum purchase commitments under coal and rail contracts. |
Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2018 and a portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.
Leasing Agreements. BNI Energy is obligated to make lease payments for a dragline totaling $2.8 million annually during the lease term, which expires in 2027. BNI Energy has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0 million termination fee. We also lease other properties and equipment under operating lease agreements with a majority of terms expiring through 2024. Total lease expense was $17.5 million in 2017 ($17.1 million in 2016; $17.3 million in 2015).
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase and Sales Agreements. Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments.
These agreements have also been evaluated under the accounting guidance for derivatives. We have determined that either these agreements are not derivatives, or if they are derivatives, the agreements qualify for the normal purchases and normal sales exemption to the accounting guidance; therefore, derivative accounting is not required.
Square Butte PPA. Minnesota Power has a PPA with Square Butte that extends through 2026 (Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s 455 MW coal‑fired generating unit. Minnesota Power’s output entitlement under the Agreement is 50 percent for the remainder of the Agreement, subject to the provisions of the Minnkota Power PSA described in the following table. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2017,2019, Square Butte had total debt outstanding of $330.0$280.7 million. Annual debt service for Square Butte is expected to be approximately $49$48.7 million annually through 2023 and $33.6 million in each of the next five years, 2018 through 2022,2024, of which Minnesota Power’s obligation is 50 percent. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.
NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase and Sales Agreements (Continued)
Minnesota Power’s cost of power purchased from Square Butte during 20172019 was $82.7 million ($78.0 million in 2018; $75.7 million ($73.3 million in 2016; $77.8 million in 20152017). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $8.3 million in 2019 ($9.1 million in 2018; $9.4 million in 2017 ($9.6 million in 2016; $10.1 million in 2015). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)
Minnesota Power has also entered into the following agreementsPPAs for the purchase or sale of capacity and energy as of December 31, 2017:2019:
|
| | | | | |
| Counterparty | Quantity | Product | Commencement | Expiration | Pricing |
| PPAs | | | | | |
| Calpine Corporation | 25 MW | Capacity | June 2019 | May 2026 | Fixed |
| Great River Energy | | | | | |
| PPA 1 | 50 MW | Capacity / Energy | June 2016 | May 2020 | (a) |
| PPA 2 | 50 MW | Capacity | June 2016 | May 2020 | Fixed |
| PPA 3 | 50 MW | Capacity | June 2017 | May 2020 | Fixed |
| Manitoba Hydro | | | | | |
| PPA 1 | (b) | Energy | May 2011 | April 2022 | Forward Market Prices |
| PPA 2 | 50 MW | Capacity / Energy | June 2015 | May 2020 | (c) |
| PPA 3 | 50 MW | Capacity | June 2017 | May 2020 | Fixed |
PPA 4 (d) | 250 MW | Capacity / Energy | June 2020 | May 2035 | (e) |
PPA 5 (d) | 133 MW | Energy | (f) | (f) | Forward Market Prices |
| Minnkota Power | 50 MW | Capacity / Energy | June 2016 | May 2020 | (g) |
Nobles 2 (h) | (h) | Capacity / Energy | (h) | (h) | Fixed |
| Oliver Wind I | (h)(i) | Energy | December 2006 | December 20312040 | Fixed |
| Oliver Wind II | (h)(i) | Energy | December 2007 | December 2032 | Fixed |
Shell Energy | 50 MW | Energy | January 2017 | December 2019 | Fixed |
TransAlta | (i) | Energy | January 2017 | December 2019 | Fixed |
Tenaska (j)
| (j) | Capacity / Energy | June 2020 | June 2040 | Fixed |
PSAs | | | | | |
Basin | | | | | |
PSA 1 | 100 MW | Capacity / Energy | May 2010 | April 2020 | (k) |
PSA 2 | 100 MW | Capacity | June 2016 | May 2018 | Fixed |
PSA 3 | 50 MW | Capacity | June 2017 | May 2019 | Fixed |
Minnkota Power | (l) | Capacity / Energy | June 2014 | December 2026 | (l) |
Silver Bay Power | (m) | Energy | January 2017 | December 2031 | (n) |
| |
| (a) | The capacity price is fixed and the energy price is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index, as well as market prices. |
| |
| (b) | The energy purchased consists primarily of surplus hydro energy on Manitoba Hydro's system and is delivered on a non-firm basis. Minnesota Power will purchase at least one million1000000 MWh of energy over the contract term. |
| |
| (c) | The capacity and energy prices are adjusted annually by the change in a governmental inflationary index. |
| |
| (d) | Agreements are subject to the construction of additional transmission capacity between Manitobathe GNTL and the U.S., along with construction of new hydroelectric generating capacity in Manitoba.MMTP. (See Great Northern Transmission Line.) |
| |
| (e) | The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices. |
| |
| (f) | The contract term shallwill be the 20-year period beginning on the in-service date for the GNTL. (See Great Northern Transmission Line.) |
| |
| (g) | The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term. |
| |
| (h) | The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota for 20 years beginning upon commercial operation of the wind energy facility which is currently expected in fourth quarter of 2020. (See Note 4. Regulatory Matters and Note 5. Equity Investments.) |
| |
| (i) | The PPAs provide for the purchase of all output from the 50 MW Oliver Wind I and 48 MW Oliver Wind II wind energy facilities. |
NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase and Sales Agreements (Continued)
Minnesota Power has also entered into the following PSAs for the sale of capacity and energy as of December 31, 2019:
|
| | | | | |
| Counterparty | Quantity | Product | Commencement | Expiration | Pricing |
| PSAs | | | | | |
| Basin | | | | | |
| PSA 1 | 100 MW | Capacity / Energy | May 2010 | April 2020 | (a) |
| PSA 2 | (b) | Capacity | June 2022 | May 2025 | Fixed |
| PSA 3 | 100 MW | Capacity | June 2025 | May 2028 | Fixed |
| Minnkota Power | (c) | Capacity / Energy | June 2014 | December 2026 | (c) |
| Oconto Electric Cooperative | 25 MW | Capacity / Energy | January 2019 | May 2026 | Fixed |
| Silver Bay Power | (d) | Energy | January 2017 | December 2031 | (e) |
| |
(i) | The energy purchased under the 50 MW PPA is during off-peak hours and the 100 MW PPA is during on-peak hours. |
| |
(j) | The PPA provides for the purchase of all output from a 250 MW wind energy facility to be constructed in southwest Minnesota and is subject to approval of the construction of a 525 MW to 550 MW combined-cycle natural gas-fired facility. (See Note 4. Regulatory Matters.) |
| |
(k)(a) | The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on the cost of fuel. The agreement also allows Minnesota Power to recover a pro rata share of increased costs related to emissions that occur during the last five years of the contract. |
| |
(l)(b) | The agreement provides for 75 MW of capacity from June 1, 2022, through May 31, 2023, and increases to 125 MW of capacity from June 1, 2023, through May 31, 2025. |
| |
| (c) | Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025. Of Minnesota Power’s 50 percent output entitlement, it sold to Minnkota Power approximately 28 percent in 20172019 (28 percent in 20162018 and in 2015)2017). (See Square Butte PPA.) |
| |
(m)(d) | Silver Bay Power supplies approximately 90 MW of load to Northshore Mining, an affiliate of Silver Bay Power, which has been served predominately through self-generation by Silver Bay Power. In the years 2016 through 2019, Minnesota Power is supplyingsupplied Silver Bay Power with at least 50 MW of energy and Silver Bay Power hashad the option to purchase additional energy. On December 31,energy from Minnesota Power as it transitioned away from self-generation. In the third quarter of 2019, Silver Bay Power will ceaseceased self-generation and Minnesota Power will supplybegan supplying the full energy requirements for Silver Bay Power. |
| |
(n)(e) | The energy pricing iswas fixed through 2019 with pricing in later years escalating at a fixed rate annually and adjusted for changes in a natural gas index. |
Coal, Rail and Shipping Contracts. Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2021. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others) and our investment in ATC.
Great Northern Transmission Line. As a condition of thea 250 MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction ofis constructing the GNTL, an approximately 220-mile220‑mile 500-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.
In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Note 4. Regulatory Matters.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL, which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-constructionConstruction activities commenced in the first quarter of 2017, with construction expectedand Minnesota Power expects the GNTL to be completed in 2020. Totalcomplete and in-service by mid-2020. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710approximately $700 million, of which Minnesota Power’s portion is expected to be between $300 million and $350approximately $325 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions in aid of construction.to capital. Total project costs of $152.4$633.3 million have been incurred through December 31, 2017,2019, of which $67.6$339.6 million has been recovered from a subsidiary of Manitoba Hydro.
Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada.
NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)
In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in CanadaMMTP to the Manitoba Conservation and Water Stewardship for regulatory approval.siting and environmental approval, which was received on April 4, 2019. In December 2016, Manitoba Hydro filed an application with the Canadian National Energy Board in Canada(NEB) requesting authorization to construct and operate an internationalthe MMTP, which was recommended for approval on November 15, 2018. On June 14, 2019, Manitoba Hydro announced Canada’s federal government approved the MMTP project and on August 22, 2019, the NEB granted final pre-construction approvals. Construction on the MMTP commenced in the third quarter of 2019.
The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission line. Both provincialin‑service requirements in PPAs with Minnesota Power, Manitoba Hydro had indicated that it would need to start construction of the MMTP by September 2019. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. In the event the MMTP is delayed and federal approvals are pending. not in-service by June 1, 2020, Minnesota Power has construction and related agreements in place with Manitoba Hydro and a Manitoba Hydro subsidiary that will protect Minnesota Power and its customers.
Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be completely in service by early 2021.
Environmental Matters.
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities.authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.
We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.
We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.
Air. The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NOX technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
New Source Review (NSR). In 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in 2011 alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota in 2014. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofitting or retiring certain small coal units, and the addition of 200 MW of wind energy. Provisions of the Consent Decree require that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted through existing emission control technology at Boswell. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as part of its EnergyForward strategic plan. We believe that costs to retire Boswell Units 1 and 2 will be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.
Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls; rather it requirescontrols but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the NOx and SO2 allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR.
Mercury and Air Toxics Standards (MATS) Rule. Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The final MATS rule addressed such emissions from coal-fired utility units greater than 25 MW and established categories of HAPs, including mercury, trace metals other than mercury, and acid gases. The EPA established emission limits for these categories of HAPs and work practice standards for the remaining categories. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan to position the unit for MATS compliance was completed in 2015. Investments and compliance work previously completed at Boswell Unit 3, including emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to operate on natural gas in 2015 positioned those units for MATS compliance.
NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Minnesota Mercury Emissions Reduction Act/Rule. Minnesota Power was required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above (see Mercury and Air Toxics Standards (MATS) Rule) fulfills the requirements of the Minnesota Mercury Emissions Reduction Act.Environmental Matters (Continued)
National Ambient Air Quality Standards (NAAQS). The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.
Ozone NAAQS. All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data; however, some areas in the metropolitan Twin Cities and southwest portionNone of the state are close to exceeding the standard. As a result, voluntary efforts to reduce ground-level ozone continue in the state. No additionalcompliance costs for complianceproposed or current NAAQS revisions are anticipated at this time.
expected to be material.
| |
• | Particulate Matter NAAQS. The EPA has designated the entire state of Minnesota as unclassifiable/attainment; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. In September 2016, environmental groups filed a lawsuit against the EPA in the U.S. District Court for the Northern District of California alleging the EPA had failed to fully implement the PM2.5 standards in certain states, including Minnesota, by not enforcing states’ submittals of required infrastructure implementation plans for the 2012 PM2.5 NAAQS. The outcome of this litigation is uncertain, and as such, any costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.
|
| |
• | NO2 NAAQS. Ambient monitoring data indicates that Minnesota is likely in compliance with the one-hour NAAQS standard for NO2. On July 16, 2017, the EPA proposed retaining the current one-hour and annual NO2 NAAQS. Additional compliance costs for the one-hour NO2 NAAQS are not expected at this time.
|
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
| |
• | SO2 NAAQS. In 2015, the EPA finalized the SO2 data requirements rule (DRR) for the 2010 one-hour NAAQS to assist the states in implementing the standard. The MPCA initially informed Minnesota Power that compliant SO2 modeling completed at Minnesota Power's Boswell and Taconite Harbor facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also require facilities have federally-enforceable permit limits at which the one-hour SO2 NAAQS compliance was modeled by January 13, 2017. Taconite Harbor was issued an amended air permit in September 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 13, 2017, deadline to amend the Boswell permit. The MPCA is in discussions with the EPA on alternate compliance pathways to use existing completed modeling at current limits. On August 21, 2017, the EPA proposed retaining the current primary SO2 one-hour NAAQS. Compliance costs for the one-hour SO2 NAAQS are not expected to be material.
|
Climate Change. The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:
Expanding our renewable power supply;supply for both our operations and the operations of others;
Providing energy conservation initiatives for our customers and engaging in other demand side management efforts;
Improving efficiency of our generating facilities;
Supporting research of technologies to reduce carbon emissions from generating facilities and carbon sequestration efforts; and
Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas‑fired generating facilities.facilities;
Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and
Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species.
EPA Regulation of GHG Emissions. In 2010,On June 19, 2019, the EPA issuedfinalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units.
The EPA repealed the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilitiesClean Power Plan (CPP), following a determination by the EPA that undergo major modifications and other facilities characterized as major sourcesthe CPP exceeded the EPA’s statutory authority under the Clean Air Act’s Title V program. For our existing facilities,Act (CAA). The primary reason for this was that the rule does not require amending our existing Title V operating permitsCPP attempted to include GHG requirements, however, GHG requirements may be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.
In 2014, the U.S. Supreme Court invalidated the aspectregulate electric generating unit’s carbon emissions through measures outside of the Tailoring Rule that established higher permitting thresholds for GHG than for other pollutants subject to PSD; however, the court also upheld the EPA’s ability to require best available control technology (BACT) for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain.affected unit’s direct control. The PSD applies to existing facilities only when they undertake a major modification that increases emissions.
In October 2016, the EPA published a proposed rule in the Federal Register to revise its PSD and Title V regulatory provisions concerning GHG emissions. In this proposed rule, the EPA proposes to amend its regulations to clarify that a source’s obligation to obtain a PSD or Title V permit is triggered only by non-GHG pollutants. If the PSD or Title V permitting requirements are triggered by non-GHG, NSR pollutants, then these programs will also apply to the source’s GHG emissions. The proposed rule,CPP was first announced as currently written, is not expected to have a material impact on the Title V permitting for current operations.
In 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred.
With the repeal of the CPP, the Affordable Clean Energy Rule was finalized. The rule establishes emissions guidelines for states to use when developing plans to limit carbon dioxide at coal-fired power plants. The rule identifies heat rate improvements made at individual units as the Cleanbest system of emission reduction. Affected facilities for Minnesota Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation planinclude Boswell Units 3 and a model rule for emissions trading. In February 2016, the U.S. Supreme Court issued an order staying the effectiveness4 and Taconite Harbor 1 and 2. Based on our initial review of the rule, until aftermany of the appellate court process is complete. In September 2016,candidate heat rate improvements are already installed on Boswell Units 3 and 4.
Additionally, the U.S. Court of AppealsEPA finalized new regulations for the District of Columbia heard oral arguments and is currently deliberating. If the CPP is upheld at the completionstate implementation of the appellate process, all ofAffordable Clean Energy Rule and any future emission guidelines issued under CAA Section 111(d). States will have three years to submit State Implementation Plans (SIP), and the CPP regulatory deadlines are expectedEPA has 12 months to be reset based onreview and approve those plans. Since the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay isAffordable Clean Energy Rule allows states considerable flexibility in force; however,how to best implement its requirements, Minnesota Power plans to work closely with the MPCA has been holdingand the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If a series of meetings on the CPP for educational and planning purposes in the interim. Minnesota Power has been actively involved in these MPCA meetings, andstate does not submit a SIP or submits a SIP that is closely monitoring the appeals process.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
If upheld, the CPP would establish uniform CO2 emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO2 emissions from the power sector. State goals were determined based on CPP source-specific performance emission rates and each state’s mix of power plants. The EPA has filed a motion with the U.S. Court of Appeals for the District of Columbia Circuitunacceptable to hold CPP-related litigation in suspension while the EPA, is reviewing the rule. On October 10, 2017, the EPA issuedwill develop a notice of proposed rulemaking, proposing to repeal the CPP. On December 28, 2017, an Advanced Notice of Proposed Rulemaking (ANPRM) for a CPP replacement rule was published in the Federal Register.Implementation Plan.
Minnesota Power is currently evaluating the CPP rescission and recently proposed ANPRM for a CPP replacement rule as it relates to the State of Minnesota as well as its potential impact on the Company. Minnesota hashad already initiated several measures consistent with those called for under the CPP.now repealed CPP and finalized Affordable Clean Energy Rule. Minnesota Power iscontinues implementing its EnergyForward strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 4. Regulatory Matters.)
We are unable to predict the GHG emission compliance costs we might incur;incur as a result of the Affordable Clean Energy Rule and the resulting SIP; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Water. The Clean Water Act requires National Pollutant Discharge Elimination System (NPDES)NPDES permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.
Clean Water Act - Aquatic Organisms. In 2014, EPA regulations under Section 316(b) of the Clean Water Act setting standards applicable to cooling water intake structures for the protection of aquatic organisms became effective. The regulations require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule will be implemented through NPDES permits issued to covered facilities. No NPDES permits for Minnesota Power facilities have been re-issued containing Section 316(b) requirements since the final rule became effective. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment indicates that Minnesota Power could incur costs of compliance up to $15 million over the next five years. Minnesota Power would seek recovery of additional costs through a rate proceeding.
NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitlimitation guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. On September 13,In 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate. On November 22, 2019, the EPA published a draft rulemaking that proposes to allow re-use of bottom ash transport water in FGD scrubber systems with minor discharges related to maintaining system water balance. The proposed rulemaking would also allow future discharge of FGD wastewater discharge provided it meets new BACT standards. A final rulemaking is anticipated in mid to late 2020.
The final ELG rule’sELG's potential impact on Minnesota Power operations is primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not discharge to surface waters, but may do so in the future.future if additional water treatment measures are implemented. Under the existingcurrent ELG rule, bottom ash transport water discharge to surface waters must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. If FGD wastewater is discharged in the future, it will require additional wastewater treatment. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell for several years to reduce the amount of water discharged and evaluate potential re-usere‑use options in its plant processes. The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce timelines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown.
At this time, we cannot estimate what compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and reuse.re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Solid and Hazardous Waste.The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Coal Ash Management Facilities. Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill, which has been idled and has a temporary landfill cover in place, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.
Coal Combustion Residuals from Electric Utilities (CCR). In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule includes additional requirements for new landfill and impoundment construction, as well asand regulates closure activities for existing impoundments. In 2017, the EPA announced its intention to formally reconsider certain provisions of the CCR rule under Subtitle D of the RCRA and on March 15, 2018, published the first phase of the proposed rule revisions in the Federal Register. In July 2018, the EPA finalized a portion of those proposed revisions that extended certain deadlines by two years, and established alternative groundwater protection standards for certain constituents and the potential for risk‑based management options at facilities based on site characteristics. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule related to certainoperation of clay-lined impoundments. In response to the August 2018 court decision and outstanding issues from litigation, the EPA proposed additional rule revisions in August and December 2019.
The EPA’s most recent proposed rule revisions are anticipated to be finalized in the first quarter of 2020 and could impact the timing of closure activities for Boswell’s existing clay-lined impoundments. Costs of CCR compliance forat Boswell are currently estimated to be between approximately $65 million and Laskin$120 million, and are expected to occur primarily over the next 10 years and be between approximately $65 million and $100 million. The EPA has indicated to Minnesota Power that the15 years. Compliance costs for CCR at Taconite Harbor landfill is aand Laskin are not expected to be material given CCR unit, based on the EPA’s interpretation of the CCR rule language. Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved.units at these facilities are closed. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-relatedCCR‑related waters. On September 13, 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA. Compliance costs, if any, for CCR at Taconite Harbor cannot be estimated at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.
NOTE 9. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Other Environmental Matters
Manufactured Gas Plant Site. We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. In December 2017,June 2019, the WDNR approved the site investigation and authorized SWL&P to transition from site investigation into the remedial design process. As of December 31, 2017,2019, we have recorded a liability of approximately $8$7 million for remediation costs at this site (approximately $7 million as of December 31, 2018), and a correspondingan associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expect to incur these costs over the next four years.
Other Matters
ALLETE Clean Energy. ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 20182020 and 2032.2039. As of December 31, 2017,2019, ALLETE Clean Energy has $15.4$64.3 million outstanding in standby letters of credit.
U.S. Water Services. BNI Energy.As of December 31, 2017, U.S. Water Services has $0.8 million outstanding in standby letters of credit.
BNI Energy. As of December 31, 2017,2019, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6$67.7 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. BNI Energy’s total reclamation liability is currently estimated at $47.5$67.3 million. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.
ALLETE Properties. As of December 31, 2017,2019, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling $8.6$4.8 million primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is $6.1$2.3 million. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Other Matters (Continued)
Community Development District Obligations. In 2005, the Town Center District issued $26.4 million of tax-exempt, 6.0 percent capital improvement revenue bonds, and in 2006, the Palm Coast Park District issued $31.8 million of tax-exempt, 5.7 percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over 31 years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in 2006 for the Town Center District and 2007 for the Palm Coast Park District. To the extent that ALLETE Properties still owns land at the time of the assessment, it will incur the cost of ourits portion of these assessments, based upon its ownership of benefited property.
As of December 31, 2017,2019, we owned 7053 percent of the assessable land in the Town Center District (72(68 percent as of December 31, 2016)2018) and 33 percentNaN of the assessable land in the Palm Coast Park District (92(19 percent as of December 31, 2016)2018). As of December 31, 2017,2019, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are $1.4 million for Town Center at Palm Coast and $2.0 million for Palm Coast Park.Coast. As we sell property at these projects, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.
Legal Proceedings.
We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.
NOTE 12.10. COMMON STOCK AND EARNINGS PER SHARE
|
| | | | | |
| Summary of Common Stock | Shares |
| Equity |
|
| | Thousands |
| Millions |
|
| Balance as of December 31, 2016 | 49,560 |
|
| $1,295.3 |
|
| Employee Stock Purchase Plan | 12 |
| 0.8 |
|
| Invest Direct | 257 |
| 19.0 |
|
| Options and Stock Awards | 22 |
| 3.6 |
|
| Contributions to RSOP | 50 |
| 3.5 |
|
| Equity Issuance Program | 1,000 |
| 65.7 |
|
| Contributions to Pension | 216 |
| 13.5 |
|
| Balance as of December 31, 2017 | 51,117 |
| 1,401.4 |
|
| Employee Stock Purchase Plan | 11 |
| 0.8 |
|
| Invest Direct | 277 |
| 20.7 |
|
| Options and Stock Awards | 57 |
| 2.1 |
|
| Contributions to RSOP | 47 |
| 3.5 |
|
| Balance as of December 31, 2018 | 51,509 |
| 1,428.5 |
|
| Employee Stock Purchase Plan | 8 |
| 0.7 |
|
| Invest Direct | 38 |
| 3.0 |
|
| Options and Stock Awards | 85 |
| 1.3 |
|
| Contributions to RSOP | 39 |
| 3.2 |
|
| Balance as of December 31, 2019 | 51,679 |
|
| $1,436.7 |
|
|
| | | | | |
| Summary of Common Stock | Shares |
| Equity |
|
| | Thousands |
| Millions |
|
| Balance as of December 31, 2014 | 45,929 |
|
| $1,107.6 |
|
| Employee Stock Purchase Plan | 18 |
| 0.9 |
|
| Invest Direct | 383 |
| 19.0 |
|
| Options and Stock Awards | 43 |
| 8.6 |
|
| Equity Issuance Program | 1,289 |
| 69.9 |
|
| Forward Sale Agreement and Issuance | 1,413 |
| 65.4 |
|
| Balance as of December 31, 2015 | 49,075 |
| 1,271.4 |
|
| Employee Stock Purchase Plan | 16 |
| 0.9 |
|
| Invest Direct | 344 |
| 20.0 |
|
| Options and Stock Awards | 65 |
| 3.7 |
|
| Contributions to RSOP | 60 |
| 3.3 |
|
| Equity Issuance Program | 130 |
| 8.0 |
|
| Received for Sale of Land Inventory | (130 | ) | (8.0 | ) |
| Acquisition of Non-Controlling Interest | — |
| (4.0 | ) |
| Balance as of December 31, 2016 | 49,560 |
| 1,295.3 |
|
| Employee Stock Purchase Plan | 12 |
| 0.8 |
|
| Invest Direct | 257 |
| 19.0 |
|
| Options and Stock Awards | 22 |
| 3.6 |
|
| Contributions to RSOP | 50 |
| 3.5 |
|
| Equity Issuance Program | 1,000 |
| 65.7 |
|
| Contributions to Pension | 216 |
| 13.5 |
|
| Balance as of December 31, 2017 | 51,117 |
|
| $1,401.4 |
|
NOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)
Equity Issuance Program. We entered into a distribution agreement with Lampert Capital Markets, Inc., in 2008, as amended most recently in August 2016, with respect to the issuance and sale of up to an aggregate of 13.6 million shares of our common stock, without par value, of which 2.9 million shares remain available for issuance as of December 31, 2017.2019. For the year ended December 31, 2017, 1.0 million2019, 0 shares of common stock were issued under this agreement resulting(NaN in net proceeds of $65.7 million (0.12018; 1.0 million shares for net proceeds of $8.0$65.7 million in 2016; 1.3 million shares for net proceeds of $69.9 million in 2015)2017). The shares issued in 2017 and 2016 were offered and sold pursuant to Registration Statement No. 333-212794,333-212794. On July 31, 2019, we filed Registration Statement No. 333-232905, pursuant to which the remaining shares will continue to be offered for sale, from time to time.
Contributions to Pension. For the year ended December 31, 2019, we contributed 0 shares of ALLETE common stock to our pension plan (NaN in 2018 and 0.2 million shares, which had an aggregate value of $13.5 million in 2017). The shares issuedof ALLETE common stock contributed in 20152017 were offered and soldcontributed in reliance upon an exemption available pursuant to Registration Statement No. 333-190335.Section 4(a)(2) of the Securities Act of 1933, as amended.
Earnings Per Share. We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below). No options to purchase shares of common stock were excluded from the computation of diluted earnings per share in 2017, 2016 and 2015.Plan.
Forward Sale Agreement and Issuance of Common Stock.In 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of 2.8 million shares of ALLETE common stock.
Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed 2.8 million shares of ALLETE common stock from third parties and sold them to the underwriters. The forward sale price was $48.01 per share, subject to adjustment as provided in the Agreement. In 2014, ALLETE physically settled a portion of its obligations under the Agreement by delivering approximately 1.4 million shares of common stock in exchange for cash proceeds of $65.0 million, and in February 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately 1.4 million shares of common stock for cash proceeds of $65.4 million.
Contributions to Pension. For the year ended December 31, 2017, we contributed approximately 0.2 million shares of ALLETE common stock to our pension plan, which had an aggregate value of $13.5 million when contributed (none in 2016 and in 2015). These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.NOTE 10. COMMON STOCK AND EARNINGS PER SHARE (Continued)
|
| | | | | | | | |
| Reconciliation of Basic and Diluted | | | |
| Earnings Per Share | |
| Dilutive |
| |
|
| Year Ended December 31 | Basic |
| Securities |
| Diluted |
|
| Millions Except Per Share Amounts | | | |
| 2019 | | | |
| Net Income Attributable to ALLETE |
| $185.6 |
| |
| $185.6 |
|
| Average Common Shares | 51.6 |
| 0.1 |
| 51.7 |
|
| Earnings Per Share |
| $3.59 |
| |
| $3.59 |
|
| 2018 | | | |
| Net Income Attributable to ALLETE |
| $174.1 |
| |
| $174.1 |
|
| Average Common Shares | 51.3 |
| 0.2 |
| 51.5 |
|
| Earnings Per Share |
| $3.39 |
| |
| $3.38 |
|
| 2017 | | | |
| Net Income Attributable to ALLETE |
| $172.2 |
| |
| $172.2 |
|
| Average Common Shares | 50.8 |
| 0.2 |
| 51.0 |
|
| Earnings Per Share |
| $3.39 |
| |
| $3.38 |
|
|
| | | | | | | | |
| Reconciliation of Basic and Diluted | | | |
| Earnings Per Share | |
| Dilutive |
| |
|
| Year Ended December 31 | Basic |
| Securities |
| Diluted |
|
| Millions Except Per Share Amounts | | | |
| 2017 | | | |
| Net Income Attributable to ALLETE |
| $172.2 |
| |
| $172.2 |
|
| Average Common Shares | 50.8 |
| 0.2 |
| 51.0 |
|
| Earnings Per Share |
| $3.39 |
| |
| $3.38 |
|
| 2016 | | | |
| Net Income Attributable to ALLETE |
| $155.3 |
| |
| $155.3 |
|
| Average Common Shares | 49.3 |
| 0.2 |
| 49.5 |
|
| Earnings Per Share |
| $3.15 |
| |
| $3.14 |
|
| 2015 | | | |
| Net Income Attributable to ALLETE |
| $141.1 |
| |
| $141.1 |
|
| Average Common Shares | 48.3 |
| 0.1 |
| 48.4 |
|
| Earnings Per Share |
| $2.92 |
| |
| $2.92 |
|
NOTE 13.11. INCOME TAX EXPENSE
| | | Income Tax Expense | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
| 2019 |
| 2018 |
| 2017 |
|
| Millions | | |
Current Income Tax Expense (a) | | |
| Federal | — |
| — |
| — |
| — |
| — |
| — |
|
| State | $0.3 | $0.4 | $0.2 | $0.1 | $0.3 |
| Total Current Income Tax Expense |
| $0.3 |
|
| $0.4 |
|
| $0.2 |
|
| $0.1 |
|
| $0.3 |
|
| $0.3 |
|
| Deferred Income Tax Expense | | |
| Federal |
| $12.1 |
|
| $12.0 |
|
| $19.4 |
| |
| Deferred Income Tax Expense (Benefit) | | |
Federal (b) | | $(27.8) | $(26.2) |
| $12.1 |
|
Federal – Remeasurement of Deferred Income Taxes (b)(c) | (13.0 | ) | — |
| — |
| — |
| — |
| (13.0 | ) |
| State | 15.8 |
| 8.1 |
| 6.5 |
| 21.7 |
| 11.0 |
| 15.8 |
|
| Investment Tax Credit Amortization | (0.5 | ) | (0.7 | ) | (0.8 | ) | (0.6 | ) | (0.6 | ) | (0.5 | ) |
| Total Deferred Income Tax Expense |
| $14.4 |
|
| $19.4 |
|
| $25.1 |
| |
| Total Income Tax Expense |
| $14.7 |
|
| $19.8 |
|
| $25.3 |
| |
| Total Deferred Income Tax Expense (Benefit) | | $(6.7) | $(15.8) |
| $14.4 |
|
| Total Income Tax Expense (Benefit) | | $(6.6) | $(15.5) |
| $14.7 |
|
| |
| (a) | For the years ended December 31, 2017, 20162019, 2018 and 2015,2017, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. The federalFederal and state NOLs will beare being carried forward to offset current and future taxable income. |
| |
| (b) | For the years ended December 31, 2019, and 2018, the federal tax benefit is primarily due to production tax credits, and the reduction of the federal statutory tax rate from 35 percent to 21 percent enacted as part of the TCJA. |
| |
| (c) | For the year ended December 31, 2017, the federal deferred income tax benefit is due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. |
NOTE 11. INCOME TAX EXPENSE (Continued).
|
| | | | | | | | | |
| Reconciliation of Taxes from Federal Statutory | | | |
| Rate to Total Income Tax Expense | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Income Before Non-Controlling Interest and Income Taxes |
| $178.9 |
|
| $158.6 |
|
| $186.9 |
|
| Statutory Federal Income Tax Rate | 21 | % | 21 | % | 35 | % |
| Income Taxes Computed at Statutory Federal Rate |
| $37.6 |
|
| $33.3 |
|
| $65.4 |
|
| Increase (Decrease) in Tax Due to: | | | |
| State Income Taxes – Net of Federal Income Tax Benefit | 17.2 |
| 8.9 |
| 10.5 |
|
| Production Tax Credits | (50.7 | ) | (45.0 | ) | (45.1 | ) |
Regulatory Differences – Excess Deferred Tax Benefit (a) | (8.8 | ) | (8.2 | ) | 1.2 |
|
| U.S. Water Services Sale of Stock Basis Difference | 1.7 |
| — |
| — |
|
| Change in Fair Value of Contingent Consideration | — |
| (0.4 | ) | — |
|
Remeasurement of Deferred Income Taxes (b) | — |
| — |
| (13.0 | ) |
| Other | (3.6 | ) | (4.1 | ) | (4.3 | ) |
| Total Income Tax Expense (Benefit) |
| ($6.6 | ) |
| ($15.5 | ) |
| $14.7 |
|
| |
| (a) | Excess deferred income taxes are being returned to customers under both the Average Rate Assumption Method and amortization periods as approved by regulators. (See Note 4. Regulatory Matters.) |
| |
| (b) | Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.) |
|
| | | | | | | | | |
| Reconciliation of Taxes from Federal Statutory | | | |
| Rate to Total Income Tax Expense | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Income Before Non-Controlling Interest and Income Taxes |
| $186.9 |
|
| $175.6 |
|
| $166.8 |
|
| Statutory Federal Income Tax Rate | 35 | % | 35 | % | 35 | % |
| Income Taxes Computed at 35 percent Statutory Federal Rate |
| $65.4 |
|
| $61.5 |
|
| $58.4 |
|
| Increase (Decrease) in Tax Due to: | | | |
| State Income Taxes – Net of Federal Income Tax Benefit | 10.5 |
| 5.6 |
| 4.4 |
|
| Regulatory Differences for Utility Plant | — |
| (0.1 | ) | (0.6 | ) |
| Production Tax Credits | (45.1 | ) | (41.5 | ) | (37.0 | ) |
| Change in Fair Value of Contingent Consideration | — |
| (3.8 | ) | — |
|
Remeasurement of Deferred Income Taxes (a) | (13.0 | ) | — |
| — |
|
| Other | (3.1 | ) | (1.9 | ) | 0.1 |
|
| Total Income Tax Expense |
| $14.7 |
|
| $19.8 |
|
| $25.3 |
|
| |
(a) | Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.) |
The effective tax rate was a benefit of 3.7 percent for 2019 (benefit of 9.8 percent for 2018; expense of 7.9 percent for 2017 (11.32017). The 2019 effective tax rate was primarily impacted by production tax credits and the gain on sale of U.S. Water Services. The 2018 effective tax rate was primarily impacted by production tax credits and the reduction of the federal income tax rate from 35 percent for 2016; 15.2to 21 percent for 2015).enacted as part of the TCJA. The 2017 effective tax rate was primarily impacted by production tax credits and the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.) The 2016 and 2015 effective rates were primarily impacted by production tax credits.
NOTE 13. INCOME TAX EXPENSE (Continued)
|
| | | | | | |
| Deferred Income Tax Assets and Liabilities | | |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Deferred Income Tax Assets | | |
| Employee Benefits and Compensation |
| $49.9 |
|
| $62.2 |
|
| Property-Related | 76.9 |
| 95.2 |
|
| NOL Carryforwards | 63.2 |
| 86.1 |
|
| Tax Credit Carryforwards | 395.5 |
| 349.8 |
|
| Power Sales Agreements | 23.7 |
| 27.5 |
|
| Regulatory Liabilities | 116.9 |
| 113.4 |
|
| Other | 23.4 |
| 25.1 |
|
| Gross Deferred Income Tax Assets | 749.5 |
| 759.3 |
|
| Deferred Income Tax Asset Valuation Allowance | (70.0 | ) | (66.5 | ) |
| Total Deferred Income Tax Assets |
| $679.5 |
|
| $692.8 |
|
| Deferred Income Tax Liabilities | | |
| Property-Related |
| $713.4 |
|
| $752.5 |
|
| Regulatory Asset for Benefit Obligations | 54.5 |
| 61.0 |
|
| Unamortized Investment Tax Credits | 31.6 |
| 32.2 |
|
| Partnership Basis Differences | 49.4 |
| 40.8 |
|
| Regulatory Assets | 35.4 |
| 29.9 |
|
| Other | 8.0 |
| — |
|
| Total Deferred Income Tax Liabilities |
| $892.3 |
|
| $916.4 |
|
Net Deferred Income Taxes (a) |
| $212.8 |
|
| $223.6 |
|
|
| | | | | | |
| Deferred Income Tax Assets and Liabilities | | |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Deferred Income Tax Assets | | |
| Employee Benefits and Compensation |
| $65.9 |
|
| $104.6 |
|
| Property Related | 104.3 |
| 110.5 |
|
| NOL Carryforwards | 99.1 |
| 185.6 |
|
| Tax Credit Carryforwards | 294.3 |
| 227.4 |
|
| Power Sales Agreements | 35.0 |
| 59.3 |
|
| Regulatory Liabilities | 117.7 |
| 7.3 |
|
| Other | 33.3 |
| 46.9 |
|
| Gross Deferred Income Tax Assets | 749.6 |
| 741.6 |
|
| Deferred Income Tax Asset Valuation Allowance | (60.0 | ) | (43.0 | ) |
| Total Deferred Income Tax Assets |
| $689.6 |
|
| $698.6 |
|
| Deferred Income Tax Liabilities | | |
| Property Related |
| $758.3 |
|
| $1,039.6 |
|
| Regulatory Asset for Benefit Obligations | 61.4 |
| 91.9 |
|
| Unamortized Investment Tax Credits | 32.8 |
| 33.3 |
|
| Partnership Basis Differences | 34.9 |
| 50.9 |
|
| Regulatory Assets | 32.0 |
| 25.6 |
|
| Other | 0.7 |
| 11.9 |
|
| Total Deferred Income Tax Liabilities |
| $920.1 |
|
| $1,253.2 |
|
Net Deferred Income Taxes (a) |
| $230.5 |
|
| $554.6 |
|
| |
| (a) | Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet. Additionally, see Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.Sheet |
|
| | | | |
| NOL and Tax Credit Carryforwards | | |
| As of December 31 | 2017 | 2016 |
|
| Millions | | |
Federal NOL Carryforwards (a) | $375.2 |
| $485.3 |
|
| Federal Tax Credit Carryforwards | $209.2 | $163.7 |
State NOL Carryforwards (a) | $289.9 | $294.4 |
State Tax Credit Carryforwards (b) | $25.6 | $21.0 |
NOTE 11. INCOME TAX EXPENSE (Continued).
|
| | | | |
| NOL and Tax Credit Carryforwards | | |
| As of December 31 | 2019 | 2018 |
|
| Millions | | |
Federal NOL Carryforwards (a) | $211.3 |
| $319.0 |
|
| Federal Tax Credit Carryforwards | $302.5 | $256.4 |
State NOL Carryforwards (a) | $274.8 | $305.8 |
State Tax Credit Carryforwards (b) | $23.4 | $27.4 |
| |
| (b) | Net of a $59.5$69.6 million valuation allowance as of December 31, 20172019 ($42.766.0 million as of December 31, 2016)2018). |
The federal NOL and tax credit carryforward periods expire between 20302031 and 2037.2039. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore, no0 federal valuation allowance has been recognized as of December 31, 2017.2019. The state NOL and tax credit carryforward periods expire between 2024 and 2045. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration. We do not expect a material impact on the Company’s ability to utilize its federal and state NOL and tax credit carryforwards due to the TCJA.
NOTE 13. INCOME TAX EXPENSE (Continued)
|
| | | | | | | | | |
| Gross Unrecognized Income Tax Benefits | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Balance at January 1 |
| $1.6 |
|
| $1.7 |
|
| $2.0 |
|
| Additions for Tax Positions Related to the Current Year | 0.1 |
| 0.1 |
| 0.1 |
|
| Additions for Tax Positions Related to Prior Years | 0.1 |
| 0.1 |
| 0.1 |
|
| Reductions for Tax Positions Related to Prior Years | (0.4 | ) | (0.2 | ) | (0.1 | ) |
| Lapse of Statute | — |
| (0.1 | ) | (0.4 | ) |
| Balance as of December 31 |
| $1.4 |
|
| $1.6 |
|
| $1.7 |
|
|
| | | | | | | | | |
| Gross Unrecognized Income Tax Benefits | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Balance at January 1 |
| $2.0 |
|
| $2.4 |
|
| $2.0 |
|
| Additions for Tax Positions Related to the Current Year | 0.1 |
| 0.1 |
| 0.5 |
|
| Additions for Tax Positions Related to Prior Years | 0.1 |
| 0.2 |
| 0.7 |
|
| Reductions for Tax Positions Related to Prior Years | (0.1 | ) | (0.3 | ) | (0.7 | ) |
| Lapse of Statute | (0.4 | ) | (0.4 | ) | (0.1 | ) |
| Balance as of December 31 |
| $1.7 |
|
| $2.0 |
|
| $2.4 |
|
Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The gross unrecognized tax benefits as of December 31, 2017,2019, included $0.8$0.6 million of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.
As of December 31, 2017,2019, we had no0 accrued interest (none(NaN as of December 31, 2016,2018, and 2015)2017) related to unrecognized tax benefits included on the Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income. Interest expense related to unrecognized tax benefits on the Consolidated Statement of Income was immaterial in 2017 (immaterial in 2016,2019, 2018 and in 2015)2017). There were no0 penalties recognized in 2017, 20162019, 2018 or 2015.2017. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.
NoNaN material changes to unrecognized tax benefits are expected during the next 12 months.
ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has no open federal or state audits, and is no longer subject to federal examination for years before 20132016 or state examination for years before 2012.2015.
NOTE 14. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Changes in Accumulated Other Comprehensive Loss.Comprehensive income (loss) is the change in shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale securities, defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits, and gains and losses on derivatives accounted for as cash flow hedges.
NOTE 14. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)
Changes in accumulated other comprehensive loss, net of tax, for the years ended December 31, 2017, 2016 and 2015, were as follows:
|
| | | | | | | | |
| | Unrealized Gain (Loss) on Available-for-sale Securities | Defined Benefit Pension, Other Postretirement Items (a) | Gain (Loss) on Cash Flow Hedge | Total |
| Millions | | | | |
| Balance as of December 31, 2014 | $(0.3) | $(20.7) | $(0.1) | $(21.1) |
| Other Comprehensive Income (Loss) Before Reclassifications | (0.4 | ) | (4.3 | ) | 0.1 |
| (4.6 | ) |
| Amounts Reclassified From Accumulated Other Comprehensive Loss | (0.1 | ) | 1.3 |
| — |
| 1.2 |
|
| Net Other Comprehensive Income (Loss) | (0.5 | ) | (3.0 | ) | 0.1 |
| (3.4 | ) |
| Balance as of December 31, 2015 | (0.8 | ) | (23.7 | ) | — |
| (24.5 | ) |
| Other Comprehensive Income (Loss) Before Reclassifications | — |
| (4.1 | ) | — |
| (4.1 | ) |
| Amounts Reclassified From Accumulated Other Comprehensive Loss | (0.2 | ) | 0.6 |
| — |
| 0.4 |
|
| Net Other Comprehensive Income (Loss) | (0.2 | ) | (3.5 | ) | — |
| (3.7 | ) |
| Balance as of December 31, 2016 | (1.0 | ) | (27.2 | ) | — |
| (28.2 | ) |
| Other Comprehensive Income (Loss) Before Reclassifications | 1.1 |
| 3.9 |
| — |
| 5.0 |
|
| Amounts Reclassified From Accumulated Other Comprehensive Loss | (0.2 | ) | 0.8 |
| — |
| 0.6 |
|
| Net Other Comprehensive Income (Loss) | 0.9 |
| 4.7 |
| — |
| 5.6 |
|
| Balance as of December 31, 2017 | $(0.1) | $(22.5) | — |
| $(22.6) |
| |
(a) | Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 15. Pension and Other Postretirement Benefit Plans.) |
NOTE 15.12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
We have noncontributory union, non-union and combined retiree defined benefit pension plans covering eligible employees. The combined retiree defined benefit pension plan was created in 2016, to include all union and non-union retirees from the existing plans as of January 1, 2016. The plans provide defined benefits based on years of service and final average pay. We contributed $1.7$10.4 million in cash to the plans in 20172019 ($6.315.0 million in 20162018; none$1.7 million in 2015)2017). We also contributed approximately 0.2 million0 shares of ALLETE common stock to the plans in 2017,2019 (NaN in 2018; 0.2 million shares, which had an aggregate value of $13.5 million when contributed (none in 2016; none in 2015)2017). We also have a defined contribution RSOP covering substantially all employees. The 20172019 plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled $11.0$10.8 million ($9.211.4 million for the 20162018 plan year; $9.0$11.0 million for the 20152017 plan year). (See Note 12.10. Common Stock and Earnings Per Share and Note 16.13. Employee Stock and Incentive Plans.)
The non-union defined benefit pension plan was frozen in 2018, and does not allow further crediting of service or earnings to the plan andplan. Further, it is closed to new participants. The Minnesota Power union defined benefit pension plan is also closed to new participants.
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
We have postretirement health care and life insurance plans covering eligible employees. In 2010, ourthe postretirement health care plan was amended to close the planclosed to employees hired after January 31, 2011. The full2011, and the eligibility requirement was also amended in 2010, to require employees to be at least age 55 with 10 years of participation in the plan.requirements were amended. In 2014, ourthe postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015.2015, and in 2018, the postretirement life plan was amended to limit the benefit level for union employees retiring after December 31, 2018. The postretirement health and life plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In 20172019, no0 contributions were made to the VEBAs (none(NaN in 2016; none2018; NaN in 2015)2017) and no0 contributions were made to the grantor trusts (none(NaN in 20162018; noneNaN in 2015)2017).
Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the pension plans. Contributions are based on estimates and assumptions which are subject to change. On January 8, 2018,15, 2020, we contributed $15.0$10.7 million in cash to the defined benefit pension plans. We do not0t expect to make any additional contributions to the defined benefit pension plans in 2018,2020, and we do not0t expect to make any contributions to the defined benefit postretirement health and life plans in 2018.2020.
Accounting for defined benefit pension and other postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.
The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset (regulatory liability) on the Consolidated Balance Sheet, in accordance with the accounting standards for the effect of certain types of regulation applicable to our Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other operations are recognized in accumulated other comprehensive income.
|
| | | | | | |
| Pension Obligation and Funded Status |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Accumulated Benefit Obligation |
| $745.4 |
|
| $698.8 |
|
| Change in Benefit Obligation | |
| |
|
| Obligation, Beginning of Year |
| $743.3 |
|
| $709.8 |
|
| Service Cost | 10.2 |
| 8.1 |
|
| Interest Cost | 32.5 |
| 33.2 |
|
| Actuarial Loss | 44.8 |
| 12.4 |
|
| Benefits Paid | (51.0 | ) | (44.5 | ) |
| Participant Contributions | 13.4 |
| 24.3 |
|
| Obligation, End of Year |
| $793.2 |
|
| $743.3 |
|
| Change in Plan Assets | |
| |
|
| Fair Value, Beginning of Year |
| $557.5 |
|
| $521.3 |
|
| Actual Return on Plan Assets | 91.6 |
| 48.8 |
|
Employer Contribution (a) | 30.1 |
| 31.9 |
|
| Benefits Paid | (51.0 | ) | (44.5 | ) |
| Fair Value, End of Year |
| $628.2 |
|
| $557.5 |
|
| Funded Status, End of Year | $(165.0) | $(185.8) |
| | | |
| Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of: | |
| |
|
| Current Liabilities | $(1.4) | $(1.4) |
| Non-Current Liabilities | $(163.6) | $(184.4) |
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
| | | | | | |
| Pension Obligation and Funded Status |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Accumulated Benefit Obligation |
| $812.0 |
|
| $713.7 |
|
| Change in Benefit Obligation | |
| |
|
| Obligation, Beginning of Year |
| $747.0 |
|
| $793.2 |
|
| Service Cost | 9.3 |
| 11.0 |
|
| Interest Cost | 31.9 |
| 29.6 |
|
| Plan Amendments | — |
| (1.5 | ) |
| Plan Curtailments | — |
| (6.9 | ) |
| Actuarial (Gain) Loss | 98.3 |
| (53.0 | ) |
| Benefits Paid | (53.4 | ) | (49.5 | ) |
| Participant Contributions | 20.9 |
| 24.1 |
|
| Obligation, End of Year |
| $854.0 |
|
| $747.0 |
|
| Change in Plan Assets | |
| |
|
| Fair Value, Beginning of Year |
| $598.0 |
|
| $628.2 |
|
| Actual Return on Plan Assets | 122.1 |
| (21.2 | ) |
Employer Contribution (a) | 32.9 |
| 40.5 |
|
| Benefits Paid | (53.4 | ) | (49.5 | ) |
| Fair Value, End of Year |
| $699.6 |
|
| $598.0 |
|
| Funded Status, End of Year | $(154.4) | $(149.0) |
| | | |
| Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of: | |
| |
|
| Current Liabilities | $(1.6) | $(1.6) |
| Non-Current Liabilities | $(152.8) | $(147.4) |
| |
| (a) | Includes Participant Contributions noted above. |
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
The pension costs that are reported as a component within the Consolidated Balance Sheet, reflected in long-term regulatory assets or liabilities and accumulated other comprehensive income, consist of a net loss of $236.2$243.4 million and prior service credit of $1.3 million as of December 31, 20172019 (net loss of $250.4$230.5 million and prior service credit of $1.4 million as of December 31, 2016)2018).
|
| | | | |
| Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Net Loss | $(243.4) | $(230.5) |
| Prior Service Credit | 1.3 |
| 1.4 |
|
| Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset) | 87.7 |
| 80.1 |
|
| Total Net Pension Amounts Recognized in Consolidated Balance Sheet | $(154.4) | $(149.0) |
|
| | | | |
| Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Net Loss | $(236.2) | $(250.4) |
| Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset) | 71.2 |
| 64.6 |
|
| Total Net Pension Amounts Recognized in Consolidated Balance Sheet | $(165.0) | $(185.8) |
|
| | | | | | | | | |
| Components of Net Periodic Pension Cost |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Service Cost |
| $10.2 |
|
| $8.1 |
|
| $10.1 |
|
| Interest Cost | 32.5 |
| 33.2 |
| 29.9 |
|
| Expected Return on Plan Assets | (42.4 | ) | (43.6 | ) | (40.7 | ) |
| Amortization of Loss | 9.9 |
| 9.5 |
| 17.9 |
|
| Amortization of Prior Service Cost | — |
| — |
| 0.2 |
|
| Net Pension Cost |
| $10.2 |
|
| $7.2 |
|
| $17.4 |
|
|
| | | | | |
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities |
| Year Ended December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Net (Gain) Loss | $(4.3) |
| $7.2 |
|
| Amortization of Loss | (9.9 | ) | (9.5 | ) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities | $(14.2) | $(2.3) |
|
| | | | | | |
| Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Projected Benefit Obligation |
| $793.2 |
|
| $743.3 |
|
| Accumulated Benefit Obligation |
| $745.4 |
|
| $698.8 |
|
| Fair Value of Plan Assets |
| $628.2 |
|
| $557.5 |
|
NOTE 15.12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
| | | | | | | | | |
| Components of Net Periodic Pension Cost |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Service Cost |
| $9.3 |
|
| $11.0 |
|
| $10.2 |
|
Non-Service Cost Components (a) | | | |
| Interest Cost | 31.9 |
| 29.6 |
| 32.5 |
|
| Expected Return on Plan Assets | (44.2 | ) | (44.4 | ) | (42.4 | ) |
| Amortization of Loss | 7.5 |
| 11.4 |
| 9.9 |
|
| Amortization of Prior Service Credit | (0.1 | ) | (0.1 | ) | — |
|
| Net Pension Cost |
| $4.4 |
|
| $7.5 |
|
| $10.2 |
|
| |
| (a) | These components of net periodic pension cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income. |
|
| | | | |
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities |
| Year Ended December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Net Loss | $20.4 | $5.8 |
| Amortization of Prior Service Credit | 0.1 |
| 0.1 |
|
| Prior Service Credit Arising During the Period | — |
| (1.6 | ) |
| Amortization of Loss | (7.5 | ) | (11.4 | ) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities | $13.0 | $(7.1) |
|
| | | | | | |
| Postretirement Health and Life Obligation and Funded Status |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Change in Benefit Obligation | | |
| Obligation, Beginning of Year |
| $173.4 |
|
| $160.2 |
|
| Service Cost | 4.4 |
| 3.9 |
|
| Interest Cost | 7.7 |
| 7.4 |
|
| Actuarial Loss | 15.5 |
| 11.9 |
|
| Benefits Paid | (12.2 | ) | (13.1 | ) |
| Participant Contributions | 3.1 |
| 3.1 |
|
| Plan Amendments | (1.8 | ) | — |
|
| Obligation, End of Year |
| $190.1 |
|
| $173.4 |
|
| Change in Plan Assets | | |
| Fair Value, Beginning of Year |
| $154.3 |
|
| $153.4 |
|
| Actual Return on Plan Assets | 24.5 |
| 9.6 |
|
| Employer Contribution | 1.3 |
| 1.3 |
|
| Participant Contributions | 3.1 |
| 3.1 |
|
| Benefits Paid | (12.2 | ) | (13.1 | ) |
| Fair Value, End of Year |
| $171.0 |
|
| $154.3 |
|
| Funded Status, End of Year | $(19.1) | $(19.1) |
| | | |
| Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of: | | |
| Non-Current Assets | $3.0 | $1.4 |
| Current Liabilities | $(1.1) | $(1.1) |
| Non-Current Liabilities | $(21.0) | $(19.4) |
|
| | | | | | |
| Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Projected Benefit Obligation |
| $854.0 |
|
| $747.0 |
|
| Accumulated Benefit Obligation |
| $812.0 |
|
| $713.7 |
|
| Fair Value of Plan Assets |
| $699.6 |
|
| $598.0 |
|
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
| | | | | | |
| Postretirement Health and Life Obligation and Funded Status |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Change in Benefit Obligation | | |
| Obligation, Beginning of Year |
| $176.0 |
|
| $190.1 |
|
| Service Cost | 3.9 |
| 4.7 |
|
| Interest Cost | 7.3 |
| 7.1 |
|
| Actuarial (Gain) Loss | 10.5 |
| (15.8 | ) |
| Benefits Paid | (14.7 | ) | (11.6 | ) |
| Participant Contributions | 3.5 |
| 3.6 |
|
Plan Amendments (a) | (34.6 | ) | (2.1 | ) |
| Plan Curtailments | (2.1 | ) | — |
|
| Obligation, End of Year |
| $149.8 |
|
| $176.0 |
|
| Change in Plan Assets | | |
| Fair Value, Beginning of Year |
| $154.3 |
|
| $171.0 |
|
| Actual Return on Plan Assets | 29.5 |
| (9.6 | ) |
| Employer Contribution | 1.1 |
| 1.0 |
|
| Participant Contributions | 3.5 |
| 3.6 |
|
| Benefits Paid | (14.7 | ) | (11.7 | ) |
| Fair Value, End of Year |
| $173.7 |
|
| $154.3 |
|
| Funded Status, End of Year | $23.9 | $(21.7) |
| | | |
| Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of: | | |
| Non-Current Assets | $37.5 | $0.4 |
| Current Liabilities | $(0.7) | $(1.0) |
| Non-Current Liabilities | $(12.9) | $(21.1) |
| |
| (a) | Plan design changes under the other postretirement benefit plans resulted in a decrease to the benefit obligation of $34.6 million in 2019. |
According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $19.2$19.1 million in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of December 31, 20172019 ($17.618.3 million as of December 31, 20162018).
The postretirement health and life costs that are reported as a component within the Consolidated Balance Sheet, reflected in regulatory long-term assets or liabilities and accumulated other comprehensive income, consist of the following:
|
| | | | |
| Unrecognized Postretirement Health and Life Costs |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Net Loss | $16.0 | $25.0 |
| Prior Service Credit | (36.3 | ) | (4.6 | ) |
| Total Unrecognized Postretirement Health and Life Cost | $(20.3) | $20.4 |
|
| | | | |
| Unrecognized Postretirement Health and Life Costs |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Net Loss | $21.1 | $19.8 |
| Prior Service Credit | (4.6 | ) | (4.7 | ) |
| Total Unrecognized Postretirement Health and Life Cost | $16.5 | $15.1 |
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
| | Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet | | As of December 31 | 2017 |
| 2016 |
| 2019 |
| 2018 |
|
| Millions | | |
Net Loss (a) | $(21.1) | $(19.8) | $(16.0) | $(25.0) |
| Prior Service Credit | 4.6 |
| 4.7 |
| 36.3 |
| 4.6 |
|
Accumulated Net Periodic Benefit Cost in Excess of Contributions (a) | (2.6 | ) | (4.0 | ) | 3.6 |
| (1.3 | ) |
| Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet | $(19.1) | $23.9 | $(21.7) |
| |
| (a) | Excludes gains, losses and contributions associated with irrevocable grantor trusts. |
|
| | | | | | | | | |
| Components of Net Periodic Postretirement Health and Life Cost |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Service Cost |
| $3.9 |
|
| $4.7 |
|
| $4.4 |
|
Non-Service Cost Components (a) | | | |
| Interest Cost | 7.3 |
| 7.1 |
| 7.7 |
|
| Expected Return on Plan Assets | (10.5 | ) | (10.9 | ) | (10.5 | ) |
| Amortization of Loss | 0.5 |
| 0.8 |
| 0.3 |
|
| Amortization of Prior Service Credit | (2.8 | ) | (2.1 | ) | (2.0 | ) |
| Effect of Plan Curtailment | (2.1 | ) | — |
| — |
|
| Net Postretirement Health and Life Credit | $(3.7) | $(0.4) | $(0.1) |
| |
| (a) | These components of net periodic postretirement health and life cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income. |
|
| | | | | |
Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities |
| Year Ended December 31 | 2019 |
| 2018 |
|
| Millions | |
| |
| Net (Gain) Loss | $(10.6) |
| $4.7 |
|
| Prior Service Credit Arising During the Period | (34.6 | ) | (2.1 | ) |
| Amortization of Prior Service Credit | 2.8 |
| 2.1 |
|
| Amortization of Loss | (0.5 | ) | (0.8 | ) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities | $(42.9) | $3.9 |
|
| | | | | | |
| Estimated Future Benefit Payments | Pension | Postretirement Health and Life |
| Millions | | |
| 2020 |
| $51.2 |
|
| $8.6 |
|
| 2021 |
| $50.7 |
|
| $8.4 |
|
| 2022 |
| $50.1 |
|
| $8.2 |
|
| 2023 |
| $49.8 |
|
| $8.0 |
|
| 2024 |
| $49.6 |
|
| $8.0 |
|
| Years 2025 – 2029 |
| $239.3 |
|
| $40.1 |
|
NOTE 15.12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
| | | | | | | | | |
| Components of Net Periodic Postretirement Health and Life Cost |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Service Cost |
| $4.4 |
|
| $3.9 |
|
| $4.3 |
|
| Interest Cost | 7.7 |
| 7.4 |
| 7.2 |
|
| Expected Return on Plan Assets | (10.5 | ) | (11.2 | ) | (10.9 | ) |
| Amortization of Loss | 0.3 |
| 0.2 |
| 0.4 |
|
| Amortization of Prior Service Credit | (2.0 | ) | (2.9 | ) | (3.0 | ) |
| Net Postretirement Health and Life Credit | $(0.1) | $(2.6) | $(2.0) |
|
| | | | | | |
Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities |
| Year Ended December 31 | 2017 |
| 2016 |
|
| Millions | |
| |
| Net Loss |
| $1.6 |
|
| $13.5 |
|
| Prior Service Credit Arising During the Period | (1.8 | ) | — |
|
| Amortization of Prior Service Credit | 2.0 |
| 2.9 |
|
| Amortization of Loss | (0.3 | ) | (0.2 | ) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities | $1.5 | $16.2 |
|
| | | | | | |
| Estimated Future Benefit Payments | Pension | Postretirement Health and Life |
| Millions | |
| |
| 2018 |
| $46.3 |
|
| $9.2 |
|
| 2019 |
| $46.2 |
|
| $9.5 |
|
| 2020 |
| $45.9 |
|
| $9.6 |
|
| 2021 |
| $45.8 |
|
| $9.6 |
|
| 2022 |
| $45.8 |
|
| $9.6 |
|
| Years 2023 – 2027 |
| $228.0 |
|
| $49.7 |
|
The pension and postretirement health and life costs recorded in regulatory long-term assets or liabilities and accumulated other comprehensive income expected to be recognized as a component of net pension and postretirement benefit costs for the year ending December 31, 2018,2020, are as follows:
|
| | | | |
| | Pension | Postretirement Health and Life |
| Millions | | |
| Net Loss | $12.8 | $1.0 |
| Prior Service Credit | (0.2 | ) | (8.0 | ) |
| Total Pension and Postretirement Health and Life Cost (Credit) | $12.6 | $(7.0) |
|
| | | | |
| | Pension | Postretirement Health and Life |
| Millions | | |
| Net Loss | $12.0 | $0.7 |
| Prior Service Credit | — |
| (1.8 | ) |
| Total Pension and Postretirement Health and Life Cost (Credit) | $12.0 | $(1.1) |
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued) |
| | |
| Assumptions Used to Determine Benefit Obligation |
| As of December 31 | 2017 | 2016 |
| Discount Rate | | |
| Pension | 3.81 - 3.96% | 4.53% |
| Postretirement Health and Life | 3.86% | 4.57% |
| Rate of Compensation Increase | 3.70 - 4.10% | 3.70 - 4.30% |
| Health Care Trend Rates | | |
| Trend Rate | 5.00 - 6.73% | 5.00 - 7.00% |
| Ultimate Trend Rate | 4.50% | 4.50% |
| Year Ultimate Trend Rate Effective | 2038 | 2038 |
|
| | |
| Assumptions Used to Determine Benefit Obligation |
| As of December 31 | 2019 | 2018 |
| Discount Rate | | |
| Pension | 3.34 - 3.47% | 4.39 - 4.53% |
| Postretirement Health and Life | 3.45% | 4.47% |
| Rate of Compensation Increase | 3.70 - 4.10% | 3.70 - 4.10% |
| Health Care Trend Rates | | |
| Trend Rate | 5.00 - 6.20% | 5.00 - 6.46% |
| Ultimate Trend Rate | 4.50% | 4.50% |
| Year Ultimate Trend Rate Effective | 2038 | 2038 |
| | Assumptions Used to Determine Net Periodic Benefit Costs | | Year Ended December 31 | 2017 | 2016 | 2015 | 2019 | 2018 | 2017 |
| Discount Rate | 4.53 - 4.57% | 4.72 - 4.73% | 4.30 - 4.33% | 4.39 - 4.53% | 3.81 - 3.96% | 4.53 - 4.57% |
Expected Long-Term Return on Plan Assets | | |
| Pension | 7.50% | 8.00% | 7.25% | 7.50% |
| Postretirement Health and Life | 6.00 - 7.50% | 6.40 - 8.00% | 5.80 - 7.25% | 6.00 - 7.50% |
| Rate of Compensation Increase | 3.70 - 4.30% | 3.70 - 4.10% | 3.70 - 4.30% |
| |
| (a) | The expected long-term rates of return used to determine net periodic benefit expense for 2020 have been reduced to 6.75 percent for pension expense and 5.40 percent to 6.75 percent for postretirement health and life expense. |
In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.
The discount rate is computed using a bond matching study which utilizes a portfolio of high quality bonds that produce cash flows similar to the projected costs of our pension and other postretirement plans.
The Company utilizes actuarial assumptions about mortality to calculate the pension and postretirement health and life benefit obligations. The mortality assumptions used to calculate our pension and other postretirement benefit obligations as of December 31, 2017,2019, considered a modified RP-2014PRI-2012 mortality table and mortality projection scale.
|
| | | | |
| Sensitivity of a One Percent Change in Health Care Trend Rates |
| | One Percent Increase | One Percent Decrease |
| Millions | | |
| Effect on Total of Postretirement Health and Life Service and Interest Cost |
| $1.8 |
| $(1.4) |
| Effect on Postretirement Health and Life Obligation |
| $16.5 |
| $(13.6) |
|
| | | | | | |
| Sensitivity of a One Percent Change in Health Care Trend Rates |
| | One Percent Increase | One Percent Decrease |
| Millions | | |
| Effect on Total of Postretirement Health and Life Service and Interest Cost |
| $1.9 |
|
| ($1.5 | ) |
| Effect on Postretirement Health and Life Obligation |
| $23.4 |
|
| ($19.3 | ) |
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
| | | Actual Plan Asset Allocations | Pension | Postretirement Health and Life (a) | Pension | Postretirement Health and Life (a) |
| | 2017 | 2016 | 2017 | 2016 | 2019 | 2018 | 2019 | 2018 |
| Equity Securities | 53 | % | 49 | % | 64 | % | 60 | % | 34 | % | 32 | % | 66 | % | 62 | % |
| Debt Securities | 38 | % | 39 | % | 31 | % | 34 | % | |
| Fixed Income Securities | | 62 | % | 60 | % | 33 | % | 34 | % |
| Private Equity | 5 | % | 7 | % | 5 | % | 6 | % | 1 | % | 5 | % | 1 | % | 4 | % |
| Real Estate | 4 | % | 5 | % | — |
| — |
| 3 | % | 3 | % | — |
| — |
|
| | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
| |
| (a) | Includes VEBAs and irrevocable grantor trusts. |
There were no0 shares of ALLETE common stock included in pension plan equity securities as of December 31, 2017 (no2019 (0 shares as of December 31, 2016)2018).
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
The defined benefit pension plans have adopted a dynamic asset allocation strategy (glide path) that increases the invested allocation to fixed income assets as the funding level of the plan increases to better match the sensitivity of the plan’s assets and liabilities to changes in interest rates. This is expected to reduce the volatility of reported pension plan expenses. The postretirement health and life plans’ assets are diversified to achieve strong returns within managed risk. Equity securities are diversified among domestic companies with large, mid and small market capitalizations, as well as investments in international companies. The majority of debt securities are made up of investment grade bonds.
Following are the current targeted allocations as of December 31, 2017:2019:
| | | Plan Asset Target Allocations | Pension | Postretirement Health and Life (a) | Pension | Postretirement Health and Life (a) |
| Equity Securities | 56 | % | 60 | % | 32 | % | 60 | % |
| Debt Securities | 35 | % | 37 | % | |
| Fixed Income Securities | | 56 | % | 37 | % |
| Private Equity | | 6 | % | — |
|
| Real Estate | 9 | % | 3 | % | 6 | % | 3 | % |
| | 100 | % | 100 | % | 100 | % | 100 | % |
| |
| (a) | Includes VEBAs and irrevocable grantor trusts. |
Fair Value
Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:(See Note 7. Fair Value)
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs. This category includes various bonds and non-public funds whose underlying investments may be Level 1 or Level 2 securities.
Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes private equity funds and real estate valued through external appraisal processes. Valuation methodologies incorporate pricing models, discounted cash flow models, and similar techniques which utilize capitalization rates, discount rates, cash flows and other factors.
NOTE 15.12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
Pension Fair Value
| | | | Fair Value as of December 31, 2017 | Fair Value as of December 31, 2019 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total |
| Millions | | |
| Assets: | | |
| Equity Securities: | | |
U.S. Large-cap (a) | — |
|
| $108.6 |
| — |
|
| $108.6 |
| — |
|
| $78.5 |
| — |
|
| $78.5 |
|
U.S. Mid-cap Growth (a) | — |
| 51.9 |
| — |
| 51.9 |
| — |
| 35.9 |
| — |
| 35.9 |
|
U.S. Small-cap (a) | — |
| 51.5 |
| — |
| 51.5 |
| — |
| 34.6 |
| — |
| 34.6 |
|
| International | — |
| 122.3 |
| — |
| 122.3 |
| — |
| 92.1 |
| — |
| 92.1 |
|
| Debt Securities: | |
| |
| |
| |
| |
| Fixed Income | — |
| 222.8 |
| — |
| 222.8 |
| |
Fixed Income Securities (a) | | — |
| 425.4 |
| — |
| 425.4 |
|
| Cash and Cash Equivalents |
| $12.4 |
| — |
| — |
| 12.4 |
|
| $7.1 |
| — |
| — |
| 7.1 |
|
| Private Equity Funds | — |
| — |
|
| $33.2 |
| 33.2 |
| — |
| — |
|
| $8.0 |
| 8.0 |
|
| Real Estate | — |
| — |
| 25.5 |
| 25.5 |
| — |
| — |
| 18.0 |
| 18.0 |
|
| Total Fair Value of Assets |
| $12.4 |
|
| $557.1 |
|
| $58.7 |
|
| $628.2 |
|
| $7.1 |
|
| $666.5 |
|
| $26.0 |
|
| $699.6 |
|
| |
| (a) | The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity securities large‑cap, mid-cap and small-capfixed income securities indexes. |
|
| | | | | | |
| Recurring Fair Value Measures | | |
| Activity in Level 3 | Private Equity Funds | Real Estate |
| Millions | | |
| Balance as of December 31, 2018 |
| $27.8 |
|
| $20.8 |
|
| Actual Return on Plan Assets | 0.4 |
| (1.3 | ) |
| Purchases, Sales, and Settlements – Net | (20.2 | ) | (1.5 | ) |
| Balance as of December 31, 2019 |
| $8.0 |
|
| $18.0 |
|
|
| | | | | | |
| Recurring Fair Value Measures | | |
| Activity in Level 3 | Private Equity Funds | Real Estate |
| Millions | | |
| Balance as of December 31, 2016 |
| $40.6 |
|
| $25.6 |
|
| Actual Return on Plan Assets | 7.1 |
| 1.7 |
|
| Purchases, Sales, and Settlements – Net | (14.5 | ) | (1.8 | ) |
| Balance as of December 31, 2017 |
| $33.2 |
|
| $25.5 |
|
|
| | | | | | | | | | | | |
| | Fair Value as of December 31, 2018 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities: | | | | |
U.S. Large-cap (a) | — |
|
| $59.1 |
| — |
|
| $59.1 |
|
U.S. Mid-cap Growth (a) | — |
| 28.1 |
| — |
| 28.1 |
|
U.S. Small-cap (a) | — |
| 27.2 |
| — |
| 27.2 |
|
| International | — |
| 75.8 |
| — |
| 75.8 |
|
Fixed Income Securities (a) | — |
| 352.9 |
| — |
| 352.9 |
|
| Cash and Cash Equivalents |
| $6.3 |
| — |
| — |
| 6.3 |
|
| Private Equity Funds | — |
| — |
|
| $27.8 |
| 27.8 |
|
| Real Estate | — |
| — |
| 20.8 |
| 20.8 |
|
| Total Fair Value of Assets |
| $6.3 |
|
| $543.1 |
|
| $48.6 |
|
| $598.0 |
|
| |
| (a) | The underlying investments consist of actively-managed funds managed to achieve the returns of certain U.S. equity and fixed income securities indexes. |
NOTE 15.12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
|
| | | | | | | |
| Recurring Fair Value Measures | | | |
| Activity in Level 3 | | Private Equity Funds | Real Estate |
| Millions | | | |
| Balance as of December 31, 2017 | |
| $33.2 |
|
| $25.5 |
|
| Actual Return on Plan Assets | | 2.8 |
| 0.7 |
|
| Purchases, Sales, and Settlements – Net | | (8.2 | ) | (5.4 | ) |
| Balance as of December 31, 2018 | |
| $27.8 |
|
| $20.8 |
|
|
| | | | | | | | | | | | |
| | Fair Value as of December 31, 2016 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities: | | | | |
U.S. Large-cap (a) |
| $94.6 |
| — |
| — |
|
| $94.6 |
|
U.S. Mid-cap Growth (a) | — |
|
| $44.8 |
| — |
| 44.8 |
|
U.S. Small-cap (a) | — |
| 45.0 |
| — |
| 45.0 |
|
| International | 46.7 |
| 42.3 |
| — |
| 89.0 |
|
| Debt Securities: | |
| |
| |
| |
|
| Fixed Income | — |
| 200.1 |
| — |
| 200.1 |
|
| Cash and Cash Equivalents | 17.8 |
| — |
| — |
| 17.8 |
|
| Private Equity Funds | — |
| — |
|
| $40.6 |
| 40.6 |
|
| Real Estate | — |
| — |
| 25.6 |
| 25.6 |
|
| Total Fair Value of Assets |
| $159.1 |
|
| $332.2 |
|
| $66.2 |
|
| $557.5 |
|
| |
(a) | The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1), mutual funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and settle daily, to achieve the returns of the U.S. Equity Securities Mid-cap Growth and Small-cap funds. Our exposure with respect to these investments includes both the futures and the underlying investments.
|
|
| | | | | | | |
| Recurring Fair Value Measures | | | |
| Activity in Level 3 | | Private Equity Funds | Real Estate |
| Millions | | | |
| Balance as of December 31, 2015 | |
| $43.3 |
|
| $28.9 |
|
| Actual Return on Plan Assets | | 5.0 |
| 2.3 |
|
| Purchases, Sales, and Settlements – Net | | (7.7 | ) | (5.6 | ) |
| Balance as of December 31, 2016 | |
| $40.6 |
|
| $25.6 |
|
Postretirement Health and Life Fair Value
|
| | | | | | | | | | | | |
| | Fair Value as of December 31, 2019 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
Equity Securities: (a) | | | | |
| U.S. Large-cap |
| $33.6 |
| — |
| — |
|
| $33.6 |
|
| U.S. Mid-cap Growth | 27.7 |
| — |
| — |
| 27.7 |
|
| U.S. Small-cap | 14.3 |
| — |
| — |
| 14.3 |
|
| International | 37.8 |
| — |
| — |
| 37.8 |
|
| Fixed Income Securities: | |
| |
| |
| |
|
| Mutual Funds | 53.4 |
| — |
| — |
| 53.4 |
|
| Debt Securities | — |
|
| $4.1 |
| — |
| 4.1 |
|
| Cash and Cash Equivalents | 1.1 |
| — |
| — |
| 1.1 |
|
| Private Equity Funds | — |
| — |
|
| $1.7 |
| 1.7 |
|
| Total Fair Value of Assets |
| $167.9 |
|
| $4.1 |
|
| $1.7 |
|
| $173.7 |
|
|
| | | | | | | | | | | | |
| | Fair Value as of December 31, 2017 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
Equity Securities: (a) | | | | |
| U.S. Large-cap |
| $32.1 |
| — |
| — |
|
| $32.1 |
|
| U.S. Mid-cap Growth | 24.3 |
| — |
| — |
| 24.3 |
|
| U.S. Small-cap | 15.5 |
| — |
| — |
| 15.5 |
|
| International | 35.8 |
| — |
| — |
| 35.8 |
|
| Debt Securities: | |
| |
| |
| |
|
| Mutual Funds | 49.8 |
| — |
| — |
| 49.8 |
|
| Fixed Income | — |
|
| $4.5 |
| — |
| 4.5 |
|
| Cash and Cash Equivalents | 0.8 |
| — |
| — |
| 0.8 |
|
| Private Equity Funds | — |
| — |
|
| $8.2 |
| 8.2 |
|
| Total Fair Value of Assets |
| $158.3 |
|
| $4.5 |
|
| $8.2 |
|
| $171.0 |
|
| |
| (a) | The underlying investments consist of mutual funds (Level 1). |
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
|
| | | |
| Recurring Fair Value Measures | |
| Activity in Level 3 | Private Equity Funds |
| Millions | |
Balance as of December 31, 20162018 |
| $9.56.5 |
|
| Actual Return on Plan Assets | 2.60.7 |
|
| Purchases, Sales, and Settlements – Net | (3.95.5 | ) |
Balance as of December 31, 20172019 |
| $8.21.7 |
|
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
|
| | | | | | | | | | | | |
| | Fair Value as of December 31, 2018 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
Equity Securities: (a) | | | | |
| U.S. Large-cap |
| $29.1 |
| — |
| — |
|
| $29.1 |
|
| U.S. Mid-cap Growth | 21.2 |
| — |
| — |
| 21.2 |
|
| U.S. Small-cap | 12.9 |
| — |
| — |
| 12.9 |
|
| International | 30.4 |
| — |
| — |
| 30.4 |
|
| Fixed Income Securities: | |
| |
| |
| |
|
| Mutual Funds | 49.6 |
| — |
| — |
| 49.6 |
|
| Debt Securities | — |
|
| $4.0 |
| — |
| 4.0 |
|
| Cash and Cash Equivalents | 0.6 |
| — |
| — |
| 0.6 |
|
| Private Equity Funds | — |
| — |
|
| $6.5 |
| 6.5 |
|
| Total Fair Value of Assets |
| $143.8 |
|
| $4.0 |
|
| $6.5 |
|
| $154.3 |
|
|
| | | | | | | | | | | | |
| | Fair Value as of December 31, 2016 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
Equity Securities: (a) | | | | |
| U.S. Large-cap |
| $27.9 |
| — |
| — |
|
| $27.9 |
|
| U.S. Mid-cap Growth | 20.7 |
| — |
| — |
| 20.7 |
|
| U.S. Small-cap | 14.0 |
| — |
| — |
| 14.0 |
|
| International | 27.9 |
| — |
| — |
| 27.9 |
|
| Debt Securities: | |
| |
| |
| |
|
| Mutual Funds | 48.6 |
| — |
| — |
| 48.6 |
|
| Fixed Income | — |
|
| $4.6 |
| — |
| 4.6 |
|
| Cash and Cash Equivalents | 1.1 |
| — |
| — |
| 1.1 |
|
| Private Equity Funds | — |
| — |
|
| $9.5 |
| 9.5 |
|
| Total Fair Value of Assets |
| $140.2 |
|
| $4.6 |
|
| $9.5 |
|
| $154.3 |
|
| |
| (a) | The underlying investments consist of mutual funds (Level 1). |
|
| | | |
| Recurring Fair Value Measures | |
| Activity in Level 3 | Private Equity Funds |
| Millions | |
Balance as of December 31, 20152017 |
| $12.08.2 |
|
| Actual Return on Plan Assets | 1.40.9 |
|
| Purchases, Sales, and Settlements – Net | (3.92.6 | ) |
Balance as of December 31, 20162018 |
| $9.56.5 |
|
Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.
NOTE 16.13. EMPLOYEE STOCK AND INCENTIVE PLANS
Employee Stock Ownership Plan. We sponsor an ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire.In 1990, the ESOP issued a $75.0 million note to use as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our common stock. The note matured in December 2015. The ESOP shares were initially pledged as collateral for the debt. As the debt was repaid, shares were released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares were released from collateral, we reported compensation expense equal to the current market price of the shares less dividends on allocated shares. The dividends received by the ESOP are distributed to participants. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings. Future ESOP employer allocations will beare funded with contributions paid in either cash or the issuance of ALLETE common stock at the Company’s discretion. We record compensation expense equal to the cash or current market price of stock contributed. ESOP compensation expense was $11.0$10.8 million in 20172019 ($9.211.4 million in 20162018; $9.011.0 million in 20152017).
According to the accounting standards for stock compensation, unallocated shares of ALLETE common stock held and purchased by the ESOP were treated as unearned ESOP shares and not considered outstanding for earnings per share computations. All ESOP shares are included in earnings per share computations after they arehave been allocated to participants.participants as of December 31, 2019, 2018 and 2017.
|
| | | | | | |
| As of December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| ESOP Shares | | | |
| Allocated | 1.4 |
| 1.6 |
| 1.8 |
|
| Unallocated | — |
| — |
| — |
|
| Total | 1.4 |
| 1.6 |
| 1.8 |
|
| Fair Value of Unallocated Shares | — |
| — |
| — |
|
Stock-Based Compensation.
Stock Incentive Plan. Under our Executive Long-Term Incentive Compensation Plan (Executive Plan), share-based awards may be issued to key employees through a broad range of methods, including non-qualified and incentive stock options, performance shares, performance units, restricted stock, restricted stock units, stock appreciation rights and other awards. There are 1.00.8 million shares of ALLETE common stock reserved for issuance under the Executive Plan, of which 0.80.7 million of these shares remain available for issuance as of December 31, 20172019.
NOTE 13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
Stock-Based Compensation (Continued)
The following types of share-based awards were outstanding in 2017, 20162019, 2018 or 2015:2017:
Non-Qualified Stock Options. These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is eligible for retirement. Stock options have not been granted since 2008 and none were outstanding as of December 31, 2017.
The risk-free interest rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the grant date. Expected volatility is estimated based on the historic volatility of our stock and the stock of our peer group companies. We utilize historical option exercise and employee pre-vesting termination data to estimate the option life. The dividend growth rate is based upon historical growth rates in our dividends.
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
Stock-Based Compensation (Continued)
Performance Shares. Under the performance share awards, plan, the number of shares earned is contingent upon attaining specific market and performance goals over a three-year performance period. Market goals are measured by total shareholder return relative to a group of peer companies.companies while performance goals are measured by earnings per share growth. In the case of qualified retirement, death, or disability during a performance period, a pro rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death, or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined byincorporates the probability of meeting the total shareholder return goals. Compensation cost is recognized over the three-yearthree-year performance period based on our estimate of the number of shares which will be earned by the award recipients.
Restricted Stock Units. Under the restricted stock units plan,unit awards, shares for participants eligible for retirement vest monthly over a three-yearthree-year period. For participants not eligible for retirement, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.
Employee Stock Purchase Plan (ESPP). Under our ESPP, eligible employees may purchase ALLETE common stock at a 5 percent discount from the market price. Because the discount is not greater than 5 percent,price; we are not required to apply fair value accounting to these awards.awards as the discount is not greater than 5 percent.
RSOP. The RSOP is a contributory defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended, and qualifies as an employee stock ownership plan and profit sharing plan. The RSOP provides eligible employees an opportunity to save for retirement.
The following share-based compensation expense amounts were recognized in our Consolidated Statement of Income for the periods presented.
|
| | | | | | | | | |
| Share-Based Compensation Expense |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Performance Shares |
| $2.3 |
|
| $2.3 |
|
| $2.1 |
|
| Restricted Stock Units | 0.8 |
| 0.9 |
| 1.0 |
|
| Total Share-Based Compensation Expense |
| $3.1 |
|
| $3.2 |
|
| $3.1 |
|
| Income Tax Benefit |
| $0.9 |
|
| $0.9 |
|
| $0.9 |
|
|
| | | | | | | | | |
| Share-Based Compensation Expense |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Performance Shares |
| $2.1 |
|
| $1.8 |
|
| $1.8 |
|
| Restricted Stock Units | 1.0 |
| 0.8 |
| 0.8 |
|
| Total Share-Based Compensation Expense |
| $3.1 |
|
| $2.6 |
|
| $2.6 |
|
| Income Tax Benefit |
| $0.9 |
|
| $1.1 |
|
| $1.1 |
|
There were no0 capitalized share-based compensation costs during the years ended December 31, 20172019, 20162018 or 20152017.
As of December 31, 20172019, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statement of Income was $2.4$2.2 million and $1.0$0.9 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.71.6 years.
NOTE 16.13. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
Stock-Based Compensation (Continued)
Non-Qualified Stock Options. The following table presents information regarding our outstanding stock options.
|
| | | | | | | | | | | | | | | |
| | 2017 | 2016 | 2015 |
| | Number of Options | Weighted-Average Exercise Price | Number of Options | Weighted-Average Exercise Price | Number of Options | Weighted-Average Exercise Price |
| Outstanding as of January 1 | 4,357 |
|
| $40.29 |
| 39,654 |
|
| $44.39 |
| 66,279 |
|
| $44.39 |
|
| Exercised | (4,357 | ) |
| $40.29 |
| (35,297 | ) |
| $44.89 |
| (24,456 | ) |
| $44.52 |
|
| Forfeited | — |
| — |
| — |
| — |
| (2,169 | ) |
| $42.93 |
|
| Outstanding as of December 31 | — |
| — |
| 4,357 |
|
| $40.29 |
| 39,654 |
|
| $44.39 |
|
| Exercisable as of December 31 | — |
| — |
| 4,357 |
|
| $40.29 |
| 39,654 |
|
| $44.39 |
|
Cash received from non-qualified stock options exercised was $0.3 million in 2017. The intrinsic value of a stock award is the amount by which the fair value of the underlying stock exceeds the exercise price of the award. The total intrinsic value of options exercised was $0.1 million during 2017 ($0.5 million in 2016; $0.2 million in 2015).
Performance Shares. The following table presents information regarding our non-vested performance shares.
| | | | 2017 | 2016 | 2015 | 2019 | 2018 | 2017 |
| | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value |
| Non-vested as of January 1 | 127,580 |
|
| $52.56 |
| 119,540 |
|
| $52.72 |
| 119,635 |
|
| $48.26 |
| 129,693 |
|
| $66.12 |
| 127,898 |
|
| $58.23 |
| 127,580 |
|
| $52.56 |
|
Granted (a) | 50,729 |
|
| $62.90 |
| 57,189 |
|
| $52.43 |
| 43,583 |
|
| $58.95 |
| 60,747 |
|
| $63.89 |
| 66,557 |
|
| $76.42 |
| 50,729 |
|
| $62.90 |
|
| Awarded | | (75,943 | ) | $53.44 | (58,293 | ) |
| $59.82 |
| — |
| — |
|
| Unearned Grant Award | (40,801 | ) |
| $46.27 |
| (42,126 | ) |
| $52.70 |
| (36,670 | ) |
| $45.41 |
| — |
| — |
| — |
| — |
| (40,801 | ) |
| $46.27 |
|
| Forfeited | (9,610 | ) |
| $58.29 |
| (7,023 | ) |
| $53.45 |
| (7,008 | ) |
| $53.49 |
| (14,912 | ) |
| $77.14 |
| (6,469 | ) |
| $72.99 |
| (9,610 | ) |
| $58.29 |
|
| Non-vested as of December 31 | 127,898 |
|
| $58.23 |
| 127,580 |
|
| $52.56 |
| 119,540 |
|
| $52.72 |
| 99,585 |
|
| $72.78 |
| 129,693 |
|
| $66.12 |
| 127,898 |
|
| $58.23 |
|
(a) Shares granted include accrued dividends.
There were 35,894approximately 22,000 performance shares granted in January 20182020 for the three-year performance period ending in 2020.2022. The ultimate issuance is contingent upon the attainment of certain goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was $2.9$1.8 million. There were 58,293approximately 25,000 performance shares awarded in February 2018.2020. The grant date fair value of the shares awarded was $3.5$1.6 million.
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
Stock-Based Compensation (Continued)
Restricted Stock Units. The following table presents information regarding our available restricted stock units.
| | | | 2017 | 2016 | 2015 | 2019 | 2018 | 2017 |
| | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value | Number of Shares | Weighted- Average Grant Date Fair Value |
| Available as of January 1 | 54,728 |
|
| $51.79 |
| 57,694 |
|
| $49.86 |
| 53,888 |
|
| $44.47 |
| 49,771 |
|
| $60.74 |
| 55,248 |
|
| $56.18 |
| 54,728 |
|
| $51.79 |
|
Granted (a) | 21,241 |
|
| $62.20 |
| 20,351 |
|
| $50.25 |
| 26,702 |
|
| $54.81 |
| 13,927 |
|
| $74.93 |
| 16,573 |
|
| $71.11 |
| 21,241 |
|
| $62.20 |
|
| Awarded | (17,281 | ) |
| $49.72 |
| (19,661 | ) |
| $44.33 |
| (19,464 | ) |
| $41.44 |
| (21,110 | ) |
| $52.44 |
| (18,881 | ) |
| $55.78 |
| (17,281 | ) |
| $49.72 |
|
| Forfeited | (3,440 | ) |
| $56.00 |
| (3,656 | ) |
| $52.87 |
| (3,432 | ) |
| $51.52 |
| (2,645 | ) |
| $72.43 |
| (3,169 | ) |
| $64.92 |
| (3,440 | ) |
| $56.00 |
|
| Available as of December 31 | 55,248 |
|
| $56.18 |
| 54,728 |
|
| $51.79 |
| 57,694 |
|
| $49.86 |
| 39,943 |
|
| $69.30 |
| 49,771 |
|
| $60.74 |
| 55,248 |
|
| $56.18 |
|
(a) Shares granted include accrued dividends.
There were 14,569approximately 14,000 restricted stock units granted in January 20182020 for the vesting period ending in 2020.2022. The grant date fair value of the restricted stock units granted was $1.1 million. There were 12,766approximately 15,000 restricted stock units awarded in February 2018.2020. The grant date fair value of the shares awarded was $0.7$0.9 million.
NOTE 17.14. BUSINESS SEGMENTS
We present three reportable segments: Regulated Operations, ALLETE Clean Energy, and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Regulated Operations includes three3 operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services iswas our integrated water management company. The ALLETE Clean Energy and U.S. Water Services reportable segments comprise our Energy Infrastructure and Related Services businesses.company, which reflects operating results until the date of its sale on March 26, 2019. We also present Corporate and Other which includes two2 operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with our investment in Nobles 2, other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately 5,0004,000 acres of land in Minnesota, and earnings on cash and investments.
NOTE 17.14. BUSINESS SEGMENTS (Continued)
|
| | | | | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Operating Revenue | | | |
| Residential |
| $139.6 |
|
| $139.7 |
|
| $127.4 |
|
| Commercial | 145.7 |
| 147.9 |
| 139.8 |
|
| Municipal | 48.6 |
| 54.9 |
| 57.9 |
|
| Industrial | 476.4 |
| 469.5 |
| 470.5 |
|
| Other Power Suppliers | 153.7 |
| 170.3 |
| 161.8 |
|
| CIP Financial Incentive | 2.8 |
| 3.0 |
| 5.5 |
|
| Other | 75.6 |
| 74.2 |
| 100.9 |
|
| Total Regulated Operations | 1,042.4 |
| 1,059.5 |
| 1,063.8 |
|
| | | | |
| ALLETE Clean Energy | | | |
| Long-term PSA | 48.0 |
| 55.2 |
| 56.9 |
|
| Sale of Wind Energy Facility | — |
| 81.1 |
| — |
|
| Other | 11.6 |
| 23.6 |
| 23.6 |
|
| Total ALLETE Clean Energy | 59.6 |
| 159.9 |
| 80.5 |
|
| | | | |
U.S. Water Services (e) | | | |
| Point-in-time | 19.0 |
| 100.3 |
| 95.8 |
|
| Contract | 9.2 |
| 38.3 |
| 36.2 |
|
| Capital Project | 5.2 |
| 33.5 |
| 19.8 |
|
| Total U.S. Water Services | 33.4 |
| 172.1 |
| 151.8 |
|
| | | | |
| Corporate and Other | | | |
| Long-term Contract | 82.8 |
| 85.5 |
| 89.3 |
|
| Other | 22.3 | 21.6 |
| 33.9 |
|
| Total Corporate and Other | 105.1 | 107.1 | 123.2 |
| Total Operating Revenue |
| $1,240.5 |
|
| $1,498.6 |
|
| $1,419.3 |
|
Net Income (Loss) Attributable to ALLETE (a)(b) | | | |
| Regulated Operations | $154.4 | $131.0 | $128.4 |
| | | | |
ALLETE Clean Energy (c) | 12.4 |
| 33.7 |
| 41.5 |
|
| U.S. Water Services | (1.1 | ) | 3.2 |
| 10.7 |
|
| | | | |
Corporate and Other (d)(e) | 19.9 |
| 6.2 |
| (8.4 | ) |
| Total Net Income Attributable to ALLETE | $185.6 | $174.1 | $172.2 |
|
| | | | | | | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
| Operating Revenue | | | |
| Regulated Operations |
| $1,063.8 |
|
| $1,000.7 |
|
| $991.2 |
|
| | | | |
| Energy Infrastructure and Related Services | | | |
ALLETE Clean Energy (a) | 80.5 |
| 80.5 |
| 262.1 |
|
| U.S. Water Services | 151.8 |
| 137.5 |
| 119.8 |
|
| | | | |
| Corporate and Other | 123.2 |
| 121.0 |
| 113.3 |
|
| Total Operating Revenue |
| $1,419.3 |
|
| $1,339.7 |
|
| $1,486.4 |
|
Net Income (Loss) Attributable to ALLETE (b)(c) | | | |
| Regulated Operations |
| $128.4 |
|
| $135.5 |
|
| $131.6 |
|
| | | | |
| Energy Infrastructure and Related Services | | | |
| ALLETE Clean Energy | 41.5 |
| 13.4 |
| 29.9 |
|
| U.S. Water Services | 10.7 |
| 1.5 |
| 0.9 |
|
| | | | |
| Corporate and Other | (8.4 | ) | 4.9 |
| (21.3 | ) |
| Total Net Income Attributable to ALLETE |
| $172.2 |
|
| $155.3 |
|
| $141.1 |
|
| Depreciation and Amortization | | | |
| Regulated Operations |
| $132.6 |
|
| $154.3 |
|
| $135.1 |
|
| | | | |
| Energy Infrastructure and Related Services | | | |
| ALLETE Clean Energy | 23.4 |
| 22.3 |
| 18.7 |
|
| U.S. Water Services | 9.8 |
| 8.9 |
| 7.3 |
|
| | | | |
| Corporate and Other | 11.7 |
| 10.3 |
| 8.9 |
|
| Total Depreciation and Amortization |
| $177.5 |
|
| $195.8 |
|
| $170.0 |
|
Operating Expenses – Other (d) | | | |
| ALLETE Clean Energy | — |
|
| $3.3 |
| — |
|
| Corporate and Other | $(0.7) | (13.6 | ) | $36.3 |
| Total Operating Expenses – Other | $(0.7) | $(10.3) | $36.3 |
Interest Expense (c) | | | |
| Regulated Operations | $57.0 | $52.1 | $53.9 |
| | | | |
| Energy Infrastructure and Related Services | | | |
| ALLETE Clean Energy | 4.2 |
| 5.8 |
| 3.3 |
|
| U.S. Water Services | 1.6 |
| 1.7 |
| 1.4 |
|
| | | | |
| Corporate and Other | 10.3 |
| 14.5 |
| 8.6 |
|
| | | | |
| Eliminations | (5.3 | ) | (3.8 | ) | (2.3 | ) |
| Total Interest Expense | $67.8 | $70.3 | $64.9 |
| Equity Earnings in ATC | | | |
| Regulated Operations | $22.5 | $18.5 | $16.3 |
| |
(a) | Includes the construction and sale of a wind energy facility by ALLETE Clean Energy to Montana-Dakota Utilities for $197.7 million in 2015. |
| |
| (b) | Net income in 2017 included a favorable impact of $13.0 million after-tax due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, which consisted of a $23.6 million after-tax benefit for ALLETE Clean Energy, a $9.2 million after-tax benefit for U.S. Water Services and a $19.8 million after-tax expense for Corporate and Other. The TCJA did not have an impact on net income for our Regulated Operations as the remeasurement of deferred income tax assets and liabilities primarily resulted in the recording of regulatory assets and liabilities. (See Note 1. Operations and Significant Accounting Policies, and Note 4. Regulatory Matters.) |
| |
(c) | Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. |
| |
| (c) | Net income in 2018 includes the recognition of profit for the sale of a wind energy facility to Montana-Dakota Utilities. |
| |
| (d) | Net income in 2017 included a $7.9 million after-tax favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits. |
(e) On March 26, 2019, ALLETE sold U.S. Water Services. The Company recognized a gain on the sale of $13.2 million after-tax which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.)
NOTE 14. BUSINESS SEGMENTS (Continued)
|
| | | | | | | | | |
| Year Ended December 31 | 2019 |
| 2018 |
| 2017 |
|
| Millions | | | |
| Depreciation and Amortization | | | |
| Regulated Operations |
| $159.4 |
|
| $158.0 |
|
| $132.6 |
|
| | | | |
| ALLETE Clean Energy | 26.8 |
| 24.4 |
| 23.4 |
|
| U.S. Water Services | 2.3 |
| 10.2 |
| 9.8 |
|
| | | | |
| Corporate and Other | 13.5 |
| 13.0 |
| 11.7 |
|
| Total Depreciation and Amortization |
| $202.0 |
|
| $205.6 |
|
| $177.5 |
|
Operating Expenses – Other (a) | | | |
| Corporate and Other | — |
| $(2.0) | $(0.7) |
| Total Operating Expenses – Other | — |
| $(2.0) | $(0.7) |
Interest Expense (b) | | | |
| Regulated Operations |
| $58.9 |
|
| $60.2 |
|
| $57.0 |
|
| | | | |
| ALLETE Clean Energy | 2.8 |
| 3.6 |
| 4.2 |
|
| U.S. Water Services | 0.2 |
| 1.5 |
| 1.6 |
|
| | | | |
| Corporate and Other | 8.0 |
| 7.3 |
| 10.3 |
|
| | | | |
| Eliminations | (5.0 | ) | (4.7 | ) | (5.3 | ) |
| Total Interest Expense |
| $64.9 |
|
| $67.9 |
|
| $67.8 |
|
| Equity Earnings | | | |
| Regulated Operations |
| $21.7 |
|
| $17.5 |
|
| $22.5 |
|
Income Tax Expense (Benefit) (c) | | | |
Regulated Operations (d) | $(7.1) | $(15.5) |
| $27.2 |
|
| | | | |
| ALLETE Clean Energy | (11.9 | ) | (1.0 | ) | (14.2 | ) |
| U.S. Water Services | (0.4 | ) | 1.0 |
| (7.8 | ) |
| | | | |
Corporate and Other (d)(e) | 12.8 |
| — |
| 9.5 |
|
| Total Income Tax Expense (Benefit) | $(6.6) | $(15.5) |
| $14.7 |
|
| |
| (a) | See Note 1. Operations and Significant Accounting Policies. |
NOTE 17. BUSINESS SEGMENTS (Continued)
|
| | | | | | | | | |
| Year Ended December 31 | 2017 |
| 2016 |
| 2015 |
|
| Millions | | | |
Income Tax Expense (Benefit) (a) | | | |
Regulated Operations (b) |
| $27.2 |
|
| $5.9 |
|
| $24.4 |
|
| | | | |
| Energy Infrastructure and Related Services | | | |
| ALLETE Clean Energy | (14.2 | ) | 8.1 |
| 21.0 |
|
| U.S. Water Services | (7.8 | ) | 1.4 |
| 0.9 |
|
| | | | |
Corporate and Other (b) | 9.5 |
| 4.4 |
| (21.0 | ) |
| Total Income Tax Expense |
| $14.7 |
|
| $19.8 |
|
| $25.3 |
|
| |
(a)(b) | Includes interest expense resulting from intercompany loan agreements and allocated to certain subsidiaries. The amounts are eliminated in consolidation. |
| |
| (c) | Income tax expense in 2017 included an income tax benefit of $13.0 million due to the remeasurement of deferred income tax assets and liabilities resulting from the TCJA, which consisted of income tax benefits of $23.6 million for ALLETE Clean Energy and $9.2 million for U.S. Water Services as well as additional income tax expense of $19.8 million for Corporate and Other. The TCJA did not have an impact on income tax expense for our Regulated Operations as the remeasurement of deferred income tax assets and liabilities primarily resulted in the recording of regulatory assets and liabilities. (See Note 1. Operations and Significant Accounting Policies and Note 4. Regulatory Matters.) |
| |
(b)(d) | In 2017, Regulated Operations includes $14.0 million of income tax expense related to North Dakota investment tax credits transferred to Corporate and Other and higher pre-tax income for the favorable impact for the regulatory outcome of the MPUC’s modification of its November 2016 order on the allocation of North Dakota investment tax credits. There was no0 impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax benefit of $7.9 million in 2017. In 2016, Regulated Operations includes $15.0 million of income tax benefit for North Dakota investment tax credits transferred from Corporate and Other and lower pre-tax income related to the adverse impact for the regulatory outcome of the November 2016 MPUC order. There was no impact to net income for Regulated Operations. Corporate and Other recorded an offsetting income tax expense of $8.8 million in 2016. (See Note 4. Regulatory Matters.) |
(e) On March 26, 2019, ALLETE sold U.S. Water Services. The Company recognized income tax expense of $10.4 million for the gain on sale of U.S. Water Services which is reflected in Corporate and Other. (See Note 1. Operations and Significant Accounting Policies.) |
| | | | | | |
| As of December 31 | 2017 |
| 2016 |
|
| Millions | | |
| Assets | | |
Regulated Operations (a) | $3,886.6 | $3,823.9 |
| | | |
| Energy Infrastructure and Related Services | | |
| ALLETE Clean Energy | 600.5 |
| 566.0 |
|
| U.S. Water Services | 292.4 |
| 264.1 |
|
| | | |
| Corporate and Other | 300.5 |
| 222.9 |
|
Total Assets (a) |
| $5,080.0 |
|
| $4,876.9 |
|
| Capital Expenditures | | |
| Regulated Operations | $177.1 | $121.8 |
| | | |
| Energy Infrastructure and Related Services | | |
| ALLETE Clean Energy | 56.1 |
| 106.9 |
|
| U.S. Water Services | 4.4 |
| 3.7 |
|
| | | |
| Corporate and Other | 28.9 |
| 15.4 |
|
| Total Capital Expenditures |
| $266.5 |
|
| $247.8 |
|
| |
(a) | See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet. |
NOTE 18.14. BUSINESS SEGMENTS (Continued)
|
| | | | | | |
| As of December 31 | 2019 |
| 2018 |
|
| Millions | | |
| Assets | | |
| Regulated Operations | $4,130.8 | $3,952.5 |
| | | |
| ALLETE Clean Energy | 1,001.5 |
| 606.6 |
|
U.S. Water Services (a) | — |
| 295.8 |
|
| | | |
| Corporate and Other | 350.5 |
| 310.1 |
|
| Total Assets |
| $5,482.8 |
|
| $5,165.0 |
|
| Capital Expenditures | | |
| Regulated Operations | $230.9 | $211.9 |
| | | |
| ALLETE Clean Energy | 385.6 |
| 89.7 |
|
U.S. Water Services (a) | — |
| 5.0 |
|
| | | |
| Corporate and Other | 10.1 |
| 12.0 |
|
| Total Capital Expenditures |
| $626.6 |
|
| $318.6 |
|
(a)On March 26, 2019, ALLETE sold U.S. Water Services. (See Note 1. Operations and Significant Accounting Policies.)
NOTE 15. QUARTERLY FINANCIAL DATA (UNAUDITED)
Information for any one quarterly period is not necessarily indicative of the results which may be expected for the year.
|
| | | | | | | | | | | | |
| Quarter Ended | Mar. 31 |
| Jun. 30 |
| Sept. 30 |
| Dec. 31 |
|
| Millions Except Earnings Per Share | | | | |
| 2019 | | | | |
| Operating Revenue |
| $357.2 |
|
| $290.4 |
|
| $288.3 |
|
| $304.6 |
|
| Operating Income |
| $56.8 |
|
| $36.2 |
|
| $37.0 |
|
| $49.8 |
|
| Net Income Attributable to ALLETE |
| $70.5 |
|
| $34.2 |
|
| $31.2 |
|
| $49.7 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $1.37 |
|
| $0.66 |
|
| $0.60 |
|
| $0.96 |
|
| Diluted |
| $1.37 |
|
| $0.66 |
|
| $0.60 |
|
| $0.96 |
|
| 2018 | | | | |
| Operating Revenue |
| $358.2 |
|
| $344.1 |
|
| $348.0 |
|
| $448.3 |
|
| Operating Income |
| $57.4 |
|
| $36.5 |
|
| $43.3 |
|
| $64.0 |
|
| Net Income Attributable to ALLETE |
| $51.0 |
|
| $31.3 |
|
| $30.7 |
|
| $61.1 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $1.00 |
|
| $0.61 |
|
| $0.59 |
|
| $1.19 |
|
| Diluted |
| $0.99 |
|
| $0.61 |
|
| $0.59 |
|
| $1.18 |
|
| 2017 | | | | |
| Operating Revenue |
| $365.6 |
|
| $353.3 |
|
| $362.5 |
|
| $337.9 |
|
| Operating Income |
| $71.6 |
|
| $54.0 |
|
| $68.0 |
|
| $32.3 |
|
| Net Income Attributable to ALLETE |
| $49.0 |
|
| $36.9 |
|
| $44.9 |
|
| $41.4 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $0.97 |
|
| $0.73 |
|
| $0.88 |
|
| $0.81 |
|
| Diluted |
| $0.97 |
|
| $0.72 |
|
| $0.88 |
|
| $0.81 |
|
|
| | | | | | | | | | | | |
| Quarter Ended | Mar. 31 |
| Jun. 30 |
| Sept. 30 |
| Dec. 31 |
|
| Millions Except Earnings Per Share | | | | |
| 2017 | | | | |
| Operating Revenue |
| $365.6 |
|
| $353.3 |
|
| $362.5 |
|
| $337.9 |
|
| Operating Income |
| $72.6 |
|
| $55.0 |
|
| $69.0 |
|
| $33.2 |
|
| Net Income Attributable to ALLETE |
| $49.0 |
|
| $36.9 |
|
| $44.9 |
|
| $41.4 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $0.97 |
|
| $0.73 |
|
| $0.88 |
|
| $0.81 |
|
| Diluted |
| $0.97 |
|
| $0.72 |
|
| $0.88 |
|
| $0.81 |
|
| 2016 | | | | |
| Operating Revenue |
| $333.8 |
|
| $314.8 |
|
| $349.6 |
|
| $341.5 |
|
| Operating Income |
| $66.8 |
|
| $42.2 |
|
| $53.4 |
|
| $61.1 |
|
| Net Income Attributable to ALLETE |
| $45.9 |
|
| $24.8 |
|
| $40.3 |
|
| $44.3 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $0.93 |
|
| $0.50 |
|
| $0.82 |
|
| $0.89 |
|
| Diluted |
| $0.93 |
|
| $0.50 |
|
| $0.81 |
|
| $0.89 |
|
| 2015 | | | | |
| Operating Revenue |
| $320.0 |
|
| $323.3 |
|
| $462.5 |
|
| $380.6 |
|
| Operating Income |
| $56.4 |
|
| $39.5 |
|
| $85.2 |
|
| $29.6 |
|
| Net Income Attributable to ALLETE |
| $39.9 |
|
| $22.5 |
|
| $60.4 |
|
| $18.3 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $0.85 |
|
| $0.46 |
|
| $1.24 |
|
| $0.37 |
|
| Diluted |
| $0.85 |
|
| $0.46 |
|
| $1.23 |
|
| $0.37 |
|
Schedule II
ALLETE
Valuation and Qualifying Accounts and Reserves
| | | | Balance at Beginning of Period | Additions | Deductions from Reserves (a) | Balance at End of Period | Balance at Beginning of Period | Additions | Deductions from Reserves (a) | Balance at End of Period |
| | Charged to Income | Other Charges | Charged to Income | Other Charges |
| Millions | | | | | | |
| Reserve Deducted from Related Assets | | | | | | |
| Reserve For Uncollectible Accounts | | | | | | |
| 2015 Trade Accounts Receivable |
| $1.1 |
|
| $1.6 |
| — |
|
| $1.7 |
|
| $1.0 |
| |
| Finance Receivables – Long-Term |
| $0.6 |
| — |
| — |
| — |
|
| $0.6 |
| |
| 2016 Trade Accounts Receivable |
| $1.0 |
|
| $4.1 |
| — |
|
| $2.0 |
|
| $3.1 |
| |
| Finance Receivables – Long-Term |
| $0.6 |
| — |
| — |
|
| $0.6 |
| — |
| |
| 2017 Trade Accounts Receivable |
| $3.1 |
| $0.8 | — |
|
| $1.8 |
|
| $2.1 |
|
| $3.1 |
|
| $0.8 |
| — |
|
| $1.8 |
|
| $2.1 |
|
| Finance Receivables – Long-Term | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| 2018 Trade Accounts Receivable | |
| $2.1 |
|
| $0.9 |
| — |
|
| $1.3 |
|
| $1.7 |
|
| Finance Receivables – Long-Term | | — |
| — |
| — |
| — |
| — |
|
| 2019 Trade Accounts Receivable | |
| $1.7 |
| $(0.1) | — |
|
| $0.7 |
|
| $0.9 |
|
| Finance Receivables – Long-Term | | — |
| — |
| — |
| — |
| — |
|
| Deferred Asset Valuation Allowance | | | | | | |
| 2015 Deferred Tax Assets |
| $22.1 |
| $9.5 | — |
| — |
|
| $31.6 |
| |
| 2016 Deferred Tax Assets |
| $31.6 |
| $11.4 | — |
| — |
|
| $43.0 |
| |
| 2017 Deferred Tax Assets |
| $43.0 |
|
| $17.0 |
| — |
| — |
|
| $60.0 |
|
| $43.0 |
| $17.0 | — |
| — |
|
| $60.0 |
|
| 2018 Deferred Tax Assets | |
| $60.0 |
| $6.5 | — |
| — |
|
| $66.5 |
|
| 2019 Deferred Tax Assets | |
| $66.5 |
|
| $3.5 |
| — |
| — |
|
| $70.0 |
|
| |
| (a) | Includes uncollectible accounts written-off. |
ALLETE, Inc. 20172019 Form 10-K
142122
