| | For the fiscal year ended December 31, 2011 | | | | | £ | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 | |
| | For the transition period from ______________ to ______________ |
Commission File No. 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, Minnesota 55802-2093
(Address(Address of principal executive offices, including zip code)
(218) 279-5000
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
|
| | |
| Title of Each Class | | Name of Each Stock Exchange on Which Registered |
| Common Stock, without par value | | 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.
Yes RT 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 £¨ No RT
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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). Yes RT 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. £T
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act).
Large Accelerated Filer RLarge Accelerated Filer T Accelerated Filer ¨Non-Accelerated Filer ¨Smaller Reporting Company ¨
| Accelerated Filer £
| Non-Accelerated Filer £
| Smaller Reporting Company £
|
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes £¨ No RT
The aggregate market value of voting stock held by nonaffiliates on June 30, 2009,2011, was $974,440,368.$1,488,071,330.
As of February 1, 2010,2012, there were 35,243,90537,537,154 shares of ALLETE Common Stock, without par value, outstanding.
Documents Incorporated By Reference
Portions of the Proxy Statement for the 20102012 Annual Meeting of Shareholders are incorporated by reference in Part III.
Index
Definitions |
| 3 | | |
| |
| | |
Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995 | 5 |
| | |
| Part I | |
| Item 1. | | 6 |
| | | 6 |
| | | | 6 |
| | | | 9 |
| | | | 11 |
| | | | 11 |
| | | | 11 |
| | | | 12 |
| | | | 15 |
| | | | 15 |
| | | | 15 |
| | | | 16 |
| | | 16 |
| | | | 16 |
| | | | 16 |
| | | Non-Rate Base Generation | 17 |
| | | Other. | 17 |
| | Environmental Matters | 17 | |
| | Employees | 21 |
| | Availability of Information | 21 |
| | | |
| | 22 |
| Item 1A. | | 23 |
| Item 1B. | | 26 |
| Item 2. | | 26 |
| Item 3. | | 26 |
| Item 4. | Submission of Matters to a Vote of Security Holders | 26 |
| Part II | |
Item 5. | and
Issuer Purchases of Equity Securities | |
| Item 6. | | 28 |
| Item 7. | | 29 |
| | | 29 |
| | 2009 | 30 |
| | 2008 | 32 |
| | | 34 |
| | | 35 |
| | | 42 |
| | | 46 |
| | | 46 |
| | | 46 |
| | New | 48 |
| Item 7A. | | 48 |
| Item 8. | | 48 |
| Item 9. | | 48 |
| Item 9A. | | 48 |
| Item 9B. | | 49 |
Index
|
| | | |
| Part III | |
| Item 10. | | 50 |
| Item 11. | | 50 |
| Item 12. | | 50 |
| Item 13. | | 50 |
| Item 14. | | 50 |
| Part IV | | |
| Item 15. | | 51 |
| | |
| 55 |
| | |
| 58 |
ALLETE 20092011 Form 10-K
3
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 |
AICPAAC | American Institute of Certified Public Accountants |
ALLETE | ALLETE, Inc. |
ALLETE Properties | ALLETE Properties, LLC and its subsidiariesAlternating Current |
| AFUDC | Allowance for Funds Used During Construction - the cost of both debt and equity funds used to finance utility plant additions during construction periods |
AREAALLETE | Arrowhead Regional Emission AbatementALLETE, Inc. |
| ALLETE Clean Energy | ALLETE Clean Energy, Inc. |
| ALLETE Properties | ALLETE Properties, LLC and its subsidiaries |
| ARS | Auction Rate Securities |
| ATC | American Transmission Company LLC |
| Basin | Basin Electric Power Cooperative |
Bison I1 | Bison I1 Wind Project |
| Bison 2 | Bison 2 Wind Project |
| Bison 3 | Bison 3 Wind Project |
| BNI Coal | BNI Coal, Ltd. |
BNSF | Burlington Northern Santa Fe Railway Company |
| Boswell | Boswell Energy Center |
Boswell NOX Reduction Plan
CAIR | NOX emission reductions from Boswell Units 1, 2, and 4
Clean Air Interstate Rule |
CO2 | Carbon Dioxide |
| Company | ALLETE, Inc. and its subsidiaries |
| CSAPR | Cross-State Air Pollution Rule |
| DC | Direct Current |
DRI | Development of Regional Impact |
EITF | Emerging Issues Task Force |
| EPA | Environmental Protection Agency |
| 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 |
FTR | Financial Transmission Rights |
| GAAP | Accounting Principles Generally Accepted in the United States |
| GHG | Greenhouse Gases |
Heating Degree DaysHibbard | Measure of the extent to which the average daily temperature is below 65 degrees Fahrenheit, increasing demand for heatingHibbard Renewable Energy Center |
| IBEW Local 31 | International Brotherhood of Electrical Workers Local 31 |
| IBEW Local 1593 | International Brotherhood of Electrical Workers Local 1593 |
| Invest Direct | ALLETE’s Direct Stock Purchase and Dividend Reinvestment Plan |
| Item___ | Item___of this Form 10-K |
| kV | Kilovolt(s) |
| Laskin | Laskin Energy Center |
| LIBOR | London Inter Bank Offered Rate |
| MACT | Maximum Achievable Control Technology |
| Magnetation | Magnetation, Inc. |
| Manitoba Hydro | Manitoba Hydro-Electric Board |
| MATS | Mercury and Air Toxics Standards |
| MBtu | Million British thermal units |
| Medicare Part D | Medicare Part D provision of the Patient Protection and Affordable Care Act of 2010 |
Definitions (continued)
|
| |
| Mesabi Nugget | Mesabi Nugget Delaware, LLC |
| Minnesota Power | An operating division of ALLETE, Inc. |
| Minnkota Power | Minnkota Power Cooperative, Inc. |
| MISO | Midwest Independent Transmission System Operator, Inc. |
| Moody’s | Moody’s Investors Service, Inc. |
| MPCA | Minnesota Pollution Control Agency |
Definitions (Continued)
| MPUC | Minnesota Public Utilities Commission |
| MW / MWh | Megawatt(s) / Megawatt-hour(s) |
NextEra EnergyNAAQS | NextEra Energy Resources, LLCNational Ambient Air Quality Standards |
| NDPSC | North Dakota Public Service Commission |
| NOL | Net Operating Loss |
| Non-residential | Retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional |
NO2 | Nitrogen Dioxide |
NOX | Nitrogen Oxides |
| Note ___ | Note ___ to the consolidated financial statements in this Form 10-K |
| NPDES | National Pollutant Discharge Elimination System |
| NYSE | New York Stock Exchange |
OES | Minnesota Office of Energy Security |
| Oliver Wind I | Oliver Wind I Energy Center |
| Oliver Wind II | Oliver Wind II Energy Center |
| Palm Coast Park | Palm Coast Park development project in Florida |
| Palm Coast Park District | Palm Coast Park Community Development District |
PolyMet Mining | PolyMet Mining Corp.Corporation |
| PPA | Power Purchase Agreement |
| PPACA | The Patient Protection and Affordable Care Act of 2010 |
| PSCW | Public Service Commission of Wisconsin |
PUHCA 2005 | Public Utility Holding Company Act of 2005 |
| Rainy River Energy | Rainy River Energy Corporation - Wisconsin |
| RSOP | Retirement Savings and Stock Ownership Plan |
| SEC | Securities and Exchange Commission |
SO2 | Sulfur Dioxide |
| Square Butte | Square Butte Electric Cooperative |
| Standard & Poor’s | Standard & Poor’s Ratings Services a division of The McGraw-Hill Companies, Inc. |
| SWL&P | Superior Water, Light and Power Company |
| Taconite Harbor | Taconite Harbor Energy Center |
| Taconite Ridge | Taconite Ridge Energy Center |
| Town Center | Town Center at Palm Coast development project in Florida |
| Town Center District | Town Center at Palm Coast Community Development District |
| U.S. | United States of America |
| USS Corporation | United States Steel Corporation |
| WDNR | Wisconsin Department of Natural Resources |
ALLETE 20092011 Form 10-K
5
Safe Harbor Statement
Under the Private Securities Litigation Reform Act of 1995Forward-Looking Statements
Statements in this report that are not statements of historical facts may beare 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 is 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,” “plans,” “projects,” “will likely result,“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 hereby filingproviding this cautionary statements identifyingstatement to identify important factors that could cause our actual results to differ materially from those projected, or expectations suggested,indicated in forward-looking statements made by or on behalf of ALLETE in this Annual Report on 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; |
· | prevailing governmental policies, regulatory actions, and legislation including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, and various local and county regulators, and city administrators, about allowed rates of return, financings, industry and rate structure, acquisition and disposal of assets and facilities, real estate development, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, present or prospective wholesale and retail competition (including but not limited to transmission costs), zoning and permitting of land held for resale and environmental matters; |
· | our ability to manage expansion and integrate acquisitions; |
· | the potential impacts of climate change and future regulation to restrict the emissions of GHG on our Regulated Operations;
|
· | effects of restructuring initiatives in the electric industry; |
· | economic and geographic factors, including political and economic risks; |
· | changes in and compliance with laws and regulations; |
· | weather conditions; |
· | natural disasters and pandemic diseases; |
· | war and acts of terrorism; |
· | wholesale power market conditions; |
· | population growth rates and demographic patterns; |
· | effects of competition, including competition for retail and wholesale customers; |
· | changes in the real estate market; |
· | pricing and transportation of commodities; |
· | changes in tax rates or policies or in rates of inflation; |
· | project delays or changes in project costs; |
· | availability and management of construction materials and skilled construction labor for capital projects;
|
· | changes in operating expenses, capital and land development expenditures;
|
· | global and domestic economic conditions affecting us or our customers; |
· | our ability to access capital markets and bank financing; |
· | changes in interest rates and the performance of the financial markets; |
· | our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and |
· | the outcome of legal and administrative proceedings (whether civil or criminal) and settlements that affect the business and profitability of ALLETE. |
our ability to successfully implement our strategic objectives;regulatory or legislative actions, including changes in governmental policies of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC, the EPA and various state, local and county regulators, and city administrators, about allowed rates of return, capital structure, financings, industry and rate structure, acquisition and disposal of assets and facilities, real estate development, operation and construction of plant facilities, recovery of purchased power, capital investments and other expenses, present or prospective wholesale and retail competition (including but not limited to transmission costs), zoning and permitting of land held for resale and environmental matters;
our ability to manage expansion and integrate acquisitions;
the potential impacts of climate change and future regulation to restrict the emissions of GHG on our Regulated Operations;
effects of restructuring initiatives in the electric industry;
economic and geographic factors, including political and economic risks;
changes in and compliance with laws and regulations;
weather conditions, natural disasters and pandemic diseases;
war, acts of terrorism and cyber attacks;
wholesale power market conditions;
population growth rates and demographic patterns;
effects of competition, including competition for retail and wholesale customers;
changes in the real estate market;
pricing and transportation of commodities;
changes in tax rates or policies or in rates of inflation;
project delays or changes in project costs;
availability and managementof construction materials and skilled construction labor for capital projects;
changes in operating expenses and capital expenditures;
global and domestic economic conditions affecting us or our customers;
our ability to access capital markets and bank financing;
changes in interest rates and the performance of the financial markets;
our ability to replace a mature workforce and retain qualified, skilled and experienced personnel; and
the outcome of legal and administrative proceedings (whether civil or criminal) and settlements.
Additional disclosures regarding factors that could cause our results and performance to differ from results or performance anticipated by this report are discussed in Item 1A under the heading “Risk Factors” beginning on page 2326 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 us in this Form 10-K and in our other reports filed with the SEC that attempt to advise interested parties of the factors that may affect our business.
ALLETE 20092011 Form 10-K
6
Part I
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 parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000 retail customers. Minnesota Power's non-affiliated municipal customers and wholesale electric service toconsist of 16 municipalities.municipalities in Minnesota Power also provides regulated utility electric service toand 1 private utility in Wisconsin. SWL&P, a wholesalewholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power,Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 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 Item 1. Business – Regulated Operations – Regulatory Matters.)
Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, formed in June 2011, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes a small amount of non-rate base generation, approximately 7,0005,500 acres of land available-for-sale 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, 2009,2011, unless otherwise indicated. All subsidiaries of ALLETE 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 | 2009 | 2008 | 2007 |
| | | | |
| Consolidated Operating Revenue – Millions | $759.1 | $801.0 | $841.7 |
| | | | |
| Percentage of Consolidated Operating Revenue | | | |
| Regulated Operations | 90% | 89% | 86% |
| Investments and Other | 10% | 11% | 14% |
| | 100% | 100% | 100% |
|
| | | | | | | | | |
| Year Ended December 31 | 2011 |
| 2010 |
| 2009 |
|
| | | | |
| Consolidated Operating Revenue – Millions |
| $928.2 |
|
| $907.0 |
|
| $759.1 |
|
| | | | |
| Percentage of Consolidated Operating Revenue | | | |
| Regulated Operations | 92 | % | 92 | % | 90 | % |
| Investments and Other | 8 | % | 8 | % | 10 | % |
| | 100 | % | 100 | % | 100 | % |
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 2. Business Segments.
REGULATED OPERATIONSRegulated Operations
Electric Sales / Customers
| Regulated Utility Electric Sales |
| Year Ended December 31 | 2009 | % | 2008 | % | 2007 | % |
| Millions of Kilowatt-hours | | | | | | |
| Retail and Municipals | | | | | | |
| Residential | 1,164 | 10 | 1,172 | 9 | 1,141 | 9 |
| Commercial | 1,420 | 12 | 1,454 | 12 | 1,456 | 11 |
| Industrial | 4,475 | 37 | 7,192 | 57 | 7,054 | 55 |
| Municipals (FERC rate regulated) | 992 | 8 | 1,002 | 8 | 1,009 | 8 |
| Total Retail and Municipals | 8,051 | 67 | 10,820 | 86 | 10,660 | 83 |
| Other Power Suppliers | 4,056 | 33 | 1,800 | 14 | 2,157 | 17 |
| Total Regulated Utility Electric Sales | 12,107 | 100 | 12,620 | 100 | 12,817 | 100 |
|
| | | | | | | | | |
| Regulated Utility Electric Sales | | | | | | |
| Year Ended December 31 | 2011 |
| % | 2010 |
| % | 2009 |
| % |
| Millions of Kilowatt-hours | | | | | | |
| Retail and Municipals | | | | | | |
| Residential | 1,159 |
| 9 | 1,150 |
| 9 | 1,164 |
| 10 |
| Commercial | 1,433 |
| 11 | 1,433 |
| 11 | 1,420 |
| 12 |
| Industrial | 7,365 |
| 56 | 6,804 |
| 52 | 4,475 |
| 37 |
| Municipals (FERC rate regulated) | 1,013 |
| 7 | 1,006 |
| 7 | 992 |
| 8 |
| Total Retail and Municipals | 10,970 |
| 83 | 10,393 |
| 79 | 8,051 |
| 67 |
| Other Power Suppliers | 2,205 |
| 17 | 2,745 |
| 21 | 4,056 |
| 33 |
| Total Regulated Utility Electric Sales | 13,175 |
| 100 | 13,138 |
| 100 | 12,107 |
| 100 |
Regulated Operations (Continued)
Seasonality
Due to the high concentration of industrial sales, Minnesota Power is not subject to significant seasonal fluctuations. The operations of our industrial customers, which make up a large portion of our sales portfolio as shown in the table above, are not typically subject to significant seasonal variations.
REGULATED OPERATIONS (Continued)
Industrial Customers. In 2009,2011, our industrial customers represented 3756 percent of total regulated utility kilowatt-hour sales. Our industrial customers are primarily in the taconite, paper, pulp and wood products, and pipeline industries.
| | | Industrial Customer Electric Sales | Industrial Customer Electric Sales | | | | | | |
| Year Ended December 31 | 2009 | % | 2008 | % | 2007 | % | 2011 |
| % | 2010 |
| % | 2009 |
| % |
Millions of Kilowatt-hours | | | | | | | | | | | | |
| Taconite Producers | 2,124 | 47 | 4,579 | 64 | 4,408 | 62 | 4,874 |
| 66 | 4,324 |
| 64 | 2,124 |
| 47 |
| Paper, Pulp and Wood Products | 1,454 | 33 | 1,567 | 22 | 1,613 | 23 | 1,560 |
| 21 | 1,573 |
| 23 | 1,454 |
| 33 |
| Pipelines | 504 | 11 | 582 | 8 | 562 | 8 | |
| Other Industrial | 393 | 9 | 464 | 6 | 471 | 7 | |
| | 4,475 | 100 | 7,192 | 100 | 7,054 | 100 | |
| Pipelines and Other Industrial | | 931 |
| 13 | 907 |
| 13 | 897 |
| 20 |
| Total Industrial Customer Electric Sales | | 7,365 |
| 100 | 6,804 |
| 100 | 4,475 |
| 100 |
Approximately 60 percent of the ore consumed by integrated steel facilities in the United StatesU.S. originates from six taconite customers of Minnesota Power, which represented 2,1244,874 million kilowatt-hours, or 4766 percent, of our total industrial sales in 2009.2011. Taconite, an iron-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.
Beginning inDuring 2011, the fall of 2008, worldwidedomestic steel makers beganindustry operated at production levels that enabled Minnesota taconite producers to dramatically cut steel production in responseoperate at near capacity for the entire year. According to reduced demand driven largely by the global credit concerns. United StatesAmerican Iron and Steel Institute (AISI), U.S. raw steel production ranoperated at approximately 5075 percent of capacity in 2011, up from 2010 levels of 70 percent, and up significantly from 2009 reflecting poor demand in automobiles, durable goods, and structural and other steel products.levels of approximately 50 percent.
In late 2008, Minnesota taconite producers began to feel the impacts of decreased steel demand, and reduced taconite production levels occurred in 2009. Annual taconite production in Minnesota wasincreased from the approximately 1836 million tons produced in 2010 to approximately 40 million tons in 2009 (40 million tons in 2008 and 39 million tons in 2007). Consequently, 20092011, near full production capacity. As a result, kilowatt-hour sales to our taconite customers in 2011 were lower by approximately 54greater than 2010 sales.
Projections from the AISI indicate that U.S. steel production levels will operate at about 75 percent from 2008of capacity in 2012. There has been a general historical correlation between U.S. steel production and Minnesota taconite production. Based on these projections, 2012 taconite production levels and we soldin Minnesota are expected to be similar to 2011. We will market available power to Other Power Suppliers, to partially mitigate the earnings impact of these lower taconite sales.
Raw steel production in the United States is projected to improve in 2010, and is estimated to run at approximately 60 percent of capacity. As a result, Minnesota Power expects an increase in taconite production in 2010 compared to 2009, although production will still be less than previous years’ levels. We will continue to market available power to Other Power Supplierswhen necessary, in an effort to mitigate the earnings impact of theseany lower industrial sales. TheseOther Power Supply sales are dependent upon the availability of generation and are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. We can make no assurances that our power marketing efforts will fully offset the reduced earnings resulting from lower demand nominations from our industrial customers.
In addition to serving the taconite industry, Minnesota Power also serves a number of customers in the paper, pulp and wood products industry, which represented 1,4541,560 million kilowatt-hours, or 3321 percent, of our total industrial sales in 2009. In total, we serve four2011. Four major paper and pulp mills, directly and one paper mill indirectly by providing wholesale service towhich represent the retail providermajority of the mill. Minnesota Power also serves several wood product manufacturers.
Minnesota Power’s paper and pulp customers ranthis load, reported operating at, or very near, full capacity for the majority of 2009, despite the fact that the industry as a whole experienced the impacts of the global recession in reduced sales of nearly every paper grade. Federal tax credits provided a subsidy for paper producers which allowed them to remain competitive. Minnesota Power’s paper and pulp customers benefited from the temporary or permanent idling of competitor plants both in North America and in Europe, as well as continued strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe.2011.
The pipeline industry is the third key industrial segment served by Minnesota Power with services provided to two crude oil pipelines and one refinery indirectly through SWL&P, which represented 504 million kilowatt-hours, or 11 percent, of our total industrial sales in 2009. These customers have a common reliance on the importation of Canadian crude oil. After near capacity operations in 2007, 2008, and 2009, both pipeline operators are executing expansion plans to transport Western Canadian crude oil reserves (Alberta Oil Sands) to United States markets. Access to traditional Midwest markets is being expanded to Southern markets as the Canadian supply is displacing domestic production and deliveries imported from the Gulf Coast.
Large Power Customer Contracts. Minnesota Power has 9 Large Power contracts with 10 Large Power Customers. All of these contracts serve requirements of 10 MWsMW or more of generating capacity.customer load. The customers consist of five taconite producing facilities (two of which are owned by one company and are served under a single contract), one iron nugget plant, and four paper and pulp mills.
ALLETE 20092011 Form 10-K
8
REGULATED OPERATIONSRegulated Operations (Continued)
Large Power Customer Contracts (Continued)
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 kilowatt-hour used that recovers the variable costs incurred in generating electricity. FourThree of the Large Power Customers 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.
All contracts with Large Power Customers continue past the contract termination date unless the required advance notice of cancellation has been given. The advance notice of cancellation varies from one to four years. Such contracts minimize the impact on earnings that otherwise would result from significant reductions in kilowatt-hour 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.)
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. TheThese customers receive estimated bills based on Minnesota Power’s prediction of the customer’s energy usage, forecasted energy prices, and fuel clause adjustment estimates. Minnesota Power’s five taconite-producing Large Power Customers have generally predictable energy usage on a week-to-week basis, which makes the variance between the estimated usage and actual usage small.
Contract Status for Minnesota Power Large Power Customers
As of February 1, 20102012
|
| | | | |
Customer(a) | Industry | Location | Ownership | Earliest Termination Date |
Hibbing Taconite Co.
| Taconite
| Hibbing, MN
| 62.3% ArcelorMittal USA Inc.
23% Cliffs Natural Resources Inc.
14.7% United States Steel Corporation
| December 31, 2015
|
ArcelorMittal USA – Minorca Mine (b)(a) | Taconite | Virginia, MN | ArcelorMittal USA Inc. | February 28, 2014January 31, 2016 |
Hibbing Taconite Co. (a) | Taconite | Hibbing, MN | 62.3% ArcelorMittal USA Inc. 23.0% Cliffs Natural Resources Inc. 14.7% USS Corporation | January 31, 2016 |
United States SteelTaconite LLC (a) | Taconite | Eveleth, MN | Cliffs Natural Resources Inc. | January 31, 2016 |
USS Corporation (USS – Minnesota Ore) (b,c)(a,b) | Taconite | Mt. Iron, MN and Keewatin, MN | United States SteelUSS Corporation | February 28, 2014 |
United Taconite LLC | Taconite | Eveleth, MN | Cliffs Natural Resources Inc. | DecemberJanuary 31, 20152016 |
Mesabi Nugget Delaware, LLC | Iron Nugget | Hoyt Lakes, MN | 80% Steel Dynamics, Inc (80%)Inc. 20% Kobe Steel USA (20%) | December 31, 2017 |
UPM, Blandin Paper Mill (b)
| Paper | Grand Rapids, MN | UPM-Kymmene Corporation | February 28, 2014 |
| Boise White Paper, LLC | Paper | International Falls, MN | Boise Paper Holdings, LLC | DecemberJanuary 31, 20132014 |
Sappi Cloquet LLCUPM, Blandin Paper Mill (a) | Paper and Pulp | Cloquet,Grand Rapids, MN | Sappi LimitedUPM-Kymmene Corporation | February 28, 2014January 31, 2016 |
NewPage Corporation – Duluth Mills Mill (b)(a,c) | Paper and Pulp | Duluth, MN | NewPage Corporation | February 28, 2014January 31, 2016 |
Sappi Cloquet LLC (a) | Paper and Pulp | Cloquet, MN | Sappi Limited | January 31, 2016 |
| (a) | During 2009, three Large Power Customers moved to the Large Light and Power rate class. |
| (b)(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, 2014.January 31, 2016. |
| (c) |
| (b) | United States SteelUSS Corporation includesowns both the Minntac Plant in Mountain Iron, MN and the Keewatin Taconite Plant in Keewatin, MN. |
| |
| (c) | NewPage filed for Chapter 11 bankruptcy protection on September 7, 2011. The Duluth mill operations have continued without interruption and we continue to provide electric and steam service to this customer. (See Note 1. Operations and Significant Accounting Policies.) |
Regulated Operations (Continued)
Residential and Commercial Customers.In 2009,2011, our residential and commercial customers represented 2220 percent of total regulated utility kilowatt-hour sales. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000 residential and commercial customers. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers.
REGULATED OPERATIONS (Continued)
Municipal Customers.In 2009,2011, our municipal customers represented 8seven percent of total regulated utility kilowatt-hour sales, which included 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts with its municipal customers with the exception of one small customer (less than 2 MW) whose contract is now in the cancellation period. The new contracts transitioned each customer to formula based rates, allowing rates to be adjusted annually based on changes in costs, and expire in December 2013. In February 2009, the FERC approved our municipal contracts, including the formula-based rate provision.(See Item 1. Business – Regulated Operations – Regulatory Matters.)
Other Power Suppliers.The Company also enters into off-system sales with Other Power Suppliers. These sales are dependent upon the availability of generation and are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.
Approximately 200 MWs of capacity and energy from our Taconite Harbor facility in northern Minnesota has been sold through two sales contracts totaling 175 MWs (201 MWs including a 15 percent reserve), which were effective May 1, 2005, and expire on April 30, 2010. Both contracts contain fixed monthly capacity charges and fixed minimum energy charges. One contract provides for an annual escalator to the energy charge based on increases in our cost of fuel, subject to a small minimum annual escalation. The other contract provides that the energy charge will be the greater of the fixed minimum charge or an annual amount based on the variable production cost of a combined-cycle, natural gas unit. Our exposure in the event of a full or partial outage at our Taconite Harbor facility is significantly limited under both contracts. When the buyer is notified at least two months prior to an outage, there is no liability. Outages with less than two months notice are subject to an annual duration limitation typical of this type of contract.
OnBasin Power Sales Agreement. In October 29, 2009, Minnesota Power entered into an agreement to sell 100 MWsMW of capacity and energy to Basin for the next ten years to Basin. The transaction is scheduled to begina ten-year period which began in May 2010, following the expiration of the two wholesale power sales contracts on April 30, 2010. 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 our cost of fuel. The agreement allows us to recover a pro rata share of increased costs related to emissions that may occur during the last five years of the contract.
Power Supply
In order to meet our customers’ electric requirements, we utilize a mix of Company generation and purchased power. The Company’s generation is primarily coal-fired, but also includes approximately 112 MWs102 MW of hydro generation from ten hydro stations in Minnesota, and 25 MWsapproximately 107 MW of wind generation, and 73 MW of biomass co-fired generation. Purchased power is made up of long-term coal, wind and hydro power purchase agreements and market purchases. The following table reflects the Company’s generating capabilities as of December 31, 2011 (with the exception of certain Bison 1 units installed in January 2012), and total electrical requirements as of December 31, 2009.output for 2011. Minnesota Power had an annual net peak load of 1,414 MWs1,599 MW on January 15, 2009.
21, 2011.
ALLETE 20092011 Form 10-K
10
REGULATED OPERATIONSRegulated Operations (Continued)
Power Supply (Continued)
| | | | | | | Year Ended |
| | | Unit | Year | Net | December 31, 2011 |
Regulated Utility Power Supply | Unit No. | Year Installed | Net Winter Capability | Year Ended December 31, 2009 Electric Requirements | No. | Installed | Capability | Generation and Purchases |
| | | | MW | MWh | % | | MW | MWh | % |
| Coal-Fired | | | | | | | | |
| Boswell Energy Center | 1 | 1958 | 68 | | | 1 | 1958 | 65 |
| | |
| in Cohasset, MN | 2 | 1960 | 67 | | | 2 | 1960 | 67 |
| | |
| | 3 | 1973 | 352 | | | 3 | 1973 | 361 |
| | |
| | 4 | 1980 | 429 | | | 4 | 1980 | 468 |
| | |
| | | | 916 | 5,390,131 | 42.8% | | 961 |
| 6,487,352 |
| 48.0 |
| Laskin Energy Center | 1 | 1953 | 55 | | | 1 | 1953 | 49 |
| | |
| in Hoyt Lakes, MN | 2 | 1953 | 51 | | | 2 | 1953 | 46 |
| | |
| | | | 106 | 510,505 | 4.1 | | 95 |
| 460,574 |
| 3.4 |
| Taconite Harbor Energy Center | 1 | 1957 | 75 | | | 1 | 1957 | 77 |
| | |
| in Schroeder, MN | 2 | 1957 | 74 | | | 2 | 1957 | 75 |
| | |
| | 3 | 1967 | 76 | | | 3 | 1967 | 82 |
| | |
| | | | 225 | 1,058,263 | 8.4 | | 234 |
| 1,116,764 |
| 8.2 |
| Total Coal | | | 1,247 | 6,958,899 | 55.3 | | 1,290 |
| 8,064,690 |
| 59.6 |
| Biomass/Coal/Natural Gas | | | | | | | | |
| Hibbard Renewable Energy Center | | | | | | |
| in Duluth, MN | 3 & 4 | 1949, 1951 | 54 | 40,703 | 0.3 | |
| | | | | | | |
| Hibbard Renewable Energy Center in Duluth, MN | | 3 & 4 | 1949, 1951 | 51 |
| 36,012 |
| 0.3 |
Cloquet Energy Center in Cloquet, MN | 5 | 2001 | 22 | 19,340 | 0.2 | 5 | 2001 | 22 |
| 63,219 |
| 0.4 |
| Total Biomass/Coal/Natural Gas | | | 76 | 60,043 | 0.5 | | 73 |
| 99,231 |
| 0.7 |
| Hydro | | | | | | | | |
| Group consisting of ten stations in MN | Various | | 109 | 434,541 | 3.5 | Various | | 102 |
| 404,080 |
| 3.0 |
| Wind | | | | | | |
Taconite Ridge in Mt. Iron, MN (a) | 1-10 | 2008 | 4 | 56,255 | 0.4 | |
Wind (a) | | | | |
| Taconite Ridge Energy Center in Mt. Iron, MN | | Various | 2008 | 4 |
| 65,052 |
| 0.5 |
| Bison 1 in Oliver and Morton Counties, ND | | Various | 2010, 2012 | 11 |
| 128,163 |
| 0.9 |
| Total Wind | | | 15 |
| 193,215 |
| 1.4 |
| Total Company Generation | | | 1,436 | 7,509,738 | 59.7 | | 1,480 |
| 8,761,216 |
| 64.7 |
| Long-Term Purchased Power | | | | | | | | |
| Square Butte burns lignite coal near Center, ND | | | | 1,695,254 | 13.5 | |
| Wind – Oliver County, ND | | | | 361,624 | 2.9 | |
| Hydro – Manitoba Hydro in Winnipeg, MB, Canada | | | | 433,543 | 3.4 | |
| Lignite Coal - Square Butte near Center, ND | | | | 1,718,751 |
| 12.7 |
| Wind - Oliver County, ND | | | | 371,760 |
| 2.8 |
| Hydro - Manitoba Hydro in Winnipeg, MB, Canada | | | | 511,402 |
| 3.8 |
| Total Long-Term Purchased Power | | | | 2,490,421 | 19.8 | | | 2,601,913 |
| 19.3 |
| | | | | | | | | |
Other Purchased Power(b) | | | | 2,579,408 | 20.5 | |
Other Purchased Power (b) | | | | 2,160,982 |
| 16.0 |
| Total Purchased Power | | | | 5,069,829 | 40.3 | | | 4,762,895 |
| 35.3 |
| Total | | | 1,436 | 12,579,567 | 100.0% | | 1,480 |
| 13,524,111 |
| 100.0 |
| |
| (a) | TheTaconite Ridge Energy Center consists of 10 wind turbine generator units with a total nameplate capacity of Taconite Ridge is 25 MWs.MW. Bison 1 consists of 31 wind turbine generator units with a total nameplate capacity of 82 MW. The capacity reflected in the table is actual accredited capacity of the facility. Accredited capacityfacility, which is the amount of net generating capability associated with the facility for which capacity credit may bewas obtained using limited historical data. As more data is collected, actual accredited capacity may increase. |
| |
| (b) | Includes short termshort-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 coal region located in Montana and Wyoming. Coal consumption in 20092011 for electric generation at Minnesota Power’s coal-fired generating stations was approximately 4.24.9 million tons. As of December 31, 2009,2011, Minnesota Power had a coal inventory of about 810,0000.9 million tons. Minnesota Power’s primary coal supply agreements have expiration dates through 2011. Under these agreements, Minnesota Power has the flexibility to procure 70 percent to 100 percent of its total coal requirements.in 2012 and 2013. In 2010,2012, Minnesota Power expects to obtain coal under these coal supply agreements and in the spot market. This diversity in coal supply options allows Minnesota Power to manage its coal market price and supply risk and to take advantage of favorable spot market prices. Minnesota Power continues to explore future coal supply options. We believe that adequate supplies of low-sulfur, sub-bituminous coal will continue to be available.
In 2001, Minnesota Power and BNSF entered into a long-term agreement under which BNSF transports all of Minnesota Power’s coal by unit train from the Powder River Basin directly to Minnesota Power’s generating facilities or to designated interconnection points. Minnesota Power also has transportation agreements with an affiliatein place for the delivery of a significant portion of its coal requirements. These transportation agreements expire in various years between 2013 and 2015. The delivered costs of fuel for Minnesota Power's generation are recoverable from Minnesota Power's utility customers through the Canadian National Railway and with Midwest Energy Resources Company to transport coal from BNSF interconnection points to certain Minnesota Power facilities.fuel adjustment clause.
REGULATED OPERATIONS (Continued)
Fuel (Continued) |
| | | | | | | | | |
| Coal Delivered to Minnesota Power |
| Year Ended December 31 | 2011 |
| 2010 |
| 2009 |
|
| Average Price per Ton |
| $28.85 |
|
| $25.49 |
|
| $24.99 |
|
| Average Price per MBtu |
| $1.60 |
|
| $1.42 |
|
| $1.37 |
|
| Coal Delivered to Minnesota Power |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Average Price per Ton | $24.99 | $22.73 | $21.78 |
| Average Price per MBtu | $1.37 | $1.25 | $1.20 |
Long-Term Purchased Power. Minnesota Power has contracts to purchase capacity and energy from various entities. The largest contract is with Square Butte. Under the agreement with Square Butte, which expires at the end of 2026, Minnesota Power is currently entitled to approximately 50 percent of the output of a 455-MW coal-fired generating unit located near Center, North Dakota. (See Note 11. Commitments, Guarantees and Contingencies.) TheBNI Coal supplies lignite that has been dedicatedcoal to Square Butte by BNI Coal is located on lands essentially all of which are under private control and presently leased by BNI Coal.Butte. This lignite supply is sufficient to provide fuel for the anticipated useful life of the generating unit. Square Butte’s cost of lignite burned in 20092011 was approximately $1.02$1.10 per MBtu.
We have Oliver Wind I and II. In 2006 and 2007, Minnesota Power entered into two long-term wind power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc. to purchase the output from two wind facilities, Oliver Wind I and II located near Center, North Dakota. We began purchasing the output from Oliver Wind I a 50-MW facility, in December 2006(50 MW) and the output from Oliver Wind II a 48-MW facility, in November 2007.(48 MW), wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities. Wefacilities at fixed prices. There are no fixed capacity charges, and we only pay a contractedfor energy price and will receive any potential renewable energy or environmental air quality credits.as it is delivered to us.
Manitoba Hydro. We also have a power purchase agreementPPA with Manitoba Hydro that began in May 2009 and expires in April 2015. Under thethis agreement, with Manitoba Hydro, Minnesota Power will purchaseis 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.
Minnesota Power has a separate PPA with Manitoba Hydro to purchase surplus energy from May 2011 through April 2022. This energy-only transaction 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. On March 31, 2011, the MPUC approved this PPA with Manitoba Hydro.
On May 19, 2011, Minnesota Power and Manitoba Hydro signed a long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and requires construction of additional transmission capacity between Manitoba and the U.S. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices. On January 26, 2012, the MPUC approved this PPA with Manitoba Hydro.
Transmission and Distribution
We have electric transmission and distribution lines of 500 kV (8 miles), 250kV345kV (29 miles), 250 kV (465 miles), 230 kV (605(632 miles), 161 kV (43 miles), 138 kV (128 miles), 115 kV (1,220(1,221 miles) and less than 115 kV (6,206(6,216 miles). We own and operate 166164 substations with a total capacity of 10,28711,132 megavoltamperes. Some of our transmission and distribution lines interconnect with other utilities.
Regulated Operations (Continued)
Investment in ATC
Rainy River Energy, our wholly owned subsidiary, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operationFERC-approved and ownership of, and investment in, transmission facilities. ATC rates are based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2009,2011, our equity investment balance in ATC was $88.4$98.9 million ($76.993.3 million at December 31, 2008)2010). (See Note 6. Investment in ATC.)
Properties
We own office and service buildings, an energy control center, repair shops, lease offices, and storerooms in various localities. All of our electric plants are subject to mortgages, which collateralize the outstanding first mortgage bonds of Minnesota Power and SWL&P. Generally, we hold fee interest in our real properties subject only to the lien of the mortgages. Most of our electric lines are located on land not owned in fee, but are covered by appropriate easement rights or by 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 4. Jointly-Owned Electric Facility.Facilities.)
REGULATED OPERATIONS (Continued)
Regulatory Matters
We are subject to the jurisdiction of various regulatory authorities. The MPUC has regulatory authority over Minnesota Power’s service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates and charges for the sale of electricity for resale and transmission of electricity in interstate commerce, certain accounting and record-keeping practices and ATC. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas, water, issuances of securities, and other matters. The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities necessary for construction in North Dakota.
Electric Rates. All rates and contract terms in our Regulated Operations are subject to approval by appropriate regulatory authorities. Minnesota Power designs its electric service rates based on cost of service studies under which allocations are made to the various classes of customers.customers as approved by the MPUC. Nearly all retail sales include billing adjustment clauses, which 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 environmental, transmission and renewable expenditures.
Information published by the Edison Electric Institute (Typical Bills and Average Rates Report – Summer 20092011 and Rankings – July 1, 20092011) ranked Minnesota Power as having the eighthseventh lowest average retail rates out of 175169 utilities in the United States. According to this report,U.S. Minnesota Power had the lowest rates in Minnesota and third lowest in the region consisting of Iowa, Kansas, Minnesota, Missouri, North Dakota, South Dakota and Wisconsin.
Minnesota Power requires that all large industrial and commercial customers under contract specify the date when power is first required. Thereafter, the customer is generally billed monthly for at least the minimum power for which they contracted. These conditions are part of all contracts covering power to be supplied to new large industrial and commercial customers and to current customers as their contracts expire or are amended. All rates and other contract terms are subject to approval by appropriate regulatory authorities.
Minnesota Public Utilities Commission. The MPUC has jurisdictionregulatory authority over Minnesota Power’s service area in Minnesota, retail rates, retail services, capital structure, issuance of securities and other matters.
20082010 Rate Case.In May 2008, On November 2, 2010, Minnesota Power filedreceived a written order from the MPUC approving a retail rate increase request with the MPUC seeking additional revenues of approximately $40$53.5 million, annually; the request also sought an 11.15a 10.38 percent return on common equity and a capital structure consisting of 54.854.29 percent equity and 45.2 percent debt. As a result of aratio, subject to reconsideration. On May 2009 Order and an August 2009 Reconsideration Order,24, 2011, the MPUC grantedissued an order authorizing Minnesota Power to implement final rates of $53.5 million, effective June 1, 2011. The May 24, 2011 order authorized Minnesota Power to collect a revenue increase$3.2 million differential between interim rates and final rates for the period from November 2, 2010 through May 31, 2011, all of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.which was recorded in 2011.
Interim rates, subject to refund, were in effect from August 1, 2008 through October 31, 2009. During 2009, Minnesota Power recordedUnder the terms of a $21.7 million liability for refunds of interim rates, including interest, required to be made as a result of the May 2009 Order and the August 2009 Reconsideration Order. In 2009, $21.4 million was refunded, with a remaining $0.3 million balance to be refunded in early 2010; $7.6 million of the refunds required to be made were related to interim rates charged in 2008.
With the May 2009 Order, the MPUC also approved the stipulation and settlement agreement approved by the MPUC as part of this rate case, Minnesota Power agreed to forgo collection of $20.5 million in revenue receivable that affirmedit was entitled to under a prior rider for the Company’s continued recoveryBoswell Unit 3 environmental retrofit. The agreement required the Company to capitalize, as part of fuelrate base, the $20.5 million to property, plant and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel beganequipment representing AFUDC. In conjunction with the implementationsettlement agreement, and upon receipt of the final rates on November 1, 2009. Any revenue impact associated with this transition will be identifiedrate order in February 2011, the Company reversed a future filing$6.2 million deferred tax liability related to the Company’s fuel clause operation.revenue receivable Minnesota Power agreed to forgo. The $20.5 million revenue receivable was previously included in regulatory assets on the Company's consolidated balance sheet.
2010 Rate Case. Minnesota Power previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.50 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue.
Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allow Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.
REGULATED OPERATIONSRegulated Operations (Continued)
Regulatory Matters (Continued)
TheOn February 22, 2011, Minnesota Power appealed the MPUC's interim rate decision in the Company's 2010 rate case process requires public hearings and an evidentiary hearing before an administrative law judge, bothwith the Minnesota Court of which are scheduled forAppeals. The Company appealed the second quarterMPUC's finding of 2010. A final decision on the rate request is expectedexigent circumstances in the fourth quarter. Weinterim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC's finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court, but cannot predict the final level of rates that may be approved by the MPUC, and we cannot predict whether a legal challenge to the MPUC’s interim rate decision will be forthcoming or successful.outcome at this time.
Pension. On December 22, 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. If our petition is successful the impact would be deferred in a regulatory asset (or liability) for recovery (or refund) in the Company’s next general rate case.
ALLETE Clean Energy.On August 26, 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements.
Bison 2 and Bison 3 Wind Project.Projects. Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota which are expected to be completed by the end of 2012. Site preparation is currently underway for both projects and total project costs for Bison 2 and Bison 3 are estimated to be approximately $160 million each, of which $37.0 million and $14.7 million, respectively, was spent through December 31, 2011. On July 7, 2009,September 8, 2011, and November 2, 2011, the MPUC approved ourMinnesota Power’s petition seeking current cost recovery offor investments and expenditures related to Bison I2 and associated transmission upgrades.Bison 3, respectively. On August 10, 2011, and October 12, 2011, the NDPSC issued a Certificate of Site Compatibility for Bison 2 and Bison 3, respectively, which authorized site construction to commence. We anticipate filing a petitionpetitions with the MPUC in the first quarterhalf of 20102012 to establish customer billing rates for the approved cost recovery. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will fulfill the 2025 renewable energy supply requirement for our retail load. Bison I will be comprised of 33 wind turbines with a total nameplate capacity of 76 MWs, located near Center, North Dakota, and be in service in late 2010 and 2011.
OnHibbard Biomass Upgrade Project. Hibbard is a 51 MW biomass/coal/natural gas facility located in Duluth, Minnesota. The biomass optimization project, which was conditionally approved by the MPUC in September 29, 2009, is designed to leverage existing assets to increase biomass renewable energy production at the NDPSC authorized site constructionfacility for Bison I. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for a 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter 2010.customers.
On December 31, 2009, we purchasedWe will seek current cost recovery authorization from the MPUC in 2012, along with any necessary permitting approvals required to commence construction. The project has an existing 250 kV DC transmission line from Square Butte for $69.7 million. The 465-mile transmission line runs from Center, North Dakota to Duluth, Minnesota. We expect to use this line to transport increasing amountsexpected cost of wind energy from North Dakota while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit. We expect that the Square Butte generating unit will continue to be fully utilizedapproximately $22 million and supplied with lignite coal by BNI Coal, as Minnkota Power isan expected to take Square Butte generation not utilized by Minnesota Power. Acquisitioncompletion date of this transmission line was approved by an MPUC order dated December 21, 2009. In addition, the FERC issued an order on November 24, 2009, authorizing acquisition of the transmission facilities and conditionally accepting, upon compliance and other filings, the proposed tariff revisions, interconnection agreement and other related agreements.2013.
Integrated Resource Plan. On In October 5, 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan, a comprehensive estimate of future capacity needs within Minnesota Power’s service territory. Minnesota Power does not anticipate the need for new base load generation within the Minnesota Power service territory over the next 15 years,through 2025 and plans to meet estimated future customer demand while achieving:
Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios;
| · |
| • | Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios; |
| · | Reductions in the emission of GHGs (primarily carbon dioxide)CO2); and |
| · | Compliance with mandated renewable energy standards. |
To achieve these objectives over the coming years, we plan to reshapeare in the process of reshaping our generation portfolio by adding approximately 300 to 500 megawattsMW of renewable energy to our generation mix and exploring options to incorporate peaking or intermediate resources. Our 76 MWThe first and second phases of the Bison I Wind Project1 wind project in North Dakota iswere put into service in 2010 and January 2012, respectively, increasing our renewable generation by a total of 82 MW. The Bison 2 105 MW and the Bison 3 105 MW wind projects, both expected to be in service in late 20102012, were approved by the MPUC in September and 2011.November 2011, respectively. These additional wind projects, along with the Hibbard Biomass Upgrade Project, will continue our expansion into renewable energy to meet our Integrated Resource Plan goals.
Regulated Operations (Continued)
Regulatory Matters (Continued)
We project average annual long-term growth, excluding prospective additional load from industrial and municipal customers, of approximately one percent in electric usage over the next 15 years.through 2025. We will also focus on conservation and demand side management to meet the energy savings goals established in Minnesota legislation. The MPUC approved our Integrated Resource Plan in its final order issued on May 6, 2011. A required baseload diversification study evaluating the impact of additional EPA regulations over the next two decades was filed on February 6, 2012. Through this study Minnesota Power evaluated environmental compliance scenarios for different potential ranges of future EPA regulation stringency to determine prominent power supply trends and impacts on customers. This study will advise of the next steps in our on-going, long-term resource planning process for consideration in our next Integrated Resource Plan submittal, which must be filed with the MPUC no later than July 1, 2013.
Emission Reduction Plans. We have made investments in pollution control equipment at our Boswell Unit 3 generating unit that reduces particulates, SO2, NOx and mercury emissions to meet future federal and state requirements. This equipment was placed in service in November 2009. During the construction phase, the MPUC authorized a cash return on construction work in progress in lieu of AFUDC, and this amount was collected through a current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates.
The environmental regulatory requirements for Taconite Harbor Unit 3 are pending approval of the Minnesota Regional Haze implementation by the EPA. We are evaluating compliance requirements for this Unit. Environmental retrofits at Laskin and Taconite Harbor Units 1 and 2 have been completed and are in-service.
Boswell NOTransmission Investments. X Reduction Plan. In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for expenditures relating to NOX emission reductions from Boswell Units 1, 2, and 4. The Boswell NOX Reduction Plan is expected to significantly reduce NOX emissions from these units. In conjunction with the NOX reduction, we plan to make an efficiency improvement to our existing turbine/generator at Boswell Unit 4 adding approximately 60 MWs of total output. The Boswell 1, 2 and 4, selective non-catalytic reduction NOX controls are currently in service, while the Boswell 4 low NOX burners and turbine efficiency projects are anticipated to be in service in late 2010. Our 2010 rate case seeks recovery for this project in base rates.
REGULATED OPERATIONS (Continued)
Regulatory Matters (Continued)
Transmission. We have an approved cost recovery rider in-placein place for certain transmission expenditures and the continued use of our current2009 billing factor was approved by the MPUC in June 2009.May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. Our 2010 rate case proposes to move completedOn June 29, 2011, we filed an updated billing factor that includes additional transmission projects from the current cost recovery riderand expenses, which we expect to base rates.be approved in 2012.
Conservation Improvement Program (CIP). Minnesota requires electric utilities to spend a minimum of 1.5 percent of gross operating revenues from service provided in the state on energy CIPs each year. These investments are recovered from retail customers through a billing adjustment and amountscombination of the conservation cost recovery charge (CCRC) included in retail base rates.rates and a conservation program adjustment (CPA), 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, as well asany financial incentive earned for cost-effective program achievements, and a carrying charge on the deferred account balance. Minnesota’s Next Generation Energy Act of 2007 introduced, in addition to minimum spending requirements, an energy-saving goal of 1.5 percent of gross annual retail electric energy sales by 2010. In June 2008, a biennial filing was submitted for 2009 throughand 2010, and in June 2010, a triennial filing was submitted for 2011 through 2013, and each was subsequently approved by the OES. For future program years, Minnesota Power will build upon current successful CIPs in an effort to meet the newly established 1.5 percent energy-saving goal.Department of Commerce. Minnesota Power’sPower's CIP investment goal was $5.9 million for 2011 ($4.6 million for 2010; $4.6 million for 2009 ($3.7 million for 2008; $3.2 million for 2007)2009), with actual spending of $6.3 million in 2011 ($5.6 million in 2010; $5.5 million in 2009 ($4.8 million in 2008; $3.9 million in 2007)2009).
In 2007, the Minnesota Legislature enacted several changes to state energy conservation goals and programs, including establishing an annual energy-savings goal for each utility of 1.5 percent of annual retail energy sales. In 2010, the MPUC adopted a new CIP financial incentive mechanism beginning with the 2010 project year. On April 1, 2011, Minnesota Power submitted its 2010 CIP consolidated filing that calculated CIP financial incentives based upon the MPUC's new procedures. The total requested incentive was $6.8 million. The requested CIP financial incentive was approved by the MPUC in a hearing held on December 22, 2011, and was recorded as revenue and as a regulatory asset; the approved financial incentive will be billed in 2012.
Federal Energy Regulatory Commission. The FERC has jurisdiction over the licensing of hydroelectric projects, the establishment of rates, and charges for the sale of electricity for resale and transmission of electricity in interstate commerce and electricity sold at wholesale (including the rates for our municipal customers), natural gas transportation, certain accounting and record-keeping practices, certain activities of our utility subsidiaries, and the operations of ATC. FERC jurisdiction also includes enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.
Regulated Operations (Continued)
Regulatory Matters (Continued)
Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. In 2008, Minnesota Power entered into newformula-based rate contracts with these customers. In February 2011, Minnesota Power entered into a new formula-based contract with the City of Nashwauk, effective May 1, 2012, through April 30, 2022. In June 2011, Minnesota Power entered into restated contracts, effective July 1, 2011, through June 30, 2019, with the remaining 15 Minnesota municipal customers, which transitioned customers to formula-basedand effective August 1, 2011, through June 30, 2019, with SWL&P. The rates allowing rates to be adjusted annually based on changesincluded in cost. In February 2009, the FERC approved our municipalthese contracts which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are calculated using a cost-based formula methodology that is set at the beginning of the year based on expectedeach July using estimated costs and providea rate of return that is equal to our authorized rate of return for Minnesota retail customers (10.38 percent). The formula-based rate methodology also provides for a monthly and yearly true-up calculation for actual costs. Wholesale rate increases totaling approximately $6 millioncosts incurred. Both the new and $10 million annually were implementedrestated contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to April 30, 2019. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on February 1, 2009 and January 1, 2010, respectively,December 31, 2011, this customer submitted a cancellation notice with approximately $6 million of additional revenues undertermination effective on December 31, 2013. We are currently in negotiations to extend the true-up provision accrued in 2009, which will be billed in 2010.contract with this customer.
In August 2005, the Energy Policy Act of 2005 (EPAct 2005) was signed into law, which enacted PUHCA 2005. PUHCA 2005 gives FERC certain authority over books and records of public utility holding companies and their affiliates. It also addresses FERC review and authorization of the allocation of costs for non-power goods, or administrative or management services when requested by a holding company system or state commission. In addition, EPAct 2005 directs the FERC to issue certain rules addressing electricity reliability, investment in energy infrastructure, fuel diversity for electric generation, promotion of energy efficiency and wise energy use.
We believe the overall impact of the EPAct 2005 on the electric utility industry has been positive and are continuing to evaluate the effects on our business as this legislation is being implemented. This federal legislation is designed to bring more certainty to energy markets in which ALLETE participates, as well as to provide investment incentives for energy efficiency, energy infrastructure (such as electric transmission lines), and energy production. The FERC has the responsibility of implementing numerous new standards as a result of the promulgation of the EPAct 2005. To date, the FERC’s regulatory efforts under the EPAct 2005 appear to be generally positive for the utility industry.
Public Service Commission of Wisconsin. The PSCW has regulatory authority over SWL&P’s retail sales of electricity, natural gas, water, issuances of securities, and other matters.
SWL&P’s current2011 retail rates are based on a December 20082010 PSCW retail rate order, that became effective January 1, 2009, and2011, that allows for an 11.1a 10.9 percent return on common equity. The new rates reflectedreflect a 3.52.4 percent average increase in retail utility rates for SWL&P customers (a 13.412.8 percent increase in water rates, a 4.72.5 percent increase in electricnatural gas rates and a 0.60.7 percent decrease increase in natural gaselectric rates). On an annualized basis, the rate increase will generate approximately $3$2.0 million in additional revenue.
North Dakota Public Service Commission.The NDPSC has jurisdiction over site and route permitting of generation and transmission facilities necessary for construction in North Dakota.
On September 29, 2009,August 10, 2011, and October 12, 2011, the NDPSC issued a Certificate of Site Compatibility for Bison 2 and Bison 3, respectively, which authorized site construction for Bison I. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for the 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter 2010.commence.
Regional Organizations
Midwest Independent Transmission System Operator, Inc.Minnesota Power and SWL&P are members of MISO, a regional transmission organization. While Minnesota Power and SWL&P retain ownership of their respective transmission assets, and control area functions, their transmission network is under the regional operational control of MISO. Minnesota Power and SWL&P take and provide transmission service under the MISO open access transmission tariff. MISO continues its efforts to standardize rates, terms, and conditions of transmission service over its broad region, encompassing all or parts of 1511 states and one Canadian province, and over 100,000 MWsMW of generating capacity.
In January 2009, MISO launched the new Ancillary Services Market (ASM), aimed at establishingMidwest Reliability Organization (MRO).MinnesotaPoweris a market for energy and operating reserves. In May 2008, in preparationmember of the new market,MRO, one of eight regional entities in North America responsible for: 1) developing and implementing electricity reliability standards; 2) enforcing compliance with those standards; 3) providing seasonal and long-term assessments of the bulk power system's ability to meet demand for electricity; and 4) providing an appeals and dispute resolution process.
The MRO region spans the Canadian provinces of Saskatchewan and Manitoba, the states of North Dakota, Minnesota, PowerNebraska, Iowa, the majority of South Dakota and Wisconsin, and a small portion of Montana. The region includes more than 100 organizations that are involved in the otherproduction and delivery of power to more than 20 million people. These organizations include municipal utilities, cooperatives, investor-owned utilities, a federal power marketing agency, Canadian Crown corporations, independent power producers and others who have interests in Minnesota prepared a joint filing seeking MPUC approval for the authority to account for costs and revenues that resulted from the institutionreliability of the ASM market. The MPUC conditionally approved Minnesota investor-owned utility participation in the MISO ASM market in an order dated March 17, 2009. Under this approval, recovery of ASM charges is subject to refund pending the MPUC’s review of our February 5, 2010 filing which documents the cost effectiveness of ASM. The utilities must validate ASM cost recovery to date, as well as on-going recovery, through a review of the cost and benefits of ASM participation. The Company cannot predict the outcome of this proceeding.bulk power system.
Mid-Continent Area Power Pool (MAPP). Minnesota Power also participates in MAPP, a power pool operating in parts of nine states in the Upper Midwest and in two Canadian provinces. MAPP functions include a regional transmission committee that is charged with planning for the future transmission needs of the region as well as ensuring that all electric industry participants have equal access to the transmission system.Regulated Operations (Continued)
Minnesota Legislation
Renewable Energy.In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail energy sales in Minnesota comebe from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. Minnesota Power has identifieddeveloped a plan to meet the renewable goals set by Minnesota and has included this plan in the most recent filing of the IRP with the MPUC.its 2010 Integrated Resource Plan. The MPUC approved our Integrated Resource Plan in its final order issued on May 6, 2011. The law allows the MPUC to modify or delay meeting a standard obligationmilestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard,milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developing and makingWe are currently on track to exceed the 12 percent renewable supply additions as partenergy requirement by the end of its generation planning strategy prior to the enactment of this law and this activity continues.2012.
Greenhouse Gas Reduction. In 2007, Minnesota passed legislation establishing non-binding targetsPower has taken several steps to begin executing its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate. We have two long-term PPAs with an affiliate of NextEra Energy, Inc., for carbon dioxide reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025,wind energy in North Dakota (Oliver Wind I and at least 80 percent below 2005 levels by 2050.II). Other steps include Taconite Ridge, our wind facility located in northeastern Minnesota, is also participating in the Midwestern Greenhouse Gas Reduction Accord, a regional effort to develop a multi-state approach to GHG emission reductions.our Bison 1, 2 and 3 wind development projects and our Hibbard Biomass Upgrade Project.
We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.
Competition
Retail 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 outside of a municipality of 2 MW and above may be allowed to choose a supplier upon MPUC approval. Minnesota Power serves 10 Large Power facilities over 10 MW, none of which have engaged in a competitive rate process. TwoNo other large commercial or small industrial customers within the past 15 years that are over 2 MW but less than 10 MW under our Large Light and Power tariff have participated inattempted to seek a competitive rate process with neighboring electric cooperatives but were ultimately retained byprovider outside of Minnesota Power.Power’s service territory since 1994. 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 fuels for their manufacturing processes.
For the year ended December 31, 2009, 82011, seven percent of the Company’s energy sales were sales to municipal customers in Minnesota and a private utility in Wisconsin by contract under a formula-based rate approved by FERC. These customers have the right to seek an energy supply from any wholesale electric service provider upon contract expiration. (See Item 1. Business – Regulatory Matters.)
The FERC has continued with its efforts to promote a more competitive wholesale market through open-access transmission and other means. As a result, our sales to Other Power Suppliers and our purchases to supply our retail and wholesale load are in the competitive market.
Franchises
Minnesota Power holds franchises to construct and maintain an electric distribution and transmission system in 9394 cities and towns located within its electric service territory. SWL&P holds 17 similar franchises for electric, natural gas and/or water systems in 15 cities1 city and 16 villages and towns within its service territory. The remaining cities, villages and towns served by us do not require a franchise to operate within their boundaries. Our exclusive service territories are established by state regulatory agencies.
INVESTMENTS AND OTHERInvestments and Other
Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, formed in June 2011, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes a small amount of non-rate base generation, approximately 7,0005,500 acres of land available-for-sale in Minnesota, and earnings on cash and investments.
Investments and Other (Continued)
BNI Coal
BNI Coal operates a lignite mine in North Dakota. BNI Coal is a low-cost supplier of lignite in North Dakota, producing about 4 million tons annually. Two electric generating cooperatives, Minnkota Power and Square Butte, presently consume virtually all of BNI Coal’s production of lignite under cost-plus, fixed fee coal supply agreements extending through 2026. (See Item 1. Business – Power Supply – Long-Term Purchased Power and Note 11. 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. The average cost to reclaim one acreAs of land is approximately $35,000; however, dependingDecember 31, 2011 BNI had a $10.3 million asset reclamation obligation ($6.7 million at December 31, 2010) included in other non-current liabilities on conditions, it could be significantly higher. Reclamationour consolidated balance sheet. These costs are included in the cost-plus contract, for which an asset reclamation cost receivable was included in other non-current assets on our consolidated balance sheet. The asset reclamation obligation is guaranteed by surety bonds and a letter of coal passed through to customers. Withcredit. (See Note 11. Commitments, Guarantees and Contingencies). BNI Coal has lignite reserves of an estimated 600650 million tons, BNI Coal has ample capacity to expand production.tons.
ALLETE Properties
ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment and sell the portfolio over time or in bulk transactions. ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise and reinvest the proceeds in its growth initiatives. ALLETE does not intend to acquire additional Florida real estate.
Our two major development projects are Town Center and Palm Coast Park. Ormond Crossings, a thirdAnother major project, thatOrmond Crossings is currently in the planning stage, received land use approvals in December 2006. However, due to a change in Florida law that became effective in July 2009, those approvals are being revised. It is anticipated that thedesign and permitting stage. The City of Ormond Beach, FL will approveFlorida, approved a new Development Agreement for Ormond Crossings in the first quarter of 2010. The new agreementwhich will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings.
Town Center. Town Center, which is located in the City of Palm Coast, is a mixed-use development with a neo-traditional downtown core area. Construction of the major infrastructure improvements at Town Center was substantially complete at the end of 2008. At build-out, Town Center is expected to include approximately 3,000 residential units and 4.0 million square feet of various types of non-residential space. Sites have also been set aside for a new city hall, a community center, an art and entertainment center, and other public uses. Market conditions will determine how quickly Town Center builds out.
Palm Coast Park. Palm Coast Park, which is located in the City of Palm Coast, is a 4,700-acre mixed-use development. Construction of the major infrastructure improvements at Palm Coast Park was substantially complete at the end of 2007. At build-out, Palm Coast Park is expected to include approximately 4,000 residential units, 3.0 million square feet of various types of non-residential space and public facilities. Market conditions will determine how quickly Palm Coast Park builds out.
Ormond Crossings. Ormond Crossings, which is located in the City of Ormond Beach, is a 3,000-acre, mixed-use development. Planning, engineering design, and permitting of the master infrastructure are ongoing. At build out, Ormond Crossings is expected to include approximately 3,000 residential units, 5.0 million square feet of various types of non-residential space and public facilities. Market conditions will determine when Ormond Crossingsour projects will be built out. We do not expect any development activity at Ormond Crossings in 2010.
Lake Swamp. Lake Swamp wetland mitigation bank is a 1,900 acre regionally significant wetlands mitigation bank that was permitted by the St. Johns River Water Management District in 2008 and the U.S. Army Corps of Engineers in December 2009. Wetland mitigation credits will be used at Ormond Crossings and will also be available for sale to developers of other projects that are located in the bank’s service area. Applications are currently being prepared to expand the bank by approximately 1,000 acres.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Outlook for more information on ALLETE Properties’ land holdings.
INVESTMENTS AND OTHER (Continued)
Seller Financing. ALLETE Properties occasionally provides seller financing to certain qualified buyers. At December 31, 2009,2011, outstanding finance receivables were $12.9$2.0 million, with maturities up to 3 years. 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.
ALLETE Clean Energy
In June 2011, we established ALLETE Clean Energy, a wholly owned subsidiary of ALLETE. ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term PPAs.
On August 26, 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements.
Investments and Other (Continued)
Non-Rate Base Generation
As of December 31, 2009,2011, non-rate base generationconsists of 30 MWs31 MW of generation at Rapids Energy Center. For January through October non-rate base generation also included Cloquet Energy Center (23 MWs of generation), which was transferred to rate base as a result of our 2008 rate order. In 2009,2011, we sold 0.20.1 million MWh of non-rate base generation (0.2(0.1 million in 20082010 and 2007)0.2 million in 2009). In November 2009, Cloquet Energy Center was transferred from non-rate base generation to regulated operations.
| Non-Rate Base Power Supply | Unit No. | Year Installed | Year Acquired | Net Capability (MW) |
| Steam | | | | |
Biomass (a) | | | | |
Cloquet Energy Center (b) | 5 | 2001 | 2001 | 22 |
| in Cloquet, MN | | | | |
Rapids Energy Center (c) | 6 & 7 | 1969, 1980 | 2000 | 29 |
| in Grand Rapids, MN | | | | |
| Hydro | | | | |
| Conventional Run-of-River | | | | |
Rapids Energy Center (c) | 4 & 5 | 1917 | 2000 | 1 |
| in Grand Rapids, MN | | | | |
|
| | | | |
| 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 | 30 |
| Hydro – Conventional Run-of-River | 4 & 5 | 1917, 1948 | 2000 | 1 |
(a) | Cloquet Energy Center is supplemented by natural gas; Rapids Energy Center is supplemented by coal. |
(b) | Transferred to Regulated Operations as a result of our 2008 rate order on November 1, 2009. |
(c)(a) | The net generation is primarily dedicated to the needs of one customer. |
| |
| (b) | Rapids Energy Center is supplemented by coal. |
Other
Minnesota Land.We have approximately 7,0005,500 acres of land available-for-sale in Minnesota. We acquired the land in 2001 when we purchased the Taconite Harbor generating facilities.
Environmental Matters
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both the Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have taken a lead in these discussions. Minnesota Power’sPower's fossil fueledfuel facilities will likely to be subject to regulation under these climate change policies.proposals. Our intention is to reduce our exposure to possible future carbon and GHG legislationthese requirements by reshaping our generation portfolio over time to reduce our reliance on coal.
We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Requirements.)
We review environmental matters for disclosure 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. These accrualsAccruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information become 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 charged to expense unless recoverable in rates from customers.
Environmental Matters (Continued)
Air.Clean Air Act. The electric utility industry is heavily regulated both at the federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2and system-wide average NOX limits.state level to address air emissions. Minnesota Power’sPower's generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of theseMinnesota Power's coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses or electrostatic precipitators. Minnesota Power’s generatingand low NOX technologies. At this time, under currently applicable environmental regulations, these facilities are currently in compliancesubstantially compliant with applicable emission requirements.
New Source Review. Review (NSR)On. In August 8, 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR)NSR requirements of the Clean Air Act at Boswell Units 1-41, 2, 3 and 4 and Laskin Unit 2. The NOV also asserts that the Boswell Unit 4 Title V permit was violated, and that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements.requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV 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 believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits.
We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Since 2006, Minnesota Power has significantly reduced, and continues to reduce, emissions at Boswell and Laskin.
Environmental Matters (Continued)
Air (Continued)
The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unable to predict the ultimate financial impact or the resolution of these matters at this time.
EPA CleanCross-State Air Interstate Rule.Pollution Rule (CSAPR) In March 2005,. On July 6, 2011, the EPA announcedissued the CSAPR, which went into effect on October 7, 2011. The final rule replaced the EPA's 2005 Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO2, NOX, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008,. However, on December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit (Court) vacatedissued a ruling staying implementation of the CSAPR, pending judicial review, and ordered that the CAIR and remandedremain in place while the rulemakingCSAPR is stayed.
If the CSAPR is reinstated after judicial review, it will require states in the CSAPR region to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. These regulations do not directly require the installation of controls. Instead, they require facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would be allocated to facilities annually by the EPA for reconsiderationand will also be able to be bought and sold.
The CAIR regulations similarly require certain states to improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. Minnesota participation in the CAIR was stayed by EPA administrative action while also granting our petition that the EPA reconsider includingcompleted a review of air quality modeling issues in conjunction with the development of a final replacement rule. In its final determination, the EPA listed Minnesota as a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested thatCSAPR-affected state based on new 24-hour fine particulate NAAQS analysis. While the CAIR be remanded without a court order. In December 2008, the Court granted the request thatremains in effect, Minnesota participation in the CAIR will continue to be remanded without a court order, effectively reinstating a January 1, 2009,stayed. It is uncertain if the CSAPR-related emission restrictions will become effective for Minnesota utilities.
Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Our analysis, based on our expected generation rates, indicates that these recent emission reductions would satisfy Minnesota Power's SO2 and NOX emission compliance date for the CAIR, including Minnesota. However, in the May 12, 2009, Federal Register, the EPA issued a proposed rule that would amend the CAIR to stay its effectivenessobligations with respect to Minnesota until completionthe EPA-allocated CSAPR allowances for 2012. We will continue to evaluate our compliance strategy under CSAPR and if any capital investments or allowance purchases are required, we would likely seek recovery of the EPA’s determination of whether Minnesota should be included as a CAIR state. The formal administrative stay of CAIR for Minnesota was published in the November 3, 2009, Federal Register with an effective date of December 3, 2009. The EPA has indicated the CAIR Replacement Rule is expected in April 2010 with finalization in early 2011. Atthose costs. We are unable to predict any additional CSAPR compliance costs we might incur at this time we do not have any indication whether Minnesota will be included in the Replacement Rule.if CSAPR is reinstated.
Minnesota Regional Haze. The federal regional haze rule requires states to submit state implementation plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources, that were put in place between 1962 and 1977, with emissions contributing to visibility impairment, are required to install emission controls, known as best available retrofit technologyBest Available Retrofit Technology (BART). We have certaintwo steam units, Boswell Unit 3 and Taconite Harbor Unit 3, which are subject to BART requirements.
Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was nevernot filed at that time due to the Court’s reviewUnited States Court of CAIR as more fully described above under “EPA Clean Air Interstate Rule.”Appeals for the District of Columbia Circuit's remand of CAIR. Subsequently, the MPCA requested that companies with BART eligibleBART-eligible units complete and submit a BART emissions control retrofit study, which was done oncompleted for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirementrequirements for that unit. OnIn December 15, 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.
On December 30, 2011, the EPA published in the Federal Register a proposal to revise the regional haze rule. This proposal would approve the trading program in the CSAPR as an alternative to determining BART. If adopted, states in the CSAPR region could substitute participation in CSAPR for source-specific BART requirements for SO2 and NOX emissions from power plants. On January 2, 2012, the MPCA submitted to the EPA a supplemental Minnesota regional haze SIP stating that it wishes to rely on the CSAPR to satisfy BART requirements for SO2 and NOx for electric generating units.
On January 25, 2012, the EPA published in the Federal Register a proposal to approve the Minnesota SIP, including the supplemental Minnesota SIP. If the Minnesota SIP, the supplemental Minnesota SIP, and the EPA's regional haze rule revisions are finalized as currently proposed, and the CSAPR rule is reinstated, then Minnesota Power does not foresee a need to make significant additional expenditures at Taconite Harbor Unit 3 to comply with the regional haze rule.
Environmental Matters (Continued)
Air (Continued)
If controls are ultimately required, Minnesota Power will have up to five years from the final promulgation deadline to bring Taconite Harbor Unit 3 into compliance with the regional haze rule requirements. It is uncertain what controls willwould ultimately be required at Taconite Harbor Unit 3 under this scenario, in connection with the regional haze rule.
Mercury and Air Toxics Standards (MATS) Rule (formerly known as the Electric Generating Unit Maximum Achievable Control Technology (MACT) 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 EPA released a proposed MATS rule on March 16, 2011, addressing such emissions from coal-fired utility units greater than 25 MW. The final rule was issued on December 21, 2011. There are currently 188 listed HAPs which the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the remaining categories. Affected sources would have to be in compliance with the rule three years after it is published in the Federal Register. States have the authority to grant sources a one-year extension. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures between $300 million to $400 million over the next five years. Some additional controls for complying with the rule at our remaining coal-fired generating units may be required, the costs of which cannot be estimated at this time.
EPA National Emission Standards for Hazardous Air Pollutants.Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2005,2011, a final rule was published in the Federal Register for industrial boiler maximum achievable control technology (Industrial Boiler MACT). The rule was stayed by the EPA also announcedon May 16, 2011, to allow the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped electric utility mercury emissionsEPA time to consider additional comments received. The EPA re-proposed the rule in the continental United States through a cap-and-trade program. In February 2008,December 2011. A final rule is expected in April 2012. On January 9, 2012, the United States District Court of Appeals for the District of Columbia Circuit vacated the CAMR and remanded the rulemaking toruled that the EPA for reconsideration. In October 2008, the EPA petitioned the Supreme Court to review the Court’s decision in the CAMR case. In January 2009, the EPA withdrew its petition, paving the way for possible regulation of mercury and other hazardous air pollutant emissions through Section 112stay of the Clean Air Act, setting Maximum Achievable Control Technology standards forIndustrial Boiler MACT was unlawful, effectively reinstating the utility sector. In December 2009, Minnesota PowerMarch 2011 rule and other utilities received an Information Collection Requestassociated compliance deadlines. Major sources are expected to have three years to achieve compliance with the final rule. It is not known yet whether the final rule from the EPA, requiring that emissions data be providedDecember 2011 proposal, expected in April 2012, will establish new compliance deadlines. This rule may result in additional control measures being required at Rapids Energy Center and stack testing be performed in order to develop an improved database with which to base future regulations. Cost estimatesHibbard. Costs for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Actfinal rule cannot be estimated at this time.
Environmental Matters (Continued)
Minnesota Mercury Emission Reduction Act.Act This legislation requires. Under Minnesota Power to file mercury emission reduction plans for Boswell Units 3 and 4, withlaw, a goal of 90 percent reduction in mercury emissions. The Boswell Unit 3 emission reduction plan was filed with the MPCA in October 2006. Mercury control equipment has been installed and was placed into service in November 2009. (See Item 1. Business – Regulated Operations – Minnesota Public Utilities Commission – Emission Reduction Plans.) A mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2011,2015, with implementation no later than December 31, 2014.2018. The legislationstatute also calls for an evaluation of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’sutility's customers. Cost estimatesUntil Minnesota Power files its mercury emission reduction plan for Boswell Unit 4, it must file an annual report updating the MPUC and other stakeholders on the status of emission reduction planning for Boswell Unit 4. The first update was filed with the MPUC on June 30, 2011.
Mercury emission limits have also been included in the recently finalized MATS rule. We anticipate that the emission reduction plan implemented to comply with the MATS rule will satisfy the mercury emission limits under Minnesota law. Costs for the Boswell Unit 4 emission reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule discussed above.
Proposed and Finalized 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 available at this time.in compliance with a NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.
Ozone NAAQS.Ozone. The EPA is attemptinghas proposed to control, more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to reducerevise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA projects stating ruleswas scheduled to address attainmentdecide upon the 2008 eight-hour ozone standard in July 2011, but has announced that it is deferring revision of these new, more stringent standards will not be requiredthis standard until December 2013.
Environmental Matters (Continued)
NAAQS (Continued)
Particulate Matter NAAQS.Climate Change. Minnesota PowerThe EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA established a more stringent 24-hour average fine particulate matter (PM2.5) standard and kept the annual average fine particulate matter standard and the 24-hour coarse particulate matter standard unchanged. The United States Court of Appeals for the District of Columbia Circuit has remanded the PM2.5 standard to the EPA, requiring consideration of lower annual average standard values. The EPA expects to propose the new PM2.5 standards in June 2012 with a goal to finalize the rule by June 2013. State attainment status determination will occur after the rule is addressing climate change by taking the following stepsfinalized. It is not known when affected sources would have to take additional control measures if modeling demonstrates non-compliance at their property boundary. The EPA has indicated that also ensure reliable and environmentally compliant generation resourcesambient air quality monitoring for 2008 through 2010 will be used as a basis for states to meet our customer’s requirements.characterize their attainment status.
| · | Expand our renewable energy supply. |
| · | Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies. |
| · | Provide energy conservation initiatives with our customers and demand side efforts. |
| · | Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts. |
| · | Achieve overall carbon emission reductions. |
SO2 and NO2 NAAQS. During 2010, the EPA finalized new one-hour NAAQS for SO2 and NO2. Monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO2 NAAQS also requires the EPA to evaluate modeling data to determine attainment. The MPCA intends to complete this initial modeling effort by the end of the first quarter of 2012, using facility data from sources that emit more than 100 tons per year of SO2. Minnesota Power provided such data for all of our steam generating facilities. It is unclear what the outcome of this evaluation will be.
These NAAQS modeling efforts could result in more stringent emission limits on our coal-fired generating facilities, and possibly additional control measures on some of our units. The MPCA has informed affected sources that compliance strategies required as a result of these modeling results must be agreed to with the MPCA by February 2013. One-hour SO2 NAAQS attainment is required by 2017.
We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.
Climate Change.The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. These physical risks could include, but are not limited to,to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’sCompany's business and operations. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers' requirements:
Expand our renewable energy supply;
Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies;
Provide energy conservation initiatives for our customers and engage in other demand side efforts; and
Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.
Federal Legislation. We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the Federal level to “cap” the amountEPA Regulation of GHG emissions have been made. On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap-and-trade program. H.R. 2454 allocates a significant number of emission allowances to the electric utility sector to mitigate cost impacts on consumers. Based on the emission allowance allocations, we expect we would have to purchase additional allowances. We’re unable to predict at this time the value of these allowances.Emissions.
On September 30, 2009, the Senate introduced S. 1733, the Senate version of H.R. 2454. This legislation proposes a more stringent, near-term greenhouse emissions reduction target in 2020 of 20 percent below 2005 levels, as compared to the 17 percent reduction proposed by H.R. 2454.
Congress may consider proposals other than cap-and-trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454, S. 1733, or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company. We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.
Greenhouse Gas Reduction. In 2007, Minnesota passed legislation establishing non-binding targets for carbon dioxide reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050.
Midwestern Greenhouse Gas Reduction Accord. Minnesota is also participating in the Midwestern Greenhouse Gas Reduction Accord (the Accord), a regional effort to develop a multi-state approach to GHG emission reductions. The Accord includes an agreement to develop a multi-sector cap-and-trade system to help meet the targets established by the group.
Greenhouse Gas Emissions Reporting. In May 2008, Minnesota passed legislation that required the MPCA to track emissions and make interim emissions reduction recommendations towards meeting the State’s goal of reducing GHG by 80 percent by 2050. GHG emissions from 2008 were reported in 2009.
We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.
Environmental Matters (Continued)
Climate Change (Continued)
International Climate Change Initiatives. The United States is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) that requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. In December 2009, leaders of developed and developing countries met in Copenhagen, Denmark, under the UNFCCC and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHG by 2020 and provide for developed countries to fund GHG emissions mitigation projects in developing countries. President Obama participated in the development of, and endorsed the Copenhagen Accord.
EPA Greenhouse Gas Reporting Rule. On September 22, 2009,2010, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.
Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and newRule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds for when permits will be required to address GHG emissions for new andfacilities, at existing facilities whichthat undergo major modifications. The rule would require large industrialmodifications and at other facilities including power plants, to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used atcharacterized as major sources under the facility to minimize GHG emissions. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.Clean Air Act's Title V program.
For our existing facilities, the proposed rule does not require amending our existing Title V Operating Permits to include GHG requirements. Implementation of the requirement to add GHG provisions to permits will be completed at the state level in Minnesota by the MPCA when the Title V permits are renewed. However, installation of new units or modification of existing units resulting in a significant increase in GHG emissions will require obtaining PSD permits and amending our operating permits to include BACT for GHGs. However, modifying or installing units with GHG emissionsdemonstrate that triggerBest Available Control Technology (BACT) is being used at the PSD permitting requirements could require amending operating permits to incorporate BACTfacility to control GHG emissions. The EPA has defined significant emissions increase for existing sources as a GHG increase of 75,000 tons or more per year of total GHG on a CO2 equivalent basis.
Environmental Matters (Continued)
Climate Change (Continued)
EPA Endangerment Findings. On December 15, 2009,In late 2010, the EPA published its findingsissued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the emissionsproject-specific top-down BACT determination process used for other pollutants will also be used to determine BACT for GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of six GHG including CO2, methane,emission control technologies and nitrous oxide, endanger human healthtechniques the EPA considers available or welfare. This finding may result in regulations that establish motor vehiclelikely to be available to sources. It is possible these control technologies could be determined to be BACT on a project-by-project basis. In the near term, one option appears to be energy efficiency maximization.
Legal challenges to the EPA's regulation of GHG emissions, standards in 2010. There isincluding the Tailoring Rule, have been filed by others and are awaiting judicial determination. Comments to the permitting guidance were also a possibility that the endangerment finding will enable expansion ofsubmitted by Minnesota Power and others and may be addressed by the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. with the United States District Court Circuit Court of Appeals on December 23, 2009.
Research and Study Initiatives. We participate in several research and study initiatives aimed at mitigating the potential impact of carbon emissions regulation on our business. Through this research, we cannot be certain that carbon emissions will be reduced or avoided through use of renewable energy sources or through implementing efficiency and conservation efforts. In developing strategies for our comprehensive approach to reducing our carbon emissions, we participate in and fund organizations and studies.
As an example, we commissioned a study with the University of Minnesota titled: Assessment of Carbon Flows Associated with Forest Management and Biomass Procurement for the Laskin Biomass Facility. This study was the first of its kind to comprehensively look at the carbon lifecycle as it relates to burning biomass for electrical generation in the region.form of revised guidance documents.
We participateare unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in the Electric Power Research Institute’s CoalFleet for Tomorrow program, which reviews advanced clean coal generation and carbon capture research and assessment. Similarly, we participate as a North Dakota Lignite Interest member of the Canadian Clean Power Coalition. It also reviews advanced clean coal technologies focusing on lower rank sub-bituminous and lignite fuel energy conversion technologies and carbon control options. These provide Minnesota Power the ability to assess what technologies will best fit the economic fuels that are available in our region and when they may be available.general rate case.
We also participate in research through the Plains COWater.2 Reduction Partnership (PCOR). PCOR is looking at CO2 capture technology through research conducted at the Energy and Environmental Research Center, University of North Dakota. Minnesota Power is a partner, along with a number of other utilities, technology providers, and consultants, to further research on CO2 capture techniques, operational issues and costs. The partnership is funded by the members as well as the Department of Energy.
We cannot predict whether our participation in any of these activities will result in a benefit to ALLETE or impact the future financial position or results of operations of the Company.
Water. The FederalClean Water Pollution Control Act requires NPDES permits to 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. We are in materialsubstantial compliance with these permits.
Clean Water Act - Aquatic Organisms. On April 20,
Environmental Matters (Continued) 2011, the EPA published in the Federal Register proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would 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 killed when they are pinned against the facility's intake structure or that are drawn into the facility's cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011. The EPA is obligated to finalize the rule by July 27, 2012. Minnesota Power is in the process of evaluating the potential impacts the proposed rule may have on its facilities. We are unable to predict the compliance cost we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.
EPA Steam Electric Power Generating Effluent Guidelines. In late 2009, the EPA announced that it will be reviewing and reissuing the federal effluent guidelines for steam electric stations. These are the underlying federal water discharge rules that apply to all steam electric stations. The EPA has indicated that the new rule promulgating these guidelines will be proposed in 2012 and finalized in 2014. As part of the review phase for this new rule, the EPA issued an Information Collection Request (ICR) in June 2010, to most thermal electric generating stations in the country, including all five of Minnesota Power's generating stations. The ICR was completed and submitted to the EPA in September 2010 for Boswell, Laskin, Taconite Harbor, Hibbard, and Rapids Energy Center. The ICR was designed to gather extensive information on the nature and extent of all water discharge and related wastewater handling at power plants. The information gathered through the ICR will form a basis for development of the eventual new rule, which could include more restrictive requirements on wastewater discharge, flue gas desulfurization, and wet ash handling operations. We are unable to predict the costs we might incur to comply with potential future water discharge regulations at this time.
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. The Toxic Substances Control Act regulates the management and disposal of materials containing polychlorinated biphenyl (PCB). In response to the EPA Region V’s request for utilities to participate in the Great Lakes Initiative by voluntarily removing remaining PCB inventories, Minnesota Power is in the process of voluntarily replacing its remaining PCB capacitor banks. Known PCB-contaminated oil in substation equipment was replaced by June 2007. We are in material compliance with these rules.
Coal Ash Management Facilities.Facilities. Minnesota Power generates coal ash at all five of its steamcoal-fired electric stations.generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. Minnesota Power continues to monitor state and federal legislative andIn June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory activities that may affect its ash management practices. The EPA is expected to propose new regulationsschemes for coal ash. Comments on the proposed rule were due in February 2010 pertaining to the management of coal ash by electric utilities.November 2010. It is unknown how potential coal ash managementestimated that the final rule changes will affect Minnesota Power’s facilities. On March 9, 2009,be published in late 2012 or early 2013. We are unable to predict the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received ancompliance cost we might incur; however, the costs could be material. We would seek recovery of any additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findingscosts through cost recovery riders or concerns from the DNR staff during the inspections.in a general rate case.
Environmental Matters (Continued)
Solid and Hazardous Waste (Continued)
Manufactured Gas Plant Site.We are reviewing and addressing environmental conditions at a former manufactured gas plant site withinin the City of Superior, Wisconsin, and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At As of December 31, 2009,2011, we have a $0.5 million liability for this site which was accrued on December 31, 2003, and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.
Employees
At December 31, 2009,2011, ALLETE had 1,4741,371 employees, of which 1,4111,315 were full-time.
Minnesota Power and SWL&P havehad an aggregate 614615 employees who are members of the International Brotherhood of Electrical Workers (IBEW)IBEW Local 31. Throughout 2009, Minnesota Power, SWL&P andThe current labor agreements with IBEW Local 31 worked under contract extensions of the agreements which expired on January 31, 2009. On April 10, 2009, IBEW Local 31 requested binding arbitration in accordance with the provisions of the contracts which also provided Minnesota Power and SWL&P with the protections of no strike clauses. Arbitration hearings took place October 5, 2009, with final resolution for Minnesota Power occurring in January 2010. The terms of the agreement are retro active to February 1, 2009, and will expire on January 31, 2012. SWL&P continues to work with its union and the arbitrator to resolve the remaining differences between the parties.2014.
BNI Coal has 137had 157 employees, of which 100117 are members of the IBEW Local 1593. The labor agreement between BNI Coal and IBEW Local 1593 have aexpired on March 31, 2011. A new labor agreement whichbetween BNI Coal and IBEW Local 1593 was accepted on March 1, 2011. The contract went into effect on April 1, 2011 and expires on March 31, 2011.2014.
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.
ALLETE 20092011 Form 10-K
24
Executive Officers of the Registrant
As of February 12, 2010,15, 2012, these are the executive officers of ALLETE:
|
| |
| Executive Officers | Initial Effective Date |
| | |
Alan R. HodnikDonald J. Shippar, Age 6052 | |
Chairman and Chief Executive Officer | May 12, 2009 |
| Chairman, President and Chief Executive Officer – ALLETE | January 1, 2006May 10, 2011 |
| President and Chief Executive Officer – ALLETE | January 21, 2004 |
| |
Alan R. Hodnik, Age 50
| May 1, 2010 |
| President – ALLETE | May 12,1, 2009 |
| Chief Operating Officer – Minnesota Power | May 8, 2007 |
| Senior Vice President – Minnesota Power Operations | September 22, 2006 |
Vice President – Minnesota Power Generation | May 1, 2005 |
| | |
Robert J. Adams, Age 4749 | |
| Vice President – Business Development and Chief Risk Officer | May 13, 2008 |
| Vice President – Utility Business Development | February 1, 2004 |
| | |
Deborah A. Amberg, Age 4446 | |
| Senior Vice President, General Counsel and Secretary | January 1, 2006 |
Vice President, General Counsel and Secretary | March 8, 2004 |
| | |
Steven Q. DeVinck, Age 5052 | |
| Controller and Vice President – Business Support | December 17,5, 2009 |
| Controller | July 12, 2006 |
| | |
David J. McMillan, Age 50 | |
| Senior Vice President – External Affairs – ALLETE | January 1, 2012 |
| Senior Vice President – Marketing, Regulatory and Public Affairs – ALLETE | January 1, 2006 |
| Executive Vice President – Minnesota Power | January 1, 2006 |
| |
Mark A. Schober, Age 5456 | |
| Senior Vice President and Chief Financial Officer | July 1, 2006 |
Senior Vice President and Controller | February 1, 2004 |
| | |
Donald W. Stellmaker, Age 5254 | |
| Vice President, Corporate Treasurer | July 24, 2004August 19, 2011 |
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 positions shown above, the following executives held other positions with the Company during the past five years.
| Mr. DeVinck was Director of Nonutility Business Development, and Assistant Controller.
|
| Mr. Hodnik was General Manager of Thermal Operations.
|
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 above extends to the first meeting of our Board of Directors after the next annual meeting of shareholders. Both meetings are scheduled for May 11, 2010.8, 2012.
ALLETE 20092011 Form 10-K
25
Readers are cautioned that forward-looking statements, including those containedThe factors discussed below, as well as other information set forth in this Form 10-K, which could materially affect our business, financial condition and results of operations should be read in conjunction with our disclosures under the heading: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” located on page 5 of this Form 10-K and the factors described below.carefully considered. The risks and uncertainties described in this Form 10-Kbelow are not the only ones facing our Company.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. Our business, financial condition or results of operations could suffer if the concerns set forth below are realized.
Our results of operations could be negatively impacted if our Large Power Customers experience an economic down cycle or fail to compete effectively in the global economy.
Our ten10 Large Power Customers accounted for approximately 2334 percent of our 20092011 consolidated operating revenue (36(31 percent in 2008)2010; 23 percent in 2009). One of these customers accounted for 812.6 percent of consolidated revenue in 20092011 (12.5 percent in 2008)2010; 8 percent in 2009). 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 global marketplace. An economic downturn or failure to compete effectively in the global economy could have a material adverse effect on their operations and, consequently, could negatively impact 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.
Our operations are subject to extensive governmental regulations that may have a negative impact on our business and results of operations.
We are subject to prevailing governmental policies and regulatory actions, including those of the United States Congress, state legislatures, the FERC, the MPUC, the PSCW, the NDPSC and the NDPSC.EPA. These governmental regulations relate to allowed rates of return, capital structure, financings, industry rate and ratecost structure, acquisition and disposal of assets and facilities, construction and operation of generation, transmission and constructiondistribution facilities (including the ongoing maintenance and reliable operation of plantsuch facilities under established reliability standards), recovery of purchased power and capital investments, and present or prospective wholesale and retail competition (including but not limited to transmission costs).competition. We must also comply with permits, licenses and any other authorizations as issued by local, state and federal agencies. These governmental regulations significantly influence our operating environment and may affect our ability to recover costs from our customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for 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. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.
Our ability to obtain rate adjustments to maintain current rates of return depends upon regulatory action under applicable statutes and regulations, and we cannot provide assurance that rate adjustments will be obtained or current authorized rates of return on capital will be earned. Minnesota Power and SWL&P, from time to time, file rate cases with, or otherwise seek cost recovery authorization from, federal and state regulatory authorities. In future rate cases, ifIf Minnesota Power and SWL&P do not receive an adequate amount of rate relief in rate cases, if rates are reduced, if increased rates are not approved on a timely basis or costs are otherwise unable to be recovered through rates, or if cost recovery is not achieved at the requested level, we may experience an adverse impact on our financial condition, results of operations and cash flows. We are unable to predict the impact on our business and operations results from future regulatory activities of any of these agencies.
Our operations could be adversely impacted by emissions of greenhouse gases (GHG) that are linked to globalthe physical risks associated with climate change.
The scientific community generally accepts that emissions of GHGs are linked to global climate change. ClimatePhysical risks of climate change, creates physical and financial risk. These physical risks could include, but are not limited to, increasedsuch as more frequent or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency ofmore extreme weather events.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 affect the Company’sour business and operations.
| |
| Item 1A. | Risk Factors (Continued) |
Our operations could be adversely impacted by initiatives designed to reduce the impact of greenhouse gas (GHG)GHG emissions such as carbon dioxide CO2from our generating facilities.
Proposals for voluntary initiatives and mandatory controls to reduce GHGs such as carbon dioxide,CO2, a by-product of burning fossil fuels, are beinghave been discussed within Minnesota, among a group of Midwestern states that includes Minnesota and in the United States Congress and worldwide.Congress. We currently use coal as the primary fuel in 95 percent of the energy produced by our generating facilities.
We cannot be certainThere is significant uncertainty regarding whether new laws or regulations will be adopted to reduce GHGs and what affecteffect any such laws or regulations would have on us. If any new laws or regulations are implemented, they could have a material effect on our results of operations, particularly if implementation costs are not fully recoverable from customers.
Risk Factors (Continued)
The cost of environmental emission allowances could have a negative financial impact on our operations.
Minnesota Power is subject to numerous environmental laws and regulations which cap emissions and could require us to purchase environmental emissions allowances to be in compliance. The laws and regulations expose us to emission allowance price fluctuationsincreases which could increase our cost of operations. We are unable to predict the emission allowance pricing, regulatory recovery or ratepayer impact of these costs.
Our operations pose certain environmental risks which could adversely affect our results of operations and financial condition.
We are subject to extensive environmental laws and regulations affecting many aspects of our present and future operations, including air quality, water quality, waste management, reclamation, hazardous wastes and other environmental considerations.natural resources. These laws and regulations can result in increased capital, operating and other costs, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions.
The laws could, among other things, restrict the output of some existing facilities, limit the use of some fuels required for the production of electricity, require additional pollution control equipment and otherwise increase costs and lead to other environmental considerations.
These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the financial or operational outcome of any related litigation that may arise.
There are no assurances that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not 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 a material effect on our results of operations.
We cannot predict with certainty the amount or timing of all future expenditures related to environmental matters because of the difficulty of estimating such costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Violations of certain statutes, rules and regulations could expose ALLETE to third party disputes and potentially significant monetary penalties, as well as other sanctions for non-compliance.
We rely on access to financing sources and capital markets. If we do not have access to sufficient capital in the amount and at the times needed, our ability to execute our business plans, make capital expenditures or pursue acquisitions that we may otherwise rely on for future growth could be impaired.
We rely on access to capital markets as sources of liquidity for capital requirements not satisfied by our cash flow from operations. If we are not able to access capital on satisfactory terms, the ability to implement our business plans may be adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our ability to access financial markets. Such disruptions could include a severe prolonged economic downturn, the bankruptcy of non-affiliated industry leaders in the same line of business or financial services sector, deterioration in capital market conditions, or volatility in commodity prices.
| |
| Item 1A. | Risk Factors (Continued) |
The operation and maintenance of our generating facilities involve risks that could significantly increase the cost of doing business.
The operation of generating facilities involves many risks, including start-up operations risks, breakdown or failure of facilities, the dependence on a specific fuel source, failures in the supply availability or transportation of fuel, or 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, the occurrence of any of which could result in lost revenue, increased expenses or both. A significant portion of Minnesota Power’s facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency. This equipment is also likely to require periodic upgrading and improvements due to changing environmental standards and technological advances. Minnesota Power could be subject to costs associated with any unexpected failure to produce power, including failure caused by breakdown or forced outage, as well as repairing damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement.
Our electrical generating operations mustmay not have access to adequate and reliable transmission and distribution facilities to deliver electricity to our customers.
Minnesota Power depends on transmission and distribution facilities owned by other utilities, and transmission facilities primarily operated by MISO, as well as its own such facilities, to deliver the electricity we produce and sell to our customers, and to other energy suppliers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered. We may have to foregoforgo sales or we 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 with our service.
Risk Factors (Continued)
In our operations theThe price of electricity and fuel may be volatile.
Volatility in market prices for electricity and fuel could adversely impact our results of operations and financial condition and may result from:
| · | severe or unexpected weather conditions; |
| · | 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 Minnesota Power’s generating facilities or those of our competitors; |
| · | changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products; |
transportation of fuel; | · | natural disasters, wars, sabotage, terrorist acts or other catastrophic events; and |
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products; | · | natural disasters, wars, sabotage, terrorist acts or other catastrophic events; and federal, state, local and foreign energy, environmental, or other regulation and legislation. |
Since fluctuations in fuel expense related to our regulated utility operations are passed on to customers through our fuel clause, risk of volatility in market prices for fuel and electricity mainly impacts our wholesale power sales.sales to Other Power Suppliers.
We are dependentThe inability to retain and attract a qualified workforce including, but not limited to, executives, key employees and employees with specialized skills, could have an adverse effect on good labor relations.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, executives, 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. We believe ourwe have good relations to be good with our 1,474 employees. Failure to successfully renegotiate labor agreements could adversely affect the services we provide and our results of operations. Currently, 714 of our employees are members of either the IBEW Local 31 orand IBEW Local 1593. The labor agreement with Local 31 at Minnesota Power1593, and SWL&P expired onhave contracts in place through January 31, 2009. A new agreement between Minnesota Power2014, and Local 31 went into effect in January 2010. The terms of the agreement are retroactive to February 1, 2009 and will expire on January 31, 2012. SWL&P continues to work with its union and the arbitrator to resolve the remaining differences between the parties. The labor agreement with Local 1593 at BNI Coal expires on March 31, 2011.2014, respectively.
ALLETE 2011 Form 10-K
28
The current downturn in economic conditions may continue to adversely affect our real estate investment.
The ability of our real estate investment to generate revenue is directly related to the Florida real estate market, the national and local economy in general and changes in interest rates and the availability of credit. While conditions in the Florida real estate market may fluctuate over the long-term, continued demand for land is dependent on long-term prospects for strong, in-migration population expansion.
Our real estate investment is subject to extensive regulation through Florida laws regulating planning and land development which makes it difficult and expensive for us to conduct our operations.
Development of real property in Florida entails an extensive approval process involving overlapping regulatory jurisdictions. Real estate projects must generally comply with the provisions of the Local Government Comprehensive Planning and Land Development Regulation Act (Growth Management Act). In addition, development projects that exceed certain specified regulatory thresholds require approval of a comprehensive DRI application. The Growth Management Act, in some instances, can significantly affect the ability of developers to obtain local government approval in Florida. In many areas, infrastructure funding has not kept pace with growth. As a result, substandard facilities and services can delay or prevent the issuance of permits. Consequently, the Growth Management Act could adversely affect the cost of and our ability to develop future real estate projects. Changes in the Growth Management Act or DRI review process or the enactment of new laws regarding the development of real property could adversely affect our ability to develop future real estate projects. | |
Item 1A. | Risk Factors (Continued) |
Market performance and other changes could decrease the value of pension and postretirement health benefit plan assets, which then could require significant additional funding and increase annual expense.
The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under our pension and postretirement benefit plans. We have significant obligations to these plans and the Company holdswe hold significant assets in these trusts. 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 postretirement benefit plan assets will increase the funding requirements under our benefit plans if the actual asset returns do not recover. Additionally, our pension and 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.
ALLETE 2009 Our pension and postretirement health care costs are generally recoverable in our electric rates as allowed by our regulators. However, there is no certainty that regulators will continue to allow recovery of these rising costs in the future. See Note 16. Pension and Other Postretirement Benefit Plans of this Form 10-K
Risk Factors (Continued) for more details regarding our current contributions and funding status.
Emerging technologies may adversely affect our business operations.
While the pace of technology development has been increasing, the basic concept upon which our business model is based of how energy is produced, sold and delivered, has remained essentially unchanged. The development of new commercially viable technology in areas such as distributed generation, energy storage and energy conservation could fundamentally change demand for our current products and services.
We may be vulnerable to cyber attacks and terrorism.
Man-made problems such as computer viruses, terrorism, theft and sabotage, may disrupt our operations and harm our operating results. Our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Our technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows.
There may be risks associated with the operation of any newly acquired assets as we can make no assurance that results from any acquisition will conform to our expectations. This in turn could adversely affect our results of operations and financial condition.
Acquisitions are not ablesubject to uncertainties. Our actual results may differ from our expectations due to factors such as our ability to obtain timely regulatory or governmental approvals, integration and operational issues and the ability to retain our executive officersmanagement and other key employees, we may not be able to implement our business strategy and our business could suffer.personnel.
The success of our business heavily depends on the leadership of our executive officers, all of whom are employees-at-will and none of whom are subject to any agreements not to compete. If we lose the service of one or more of our executive officers or key employees, or if one or more of them decides to join a competitor or otherwise compete directly or indirectly with us, wecontinued downturn in economic conditions may not be able to successfully manage our business or achieve our business objectives. We may have difficulty in retaining and attracting customers, developing new services, negotiating favorable agreements with customers and providing acceptable levels of customer service.
We rely on access to financing sources and capital markets. If we do not have access to sufficient capital in the amount and at the times needed, our ability to execute our business plans, make capital expenditures or pursue acquisitions that we may otherwise rely on for future growth could be impaired.
We rely on access to capital markets as sources of liquidity for capital requirements not satisfied by our cash flow from operations. If we are not able to access capital on satisfactory terms, the ability to implement our business plans may be adversely affected. Market disruptions or a downgrade of our credit ratings may increase the cost of borrowing or adversely affect our abilitystrategy to access financial markets. Such disruptions could include a severe prolonged economic downturn, the bankruptcy of non-affiliated industry leaderssell our Florida real estate.
ALLETE intends to sell its Florida land assets over time or in the same line of business or financial services sector, deterioration in capitalbulk transactions when opportunities arise. However, if weak market conditions or volatilitycontinue, the impact on our future operations would be the continuation of little to no sales while still incurring operating expenses such as community development district assessments and property taxes. This could result in commodity prices.continued annual net operating losses. See Note 1. Operations and Significant Accounting Policies – Impairment of Long-Lived Assets.
| |
| Item 1B. | Unresolved Staff Comments |
None.
Properties are included in the discussion of our businesses in Item 1 and are incorporated by reference herein.
Material legal and regulatory proceedings are included in the discussion of our businesses in Item 1 and are incorporated by reference herein.
United Taconite Lawsuit. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of December 31, 2011, because a potential loss is not currently probable; however, the Company believes it has adequate insurance coverage for potential loss.
Interim Rate Decision. On February 22, 2011, Minnesota Power appealed the MPUC's interim rate decision in the Company's 2010 rate case with the Minnesota Court of Appeals. The Company appealed the MPUC's finding of exigent circumstances in the interim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a body of record evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC's finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a petition for review at the Minnesota Supreme Court, but cannot predict the outcome at this time.
CapX2020 Bemidji to Grand Rapids Line. In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids, Minnesota line and construction for the 230 kV line project commenced in January 2011. The Leech Lake Band of Ojibwe (LLBO) subsequently requested the MPUC suspend or revoke the route permit and also served the CapX2020 owners with a complaint filed in Leech Lake Tribal Court asserting adjudicatory and regulatory authority over the project. The CapX2020 owners filed a request for declaratory judgment in the United States District Court for the District of Minnesota (District Court) that the project does not require LLBO consent to cross non-tribal land within the reservation. On June 22, 2011, the federal judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The LLBO abandoned its motion to dismiss the declaratory action because the District Court’s injunction order had already dismissed the basis for the motion, namely, that the District Court did not have jurisdiction to hear the CapX2020 owners’ action. The parties are now proceeding with discovery and the CapX2020 owners do not anticipate any actions by the District Court until after the completion of discovery closes on May 31, 2012. The MPUC has taken no action in the matter in light of ongoing litigation in federal and tribal courts. The CapX2020 utilities are vigorously defending against the LLBO actions.
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, 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. | Submission of Matters to a Vote of Security HoldersMine Safety Disclosures |
NoThe 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 were submittedrequired by Section 1503(a) of the Dodd-Frank Act and this Item are included in Exhibit 95 to a vote of security holders during 2009.
this Form 10-K.
ALLETE 20092011 Form 10-K
30
Part II
| |
| Item 5. | Market for Registrant’sRegistrant'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 $0.44$0.46 per share on our common stock will be paidis payable on March 1, 2010,2012, to the holders of record on February 15, 2010.2012.
The following table shows dividends declared per share, and the high and low prices for our common stock for the periods indicated as reported by the NYSE:
| | | | 2009 | 2008 | | 2011 | | 2010 | |
| | Price Range | Dividends | Price Range | Dividends | Price Range | Dividends | Price Range | Dividends |
| Quarter | High | Low | Declared | High | Low | Declared | High | Low | Declared | High | Low | Declared |
| | | | | | | | |
| First | $33.27 | $23.35 | $0.44 | $39.86 | $33.76 | $0.43 |
| $39.36 |
|
| $36.33 |
|
| $0.445 |
|
| $34.00 |
|
| $29.99 |
|
| $0.44 |
|
| Second | 29.14 | 24.45 | 0.44 | 46.11 | 38.82 | 0.43 | 41.43 |
| 37.87 |
| 0.445 |
| 37.87 |
| 32.90 |
| 0.44 |
|
| Third | 34.57 | 27.75 | 0.44 | 49.00 | 38.05 | 0.43 | 42.10 |
| 35.51 |
| 0.445 |
| 37.75 |
| 33.16 |
| 0.44 |
|
| Fourth | 35.29 | 32.23 | 0.44 | 44.63 | 28.28 | 0.43 | 42.54 |
| 35.14 |
| 0.445 |
| 37.95 |
| 34.81 |
| 0.44 |
|
| Annual Total | | | $1.76 | | | $1.72 | |
| $1.78 |
| |
| $1.76 |
|
At February 1, 2010,2012, there were approximately 29,00027,000 common stock shareholders of record.
Common Stock Repurchases. We did not repurchase any ALLETE common stock during 2009.
ALLETE 20092011 Form 10-K
31
| |
| Item 6. | Selected Financial Data |
| | | | 2009 | | 2008 | | 2007 | | 2006 | | 2005 | | 2011 |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
|
| Millions | | | | | | | | | | | |
| Operating Revenue | $759.1 | | $801.0 | | $841.7 | | $767.1 | | $737.4 | |
| $928.2 |
|
| $907.0 |
|
| $759.1 |
|
| $801.0 |
|
| $841.7 |
|
| Operating Expenses | 653.1 | | 679.2 | | 710.0 | | 628.8 | | 692.3 | (e) | 778.2 |
| 771.2 |
| 653.1 |
| 679.2 |
| 710.0 |
|
| Income from Continuing Operations Before Non-Controlling Interest – Net of Tax | 60.7 | | 83.0 | | 89.5 | | 81.9 | | 20.3 | (e) | |
| Income (Loss) from Discontinued Operations – Net of Tax | – | | – | | – | | (0.9) | | (4.3) | (e) | |
| Net Income | 60.7 | | 83.0 | | 89.5 | | 81.0 | | 16.0 | | 93.6 |
| 74.8 |
| 60.7 |
| 83.0 |
| 89.5 |
|
| Less: Non-Controlling Interest in Subsidiaries | (0.3) | | 0.5 | | 1.9 | | 4.6 | | 2.7 | | (0.2 | ) | (0.5 | ) | (0.3 | ) | 0.5 |
| 1.9 |
|
| Net Income Attributable to ALLETE | 61.0 | | 82.5 | | 87.6 | | 76.4 | | 13.3 | | 93.8 |
| 75.3 |
| 61.0 |
| 82.5 |
| 87.6 |
|
| Common Stock Dividends | 56.5 | | 50.4 | | 44.3 | | 40.7 | | 34.4 | | 62.1 |
| 60.8 |
| 56.5 |
| 50.4 |
| 44.3 |
|
| Earnings Retained in (Distributed from) Business | $4.5 | | $32.1 | | $43.3 | | $35.7 | | $(21.1) | | |
| Earnings Retained in Business | |
| $31.7 |
|
| $14.5 |
|
| $4.5 |
|
| $32.1 |
|
| $43.3 |
|
| Shares Outstanding – Millions | | | | | | | | | | | |
| Year-End | 35.2 | | 32.6 | | 30.8 | | 30.4 | | 30.1 | | 37.5 |
| 35.8 |
| 35.2 |
| 32.6 |
| 30.8 |
|
Average (a) | | | | | | | | | | | |
| Basic | 32.2 | | 29.2 | | 28.3 | | 27.8 | | 27.3 | | 35.3 |
| 34.2 |
| 32.2 |
| 29.2 |
| 28.3 |
|
| Diluted | 32.2 | | 29.3 | | 28.4 | | 27.9 | | 27.4 | | 35.4 |
| 34.3 |
| 32.2 |
| 29.3 |
| 28.4 |
|
| Diluted Earnings (Loss) Per Share | | | | | | | | | | | |
| Continuing Operations | $1.89 | | $2.82 | | $3.08 | | $2.77 | | $0.64 | (e) | |
Discontinued Operations (b) | – | | – | | – | | (0.03) | | (0.16) | | |
| | $1.89 | | $2.82 | | $3.08 | | $2.74 | | $0.48 | | |
| Diluted Earnings Per Share | |
| $2.65 |
|
| $2.19 |
|
| $1.89 |
|
| $2.82 |
|
| $3.08 |
|
| Total Assets | $2,393.1 | | $2,134.8 | | $1,644.2 | | $1,533.4 | (d) | $1,398.8 | |
| $2,876.0 |
|
| $2,609.1 |
|
| $2,393.1 |
|
| $2,134.8 |
|
| $1,644.2 |
|
| Long-Term Debt | 695.8 | | 588.3 | | 410.9 | | 359.8 | | 387.8 | | 857.9 |
| 771.6 |
| 695.8 |
| 588.3 |
| 410.9 |
|
| Return on Common Equity | 6.9% | | 10.7% | | 12.4% | | 12.1% | | 2.2% | (e) | 9.1 | % | 7.8 | % | 6.9 | % | 10.7 | % | 12.4 | % |
| Common Equity Ratio | 57.0% | | 58.0% | | 63.7% | | 63.1% | | 60.7% | | 56 | % | 56 | % | 57 | % | 58 | % | 64 | % |
| Dividends Declared per Common Share | $1.76 | | $1.72 | | $1.64 | | $1.45 | | $1.245 | |
| $1.78 |
|
| $1.76 |
|
| $1.76 |
|
| $1.72 |
|
| $1.64 |
|
| Dividend Payout Ratio | 93% | | 61% | | 53% | | 53% | | 259% | (e) | 67 | % | 80 | % | 93 | % | 61 | % | 53 | % |
| Book Value Per Share at Year-End | $26.39 | | $25.37 | | $24.11 | | $21.90 | | $20.03 | |
| $28.77 |
|
| $27.25 |
|
| $26.39 |
|
| $25.37 |
|
| $24.11 |
|
Capital Expenditures by Segment (c) | | | | | | | | | | | |
| Capital Expenditures by Segment | | |
| Regulated Operations | $299.2 | | $317.0 | | $220.6 | | $107.5 | | $46.5 | |
| $228.0 |
|
| $256.4 |
|
| $299.2 |
|
| $317.0 |
|
| $220.6 |
|
| Investments and Other | 4.5 | | 5.9 | | 3.3 | | 1.9 | | 12.1 | | 18.8 |
| 3.6 |
| 4.5 |
| 5.9 |
| 3.3 |
|
| Discontinued Operations | – | | – | | – | | – | | 4.5 | | |
| Total Capital Expenditures | $303.7 | | $322.9 | | $223.9 | | $109.4 | | $63.1 | |
| $246.8 |
|
| $260.0 |
|
| $303.7 |
|
| $322.9 |
|
| $223.9 |
|
| |
| (a) | Excludes unallocated ESOP shares. |
(b) | Operating results of our Water Services businesses and our telecommunications business are included in discontinued operations, and accordingly, amounts have been restate for all periods presented. |
(c) | In 2008, we made changes to our reportable business segments in our continuing effort to manage and measure performance of our operations based on the nature of products and services provided and customers served. (See Note 2. Business Segments.) |
(d) | Included $86.1 million of assets reflecting the adoption of Plan Accounting – Defined Benefit Pension Plans, and Health and Welfare Benefit Plans. |
(e) | Impacted by a $50.4 million, or $1.84 per share, charge related to the assignment of the Kendall County power purchase agreement. |
ALLETE 20092011 Form 10-K
32
| |
| Item 7. | Management’sManagement'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 report 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: “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995”“Forward-Looking Statements” located on page 56 and “Risk Factors” located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only ones 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 concerns set forth in this Form 10-K are realized.
Overview
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 parts of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 144,000 retail customers. Minnesota Power's non-affiliated municipal customers and wholesale electric service toconsist of 16 municipalities.municipalities in Minnesota Power also provides regulated utility electric service toand 1 private utility in Wisconsin. SWL&P is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 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. (Seeauthorities. (See Item 1. Business – Regulated Operations – Regulatory Matters.)
Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, formed in June 2011, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes a small amount of non-rate base generation, approximately 7,0005,500 acres of land available-for-sale 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, 2009,2011, 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.
20092011 Financial Overview
The following net income discussion summarizes a comparison of the year ended December 31, 2009,2011, to the year ended December 31, 2008.2010.
NetConsolidated net income attributable to ALLETE for 20092011 was $61.0$93.8 million, or $1.89$2.65 per diluted share, compared to $82.5$75.3 million, or $2.82$2.19 per diluted share, for 2008.2010. This increase is due to higher net income at our Regulated Operations segment, partially offset by increased losses at our Investments and Other segment (see below for detailed discussion). Earnings per diluted share decreased approximately $0.19 compared to 2008dilution was $0.08 as a result of additional shares of common stock outstanding in 2009.2011. (See Note 12. Common Stock and Earnings Per Share.)
Regulated Operations net income attributable to ALLETE was $65.9$100.4 million in 2009 ($67.92011, compared to $79.8 million in 2008)2010. The decrease is primarily attributableNet income for 2011 included the reversal of a $6.2 million deferred tax liability related to lower net income ata revenue receivable Minnesota Power dueagreed to forgo as part of a 4.1 percent decreasestipulation and settlement agreement in kilowatt-hourits 2010 rate case and the recognition of a $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA. Net income for 2011 also included higher retail and municipal MWh sales, higher depreciationcurrent cost recovery rider revenue, an increase in our financial incentives under the Minnesota Conservation Improvement Program, an increase in wholesale rates, and interest expense, and the accrual of retail rate refunds related to 2008. These decreasesincreased renewable tax credits, which were partially offset by increased FERC-approved wholesale rateshigher operating and MPUC-approved current cost recovery revenue. In addition, 2009 reflected $1.4maintenance, depreciation, property tax, benefit and interest expenses. Net income for 2010 was reduced by a $3.6 million in additional after-tax earningscharge resulting from our investment in ATC asPPACA and a result$3.4 million (after-tax) charge for the write-off of additional investments madea deferred fuel clause regulatory asset related to fund our pro-rata share of ATC’s voluntary capital contribution program.the 2008 rate case.
Investments and Other reflected a net loss attributableof $6.6 million for 2011, compared to ALLETE of $4.9 million in 2009 ($14.6 million of net income attributable to ALLETE in 2008). The decrease is primarily attributable to a $6.5 million reduction in earnings at ALLETE Properties and the absence of non-recurring items recorded in 2008. In 2009, ALLETE Properties recorded a net loss of $4.7$4.5 million versus in 2010. The increase in net income of $1.8 million in 2008. In 2008, we recorded a $3.8 million non-recurring gain on the sale of certain available-for-sale securities and $5.8 million in non-recurring tax benefits and related interestloss was primarily due to the closinghigher business development, state income tax and investment related expenses. The net loss in 2010 included an income tax benefit of a tax year and$1.1 million (including interest) resulting from the completion of an IRS review.a state income tax audit.
ALLETE 20092011 Form 10-K
33
20092011 Compared to 20082010
(See Note 2. Business Segments for financial results by segment.)
Regulated Operations
Operating revenue decreased $30.4increased$16.4 million, or 2 percent, from 2010 primarily due to increased sales to our retail and municipal customers, increased current cost recovery rider revenue, higher fuel clause recoveries, increased financial incentives under the Minnesota Conservation Improvement Program, and implementation of final retail rates. These increases were partially offset by lower sales to Other Power Suppliers.
Revenue and kilowatt-hour sales to retail and municipal customers increased $21.5 million and 5.6 percent, respectively, from 2010 primarily due to a 8.2 percent increase in kilowatt-hour sales to our industrial customers and the implementation of final retail rates. Increased revenue from those sales was offset by a $30.5 million and a 19.7 percentdecrease in revenue and kilowatt-hour sales, respectively, to Other Power Suppliers. 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.
|
| | | | | | | | |
Kilowatt-hours Sold | 2011 |
| 2010 |
| Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipals | | | | |
| Residential | 1,159 |
| 1,150 |
| 9 |
| 0.8 |
|
| Commercial | 1,433 |
| 1,433 |
| — |
| — |
|
| Industrial | 7,365 |
| 6,804 |
| 561 |
| 8.2 |
|
| Municipals | 1,013 |
| 1,006 |
| 7 |
| 0.7 |
|
| Total Retail and Municipals | 10,970 |
| 10,393 |
| 577 |
| 5.6 |
|
| Other Power Suppliers | 2,205 |
| 2,745 |
| (540 | ) | (19.7 | ) |
| Total Regulated Utility Kilowatt-hours Sold | 13,175 |
| 13,138 |
| 37 |
| 0.3 |
|
Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2011 (24 percent in 2010). Revenue from electric sales to paper, pulp and wood product customers accounted for 9 percent of consolidated operating revenue in 2011 (9 percent in 2010). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2011 (6 percent in 2010).
Current cost recovery rider revenue increased $12.2 million due to higher capital expenditures primarily related to our Bison 1 and CapX2020 projects.
Fuel adjustment clause recoveries increased $6.3 million, or 48 percent, from 20082010 due to loweran increase in kilowatt-hour sales and higher fuel and purchased power recoveries, lowercosts attributable to our retail and municipal customers.
Financial incentives under the Minnesota Conservation Improvement Program increased $5.9 million reflecting a shared savings model to recognize utility progress toward meeting the energy-saving goal of 1.5 percent established in the Next Generation Energy Act of 2007.
Wholesale rate revenue increased $5.6 million reflecting higher rates.
Operating expenses were consistent with 2010 overall.
Fuel and Purchased Power Expensedecreased$18.5 million, or 6 percent, from 2010 primarily due to a 23 percent reduction in MWhs purchased and lower purchased power prices. In 2010, additional purchased power was required to meet planned major outages at Boswell and Square Butte. Also included in 2010 was a $5.4 million charge for the write-off of a deferred fuel clause regulatory asset related to the 2008 rate case. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause (see Operating Revenue) and increased due to higher kilowatt-hour sales to these customers.
2011 Compared to 2010 (Continued)
Regulated Operations (Continued)
Operating and Maintenance Expenseincreased$9.2 million, or 3 percent, from 2010 primarily reflecting increased property tax and benefit expense. Property tax expense increased $5.5 million due to more taxable plant and higher rates while benefits increased $4.0 primarily due to increased pension costs as a result of lower natural gasdiscount rates.
Depreciation Expenseincreased$9.3 million, or 12 percent, from 2010 reflecting additional property, plant and equipment in service.
Interest expenseincreased$3.5 million, or 11 percent, from 2010 primarily due to higher long-term debt balances.
Income tax expensedecreased$8.4 million, or 16 percent, from 2010 primarily due to the reversal of a $6.2 million deferred tax liability related to a revenue receivable Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, increased renewable tax credits of $3.2 million and the recognition of a non-recurring $2.9 million income tax benefit related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 resulting from PPACA. Also contributing to the decrease was a non-recurring income tax charge of $3.6 million resulting from PPACA in the first quarter of 2010. (See Note 5. Regulatory Matters.)
Investments and Other
Operating revenueincreased$4.8 million, or 7 percent, from 2010 reflecting a $5.6 million increase in revenue at SWL&P,BNI Coal, partially offset by a $0.9 million decrease in revenue at ALLETE Properties. BNI Coal, which operates under a cost-plus contract, recorded higher sales revenue as a result of higher expenses in 2011. (See Operating Expense.)
|
| | | | | | | | | | |
| ALLETE Properties | | 2011 | | 2010 |
| Revenue and Sales Activity | Quantity |
| Amount |
| Quantity |
| Amount |
|
| Dollars in Millions | | | | |
| Revenue from Land Sales | | | | |
Acres (a) | 3 |
|
| $0.4 |
| — |
| — |
|
| Revenue from Land Sales | | 0.4 |
| | — |
|
Other Revenue (b) | | 0.9 |
| |
| $2.2 |
|
| Total ALLETE Properties Revenue | |
| $1.3 |
| |
| $2.2 |
|
| |
| (a) | Acreage amounts are shown on a gross basis, including wetlands. |
| |
| (b) | For the year ended December 31, 2011, Other Revenue included mitigation bank credit sales, finance income, and a forfeited deposit on a land sale contract. For the year ended December 31, 2010, Other Revenue included a $0.7 million pretax gain due to the return of seller-financed property from an entity which filed for Chapter 11 bankruptcy in June 2009. Also included in 2010 were $0.3 million of forfeited deposits and $0.3 million related to a lawsuit settlement. |
Operating expenses increased $7.0 million, or 9 percent, from 2010 reflecting higher expenses at BNI Coal of $5.1 million primarily due to higher fuel costs; these costs were recovered through the cost-plus contract. (See Operating Revenue.) The remaining increase in 2011 was primarily attributable to higher business development, interest and investment-related expenses. Also contributing to the increased expenses was a $1.7 million pretax impairment charge taken at ALLETE Properties. In the fourth quarter of 2011, an impairment analysis of estimated future undiscounted cash flows was conducted and indicated that the cash flows were not adequate to recover the carrying basis of certain properties not strategic to our three major development projects. These increases were partially offset by a reduction in operating expenses at ALLETE Properties.
Income Taxes – Consolidated
For the year ended December 31, 2011, the effective tax rate was 27.6 percent (37.2 percent for the year ended December 31, 2010). Excluding additional tax benefits recorded as a result of the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of PPACA and the reversal of a deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case, the 2011 effective tax rate was 32.7 percent. The effective tax rate deviated from the statutory rate (approximately 41 percent) in each period due to deductions for depletion, investment tax credits, and renewable tax credits. (See Note 14. Income Tax Expense.)
2010 Compared to 2009
(See Note 2. Business Segments for financial results by segment.)
Regulated Operations
Operating revenue increased $153.7 million, or 23 percent, from 2009 due to higher MPUC-approved retail rates (subject to final order) and the absence of an accrual offor prior year retail rate refunds related to our 2008 retail rate case. Also contributing to increased revenue were higher transmission revenues, higher fuel and purchased power recoveries, and increased sales to retail and municipal customers. These decreasesincreases were partially offset by higherlower sales to Other Power Suppliers, higher FERC-approved wholesale rates and increased revenue from MPUC-approved current cost recovery riders.Suppliers.
LowerInterim retail rates authorized by the MPUC in December 2009 and effective January 1, 2010, resulted in an increase of approximately $52 million.
Retail rate refunds related to 2008 resulting from the 2009 MPUC rate order were recorded in 2009 and resulted in a reduction in 2009 revenues of $7.6 million.
Transmission revenues increased $24.3 million from 2009 primarily due to revenues related to the 250 kV DC transmission line purchased from Square Butte on December 31, 2009.
Higher fuel and purchased power recoveries, along with a decreasean increase in retail and municipal kilowatt-hour sales, combined for a total revenue reductionincrease of $116.2$115.5 million. Fuel and purchased power recoveries decreasedincreased due to a reductionan increase in fuel and purchased power expense. (See Fuel and Purchased Power Expense.) Total kilowatt-hour sales to retail and municipal customers decreased 26 percent from 2008 primarily due to idled production lines and temporary closures at some of our taconite customers’ plants.
Natural gas revenue at SWL&P was lower by $7.8 million due to a 27 percent decrease in the price of natural gas and a 9 percent decline in sales. Natural gas revenue is primarily a flow-through of the natural gas costs. (See Operating and Maintenance Expense.)
Prior year retail rate refunds resulting from the 2009 MPUC Order and August 2009 Reconsideration Order were recorded in 2009 and resulted in a reduction in revenues of $7.6 million.
The decreaseincrease in kilowatt-hour sales to retail and municipal customers has beenwas partially offset by decreased revenue from marketing the power to Other Power Suppliers, which increased $77.2decreased $50.3 million in 2009.2010. 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.
Higher rates from the March 1, 2008,Total kilowatt-hour sales to retail and February 1, 2009, FERC-approved wholesale rate increases for our municipal customers increased revenue by $13.2 million.
MPUC-approved current cost recovery rider revenue increased $10.4 million in29.1 percent from 2009 from 2008 primarily due to increased capital expenditures relatedan increase in sales to our Boswell Unit 3 emission reduction plan.taconite customers. Increased revenue from industrial sales was partially offset by a 32.3 percent decrease in kilowatt-hour sales to Other Power Suppliers.
| Kilowatt-hours Sold | 2009 | 2008 | Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipals | | | | |
| Residential | 1,164 | 1,172 | (8) | (0.7) % |
| Commercial | 1,420 | 1,454 | (34) | (2.3) % |
| Industrial | 4,475 | 7,192 | (2,717) | (37.8) % |
| Municipals | 992 | 1,002 | (10) | (1.0) % |
| Total Retail and Municipals | 8,051 | 10,820 | (2,769) | (25.6) % |
| Other Power Suppliers | 4,056 | 1,800 | 2,256 | 125.3 % |
Total Regulated Utility Kilowatt-hours Sold | 12,107 | 12,620 | (513) | (4.1) % |
|
| | | | | | | | |
Kilowatt-hours Sold | 2010 |
| 2009 |
| Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipals | | | | |
| Residential | 1,150 |
| 1,164 |
| (14 | ) | (1.2 | ) |
| Commercial | 1,433 |
| 1,420 |
| 13 |
| 0.9 |
|
| Industrial | 6,804 |
| 4,475 |
| 2,329 |
| 52.0 |
|
| Municipals | 1,006 |
| 992 |
| 14 |
| 1.4 |
|
| Total Retail and Municipals | 10,393 |
| 8,051 |
| 2,342 |
| 29.1 |
|
| Other Power Suppliers | 2,745 |
| 4,056 |
| (1,311 | ) | (32.3 | ) |
| Total Regulated Utility Kilowatt-hours Sold | 13,138 |
| 12,107 |
| 1,031 |
| 8.5 |
|
Revenue from electric sales to taconite customers accounted for 1524 percent of consolidated operating revenue in 2009 (262010 (15 percent in 2008)2009). The decreaseincrease in revenue from our taconite customers was partially offset by a decrease in revenue from electric sales to Other Power Suppliers, which accounted for 2012 percent of consolidated operating revenue in 2009 (102010 (20 percent in 2008)2009). Revenue from electric sales to paper, pulp and pulp millswood product customers accounted for 9 percent of consolidated operating revenue in 20092010 (9 percent in 2008)2009). Revenue from electric sales to pipelines and other industrials accounted for 76 percent of consolidated operating revenue in 20092010 (7 percent in 2008)2009).
Operating expenses decreased $20.1 increased $118.0 million, or 321 percent, from 2008.2009.
2010 Compared to 2009 (Continued)
Regulated Operations (Continued)
Fuel and Purchased Power Expense decreased $26.1 increased $45.6 million, or 916 percent, from 20082009. The increase was partially due to decreasedhigher fuel costs of $18.6 million resulting from a 10 percent increase in coal generation at our facilities and higher coal prices and related transportation. Purchased power generation attributableexpense also increased $19.1 million reflecting increased kilowatt-hour purchases partially offset by lower market prices. Also included in the fourth quarter of 2010 was a $5.4 million charge for the write-off of a deferred fuel clause regulatory asset related to lower kilowatt-hour sales, as well as a reductionthe 2008 rate case, which was determined to be no longer probable of recovery in wholesale electricity prices.future utility rates. In 2009, Minnesota Power’s coal generating fleet produced fewer kilowatt-hours of electricity due to planned outages to implement environmental retrofits and to respond to decreased demand from our taconite customers.
Operating and Maintenance Expense decreased $3.5 increased $56.5 million, or 24 percent, from 2008 primarily2009 reflecting additional MISO expenses of $17.3 million relating to the 250 kV DC transmission line purchased from Square Butte on December 31, 2009, higher plant outage and maintenance of $10.2 million, higher environmental reagent expenses of $6.1 million, increased labor and employee benefit costs of $11.0 million and increased property taxes of $3.0 million due to $7.4 million in lower natural gas costs at SWL&P from a decline in the price and quantity of natural gas purchased. This decrease was partially offset by increased salaries and benefits costs, rate case expenses and plant maintenance.more taxable plant.
2009 Compared to 2008 (Continued)
Regulated Operations (Continued)
Depreciation Expenseincreased $9.5$15.9 million, or 1926 percent, from 20082009 reflecting higher property, plant, and equipment balances placed in service.
Interest expenseincreased $4.3$4.0 million, or 1814 percent, from 20082009 primarily due to additional long-term debt issued to fund new capital investments and $0.5 million related to retail rate refunds.for general corporate purposes.
Income tax expenseEquity earnings increased $2.2$16.2 million, or 1446 percent, from 2008 reflecting2009 primarily due to higher earningspretax income and a non-recurring income tax charge of $3.6 million from our increased investment in ATC. (See Note 6. Investment in ATC.)the deduction of expenses reimbursed under Medicare Part D.
Investments and Other
Operating revenue decreased $11.5$5.8 million, or 138 percent, from 20082009 primarily due to a $14.3$4.8 million reductiondecrease in revenue from non-regulated generation. This decrease was primarily the result of the transfer of a small generating facility to Regulated Operations in November 2009. This decrease was partially offset by a $1.3 million increase in revenue at BNI Coal, which operates under a cost-plus contract and recorded higher sales revenue as a result of higher expenses in 2010. (See Operating Expense.)
Revenue at ALLETE Properties. InProperties decreased $1.8 million from 2009 ALLETE Properties sold approximately 35 acresprimarily due to lack of properties located outside of our three main development projects for $3.8 million; no otherland sales were made in 2009during 2010. This was due to the continued lack of demand for our properties as a result of poor real estate market conditions in Florida. In 2008,During 2009, ALLETE Properties sold approximately 21935 acres of property located outside of ourits three main development projects for $6.3 million and recognized $3.7 million of previously deferred revenue under percentage of completion accounting. Revenue at ALLETE Properties in 2008 also included a pre-tax gain of $4.5 million from the sale of a retail shopping center in Winter Haven, Florida.$3.8 million.
| | | ALLETE Properties | 2009 | 2008 | | 2010 | | 2009 |
| Revenue and Sales Activity | Quantity | Amount | Quantity | Amount | Quantity |
| Amount |
| Quantity |
| Amount |
|
| Dollars in Millions | | | | | |
| Revenue from Land Sales | | | | | |
Acres (a) | 35 | $3.8 | 219 | $6.3 | — |
| — |
| 35 |
|
| $3.8 |
|
Contract Sales Price (b) | | 3.8 | | 6.3 | |
| Revenue Recognized from Previously Deferred Sales | | – | | 3.7 | |
Revenue from Land Sales | | 3.8 | | 10.0 | | — |
| | 3.8 |
|
Other Revenue (c) | | 0.2 | | 8.3 | |
| $2.2 |
| | 0.2 |
|
| Total ALLETE Properties Revenue | | $4.0 | | $18.3 | |
| $2.2 |
| |
| $4.0 |
|
| |
| (a) | Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest. |
| |
| (b) | ReflectedReflects total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method. (See Note 1. Operations and Significant Accounting Policies.) |
| |
| (c) | IncludedOther Revenue included a $4.5$0.7 million pre-taxpretax gain in 2010 due to the return of seller-financed property from the salean entity which filed for Chapter 11 bankruptcy in June 2009. Also included in 2010 were $0.3 million of forfeited deposits and $0.3 million related to a shopping center in Winter Haven, Florida in 2008.lawsuit settlement. |
BNI Coal, which operates under a cost-plus contract, recorded additional revenue of $5.6 million as a result of higher expenses. (See Operating Expenses.)
Operating expenses decreased $6.0 increased $0.1 million or 7 percent, from 20082009 reflecting lowerhigher expenses at BNI Coal of $1.8 million primarily due to higher diesel fuel costs at ourin 2010 which were recovered through the cost-plus contract (See Operating Revenue) and higher donation expenses of $1.5 million.These increases were mostly offset by lower non-regulated generation expenses of $2.2 million primarily due to the transfer of a small generating facilitiesfacility to Regulated Operations in November 2009, and decreased expenseexpenses at ALLETE Properties of $2.0 million due to both lowerreductions in the cost of land sold and reductions in general and administrative expenses. Expenses incurred as a result of a planned maintenance outage at a non-regulated generating facility in the third quarter of 2008 also contributed
2010 Compared to the decrease in 2009. Partially offsetting these decreases was an increase in expense at BNI Coal due to higher permitting costs relating to mining expansion, a warranty credit in 2008,2009 (Continued)
Investments and dragline repairs in 2009. These costs were recovered through the cost-plus contract. (See Operating Revenue.)Other (Continued)
Other incomeInterest expense increased $3.2$4.8 million from 20082009 primarily due to a decrease$4.4 million lower equity losses on investments in the proportion of ALLETE interest expense assigned to Minnesota Power. We record interest expense for Minnesota Power regulated operations based on Minnesota Power’s authorized capital structure and allocate the balance to Investments and Other. Effective August 1, 2008, the proportion of interest expense assigned to Minnesota Power decreased to reflect the authorized capital structure inherent in interim rates that commenced on that date. Interest expense was also higher in 2009 as 2008 included a $0.6 million reversal of interest expense previously accrued due to the closing of a tax year.2010.
Other income (expense) decreased $16.0 million from 2008 primarily due to a $6.5 million pre-tax gain realized from the sale of certain available-for-sale securities in the first quarter of 2008, lower earnings on excess cash in 2009 of $1.9 million, and $1.4 million of interest income related to tax benefits recognized in the third quarter of 2008. Losses incurred on emerging technology investments totaled $4.6 million in 2009, and were $3.9 million higher than similar losses recorded in 2008.
2009 Compared to 2008 (Continued)
Income Taxes – Consolidated
For the year ended December 31, 2009,2010, the effective tax rate was 33.737.2 percent (34.3(33.7 percent for the year ended December 31, 2008)2009). Excluding additional tax expense recorded as a result of the elimination of the deduction for expenses reimbursed under Medicare Part D, the 2010 effective tax rate was 33.8 percent. The effective tax rate in each period deviated from the statutory rate (approximately 41 percent for 2009)percent) by comparable amounts in each period due to deductions for Medicare health subsidies, AFUDC-Equity, investment tax credits, wind production tax credits, and depletion. In addition, the effective rate for 2009 was impacted by lower pre-tax income. In 2008, non-recurring tax benefits due to the closing of a tax year and the completion of an IRS review totaled $4.6 million.
2008 Compared to 2007
Regulated Operations
Regulated Operations contributed income of $67.9 million in 2008 ($62.4 million in 2007). The increase in earnings is primarily the result of higher rates and higher income from our investment in ATC. Higher rates resulted from a March 1, 2008, increase in FERC-approved wholesale rates, an August 1, 2008, MPUC-approved interim rate increase (subject to refund) for retail customers in Minnesota, and MPUC-approved current cost recovery on our environmental retrofit projects. These rate increases were partially offset by the expiration of sales contracts to Other Power Suppliers, and higher operations and maintenance expense, depreciation expense, and interest expense
Operating revenue decreased $11.6 million, or 2 percent, from 2007 primarily due to decreased fuel and purchased power recoveries and the expiration of sales contracts to Other Power Suppliers. These decreases were partially offset by higher rates and kilowatt-hour sales to retail and municipal customers.
Fuel and purchased power recoveries decreased due to a $42.0 million reduction in fuel and purchased power expense. (See Fuel and Purchased Power Expense discussion below.)
Revenue from sales to Other Power Suppliers decreased $21.1 million from 2007 due to the expiration of sales contracts.
Higher rates resulted from the August 1, 2008, interim rate increase for retail customers in Minnesota of approximately $13 million, current cost recovery on our environmental retrofit projects of approximately $21 million, and the March 1, 2008, increase in FERC-approved wholesale rates of approximately $6 million.
Kilowatt-hour sales to our retail and municipal customers increased 2 percent from 2007 primarily due to a 2 percent increase in industrial load. The increase in industrial sales was primarily due to an idled production line and production delays at one of our taconite customers in 2007. Total regulated utility kilowatt-hour sales were down 2 percent as the expiration of sales contracts to Other Power Suppliers more than offset the increased retail and municipal sales.
| Kilowatt-hours Sold | 2008 | 2007 | Quantity Variance | % Variance |
| Millions | | | | |
| Regulated Utility | | | | |
| Retail and Municipals | | | | |
| Residential | 1,172 | 1,141 | 31 | 2.7% |
| Commercial | 1,454 | 1,457 | (3) | (0.2)% |
| Industrial | 7,192 | 7,054 | 138 | 2.0% |
| Municipals | 1,002 | 1,008 | (6) | (0.6)% |
| Total Retail and Municipals | 10,820 | 10,660 | 160 | 1.5% |
| Other Power Suppliers | 1,800 | 2,157 | (357) | (16.6)% |
Total Regulated Utility Kilowatt-hours Sold | 12,620 | 12,817 | (197) | (1.5)% |
Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2008 (24 percent in 2007). Revenue from electric sales to paper and pulp mills accounted for 9 percent of consolidated operating revenue in 2008 (9 percent in 2007). Revenue from electric sales to pipelines and other industrials accounted for 7 percent of consolidated operating revenue in 2008 (7 percent in 2007).
Operating expenses decreased $25.1 million, or 4 percent, from 2007.
Fuel and Purchased Power Expense decreased $42.0 million, or 12 percent, from 2007 primarily due to a decrease in purchased power expense, as a result of higher electricity production at the Company’s generation facilities. Megawatt-hour generation at our facilities and Square Butte increased 9 percent over 2007.
2008 Compared to 2007 (Continued)
Regulated Operations (Continued)
Operating and Maintenance Expense increased $10.0 million, or 4 percent, over 2007 primarily due to $3.3 million in increased natural gas purchases at SWL&P, reflecting a colder 2008, $2.5 million higher salaries and wages, $1.8 million in increased transmission costs, and $1.5 million in conservation improvement costs.
Depreciation Expense increased $6.9 million, or 16 percent, from 2007 reflecting higher property, plant, and equipment balances placed in service and higher annual depreciation rates for distribution and transmission effective January 1, 2008.
Interest expense increased $3.0 million, or 14 percent, from 2007 primarily due to higher long-term debt balances from increased construction activity.
Equity earnings increased $2.7 million, or 21 percent, from 2007 reflecting higher earnings from our investment in ATC. (See Note 6. Investment in ATC.)
Investments and Other
Investments and Other reflected net income of $14.6 million in 2008 ($25.2 million in 2007). The decrease in 2008 is primarily due to lower net income at ALLETE Properties, which continues to experience difficult real estate market conditions in Florida. This decrease was partially offset by the sale of certain available-for-sale securities in the first quarter of 2008, and tax benefits and related interest recognized in the third quarter of 2008.
Operating revenue decreased $29.1 million, or 25 percent, from 2007 primarily due to a decrease in sales revenue at ALLETE Properties in 2008. ALLETE Properties sold 219 acres of property in 2008 compared to 483 acres in 2007. In addition, 580,059 of non-residential square footage and 736 residential units were sold in 2007 compared to no non-residential or residential sales in 2008. Operating revenue in 2008 included a pre-tax gain of $4.5 million for the sale of our retail shopping center in Winter Haven, Florida in May 2008.
| ALLETE Properties | 2008 | 2007 |
| Revenue and Sales Activity | Quantity | Amount | Quantity | Amount |
| Dollars in Millions | | | | |
| Revenue from Land Sales | | | | |
| Non-residential Sq. Ft. | – | – | 580,059 | $17.0 |
| Residential Units | – | – | 736 | 14.8 |
Acres (a) | 219 | $6.3 | 483 | 10.6 |
Contract Sales Price (b) | | 6.3 | | 42.4 |
| Revenue Recognized from Previously Deferred Sales | | 3.7 | | 3.1 |
| Deferred Revenue | | – | | (1.2) |
| Revenue from Land Sales | | 10.0 | | 44.3 |
Other Revenue (c) | | 8.3 | | 6.2 |
| Total ALLETE Properties Revenue | | $18.3 | | $50.5 |
(a) | Acreage amounts are shown on a gross basis, including wetlands and non-controlling interest. |
(b) | Reflected total contract sales price on closed land transactions. Land sales are recorded using a percentage-of-completion method. (See Note 1. Operations and Significant Accounting Policies.) |
(c) | Included a $4.5 million pre-tax gain from the sale of a shopping center in Winter Haven, Florida in 2008. |
Operating expenses decreased $5.7 million, or 6 percent, from 2007, primarily due to a $4.8 million decrease in the cost of real estate sold in Florida.
Interest expense increased $0.7 million in 2008 primarily due to higher interest expense at ALLETE, a portion of which is assigned to Minnesota Power and the remainder is reflected in the Investments and Other segment.
Other income increased $0.6 million, or 5 percent, from 2007 primarily due to a $6.5 million pre-tax gain realized from the sale of certain available-for-sale securities in the first quarter of 2008 and interest income related to tax benefits recognized in the third quarter of 2008. The gain was triggered when securities were sold to reallocate investments to meet defined investment allocations based upon an approved investment strategy. The increase was partially offset by fewer gains from land sales in Minnesota during 2008, and lower earnings on cash and short-term investments reflecting lower average cash balances, and the 2007 release from a loan guarantee for Northwest Airlines, Inc. of $1.0 million.
2008 Compared to 2007 (Continued)
Income Taxes – Consolidated
For the year ended December 31, 2008, the effective tax rate on income from continuing operations before non-controlling interest was 34.3 percent (34.8 percent for the year ended December 31, 2007). The effective tax rate in both years deviated from the statutory rate (approximately 40 percent) primarily due to the recognition of various tax benefits as well as deductions for Medicare health subsidies, AFUDC-Equity,depletion, investment tax credits, and wind production tax credits. In 2007, aThe 2009 effective tax benefit was realized as a resultrate also included the effect of a state income tax audit settlement ($1.6 million). In 2008, non-recurring tax benefits due to the closing of a tax year and the completion of an IRS review totaled $4.6 million.deductions for expenses reimbursed under Medicare Part D.
Critical Accounting EstimatesPolicies
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. The following represent the policies we believe are most critical to our business and the understanding of our results of operations.
Regulatory Accounting.Our regulated utility operations are subject toaccounted for in accordance with the guidance on accounting standards for the effects of certain types of regulation. This guidance requiresThese standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets or liabilities arise as a result of a difference between GAAP and the accounting principlestreatment for certain items imposed by the regulatory agencies. 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.
We recognize regulatory assets and liabilities in accordance with applicable state and federal regulatory rulings. The recoverability of regulatory assets is periodically assessed on a quarterly basis by considering factors such as, but not limited to, changes in regulatory rules and rate orders issued by applicable regulatory agencies. The assumptions and judgments used by regulatory authorities may have an impact on the recovery of costs, the rate of return on invested capital, and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on our results of operations. (See Note 5. Regulatory Matters.)
Valuation of Investments. Our long-term investment portfolio includes the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits, auction rate securities, and investments in emerging technology funds. Our policy is to review these investments for impairment on a quarterly basis by assessing such factors as continued commercial viability of products, cash flow and earnings. Our consideration of possible impairment for our real estate assets requires us to make judgments with respect to the current fair values of this real estate. The poor market conditions for real estate in Florida at this time require us to make certain assumptions in the determination of fair values due to the lack of current comparable sales activity. Any impairment would reduce the carrying value of our investments and be recognized as a loss. In 2009, we recorded an impairment loss on these investments of $1.1 million pretax (none in 2008; $0.5 million pretax in 2007), primarily due to our emerging technology funds. (See Note 7. Investments.)
Pension and Postretirement Health and Life Actuarial Assumptions. We account for our pension and postretirement benefit obligations in accordance with the accounting standards for defined benefit pension and other postretirement plans. These standards require the use of assumptions in determining our obligations and the annual cost of our pension and postretirement benefits. An important actuarial assumption for pension and other postretirement benefit plans is the expected long-term rate of return on plan assets. In establishing the expected long-term return on plan assets, we take into account the actual long-term historical performance of our plan assets, the actual long-term historical performance for the type of securities we are invested in, and apply the historical performance utilizing the target allocation of our plan assets to forecast an expected long-term return. Our expected rate of return is then selected after considering the results of each of those factors, in addition to considering the impact of current economic conditions, if applicable, on long-term historical returns. Our pension asset allocation at December 31, 2009,2011, was approximately 5352 percent equity 28securities, 27 percent debt, 1416 percent private equity, and 5 percent real estate. Our postretirement health and life asset allocation at December 31, 2009,2011, was approximately 5451 percent equity 38securities, 39 percent debt, and 810 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. We currently use an expected long-term rate of return of 8.5 percent in our actuarial determination of our pension and other postretirement expense. We review our expected long-term rate of return assumption annually and will adjust it to respond to any 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 $1.3$1.3 million pre-tax., pretax.
ALLETE 20092011 Form 10-K
38
Critical Accounting EstimatesPolicies (Continued)
Pension and Postretirement Health and Life Actuarial Assumptions (Continued)
The discount rate is computed using the Citigroup Pension Discount Curvea yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The Citigroup Pension Discount Curveyield curve is determined using high-quality, long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension and other postretirement obligation. In 2011, we used a discount rate of 5.40 percentfor our actuarial determination of our pension obligation.and other postretirement expense. We review our discount rate annually and will adjust it 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 $2.0 million, pretax. (See Note 16. Pension and Other Postretirement Benefit Plans.)
Impairment of Long-Lived Assets. We review our long-lived assets for indicators of impairment in accordance with the accounting standards for property, plant and equipmenton a quarterly basis. Long-lived assets that we evaluated include our real estate assets of ALLETE Properties. (See Note 1. Operations and Significant Accounting Policies.)
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, real estate and sales/use 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 guidance for accounting standards for uncertainty in income taxes. We must also assess our ability to generate capital gains to realize tax benefits associated with capital losses. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the two prior or five succeeding years for federal purposes. We have recordedrecord a valuation allowance against our deferred tax assets associated with realized capital losses to the extent it has been determined that it is more-likely-than-not that some portion or all of the deferred tax asset will not be realized.
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 a key long-term objective of achieving a minimum average earnings per share growth of 5 percent per year and maintaining a competitive dividend payout. To accomplish this, we intend to take the actions necessary to earn our allowed rate of return in our regulated businesses, while we pursue growth initiatives in renewable energy, transmission and other energy-centric businesses.
We believe that, over the long term, windlong-term, less carbon intensive and more sustainable renewable energy sources will play an increasingly important role in our nation’s energy mix. We intend to pursue the establishment of aMinnesota Power is developing additional renewable energy business focused initially on developing wind assets in North Dakota and the upper Midwest. We intend to develop wind resources which will be used to meet regulated renewable supply requirementsrequirements. In addition, in June 2011, we established ALLETE Clean Energy, a wholly-owned subsidiary of our regulated businesses as well asALLETE. ALLETE Clean Energy operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, thatclean coal and other clean energy innovations. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term PPAs, and will be marketedsubject to others. Weapplicable state and federal regulatory approvals.
For wind development, we will capitalize on our existing presence in North Dakota through BNI Coal, our recently acquired DC transmission line and our Bison 1, 2 and 3 wind project. Through BNI Coal weprojects. We have a long-term business presence and established landowner relationships in North Dakota. See page 38Renewable Energy below for more discussion on the DC line acquisition and our Bison I project. For projects to be marketed to others, we intend to secure long-term power purchase agreements prior to construction of the1, 2 and 3 wind generation facilities. Establishment of the business is subject to appropriate MPUC approvals.projects.
We also plan to make investments in upperUpper Midwest transmission opportunities that strengthen or enhance the regional transmission grid or take advantage of our geographical location between sources of renewable energy and end users. Minnesota Power is participating with other regional utilities in making regional transmission investments as a member of the CapX2020 initiative. In addition, we plan to make additional investments to fund our pro rata share of ATC’s future capital expansion program. Minnesota Power is also participating with other regional utilities in making regional transmission investments as a member ofBoth the CapX2020 initiative. The CapX2020 initiative isand our investment in ATC are discussed in more detail on page 40.under Transmission below.
We are also exploring investing in other energy-centric businesses that will complement an entrance into theour non-regulated renewable energy business or leverage demand trends related to transmission, environmental control or energy efficiency.
ALLETE intends to sell its Florida land assets at reasonable prices, over time or in bulk transactions, and reinvest the proceeds in its growth initiatives. ALLETE Properties does not intend to acquire additional real estate.
Regulated Operations.Minnesota Power’s long-term strategy is to maintain its competitively priced production of energy, reduce customer concentration exposure, complywhile complying with environmental permit conditions and renewable requirements, and to earn our allowed rate of return. Keeping the productioncost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain the viability of its customers. 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. Minnesota Power intends to reduce its customer concentration risk to reduce exposure to cyclical industries; this may include restructuring commercial contracts, additional sales to other regional power suppliers, and reshaping our power supply to be more flexible to swings in customer demand. We will monitor and review proposed environmental proposalsregulations and may challenge those that add considerable cost with limited environmental benefit. Current economic conditions require a very careful balancing of the benefit of further environmental controls with the impacts of the costs of those controls on our customers as well as on the company, and its competitive position. We will continue to pursue current cost recovery riders to recoverrider approval for environmental and renewable investments, and will work with our legislators and regulators to earn a fair return. In 2011 our Regulated Operations earnings were near its allowed rate of return. 2011 was positively impacted by the reversal of a $6.2 million deferred tax liability related to a 2010 rate case stipulation and settlement agreement, and the recognition of a $2.9 million income tax benefit related to the deferral of the retail portion of the tax charge taken in 2010 resulting from the PPACA. We project that our Regulated Operations will not earn its allowed rate of return in 2012.
Regulatory Matters.Rates. Entities within our Regulated Operations segment file for periodic rate revisions withare under the jurisdiction of the MPUC, the FERC or the PSCW.
Outlook (Continued)
Rates (Continued)
2008 Rate Case. In May 2008, See Item 1. Business – Regulated Operations – Regulatory Matters for discussion of regulatory matters within our Minnesota, Power filed a retail rate increase request with the MPUC seeking additional revenues of approximately $40 million annually; the request also sought an 11.15 percent return on equity,FERC, Wisconsin and a capital structure consisting of 54.8 percent equity and 45.2 percent debt. As a result of a May 2009 Order and an August 2009 Reconsideration Order, the MPUC granted Minnesota Power a revenue increase of approximately $20 million, including a return on equity of 10.74 percent and a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.North Dakota jurisdictions.
Interim rates, subject to refund, were in effect from August 1, 2008 through October 31, 2009. During 2009, Minnesota Power recorded a $21.7 million liability for refunds of interim rates, including interest, required to be made as a result of the May 2009 Order and the August 2009 Reconsideration Order. In 2009, $21.4 million was refunded, with a remaining $0.3 million balance to be refunded in early 2010; $7.6 million of the refunds required to be made were related to interim rates charged in 2008.
With the May 2009 Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.
2010 Rate Case. Minnesota Power previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.50 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue.
Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allow Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.
The rate case process requires public hearings and an evidentiary hearing before an administrative law judge, both of which are scheduled for the second quarter of 2010. A final decision on the rate request is expected in the fourth quarter. We cannot predict the final level of rates that may be approved by the MPUC, and we cannot predict whether a legal challenge to the MPUC’s interim rate decision will be forthcoming or successful.
FERC-Approved Wholesale Rates. Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a customer of Minnesota Power. In 2008, Minnesota Power entered into new contracts with these customers which transitioned customers to formula-based rates, allowing rates to be adjusted annually based on changes in cost. In February 2009, the FERC approved our municipal contracts which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are set at the beginning of the year based on expected costs and provide for a true-up calculation for actual costs. Wholesale rate increases totaling approximately $6 million and $10 million annually were implemented on February 1, 2009 and January 1, 2010, respectively, with approximately $6 million of additional revenues under the true-up provision accrued in 2009, which will be billed in 2010.
2009 Wisconsin Rate Increase. SWL&P’s current retail rates are based on a December 2008 PSCW retail rate order that became effective January 1, 2009, and allows for an 11.1 percent return on equity. The new rates reflected a 3.5 percent average increase in retail utility rates for SWL&P customers (a 13.4 percent increase in water rates, a 4.7 percent increase in electric rates, and a 0.6 percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately $3 million in additional revenue.
Industrial Customers. Electric power is one of several key inputs in the taconite mining, paper production, and pipeline industries. In 2009,2011, approximately 3756 percent (57 (52 percent in 2008),2010) of our Regulated Utility kilowatt-hour sales were made to our industrial customers, which includes the taconite, paper, pulp and pulp,wood products, and pipeline industries.
Beginning inAccording to the fallAmerican Iron and Steel Institute (AISI), an association of 2008, worldwideNorth American steel makers began to dramatically cut steel production in response to reduced demand driven largely by the global credit concerns. United Statesproducers, U.S. raw steel production ranoperated at approximately 5075 percent of capacity in 2009, reflecting poor demand2011 (70 percent in automobiles, durable goods, and structural and other steel products.
Outlook (Continued)
Industrial Customers (Continued)
In late 2008, Minnesota taconite producers began to feel the impacts of decreased steel demand, and reduced taconite production levels occurred2010, 50 percent in 2009.2009). Annual taconite production in Minnesota was approximately 40 million tons in 2011, near full production capacity (36 million tons in 2010, 18 million tons in 2009 (40 million tons in 2008 and 39 million tons in 2007)2009). Consequently, 2009 kilowatt-hour sales to our taconite customers were lower by approximately 54 percent from 2008 levels, and we sold available power to Other Power Suppliers to partially mitigate the earnings impact of these lower taconite sales.
RawThe AISI and the World Steel Association, an association of approximately 170 steel producers, national and regional steel industry associations and steel research institutes representing around 85 percent of world steel production, project U.S. steel consumption will be similar in the United States is projected2012 compared to improve in 2010, and is estimated to run at approximately 60 percent of capacity. As a result, Minnesota Power expects an increase in2011. Based on these projections, 2012 taconite production levels in 2010 comparedMinnesota are also expected to 2009, although production will still be less than previous years’ levels. We will continuesimilar to market available power to Other Power Suppliers in an effort to mitigate the earnings impact of these lower industrial sales. Sales to Other Power Suppliers are dependent upon the availability of generation and are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations. We can make no assurances that our power marketing efforts will fully offset the reduced earnings resulting from lower demand nominations from our industrial customers.2011.
Minnesota Power’s four major paper and pulp customersmills ran at, or very near, full capacity for the majority of 2009, despite the fact that the industry as a whole experienced the impacts of the global recession2011. Similar levels are expected in reduced sales of nearly every paper grade. Federal tax credits provided a subsidy for paper producers which allowed them to remain competitive. Minnesota Power’s paper and pulp customers benefited from the temporary or permanent idling of competitor plants both in North America and in Europe, as well as continued strength of the Canadian dollar and the Euro which has reduced imports both from Canada and Europe.2012.
Our pipeline customers continued to operate at near capacity levels. As Western Canadian oil sands reserves continue to develop and expand, pipeline operators served by the Company are executing expansion plans to transport Western Canadian crude oil reserves (Alberta Oil Sands) to United States markets. Access to traditional Midwest markets is being expanded to Southern markets as the Canadian supply is displacing domestic production and deliveries imported from the Gulf Coast. We believe we are strategically positioned to serve these expanding pipeline facilities.
Prospective Additional Load. SeveralMinnesota 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. These potential projects are in the ferrous and non-ferrous mining and steel industries. These projectsindustries and include PolyMet, Mining Corporation (PolyMet), Mesabi Nugget, Delaware, LLC (Mesabi Nugget), and United States SteelUSS Corporation’s expansion at its Keewatin Taconite facility. Additionally,taconite facility, Essar Steel Limited Minnesota (Essar), continuesMagnetation, and Mining Resources, LLC (Mining Resources). We cannot predict the outcome of these projects, but if these projects are constructed, Minnesota Power could serve up to work with local agencies on infrastructure development for its taconite mine, direct reduction iron-making facility, and steel mill within the Nashwauk, MN municipal utility service boundary.approximately 600 MW of new retail or wholesale load.
PolyMet. Minnesota Power has executed a long-term contract with PolyMet, a new industrial customer planning to start a copper-nickel and precious metal (non-ferrous) mining operation in northeastern Minnesota. PolyMet is currently in the environmental permitting process, and the public comment periodbegan work on itsa Supplemental Draft Environmental Impact Statement (DEIS) closed on February 3,(SDEIS) in 2010. Assuming that the DEIS is judged to be complete, the Minnesota Department of Natural ResourcesThe SDEIS addresses environmental issues, most notably those dealing with a land exchange between PolyMet and the U.S. Army CorpsForest Service (USFS). This land exchange is critical to the mine site development. The EPA and the USFS joined as lead agencies in the SDEIS process. Release of Engineers may issuethe SDEIS is expected in late 2012, to be followed by a Statementpublic review and comment period. Assuming successful completion of Adequacy by mid-year 2010, withthe SDEIS process and subsequent issuance of environmental permitting to follow. Should these events occur, operations could begin in late 2011 andpermits, Minnesota Power willcould begin to supply approximately 70between 45-70 MW of power in approximately 2014 through a 10-year power supply contract lasting at least through 2018.that would begin upon start-up.
Mesabi Nugget.The construction of the initial Mesabi Nugget facility is essentially complete and the first production occurred in January 2010. Steel Dynamics, Inc. (Steel Dynamics), the principalmajority owner of Mesabi Nugget, has indicated that commissioning and production ramp-up activities will occur throughout 2010,continue in 2012, with full production levels expected to be reached during the year. Mesabi Nugget is also currently pursuing permits for taconite mining activities on lands formerly mined by Erie Mining Company and LTV Steel Mining Company near Hoyt Lakes, MN. Assuming receipt of environmental permitsMinnesota. Permits to mine are expected by the end of 2010, mining2013. Mining activities could begin in 2011,2014, which would allow Mesabi Nugget to self-supply its own taconite concentrates and would result in increased electrical loads. Minnesota Power has a 15loads above the current 19 MW long-term power supply contract with Mesabi Nugget lasting at least through 2017.
Outlook (Continued)
Industrial Customers (Continued)
Keewatin Taconite. In February 2008, United States SteelUSS Corporation announced its intent to restart a pellet line at its Keewatin Taconite processing facility (Keetac). ThisIf restarted, this pellet line, which has been idledidle since 1980, could be restarted and updated as part of a $300 million investment, bringing aboutbring 3.6 million tons of additional pellet making capability to northeastern Minnesota. The public comment period for a Draft Environmental Impact Statement forMinnesota and could result in over 60 MW of additional load. Project permits have been received and should the Keetac facility ended on January 26, 2010.project be approved by USS Corporation's Board of Directors in the first half of 2012, construction activities should commence immediately thereafter with production expected to begin in 2015.
Outlook (Continued)
City of Nashwauk. In February 2011, the Company entered into a new formula-based wholesale electric sales agreement with the City of Nashwauk for all of the City’s electric service requirements, effective May 1, 2012 through April 30, 2022. On July 27, 2011, the City of Nashwauk entered into a long-term electric service agreement with Essar for service beginning in 2013 for Essar’s proposed taconite facility. The proposed taconite facility would result in 70 to 110 MW of additional load for Minnesota Power, and is currently under construction. An expansion to include a direct reduced iron and steel-making facility is also being considered for 2015. Under the terms of a facilities construction agreement, Minnesota Power has begun site preparation and transmission construction for a 230 kV transmission line which is expected to cost approximately $28 million and is scheduled to be in service in April 2013.
Magnetation. In December 2011, the MPUC approved Minnesota Power's electric service agreement with Magnetation. Magnetation, a company in northeastern Minnesota that will produce iron ore concentrate from low-grade natural ore tailing basins, already mined stockpiles and newly mined iron formations. The plant near Taconite, Minnesota is under construction and is expected to begin operations in the spring of 2012 resulting in 5 to 7 MW of additional load for Minnesota Power.
In October 2011, Magnetation and integrated steelmaker, AK Steel Corporation (AK Steel), announced a joint venture, Magnetation LLC, that could lead to the construction of two facilities near Calumet and Coleraine, Minnesota. This would result in a total of 10 to 15 MW of additional load for Minnesota Power. Magnetation and AK Steel have also indicated the potential for a three million ton pellet plant near the Coleraine plant, which would result in 15 to 25 MW of additional load in 2016.
Mining Resources. In November 2011, Minnesota Power entered into an electric service agreement with Mining Resources, a joint venture between Magnetation and Steel Dynamics. Mining Resources has begun construction on a $50 million plant near Chisholm, Minnesota to supply iron ore concentrate to Mesabi Nugget until it begins its own mining operations. The electric service agreement was approved by the MPUC on February 3, 2012. Operations are expected to begin in late 2012, resulting in 5 to 7 MW of additional load for Minnesota Power.
Renewable Energy.In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power’s total retail energy sales in Minnesota comebe from renewable energy sources by 2025. The law also requires Minnesota Power to meet interim milestones of 12 percent by 2012, 17 percent by 2016 and 20 percent by 2020. Minnesota Power has identifieddeveloped a plan to meet the renewable goals set by Minnesota and has included this plan in the most recent filing of the IRP with the MPUC.its 2010 Integrated Resource Plan. The MPUC approved our Integrated Resource Plan in its final order issued on May 6, 2011. The law allows the MPUC to modify or delay meeting a standard obligationmilestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a standard,milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power was developing and makingWe are currently on track to exceed the 12 percent renewable supply additions as partenergy requirement by the end of its generation planning strategy prior to the enactment of this law and this activity continues.2012.
We areMinnesota Power has taken several steps to begin executing ourits renewable energy strategy. In 2006 and 2007,strategy through key renewable projects that will ensure we entered intomeet the identified state mandate. We have executed two long-term power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc., for a total of 98 MWs of wind energy constructed in North Dakota (Oliver Wind I and II). Other steps include Taconite Ridge, Wind I, our $50 million, 25-MW wind facility located in northeastern Minnesota, became operational in 2008.our Bison 1, 2 and 3 wind development projects and our Hibbard Biomass Upgrade Project.
North Dakota Wind Project.Development. On December 31, 2009, we purchased an existing We use our 465-mile, 250 kV DC transmission line from Square Butte for $69.7 million. The 465-mile transmission linethat runs from Center, North Dakota, to Duluth, Minnesota. We expect to use this lineMinnesota to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’sButte's lignite coal-fired generating unit. Acquisition
Outlook (Continued)
Renewable Energy (Continued)
Bison 1 is an 82 MW wind project in North Dakota. All permitting has been received, the first phase was completed in 2010, and the second phase was completed in January 2012. Phase one included the construction of thisa 22-mile, 230 kV transmission line was approved by the MPUC and the FERC. In addition, the FERC issued an order on November 24, 2009, authorizing acquisitioninstallation of sixteen2.3 MW wind turbines. Phase two consisted of the transmission facilities and conditionally accepting, upon compliance and other filings, the proposed tariff revisions, interconnection agreement and other related agreements.installation of
On July 7, fifteen3 MW wind turbines. Bison 1 is expected to have a total project cost of $177 million, of which $171.5 million was spent through December 31, 2011. In 2009, the MPUC approved ourMinnesota Power’s petition seeking current cost recovery offor investments and expenditures related to Bison I1 and associated transmission upgrades.in July 2010, the MPUC approved our petition establishing rates effective August 1, 2010. On November 3, 2011, the MPUC issued an order approving our petition to update the rates for additional investments and expenditures related to Bison 1.
Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota which are expected to be completed by the end of 2012. Site preparation is currently underway for both projects and total project costs for Bison 2 and Bison 3 are estimated to be approximately $160 million each, of which $37.0 million and $14.7 million, respectively, was spent through December 31, 2011. On September 8, 2011, and November 2, 2011, the MPUC approved Minnesota Power’s petition seeking current cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively. On August 10, 2011, and October 12, 2011, the NDPSC issued a Certificate of Site Compatibility for Bison 2 and Bison 3, respectively, which authorized site construction to commence. We anticipate filing a petitionpetitions with the MPUC in the first quarterhalf of 20102012 to establish customer billing rates for the approved cost recovery. Bison I is the first portion of several hundred MWs of our North Dakota Wind Project, which upon completion will fulfill the 2025 renewable energy supply requirement for our retail load. Bison I, located near Center, North Dakota, will be comprised of 33 wind turbines with a total nameplate capacity of 75.9 MWs and will be phased into service in late 2010 and 2011.
On September 29, 2009, the NDPSC authorized site construction for Bison I. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for a 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter of 2010.
Manitoba Hydro. Minnesota Power has a long-term powerPPA with Manitoba Hydro, for the purchase of 50 MW of capacity and energy associated with that capacity, which expires in April 2015. In addition, Minnesota Power signed a separate PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only transaction 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 with Manitoba Hydro, expiringMinnesota Power will be purchasing at least one million MWh of energy over the contract term. On March 31, 2011, the MPUC approved this PPA with Manitoba Hydro.
On May 19, 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2015.2020. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices. On January 26, 2012, the MPUC approved this PPA with Manitoba Hydro. The agreement requires construction of additional transmission capacity between Manitoba and Hibbing, Minnesota. In addition, we are exploring other regional grid enhancements that would allow for the movement of more renewable energy in the Upper Midwest while at the same time strengthening electric reliability in the region.
Hibbard Biomass Upgrade Project. Hibbard is a 51 MW biomass/coal/natural gas facility located in Duluth, Minnesota. The biomass optimization project, which was conditionally approved by the MPUC in September 2009, is designed to leverage existing assets to increase biomass renewable energy production at the facility for Minnesota Power customers.
We will seek current cost recovery authorization from the MPUC in 2012, along with any necessary permitting approvals required to commence construction. The project has an expected cost of approximately $22 million and an expected completion date of 2013.
Integrated Resource Plan. The MPUC approved our Integrated Resource Plan in its final order issued on May 6, 2011. A required baseload diversification study evaluating the impact of additional EPA regulations over the next two decades was filed on February 6, 2012. Through this study Minnesota Power evaluated environmental compliance scenarios for different potential ranges of future EPA regulation stringency to determine prominent power supply trends and impacts on customers. This study will advise of the next steps in our on-going, long-term resource planning process for consideration in our next Integrated Resource Plan submittal, which must be filed with the MPUC no later than July 1, 2013. (See Item 1. Business – Power Supply.Regulatory Operations – Regulatory Matters.) In addition, Minnesota Power is currently negotiating definitive agreements
Transmission. We plan to make investments in upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. This includes the CapX2020 initiative, investments in our own transmission assets, investments in other regional transmission assets (by ourselves or in combination with others), and our investment in ATC.
Outlook (Continued)
Transmission (Continued)
Transmission Investments. We have an approved cost recovery rider in place for certain transmission expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. The billing factor allows us to charge our retail customers on two additional purchased power transactions with Manitoba Hydro: an initial purchasea current basis for the costs of surplus energy over the next ten years, followed by an anticipated long-term purchase of a 250-MW capacity and energy agreement beginning in approximately 2020. The 250-MW long-term purchase will require construction of hydroelectric facilities in Manitoba and major newconstructing certain transmission facilities between Canadaplus a return on the capital invested. On June 29, 2011, we filed an updated billing factor that includes additional transmission projects and the United States. Transmission studies and definitive agreement negotiations are ongoing. Both purchases require MPUC approval.expenses, which we expect to be approved in 2012.
Hibbard Renewable Energy Center. On September 30, 2009, we purchased boilers and associated systems previously owned by the City of Duluth. This facility was initially built in the late 1930s as a coal burning power plant, and retrofitted to burn wood-based biomass fuel as well as coal. Over time, Minnesota Power intends to invest approximately $20 million to upgrade the boilers and associated systems to increase biomass energy generation at the plant. Hibbard’s current generating capacity is approximately 50 MWs. This purchase will help us achieve Minnesota’s mandate of providing 25 percent of our retail energy from renewable resources by 2025.
Integrated Resource Plan. On October 5, 2009, Minnesota Power filed with the MPUC its 2010 Integrated Resource Plan, a comprehensive estimate of future capacity needs within Minnesota Power’s service territory. Minnesota Power does not anticipate the need for new base load generation within the Minnesota Power service territory over the next 15 years, and plans to meet estimated future customer demand while achieving:
| · | Increased system flexibility to adapt to volatile business cycles and varied future industrial load scenarios; |
| · | Reductions in the emission of GHGs (primarily carbon dioxide); and |
| · | Compliance with mandated renewable energy standards. |
To achieve these objectives over the coming years, we plan to reshape our generation portfolio by adding 300 to 500 megawatts of renewable energy to our generation mix, and exploring options to incorporate peaking or intermediate resources. Our 76 MW Bison I Wind Project in North Dakota is expected to be in service in late 2010 and 2011.
We project average annual long-term growth of approximately one percent in electric usage over the next 15 years. We will also focus on conservation and demand side management to meet the energy savings goals established in Minnesota legislation.
Outlook (Continued)
Climate Change. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customer’s requirements.
| · | Expand our renewable energy supply. |
| · | Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies. |
| · | Provide energy conservation initiatives with our customers and demand side efforts. |
| · | Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts. |
| · | Achieve overall carbon emission reductions. |
The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. These physical risks could include, but are not limited to, increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations.
Federal Legislation. We believe that future regulations may restrict the emissions of GHGs from our generation facilities. Several proposals at the Federal level to “cap” the amount of GHG emissions have been made. On June 26, 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. H.R. 2454 is a comprehensive energy bill that also includes a cap-and-trade program. H.R. 2454 allocates a significant number of emission allowances to the electric utility sector to mitigate cost impacts on consumers. Based on the emission allowance allocations, we expect we would have to purchase additional allowances. We’re unable to predict at this time the value of these allowances.
On September 30, 2009, the Senate introduced S. 1733, the Senate version of H.R. 2454. This legislation proposes a more stringent, near-term greenhouse emissions reduction target in 2020 of 20 percent below 2005 levels, as compared to the 17 percent reduction proposed by H.R. 2454.
Congress may consider proposals other than cap-and-trade programs to address GHG emissions. We are unable to predict the outcome of H.R. 2454, S. 1733, or other efforts that Congress may make with respect to GHG emissions, and the impact that any GHG emission regulations may have on the Company. We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.
Greenhouse Gas Reduction. In 2007, Minnesota passed legislation establishing non-binding targets for carbon dioxide reductions. This legislation establishes a goal of reducing statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, at least 30 percent below 2005 levels by 2025, and at least 80 percent below 2005 levels by 2050.
Midwestern Greenhouse Gas Reduction Accord. Minnesota is also participating in the Midwestern Greenhouse Gas Reduction Accord (the Accord), a regional effort to develop a multi-state approach to GHG emission reductions. The Accord includes an agreement to develop a multi-sector cap-and-trade system to help meet the targets established by the group.
Greenhouse Gas Emissions Reporting. In May 2008, Minnesota passed legislation that required the MPCA to track emissions and make interim emissions reduction recommendations towards meeting the State’s goal of reducing GHG by 80 percent by 2050. GHG emissions from 2008 were reported in 2009.
We cannot predict the nature or timing of any additional GHG legislation or regulation. Although we are unable to predict the compliance costs we might incur, the costs could have a material impact on our financial results.
International Climate Change Initiatives. The United States is not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC) that requires developed countries to cap GHG emissions at certain levels during the 2008 to 2012 time period. In December 2009, leaders of developed and developing countries met in Copenhagen, Denmark, under the UNFCCC and issued the Copenhagen Accord. The Copenhagen Accord provides a mechanism for countries to make economy-wide GHG emission mitigation commitments for reducing emissions of GHG by 2020 and provide for developed countries to fund GHG emissions mitigation projects in developing countries. President Obama participated in the development of, and endorsed the Copenhagen Accord.
EPA Greenhouse Gas Reporting Rule. On September 22, 2009, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.
Outlook (Continued)
Climate Change (Continued)
Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and new thresholds for when permits will be required for new facilities and existing facilities which undergo major modifications. The rule would require large industrial facilities, including power plants, to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used at the facility to minimize GHG emissions. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.
For our existing facilities, the proposed rule does not require amending our existing Title V operating permits to include BACT for GHGs. However, modifying or installing units with GHG emissions that trigger the PSD permitting requirements could require amending operating permits to incorporate BACT to control GHG emissions.
EPA Endangerment Findings. On December 15, 2009, the EPA published its findings that the emissions of six GHG, including CO2, methane, and nitrous oxide, endanger human health or welfare. This finding may result in regulations that establish motor vehicle GHG emissions standards in 2010. There is also a possibility that the endangerment finding will enable expansion of the EPA regulation under the Clean Air Act to include GHGs emitted from stationary sources. A petition for review of the EPA’s endangerment findings was filed by the Coalition for Responsible Regulation, et. al. with the United States District Court Circuit Court of Appeals on December 23, 2009.
Coal Ash Management Facilities. Minnesota Power generates coal ash at all five of its steam electric stations. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use, or trucked to state permitted landfills. Minnesota Power continues to monitor state and federal legislative and regulatory activities that may affect its ash management practices. The EPA is expected to propose new regulations in February 2010 pertaining to the management of coal ash by electric utilities. It is unknown how potential coal ash management rule changes will affect Minnesota Power’s facilities. On March 9, 2009, the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received an additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findings or concerns from the DNR staff during the inspections.
CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which includes Minnesota’s largest transmission owners, consists of electric cooperatives, municipals and investor-owned utilities, andincluding Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region'sregion’s transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.
Minnesota Power intendsis currently participating in three CapX2020 projects: the Fargo, North Dakota to invest in two lines,St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 250-mile238-mile, 345 kV line betweenfrom Fargo, North Dakota andto Monticello, Minnesota, and athe 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015, of which $27.8 million was spent through December 31, 2011. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.
In July 2010, the MPUC granted a route permit for the 28-mile, 345 kV line between Monticello and St. Cloud. The project was completed and placed into service in December 2011. On June 10, 2011, the MPUC issuedapproved the Certificateroute permit for the Minnesota portion of Needthe Fargo to St. Cloud project. The North Dakota permitting process is underway. The entire 238-mile, 345 kV line from Fargo to Monticello is expected to be in service by 2015.
In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids, Minnesota line and construction for the 230 kV line project commenced in July 2009.January 2011. The Leech Lake Band of Ojibwe (LLBO) subsequently requested the MPUC suspend or revoke the route permit and also served the CapX2020 owners with a complaint filed in Leech Lake Tribal Court asserting adjudicatory and regulatory authority over the project. The CapX2020 owners filed a request for declaratory judgment in the United States District Court for the District of Minnesota (District Court) that the project does not require LLBO consent to cross non-tribal land within the reservation. On June 22, 2011, the federal judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The LLBO abandoned its motion to dismiss the declaratory action because the District Court’s injunction order had already dismissed the basis for the motion, namely, that the District Court did not have jurisdiction to hear the CapX2020 owners’ action. The parties are now proceeding with discovery and the CapX2020 owners do not anticipate any actions by the District Court until after the completion of discovery closes on May 31, 2012. The MPUC decision on the Route Permit application is expected in 2010. Our total investment in these lines is expected to be approximately $100 million. We intend to seek recovery of these costs in a filing with the MPUChas taken no action in the first quartermatter in light of 2010, under a Minnesota Power transmission cost recovery tariff rider authorized by Minnesota legislation. Construction ofongoing litigation in federal and tribal courts. The CapX2020 utilities are vigorously defending against the lines is targeted to begin in late 2010 and may take up to four years.LLBO actions.
Emission Reduction Plans. We have made investments in pollution control equipment at our Boswell Unit 3 generating unit that reduces particulates, SO2, NOx and mercury emissions to meet future federal and state requirements. This equipment was placed in service in November 2009. During the construction phase, the MPUC authorized a cash return on construction work in progress in lieu of AFUDC, and this amount was collected through a current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates.
The environmental regulatory requirements for Taconite Harbor Unit 3 are pending approval of the Minnesota Regional Haze implementation by the EPA. We are evaluating compliance requirements for this Unit. Environmental retrofits at Laskin and Taconite Harbor Units 1 and 2 have been completed and are in-service.
Boswell NOX Reduction Plan. In September 2008, we submitted to the MPCA and MPUC a $92 million environmental initiative proposing cost recovery for expenditures relating to NOX emission reductions from Boswell Units 1, 2, and 4. The Boswell NOX Reduction Plan is expected to significantly reduce NOX emissions from these units. In conjunction with the NOX reduction, we plan to make an efficiency improvement to our existing turbine/generator at Boswell Unit 4 adding approximately 60 MWs of total output. The Boswell 1, 2 and 4, selective non-catalytic reduction NOX controls are currently in service, while the Boswell 4 low NOX burners and turbine efficiency projects are anticipated to be in service in late 2010. Our 2010 rate case seeks recovery for this project in base rates.
Outlook (Continued)
Transmission. We have an approved cost recovery rider in-place for certain transmission expenditures, and our current billing factor was approved by the MPUC in June 2009. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. Our 2010 rate case proposes to move completed transmission projects from the current cost recovery rider to base rates.
Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin 100 MWs of capacity and energy for the next ten years. The transaction is scheduled to begin in May 2010, following the expiration of two wholesale power sales contracts on April 30, 2010. The Basin agreement contains a fixed monthly schedule of capacity charges with an annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro-rata share of increased costs related to emissions that may occur during the last five years of the contract. (See Item 3. Power Marketing.)
Investment in ATCATC.. As of At December 31, 2009,2011, our equity investment in ATC was $88.4$98.9 million, representing an approximate 8 percent ownership interest. ATC provides transmission service under rates regulated by the FERC that are set in accordance with the FERC’s policy of establishing the independent operation and ownership of, and investment in, transmission facilities. ATC rates are based on a FERC approved 12.2 percent return on common equity dedicated to utility plant. In September 2011, ATC has identified $2.5updated its 10-year transmission assessment covering the years 2011 through 2020 which identifies between $3.8 and $4.4 billion in future projects needed over the next 10 years to improve the adequacy and reliability of the electric transmission system.system improvements. This investment is expected to be funded by ATC through a combination of internally generated cash, debt and investor contributions. As additional opportunities arise, we plan to make additional investments in ATC through general capital calls based upon our pro-ratapro rata ownership interest in ATC. On January 29, 2010,30, 2012, we invested an additional $1.2$0.8 million in ATC. In total, we expect to invest approximately $2$3 million throughout 2010.2012. (See Note 6. Investment in ATC.)
In April 2011, ATC and Duke Energy Corporation announced the creation of a joint venture, Duke-American Transmission Co. (DATC) that intends to build, own and operate new electric transmission infrastructure in the U.S. and Canada. DATC is subject to the rules and regulations of FERC, MISO, PJM Interconnection LLC and various other independent system operators and state regulatory authorities. In September 2011, DATC announced its first set of proposed transmission projects, which include seven new transmission line projects in five Midwestern states. The individual projects have a total cost of approximately $4 billion. We intend to maintain our approximate 8 percent ownership interest in ATC.
Investments and Other
BNI Coal. In 2009,2011, BNI Coal sold approximately 4.24.3 million tons of coal (4.5(3.8 million tons in 2008)2010) and anticipates 2012 sales to be similar sales in 2010.to 2011.
ALLETE Properties. ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell the portfolio over time or in bulk transactions. ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise and reinvest the proceeds in its growth initiatives. ALLETE does not intend to acquire additional Florida real estate.
Our two major development projects are Town Center and Palm Coast Park. Ormond Crossings, a thirdAnother major project, thatOrmond Crossings, is currently in the planning stage, received land use approvals in December 2006. However, due to a change in the Florida law that became effective in July 2009, those approvals are being revised. It is anticipated that thestage. The City of Ormond Beach, FL will approveFlorida, approved a new Development Agreement for Ormond Crossings in the first quarter of 2010. The new agreementwhich will facilitate development of the project as currently planned. Separately, the Lake Swamp wetland mitigation bank was permitted on land that was previously part of Ormond Crossings.
| Summary of Development Projects | | Total | Residential | Non-residential |
| Land Available-for-Sale | Ownership | Acres (a) | Units (b) | Sq. Ft. (b, c) |
| Current Development Projects | | | | |
| Town Center | 80% | 854 | 2,264 | 2,238,400 |
| Palm Coast Park | 100% | 3,143 | 3,154 | 3,555,000 |
| Total Current Development Projects | | 3,997 | 5,418 | 5,793,400 |
| Proposed Development Project | | | | |
| Ormond Crossings | 100% | 2,924 | (d) | (d) |
| Other | | | | |
| Lake Swamp Wetland Mitigation Project | 100% | 3,034 | (e) | (e) |
| Total of Development Projects | | 9,955 | 5,418 | 5,793,400 |
|
| | | | | | | | |
| Summary of Development Projects | | | | Residential | Non-residential |
| Land Available-for-Sale | Ownership | Acres (a) | Units (b) | Sq. Ft. (b,c) |
| Current Development Projects | | | | | |
| Town Center | 100% | (d) | 965 |
| 2,485 |
| 2,246,200 |
|
| Palm Coast Park | 100% | | 3,888 |
| 3,554 |
| 3,096,800 |
|
| Total Current Development Projects | | | 4,853 |
| 6,039 |
| 5,343,000 |
|
| Proposed Development Project | | | | | |
| Ormond Crossings | 100% | | 2,914 |
| 2,950 |
| 3,215,000 |
|
| Other | | | | | |
| Lake Swamp Wetland Mitigation Project | 100% | | 3,044 |
| (e) |
| (e) |
|
| Total of Development Projects | | | 10,811 |
| 8,989 |
| 8,558,000 |
|
| |
| (a) | Acreage amounts are approximate and shown on a gross basis, including wetlands and non-controlling interest.wetlands. |
| |
| (b) | EstimatedUnits and includes non-controlling interest.square footage are estimated. Density at build out may differ from these estimates. |
| |
| (c) | Depending on the project, non-residential includes retail commercial, non-retail commercial, office, industrial, warehouse, storage and institutional. |
| |
| (d) | A development order that was approvedIn 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased for $8.8 million by the Cityissuing 0.2 million shares of Ormond Beach is being replaced by a development agreement to facilitate development of Ormond Crossings as currently planned. At build-out, we expect the project to include 2,950 residential units, 4.87 million square feet of various types of non-residential space and public facilities.ALLETE common stock. |
| |
| (e) | The Lake Swamp wetland mitigation bank is a permitted, regionally significant wetlands mitigation bank that was permitted by the St. Johns River Water Management District in 2008 and by the U.S. Army Corps of Engineers in December 2009.bank. Wetland mitigation credits will be used at Ormond Crossings and will also be available for saleare available-for-sale to developers of other projects that are located in the bank’s service area. |
Outlook (Continued)
Investments and Other (Continued)
Other Land Available-for-Sale (a) | Total | Mixed Use | Residential | Non-residential | Agricultural |
Acres (b) | | | | | |
| Other Land | 1,277 | 394 | 113 | 267 | 503 |
(a) | Other land includes land located in Palm Coast, Lehigh, and Cape Coral, Florida. |
(b) | Acreage amounts are approximate and shown on a gross basis, including wetlands and non-controlling interest. |
Long-term finance receivables asIn addition to the three development projects and the mitigation bank, ALLETE Properties has 1,979 acres of December 31, 2009, were $12.9 million, which included $7.8 million due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair value of the collateral relating to these receivables was greater than the $7.8 million amount due at December 31, 2009, and no impairment was recorded on these receivables; however, $0.3 million of impairments was recorded on other receivables.
If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. In many cases, contract purchasers incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they have substantially more at risk than the deposit.land available-for-sale.
ALLETE intends to sell its Florida land assets at reasonable prices when opportunities arise. However, if weak market conditions continue for an extended period of time, the impact on our future operations would be the continuation of little toor no sales while still incurring operating expenses and carrying costs such as community development district assessments and property taxes. This could result in annual net losses for ALLETE Properties similar to 2009.
ALLETE Clean Energy. On August 26, 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements.
Income TaxesTaxes.. ALLETE’s ALLETE's aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2010.2012. On an ongoing basis, ALLETE has certain tax credits and other tax adjustments that will reduce the statutory rate to the expected effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, wind productionrenewable tax credits, AFUDC-Equity, domestic manufacturer’smanufacturer's deduction, depletion, Medicare prescription reimbursement, as well as other items. The annual effective rate can also be impacted by such items as changes in income from operations before non-controlling interest and income taxes, state and federal tax law changes that become effective during the year, business combinations and configuration changes, tax planning initiatives and resolution of prior years’years' tax matters. WeDue primarily to increased renewable tax credits as a result of additional wind generation, we expect our effective tax rate to be approximately 3530 percent for 2010.2012.
Liquidity and Capital Resources
Liquidity Position.ALLETE is well-positioned to meet the Company’s immediate cash flow needs. At As of December 31, 2009,2011, we have ahad cash balanceand cash equivalents of approximately $26$101.1 million $87.8, $255.3 million of unused in available consolidated lines of credit ($157.0 million net of $69.2 million drawn down as of December 31, 2009), and a debt-to-capital ratio of 4344 percent. InOn February 1, 2012, the first quarter 2010, we expect to use proceeds from the saleCompany entered into an additional $150 million syndicated revolving credit facility. This new facility is unsecured and has a maturity date of $80 million First Mortgage Bonds to repay the amount drawn down on the line of credit.January 31, 2014.
Capital Structure.ALLETE’s capital structure for each of the last three years is as follows:
| Year Ended December 31 | 2009 | % | 2008 | % | 2007 | % |
| Millions | | | | | | |
| Common Equity | $929.5 | 57 | $827.1 | 57 | $742.6 | 63 |
| Non-Controlling Interest | 9.5 | – | 9.8 | 1 | 9.3 | 1 |
| Long-Term Debt (Including Current Maturities) | 701.0 | 43 | 598.7 | 42 | 422.7 | 36 |
| Short-Term Debt | 1.9 | – | 6.0 | – | – | – |
| | $1,641.9 | 100 | $1,441.6 | 100 | $1,174.6 | 100 |
|
| | | | | | | | | | | | | |
| Year Ended December 31 | 2011 |
| % | 2010 |
| % | 2009 |
| % |
| Millions | | | | | | |
| Common Equity |
| $1,079.3 |
| 56 |
| $976.0 |
| 55 |
| $929.5 |
| 57 |
|
| Non-Controlling Interest | — |
| — | 9.0 |
| 1 | 9.5 |
| — |
|
| Long-Term Debt (Including Current Maturities) | 863.3 |
| 44 | 785.0 |
| 44 | 701.0 |
| 43 |
|
| Short-Term Debt | 1.1 |
| — | 1.0 |
| — | 1.9 |
| — |
|
| |
| $1,943.7 |
| 100 |
| $1,771.0 |
| 100 |
| $1,641.9 |
| 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 | 2009 | 2008 | 2007 |
| Millions | | | |
| Cash and Cash Equivalents at Beginning of Period | $102.0 | $23.3 | $44.8 |
| Cash Flows from (used for) | | | |
| Operating Activities | 137.4 | 153.6 | 124.2 |
| Investing Activities | (320.0) | (276.1) | (154.1) |
| Financing Activities | 106.3 | 201.2 | 8.4 |
| Change in Cash and Cash Equivalents | (76.3) | 78.7 | (21.5) |
| Cash and Cash Equivalents at End of Period | $25.7 | $102.0 | $23.3 |
|
| | | | | | | | | |
| Year Ended December 31 | 2011 |
| 2010 |
| 2009 |
|
| Millions | | | |
| Cash and Cash Equivalents at Beginning of Period |
| $44.9 |
|
| $25.7 |
|
| $102.0 |
|
| Cash Flows from (used for) | | |
|
| Operating Activities | 241.7 |
| 228.7 |
| 137.4 |
|
| Investing Activities | (240.9 | ) | (250.9 | ) | (320.0 | ) |
| Financing Activities | 55.4 |
| 41.4 |
| 106.3 |
|
| Change in Cash and Cash Equivalents | 56.2 |
| 19.2 |
| (76.3 | ) |
| Cash and Cash Equivalents at End of Period |
| $101.1 |
|
| $44.9 |
|
| $25.7 |
|
Operating Activities. Cash from operating activities was $137.4$241.7 million for 2009 ($153.62011 ($228.7 million for 2008; $124.22010; $137.4 million for 2007)2009). CashThe increase in cash from operating activities was lower in 2009 primarily due to lowerhigher 2011 net income an increaseprimarily from our Regulated Operations Segment, decreased cash contributions to our pension and other post-retirement employee benefit plans ($24.7 million in accounts receivable,2011 and higher deferred regulatory assets,$39.3 million in 2010), increased customer deposits, partially offset by a decrease in accounts payable and higher deferred tax and depreciation expense. Accounts receivable increased due a receivable for 2009 income tax refunds primarily resulting from substantial income tax deductions under the bonus depreciation provision of the American Recovery and Reinvestment Act of 2009 (the Act). Deferred regulatory assets increased due to the collection of certain current cost recovery rider revenue attributable to 2009 being deferred into a later year. Deferred tax expense increased also due to the bonus depreciation provisions of the Act, and depreciation expense increased in conjunction with the increase in property, plant and equipment.inventory balances.
Cash from operating activities was higher in 20082010 than 20072009 primarily due to an increasehigher net income, higher depreciation expense related to increased plant in deferredservice in 2010, and collections of income tax expensereceivables due to bonus depreciation as a result of the American Recovery and decreased working capital requirements, whichReinvestment Act of 2009 and tax planning initiatives. This increase was partially offset by lower net income and higher cash contributions to the defined benefit pension and other postretirement healthbenefit plans (included in Other Liabilities on the Consolidated Statement2010 of Cash Flows). Working capital requirements decreased mainly due to lower uncollected purchased power costs (included$26.5 million and $12.8 million respectively ($20.9 million and $9.3 million in Prepayments and Other on the Consolidated Statement of Cash Flows)2009). Deferred income tax expense increased due to the Economic Stimulus Act of 2008, and contributions to defined benefit pension and postretirement health plans increased $15.6 million during 2008.
Investing Activities. Cash used for investing activities was $320.0$240.9 million for 2009 ($276.12011 ($250.9 million for 2008; $154.12010; $320.0 million for 2007)2009). CashThe decrease in cash used for investing activities was higher than 2008 reflecting increased capital additions to property, plant, and equipment. Capital additions to property, plant, and equipment increasedprimarily due to lower capital expenditures in 2011 and the purchaseredemption of an existing 250 kV DC transmission lineARS for $69.7$6.7 million offset by a decrease in other capital additions because of the completion of some major capital projects in 2008 and 2009. In addition, 2008 included higher net sales of short-term investments and proceeds from the sale of assets (retail shopping center) in Winter Haven, Florida.January 2011.
Cash used for investing activities in 2010 was higher in 2008lower than 20072009 reflecting increaseddecreased capital additions to property, plant and equipment, which were partially offset by the proceeds from the sale of assets (retail shopping center) in Winter Haven, Florida. Capital additions to property, plant, and equipment increased due to construction activity for environmental retrofit projects, AREA Plan projects, Taconite Ridge, and additionallower investments in ATC.
Financing Activities. Cash from financing activities was $106.3$55.4 million for 2009 ($201.22011 ($41.4 million for 2008; $8.42010; $106.3 million for 2007)2009). Cash from financing activities was higher in 2011 primarily due to increased proceeds from the issuances of common stock, partially offset by lower net proceeds of long-term debt in 2011.
Liquidity and Capital Resources (Continued)
Financing Activities (Continued)
Cash from financing activities was lower in 2010 compared to 2009 than 2008 due to less debthigher internally generated cash and common stock issuance. During 2009, $111.4 million of debt was issued, whilelower capital expenditures which resulted in 2008 $198.7 million of debt was issued. During 2009, proceeds fromlower common stock issuances totaled $65.2 million, while in 2008, proceeds from common stock issuances totaled $71.1 million. Lower debt and common stock issuance in 2009 was a result of issuing capital in 2008 ahead of the need for this capital.
less incremental external financing required. Cash from financing activities in 2010 included new debt issuances of $155 million compared to $111.4 million in 2009, of which $65 million of the proceeds were used to pay off the syndicated revolving credit facility that was higherdrawn in 2008 than 2007 primarily from the issuance of debt for $198.7 million. In addition, common stock was issued for net proceeds of $71.1 million. Financing activities increased to support our capital expenditure program.late 2009.
Working Capital.Capital. Additional working capital, if and when needed, generally is provided by consolidated bank lines of credit or the sale of securities or commercial paper. We haveAs of December 31, 2011, we had available consolidated bank lines of credit aggregating $87.8$255.3 million, the majority of which expire in June 2015. On February 1, 2012, ALLETE entered into an additional $150 million syndicated revolving credit facility. This new facility is unsecured and has a maturity date of January 2012.31, 2014. In addition, we have 0.41.4 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 3.32.7 million original issue shares of common stock available for issuance through a Distribution Agreement with KCCI, Inc. The amount and timing of future sales of our securities will depend upon market conditions and our specific needs.
Liquidity and Capital Resources (Continued)
Securities. In January 2009, we issued $42.0 million in principal amount of unregistered First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We have the option to prepay all or a portion of the Bonds at our discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for this type of transaction. We are using the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.
In December 2009, we agreed to sell $80.0 million in principal amount of First Mortgage Bonds (Bonds) in the private placement market in three series as follows:
Issue Date
(on or about)
| Maturity | Principal Amount | Coupon |
February 17, 2010 | April 15, 2021 | $15 Million | 4.85% |
February 17, 2010 | April 15, 2025 | $30 Million | 5.10% |
February 17, 2010 | April 15, 2040 | $35 Million | 6.00% |
We expect to use the proceeds from the February 2010 sale of Bonds to pay down the syndicated revolving credit facility, to fund utility capital investments or for general corporate purposes.
We entered into a Distribution Agreementdistribution agreement with KCCI, Inc., originating in February 2008, and subsequentlyas amended, in February 2009, with respect to the issuance and sale of up to an aggregate of 6.6 million shares of our common stock, without par value. For the year ended December 31, 2011, 0.4 million shares of common stock were issued under this agreement, for net proceeds of $16.0 million (0.2 million shares for net proceeds of $6.0 million in 2010). As of December 31, 2011, 2.7 million shares of common stock remain available for issuance pursuant to the amended distribution agreement. The shares issued in 2011 and 2010 were offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement Nos. 333-170289 and 333-147965. The remaining shares may be offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-147965. During 2009, 1.7 million shares of common stock were issued under this agreement resulting in net proceeds of $51.9 million. In 2008, 1.6 million shares were issued for net proceeds of $60.8 million.333-170289.
In March 2009, we contributed 463,000 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registered the 463,000 shares of ALLETE common stock with the SEC pursuant to Registration Statement No. 333-147965.
In 2009,2011, we issued 0.40.6 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 $13.3 million.$24.7 million. These shares of common stock were registered under the following Registration Statement Nos. 333-150681, 333-105225 and 333-124455,333-162890, respectively.
On December 15, 2011, ALLETE contributed approximately 507,600 shares of ALLETE common stock to its pension plan. These shares of ALLETE common stock were contributed in reliance upon exemption available pursuant to Section 4(2) of the Securities Act of 1933 and had an aggregate value of $20.0 million when contributed.
In the third quarter of 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss is recognized in net income or comprehensive income.
Financial Covenants. Our long-term debt arrangements contain customary covenants. In addition,See Note 10. Short-Term and Long-Term Debt for information regarding our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. The most restrictive covenant requires ALLETE to maintain a ratio of its Funded Debt to Total Capital (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, 2009, our ratio was approximately 0.41 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. As of December 31, 2009, ALLETE was in compliance with its financial covenants.
Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 11. Commitments, Guarantees and Contingencies.
Liquidity and Capital Resources (Continued)
Contractual Obligations and Commercial Commitments. Minnesota Power has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. The followingFollowing is a summarized table of contractual obligations and other commercial commitments at December 31, 2009.2011.
| | Payments Due by Period |
| Contractual Obligations | | Less than | 1 to 3 | 4 to 5 | After |
| As of December 31, 2009 | Total | 1 Year | Years | Years | 5 Years |
| Millions | | | | | |
Long-Term Debt (a) | $1,172.1 | $41.5 | $196.6 | $98.2 | $835.8 |
| Pension and Other Postretirement Benefit Plans | 194.1 | 36.6 | 105.4 | 52.1 | – |
| Operating Lease Obligations | 89.1 | 8.8 | 26.4 | 15.8 | 38.1 |
Uncertain Tax Positions (b) | – | – | – | – | – |
| Unconditional Purchase Obligations | 394.0 | 114.1 | 102.7 | 30.4 | 146.8 |
| | $1,849.3 | $201.0 | $431.1 | $196.5 | $1,020.7 |
ALLETE 2011 Form 10-K
46
Liquidity and Capital Resources (Continued)
Contractual Obligations (Continued)
|
| | | | | | | | | | | | | | | |
| | Payments Due by Period |
| Contractual Obligations | | Less than | 1 to 3 | 4 to 5 | After |
| As of December 31, 2011 | Total | 1 Year | Years | Years | 5 Years |
| Millions | | | | | |
| Long-Term Debt |
| $1,372.2 |
|
| $48.2 |
|
| $307.6 |
|
| $140.8 |
|
| $875.6 |
|
| Pension | 132.9 |
| 1.0 |
| 96.5 |
| 35.4 |
| — |
|
| Other Postretirement Benefit Plans | 55.0 |
| 13.9 |
| 29.5 |
| 11.6 |
| — |
|
| Operating Lease Obligations | 96.8 |
| 10.9 |
| 33.7 |
| 17.7 |
| 34.5 |
|
Uncertain Tax Positions (a) | — |
| — |
| — |
| — |
| — |
|
Unconditional Purchase Obligations (b) | 671.6 |
| 319.5 |
| 126.1 |
| 43.6 |
| 182.4 |
|
| |
| $2,328.5 |
|
| $393.5 |
|
| $593.4 |
|
| $249.1 |
|
| $1,092.5 |
|
| |
| (a) | Includes interest and assumes variable interest rates in effect at December 31, 2009, remains constant through remaining term. |
(b) | Excludes $9.5$11.4 million of noncurrentnon-current unrecognized tax benefits due to uncertainty regarding the timing of future cash payments related to the guidance in accounting for uncertain tax positions. |
| |
| (b) | Excludes agreements with Manitoba Hydro expiring in 2022 and 2035 as our obligation under these contracts is conditional on surplus energy and the construction of additional transmission capacity. |
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 our consolidated balance sheet, plus interest. The table above assumes that the interest raterates in effect at December 31, 2009, remains2011, remain constant through the remaining term. (See Note 10. Short-Term and Long-Term Debt.)
Pension and Other Postretirement Benefit Plans. The funded status of the defined Our pension and other postretirement benefit plan obligations refers to the difference between plan assets and estimated obligations under the plans. The funded status may change over time due torepresent our current estimate of employer contributions. Pension contributions will be dependent on several factors including contribution levels, assumedrealized asset performance, future discount ratesrate and actualother actuarial assumptions, IRS and assumed rates of return on plan assets.
Management considers various factors when making funding decisions such asother regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. Estimated defined benefit pension contributions for years 2010 through 2014 are expected to be up to $25 million per year, and are based on estimates and assumptions that are subject to change. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements. Estimated postretirement healthThese amounts are estimates and life contributions for years 2010 through 2014 are approximately $11 million per year, and arewill change based on estimatesactual market performance, changes in interest rates and assumptions that are subject to change.any changes in governmental regulations. (See Note 16. Pension and Other Postretirement Benefit Plans.)
Unconditional Purchase Obligations.Unconditional purchase obligations represent our Square Butte power purchase agreements,and Manitoba Hydro PPAs, minimum purchase commitments under coal and rail contracts, and purchase obligations for certain capital expenditure projects. (See Note 11. Commitments, Guarantees and Contingencies.)
Under our power purchase agreementMinnesota Power's PPA with Square Butte that extends through 2026, we are obligated to pay our pro rata share of Square Butte’s costs based on our entitlement to the output of Square Butte’s 455-MW455 MW coal-fired generating unit near Center, North Dakota. 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 fixed costs consist primarily of debt service. The table above reflects our share of future debt service based on our output entitlement of 50 percent. This debt service may be reduced if the contingent power sales agreement with Minnkota Power goes into effect in 2013. For further information on Square Butte see(See Note 11. Commitments, Guarantees and Contingencies.)
We have a PPA with Manitoba Hydro that expires in April 2015. 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.
In 2006 and 2007, Minnesota Power entered into two long-term wind power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc. to purchase the output from two wind facilities, Oliver Wind I and Oliver Wind II located near Center, North Dakota. We began purchasing the output from Oliver Wind I a 50-MW facility, in December 2006(50 MW) and the output from Oliver Wind II a 48-MW facility in November 2007.(48 MW) – wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities.facilities at fixed prices. There are no fixed capacity charges and we only pay for energy as it is delivered to us.
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’s 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. 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.
Liquidity and Capital Resources (Continued)
Credit Ratings (Continued)
|
| | |
| Credit Ratings | Standard & Poor’s | Moody’s |
| Issuer Credit Rating | BBB+ | Baa1 |
| Commercial Paper | A-2 | P-2 |
| Senior Secured | | |
First Mortgage Bonds (a) | A– | A2 |
| Unsecured Debt | | |
| Collier County Industrial Development Revenue Bonds – Fixed Rate | BBB | – |
| |
| (a) | Includes collateralized pollution control bonds. |
Common Stock Dividends. ALLETE is committed to providing an attractive, secure dividend to its shareholders while at the same time funding its growth strategy.growth. The Company’s long-term objective is to maintain a dividend payout ratio similar to our peers and provide for future dividend increases. In 2009,2011, we paid out 66 percent (81 percent in 2010; 93 percent (61 percent in 2008; 53 percent in 2007)2009) of our per share earnings in dividends. On January 21, 2010,26, 2012, our Board of Directors declared a dividend of $0.44$0.46 per share, unchanged from 2009, which is payable on March 1, 2010,2012, to shareholders of record at the close of business on February 15, 2010.2012.
Capital Requirements
ALLETE’s projected capital expenditures for the years 20102012 through 20142016 are presented in the table below. Actual capital expenditures may vary from the estimates due to changes in forecasted plant maintenance, regulatory decisions or approvals, future environmental requirements, base load growth, or capital market conditions.conditions or executions of new business strategies.
Capital Expenditures | 2010 | 2011 | 2012 | 2013 | 2014 | Total |
| Regulated Utility Operations | | | | | | |
| | Base and Other | $156 | $82 | $81 | $82 | $89 | $490 |
| | Current Cost Recovery (a) | | | | | | |
| | | Environmental | 2 | – | – | – | – | 2 |
| | | Renewable | 81 | 66 | – | – | – | 147 |
| | | Transmission | 5 | 21 | 27 | 42 | 13 | 108 |
| | | Generation | – | – | – | – | – | – |
| | Total Current Cost Recovery | 88 | 87 | 27 | 42 | 13 | 257 |
| Regulated Utility Capital Expenditures | 244 | 169 | 108 | 124 | 102 | 747 |
| Other | | 6 | 18 | 24 | 8 | 8 | 64 |
| Total Capital Expenditures | $250 | $187 | $132 | $132 | $110 | $811 |
|
| | | | | | | | | | | | | | | | | | | |
| Capital Expenditures | 2012 |
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| Total |
|
| Millions | | | | | | |
| Regulated Utility Operations | | | | | | |
| | Base and Other |
| $112 |
|
| $148 |
|
| $143 |
|
| $122 |
|
| $116 |
|
| $641 |
|
| | Current Cost Recovery (a) | | | | | | |
| | Environmental (b) | 11 |
| 94 |
| 152 |
| 68 |
| — |
| 325 |
|
| | Renewable | 274 |
| 3 |
| 7 |
| — |
| — |
| 284 |
|
| | Transmission (c) | 31 |
| 36 |
| 26 |
| 8 |
| 12 |
| 113 |
|
| | Total Current Cost Recovery | 316 |
| 133 |
| 185 |
| 76 |
| 12 |
| 722 |
|
| Regulated Utility Capital Expenditures | 428 |
| 281 |
| 328 |
| 198 |
| 128 |
| 1,363 |
|
| Other | | 13 |
| 20 |
| 8 |
| 8 |
| 4 |
| 53 |
|
| Total Capital Expenditures |
| $441 |
|
| $301 |
|
| $336 |
|
| $206 |
|
| $132 |
|
| $1,416 |
|
| |
| (a) | Estimated current capital expenditures recoverable outside of a rate case. |
| |
| (b) | Environmental capital expenditures relate to Boswell Unit 4 in order to address compliance with the MATS rule. Compliance costs for this project are estimated between $300 million and $400 million with the lower end of this range reflected in the table above. |
| |
| (c) | Transmission capital expenditures related to CapX2020 are estimated at approximately $90 million over the 2012 to 2016 period. |
We intend to finance expenditures from both internally generated funds and incremental debt and equity. Based on our anticipated capital expenditures reflected above, we project our rate base to grow by approximately 40 percent through 2016. Other proposed environmental regulations could result in future capital expenditures that are not included in the table above. Currently, future CapX2020 projects are under discussion and Minnesota Power may elect to participate on a project by project basis.
Environmental and Other Matters
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. We are unable to predict the outcome of the issues discussed in Note 11. Commitments, Guarantees and Contingencies. (See Item 1. Business – Environmental Matters.)
Market Risk
Securities Investments
Available-for-Sale Securities. At December 31, 2009,2011, our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities.benefits. (See Note 7. Investments.)
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 table below presents the long-term debt obligations and the corresponding weighted average interest rate at December 31, 2009.2011
Market Risk (Continued)
Interest Rate Risk (Continued).
| | Expected Maturity Date |
| Interest Rate Sensitive | | | | | | | | Fair |
| Financial Instruments | 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | Total | Value |
| Dollars in Millions | | | | | | | | |
| Long-Term Debt | | | | | | | | |
Fixed Rate (a) | $1.6 | $1.6 | $1.6 | $71.1 | $19.6 | $528.1 | $623.6 | $657.3 |
| Average Interest Rate – % | 5.9 | 5.9 | 5.9 | 5.2 | 6.9 | 5.9 | 5.8 | |
| | | | | | | | | |
| Variable Rate | $3.6 | $12.3 | $1.7 | $2.8 | – | $57.0 | $77.4 | $77.5 |
Average Interest Rate – % (b) | 0.4 | 3.6 | 1.9 | 0.3 | – | 0.3 | 0.9 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Expected Maturity Date |
| Interest Rate Sensitive | | | | | | | | Fair |
| Financial Instruments | 2012 |
| 2013 |
| 2014 |
| 2015 |
| 2016 |
| Thereafter |
| Total |
| Value |
| Dollars in Millions | | | | | | | | |
| Long-Term Debt | | | | | | | | |
| Fixed Rate |
| $2.0 |
|
| $71.5 |
|
| $19.2 |
|
| $1.0 |
|
| $21.0 |
|
| $600.9 |
|
| $715.6 |
|
| $818.7 |
|
| Average Interest Rate – % | 5.6 |
| 5.2 |
| 6.8 |
| 4.8 |
| 7.6 |
| 5.7 |
| 5.8 |
| |
| | | | | | | | | |
| Variable Rate |
| $3.4 |
|
| $12.3 |
|
| $75.0 |
|
| $15.7 |
| — |
|
| $41.3 |
|
| $147.7 |
|
| $147.7 |
|
Average Interest Rate – % (a) | 3.1 |
| 3.6 |
| 1.3 |
| 0.2 |
| — |
| 0.1 |
| 1.1 |
| |
| |
| (a) | The $65 million line of credit is included in the fixed rate maturity of $528.1 as it will be refinanced with long-term debt in the first quarter of 2010. |
(b) | Assumes raterates in effect at December 31, 2009, remains2011 remain constant through remaining term. The $75 million term loan maturing in 2014 has an effective fixed rate of 1.825% due to an interest rate swap. |
Interest rates on variable rate long-term debt are reset on a periodic basis reflecting currentprevailing market conditions. Based on the variable rate debt outstanding at December 31, 2009,2011, and assuming no other changes to our financial structure, an increase or decrease of 100 basis points in interest rates would impact the amount of pretax 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, 2011.
Commodity Price Risk. Our regulated utility operations in Minnesota and Wisconsin 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 territories.territory in Wisconsin. Our Minnesota regulated utilities’utility’s exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory environment,framework, which allows recovery of fuel costs in excess of those included in the 2008 retail rate case filing.base rates. Conversely, costs below those in the 2008 retail rate case filingbase rates result in a credit to our ratepayers. 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 power (in Minnesota), powerrelated transportation costs (Minnesota Power) and natural gas (in Wisconsin), and related transportation costs.(SWL&P).
Power Marketing. Our power marketing activities consist ofof: (1) purchasing energy in the wholesale market for resale into serve our regulated service territoriesterritory when retail energy requirements exceed generation outputoutput; and (2) selling excess available energy and purchased power. From time to time, our utility operations may have excess energy that is temporarily not required by retail and wholesalemunicipal customers in our regulated service territory. We actively sell thisany excess energy to the wholesale market to optimize the value of our generating facilities.
In 2009 kilowatt-hour sales to our taconite customers were lower by approximately 54 percent from 2008 levels. During 2009, we sold available power to Other Power Suppliers to partially mitigate the earnings impact of these lower industrial sales. Minnesota Power expects an increase in taconite production in 2010 compared to 2009, although production will still be less than previous years’ levels.
For the year ended December 31, 2009, we have entered into financial derivative instruments to manage price risk for certain power marketing contracts. Outstanding derivative contracts at December 31, 2009, consist of cash flow hedges for an energy sale that includes pricing based on daily natural gas prices, and FTRs purchased to manage congestion risk for forward power sales contracts. These derivative instruments are recorded on our consolidated balance sheet at fair value. As of December 31, 2009, we recorded approximately $0.7 million of derivatives in other assets on our consolidated balance sheet of which the entire balance relates to our FTRs. These derivative instruments settle monthly throughout the first five months of 2010. (See Note 8. Derivatives.)
Approximately 200 MWs of capacity and energy from our Taconite Harbor facility in northern Minnesota has been sold through two sales contracts totaling 175 MWs (201 MWs including a 15 percent reserve), which were effective May 1, 2005, and expire on April 30, 2010. Both contracts contain fixed monthly capacity charges and fixed minimum energy charges. One contract provides for an annual escalator to the energy charge based on increases in our cost of fuel, subject to a small minimum annual escalation. The other contract provides that the energy charge will be the greater of the fixed minimum charge or an annual amount based on the variable production cost of a combined-cycle, natural gas unit. Our exposure in the event of a full or partial outage at our Taconite Harbor facility is significantly limited under both contracts. When the buyer is notified at least two months prior to an outage, there is no liability. Outages with less than two months notice are subject to an annual duration limitation typical of this type of contract. These contracts qualify for the normal purchase normal sale exception under the guidance for derivative instruments and hedging activities and are not required to be recorded at fair value.
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.
ALLETE 20092011 Form 10-K
49
Market Risk (Continued)
Power Marketing (Continued)
Power Sales Agreement. On October 29, 2009, Minnesota Power entered into an agreement to sell Basin 100 MWs of capacity and energy for the next ten years. The transaction is scheduled to begin in May 2010, following the expiration of two wholesale power sales contracts on April 30, 2010. The Basin agreement contains a fixed monthly schedule of capacity charges with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on our cost of fuel. The agreement allows us to recover a pro-rata share of increased costs related to emissions that may occur during the last five years of the contract.
NewRecently Adopted Accounting StandardsStandards.
New accounting standards 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, 20092011 and 2008,2010, and for each of the three years in the period ended December 31, 2009,2011, 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
Under the supervision and with the participation of management, including our principal executive officer and principal financial officer, as of December 31, 2011, we conducted an evaluation of the effectiveness of the design and operation of ALLETE’s disclosure controls and procedures (as defined in Rules 13a-15(e) andor 15d-15(e) of the Securities Exchange Act of 1934 (“Exchange Act”)(Exchange Act)). Based upon those evaluations, our principal executive officer and principal financial officer have concluded that, as of December 31, 2011, 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 framework in Internal Control—Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.2011.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009,2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Item 9A. | Controls and Procedures (Continued) |
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. In January 2012, the Company completed and installed new information systems designed to enhance certain supply-chain, financial and asset management applications. These changes were not the result of any identified deficiencies in our internal control over financial reporting.
| |
| Item 9B. | Other Information |
None.
Not applicable.
ALLETE 20092011 Form 10-K
50
Part III
| |
| Item 10. | Directors, Executive Officers and Corporate Governance |
Unless otherwise stated, the information required for this Item is incorporated by reference herein from our Proxy Statement for the 20102012 Annual Meeting of Shareholders (2010(2012 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 “Audit Committee Report” section;
|
| · | Audit Committee Members. The identity of the Audit Committee members is included in 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 “Section 16(a) Beneficial Ownership Reporting Compliance” section.
|
Audit Committee Financial Expert. The information regarding the Audit Committee financial expert will be included in the “Audit Committee Report” section;
Audit Committee Members. The identity of the Audit Committee members will be included in 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 20102012 Proxy Statement will be filed with the SEC within 120 days after the end of our 20092011 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 controller. 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 CompensationAudit Committee Charter; and |
| · |
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 for this Item is incorporated by reference herein from the “Compensation of Executive Officers,Discussion and Analysis,” the “Compensation Discussionof Directors and Analysis”,Executive Officers,” the “Executive Compensation Committee Report” and the “Director Compensation – 2009”2011” sections in our 20102012 Proxy Statement.
| |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required for this Item is incorporated by reference herein from the “Securities“Ownership of ALLETE Common Stock – Securities Owned by Certain Beneficial Owners,” the “Securities owned“Ownership of ALLETE Common Stock – Securities Owned by Directors and Management” and the “Equity Compensation Plan Information” sections in our 20102012 Proxy Statement.
| |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information required for this Item is incorporated by reference herein from the “Corporate Governance” section in our 20102012 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 byfor this Item is incorporated by reference herein from the “Audit Committee Report” section in our 20102012 Proxy Statement.
ALLETE 20092011 Form 10-K
52
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 15. |
| Exhibits and Financial Statement Schedules | | | |
| (a) | Certain Documents Filed as Part of this Form 10-K. | |
| (1) | Financial Statements | Page |
| | | ALLETE | |
| | | | 57 |
| | | | 58 |
| | For the Three Years Ended December 31, 20092011 | |
| | | | | 59 |
| | | | | 60 |
| | | | | 61 |
| | | | 62 |
| (2) | Financial Statement Schedules | |
| | | | 97 |
| | 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
|
| | | | | | |
| | *3(a)1 | -— | Articles of Incorporation amended and restated as of May 8, 2001 (filed as Exhibit 3(b) to the March 31, 2001, Form 10-Q, File No. 1-3548). |
| | *3(a)2 | -— | Amendment to Articles of Incorporation, dated as of May 12, 2009 (filed as Exhibit 3 to the June 30, 2009, Form 10-Q, File No. 1-3548). |
| | *3(a)3 | -— | Amendment to Articles of Incorporation, dated as of May 19, 2010 (filed as Exhibit 3(a) to the May 14, 2010, Form 8-K, File No. 1-3548). |
| *3(a)4 | — | Amendment to Certificate of Assumed Name, filed with the Minnesota Secretary of State on May 8, 2001 (filed as Exhibit 3(a) to the March 31, 2001, Form 10-Q, File No. 1-3548). |
| | *3(b) | -— | Bylaws, as amended effective August 24, 2004,May 11, 2010 (filed as Exhibit 33(b) to the August 25, 2004,May 14, 2010, Form 8-K, File No. 1-3548). |
| | *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 Douglas J. MacInnesMing Ryan (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) |
| | | | Nineteenth | February 1, 1997 | 1-3548 (1996 Form 10-K) | 4(a)3 |
| | | | Twentieth | November 1, 1997 | 1-3548 (1997 Form 10-K) | 4(a)3 |
| | | | Twenty-first | October 1, 2000 | 333-54330 | 4(c)3 |
| | | | Twenty-second | July 1, 2003 | 1-3548 (June 30, 2003 Form 10-Q) | 4 |
| | | | Twenty-third | August 1, 2004 | 1-3548 (Sept. 30, 2004 Form 10-Q) | 4(a) |
| | | | Twenty-fourth | March 1, 2005 | 1-3548 (March 31, 2005 Form 10-Q) | 4 |
| | | | Twenty-fifth | December 1, 2005 | 1-3548 (March 31, 2006 Form 10-Q) | 4 |
| | | | Twenty-sixth | October 1, 2006 | 1-3548 (2006 Form 10-K) | 4 |
| | | | Twenty-seventh | February 1, 2008 | 1-3548 (2007 Form 10-K) | 4(a)3 |
| | | | Twenty-eighth | May 1, 2008 | 1-3548 (June 30, 2008 Form 10-Q) | 4 |
| | | | Twenty-ninth | November 1, 2008 | 1-3548 (2008 Form 10-K) | 4(a)3 |
| | | | Thirtieth | January 1, 2009 | 1-3548 (2008 Form 10-K) | 4(a)4 |
| | | Thirty-first | February 1, 2010 | 1-3548 (March 31, 2010 Form 10-Q) | 4 |
| | | Thirty-second | August 1, 2010 | 1-3548 (Sept. 30, 2010 Form 10-Q) | 4 |
ALLETE 20092011 Form 10-K
54
Exhibit Number
|
| | | | | | |
| | *4(b)1 | -— | Indenture of Trust, dated as of August 1, 2004, between the City of Cohasset, Minnesota and U.S. Bank National Association, as Trustee relating to $111 Million Collateralized Pollution Control Refunding Revenue Bonds (filed as Exhibit 4(b) to the September 30, 2004, Form 10-Q, File No. 1-3548). |
| | *4(b)2 | -— | Loan Agreement, dated as of August 1, 2004, between the City of Cohasset, Minnesota and ALLETE relating to $111 Million Collateralized Pollution Control Refunding Revenue Bonds (filed as Exhibit 4(c) to the September 30, 2004, Form 10-Q, File No. 1-3548). |
| | *4(c)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(c)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 |
| | | | Sixth | March 24, 1994 | 1-3548 (1996 Form 10-K) | 4(b)1 |
| | | | Seventh | November 1, 1994 | 1-3548 (1996 Form 10-K) | 4(b)2 |
| | | | Eighth | January 1, 1997 | 1-3548 (1996 Form 10-K) | 4(b)3 |
| | | | Ninth | October 1, 2007 | 1-3548 (2007 Form 10-K) | 4(c)3 |
| | | | Tenth | October 1, 2007 | 1-3548 (2007 Form 10-K) | 4(c)4 |
| | | | Eleventh | December 1, 2008 | 1-3548 (2008 Form 10-K) | 4(c)3 |
| | *4(d) | — | Term Loan Agreement, dated as of August 25, 2011, between ALLETE, Inc. and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 4 to the August 31, 2011, Form 8-K, File No. 1-3548). |
| *10(a) | -— | Power Purchase and Sale Agreement, dated as of May 29, 1998, between Minnesota Power, Inc. (now ALLETE) and Square Butte Electric Cooperative (filed as Exhibit 10 to the June 30, 1998, Form 10-Q, File No. 1-3548). |
| | *10(b) | — | Fourth Amended and Restated Committed Facility Letter,Credit Agreement, dated January 11, 2006, by andas of May 25, 2011, among ALLETE, Inc., as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and LaSalle Bank National Association,JPMorgan Securities LLC, as Agent. |
| *10(d)2 | - | First Amendment to Fourth AmendedSole Lead Arranger and Restated Committed Facility Letter dated June 19, 2006, by and among ALLETE and LaSalle Bank National Association, as AgentSole Book Runner (filed as Exhibit 10(a)99 to the June 30, 2006,May 27, 2011, Form 10-Q,8-K, File No. 1-3548). |
| | *10(d)310(c) | -— | Second Amendment to Fourth Amended and Restated Committed Facility LetterCredit Agreement, dated December 14, 2006, by andas of February 1, 2012, among ALLETE, Inc., as Borrower, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and LaSalle Bank National Association,JPMorgan Securities LLC, as AgentSole Lead Arranger and Sole Book Runner (filed as Exhibit 10(d)310 to the 2006February 6, 2011, Form 10-K,8-K, File No. 1-3548). |
| | *10(e)1 | -— | Financing Agreement between Collier County Industrial Development Authority and ALLETE dated as of July 1, 2006 (filed as Exhibit 10(b)1 to the June 30, 2006, Form 10-Q, File No. 1-3548). |
| | *10(e)2 | -— | Amended and Restated Letter of Credit Agreement, dated as of July 5, 2006,June 3, 2011, among ALLETE, the Participating Banks and Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (filed as Exhibit 10(b)2 to the June 30, 2006,2011, Form 10-Q, File No. 1-3548). |
| | | — | LLC (filed as Exhibit 10(g) to the 2009 Form 10-K, File No. 1-3548). |
| | | — | 2011 (filed as Exhibit 10(h)1 to the December 31, 2010, Form 10-K, File No. 1-3548). |
| | +*10(h)2 | -— | Form of ALLETE Executive Annual Incentive Plan Form of Awards Effective 20092010 (filed as Exhibit 10(h)73 to the 2008 2009 Form 10-K, File No. 1-3548). |
| | | — | | December 31, 2010, Form 10-K, File No. 1-3548). |
| +10(h)4 | — | ALLETE Executive Annual Incentive Plan Form of Awards Effective 2012. |
| | +*10(i)1 | -— | ALLETE and Affiliated Companies Supplemental Executive Retirement Plan I (SERP I), as amended and restated, effective January 1, 2009 (filed as Exhibit 10(i)4 to the 2008 Form 10-K, File No. 1-3548). |
| | +*10(i)2 | -— | Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan (SERP I), effective January 1, 2011 (filed as Exhibit 10(i)2 to the December 31, 2010, Form 10-K, File No. 1-3548). |
| +*10(i)3 | — | ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), as amended and restated, effective January 1, 2009,2011 (filed as Exhibit 10(i)53 to the 2008 Form 10-K, File No. 1-3548). |
| +*10(i)3 | - | January 2009 Amendment to the ALLETE and Affiliated Companies Supplemental Executive Retirement Plan II (SERP II), effective January 20, 2009, (filed as Exhibit 10(i)6 to the 2008December 31, 2010, Form 10-K, File No. 1-3548). |
| | +*10(j)1 | -— | Minnesota Power and Affiliated Companies Executive Investment Plan I, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(c) to the 1988 Form 10-K, File No. 1-3548). |
| +*10(j)2 | — | Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548). |
Exhibit Number
|
| | | | |
| +*10(j)1 | — |
| Minnesota Power and Affiliated Companies Executive Investment Plan I, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(c) to the 1988 Form 10-K, File No. 1-3548). |
| | +*10(j)2 | -— |
| Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(v)2 to the 2003 Form 10-K, File No. 1-3548). |
Exhibit Number
| | +*10(j)3 | -— |
| July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(b) to the June 30, 2004, Form 10-Q, File No. 1-3548). |
| | +*10(j)4 | -— |
| August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan I (filed as Exhibit 10(b) to the September 30, 2006, Form 10-Q, File No. 1-3548). |
| | +*10(k)1 | -— |
| Minnesota Power and Affiliated Companies Executive Investment Plan II, as amended and restated, effective November 1, 1988 (filed as Exhibit 10(d) to the 1988 Form 10-K, File No. 1-3548). |
| | +*10(k)2 | -— |
| Amendments through December 2003 to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(w)2 to the 2003 Form 10-K, File No. 1-3548). |
| | +*10(k)3 | -— |
| July 2004 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(c) to the June 30, 2004, Form 10-Q, File No. 1-3548). |
| | +*10(k)4 | -— |
| August 2006 Amendment to the Minnesota Power and Affiliated Companies Executive Investment Plan II (filed as Exhibit 10(c) to the September 30, 2006, Form 10-Q, File No. 1-3548). |
| | +*10(l) | -— |
| Deferred Compensation Trust Agreement, as amended and restated, effective January 1, 1989 (filed as Exhibit 10(f) to the 1988 Form 10-K, File No. 1-3548). |
| | +*10(m)1 | -— |
| ALLETE Executive Long-Term Incentive Compensation Plan as amended and restated effective January 1, 2006 (filed as Exhibit 10 to the May 16, 2005, Form 8-K, File No. 1-3548). |
| | +*10(m)2 | -— | Form of
| Amendment to the ALLETE Executive Long-Term Incentive Compensation Plan, 2006 Nonqualified Stock Option Granteffective January 1, 2011 (filed as Exhibit 10(a)110(m)2 to the January 30, 2006,December 31, 2010, Form 8-K,10-K, File No. 1-3548). |
| | +*10(m)3 | -— |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan Nonqualified Stock Option Grant Effective 2007 (filed as Exhibit 10(m)6 to the 2006 Form 10-K, File No. 1-3548). |
| | +*10(m)4 | -— |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2007 (filed as Exhibit 10(m)7 to the 2006 Form 10-K, File No. 1-3548). |
| | +*10(m)5 | -— |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2008 (filed as Exhibit 10(m)10 to the 2007 Form 10-K, File No. 1-3548). |
| | +*10(m)6 | -— |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2009 (filed as Exhibit 10(m)11 to the 2008 Form 10-K, File No. 1-3548). |
| | +*10(m)7 | -— |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan – Restricted Stock Unit Grant Effective 2009 (filed as Exhibit 10(m)12 to the 2008 Form 10-K, File No. 1-3548). |
| | | — | | Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2010.2010 (filed as Exhibit 10(m)8 to the 2009 Form 10-K, File No. 1-3548). |
| | 89 | — | | Form of ALLETE Executive Long-Term Incentive Compensation Plan – Restricted Stock Unit Grant Effective 2010.2010 (filed as Exhibit 10(m)9 to the 2009 Form 10-K, File No. 1-3548). |
| +*10(m)10 | — |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2011 (filed as Exhibit 10(m)11 to the December 31, 2010, Form 10-K, File No. 1-3548). |
| +*10(m)11 | — |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan – Restricted Stock Unit Grant Effective 2011 (filed as Exhibit 10(m)12 to the December 31, 2010, Form 10-K, File No. 1-3548). |
| +10(m)12 | — |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan Performance Share Grant Effective 2012. |
| +10(m)13 | — |
| Form of ALLETE Executive Long-Term Incentive Compensation Plan – Restricted Stock Unit Grant Effective 2012. |
| | +*10(n)1 | -— |
| Minnesota Power (now ALLETE) Director Stock Plan, effective January 1, 1995 (filed as Exhibit 10 to the March 31, 1995, Form 10-Q, File No. 1-3548). |
| | +*10(n)2 | -— |
| Amendments through December 2003 to the Minnesota Power (now ALLETE) Director Stock Plan (filed as Exhibit 10(z)2 to the 2003 Form 10-K, File No. 1-3548). |
| | +*10(n)3 | -— |
| July 2004 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(e) to the June 30, 2004, Form 10-Q, File No. 1-3548). |
| | +*10(n)4 | -— |
| January 2007 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(n)4 to the 2006 Form 10-K, File No. 1-3548). |
| | +*10(n)5 | -— |
| May 2009 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(b) to the June 30, 2009, Form 10-Q, File No. 1-3548). |
| | +*10(n)6 | -— |
| May 2010 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10(a) to the June 30, 2010, Form 10-Q, File No. 1-3548). |
| +*10(n)7 | — |
| October 2010 Amendment to the ALLETE Director Stock Plan (filed as Exhibit 10 to the September 30, 2010, Form 10-Q, File No. 1-3548). |
Exhibit Number
|
| | | |
| +*10(n)8 | — | ALLETE Non-Management Director Compensation Summary Effective February 15, 2007May 1, 2010 (filed as Exhibit 10(n)610(b) to the 2006March 31, 2010, Form 10-Q, File No. 1-3548). |
| +*10(n)9 | — | ALLETE Non-Management Director Compensation Summary effective January 19, 2011 (filed as Exhibit 10(n)9 to the December 31, 2010, Form 10-K, File No. 1-3548). |
| | +10(n)10 | — | ALLETE Non-Management Director Compensation Summary effective January 19, 2012. |
| +*10(o)1 | -— | Minnesota Power (now ALLETE) Director Compensation Deferral Plan Amended and Restated, effective January 1, 1990 (filed as Exhibit 10(ac) to the 2002 Form 10-K, File No. 1-3548). |
| | +*10(o)2 | -— | October 2003 Amendment to the Minnesota Power (now ALLETE) Director Compensation Deferral Plan (filed as Exhibit 10(aa)2 to the 2003 Form 10-K, File No. 1-3548). |
| | +*10(o)3 | -— | January 2005 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(c) to the March 31, 2005, Form 10-Q, File No. 1-3548). |
| | +*10(o)4 | -— | August 2006 Amendment to the ALLETE Director Compensation Deferral Plan (filed as Exhibit 10(d) to the September 30, 2006, Form 10-Q, File No. 1-3548). |
Exhibit Number
| | +*10(o)5 | -— | ALLETE Non-Employee Director Compensation Deferral Plan II, effective May 1, 2009 (filed as Exhibit 10(a) to the June 30, 2009, Form 10-Q, File No. 1-3548). |
| | +*10(p) | -— | ALLETE Director Compensation Trust Agreement, effective October 11, 2004 (filed as Exhibit 10(a) to the September 30, 2004, Form 10-Q, File No. 1-3548). |
| | +*10(q) | -— | ALLETE and Affiliated Companies Change ofin Control Severance Pay Plan, Effective February 13, 2008,as amended and restated, effective January 19, 2011 (filed as Exhibit 10(q) to the 2007December 31, 2010, Form 10-K, File No. 1-3548). |
| | | — | |
| | | — | |
| | | — | |
| | | — | |
| | | — | |
| | | — | |
| | 95 | -— | Mine Safety. |
| 99 | — | |
| 101.INS | — | XBRL Instance |
| 101.SCH | — | XBRL Schema |
| 101.CAL | — | XBRL Calculation |
| 101.DEF | — | XBRL Definition |
| 101.LAB | — | XBRL Label |
| 101.PRE | — | XBRL Presentation |
SWL&P is a party to other long-term debt instruments, $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, that, pursuant to Regulation S-K, Item 601(b)(4)(iii), are not filed as exhibits since the total amount of debt authorized under each of these omitted instruments does not exceed 10 percent of our total consolidated assets. We will furnish copies of these instruments to the SEC upon its request.
We are a party to another long-term debt instrument, $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, Series 1997B and Series 1997C ($28,280,000 remaining principal balance) that, pursuant to Regulation S-K, Item 601(b)(4)(iii), is not filed as an exhibit since the total amount of debt authorized under this omitted instrument does not exceed 10 percent of our total consolidated assets. We will furnish copies of this instrument to the SEC upon its request.
|
| |
| * | Incorporated herein by reference as indicated. |
| + | Management contract or compensatory plan or arrangement pursuant to Item 15(b). |
ALLETE 20092011 Form 10-K
57
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 12, 201015, 2012 | By | Donald J. Shippar /s/ Alan R. Hodnik |
| | Donald J. Shippar | Alan R. Hodnik |
| | | Chairman, President and Chief Executive Officer |
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 |
| | | | | |
Donald J. Shippar/s/ Alan R. Hodnik | | Chairman, President and Chief Executive Officer | | February 12, 201015, 2012 |
Donald J. ShipparAlan R. Hodnik | | and Director
(Principal Executive Officer) | | |
| | | | | |
Alan R. Hodnik | | President and Director | | February 12, 2010 |
Alan R. Hodnik | | | | |
| | | | |
| /s/ Mark A. Schober | | Senior Vice President and Chief Financial Officer | | February 12, 201015, 2012 |
| Mark A. Schober | | (Principal Financial Officer) | | |
| | | | | |
| /s/ Steven Q. DeVinck | | Controller and Vice President – Business Support | | February 12, 201015, 2012 |
| Steven Q. DeVinck | | (Principal Accounting Officer) | | |
ALLETE 20092011 Form 10-K
58
Signatures (Continued)
|
| | | | |
| Signature | | Title | | Date |
| | | | | |
| /s/ Kathleen A. Brekken | | Director | | February 12, 201015, 2012 |
| Kathleen A. Brekken | | | | |
| | | | | |
| /s/ Kathryn W. Dindo | | Director | | February 12, 201015, 2012 |
| Kathryn W. Dindo | | | | |
| | | | | |
| /s/ Heidi J. Eddins | | Director | | February 12, 201015, 2012 |
| Heidi J. Eddins | | | | |
| | | | | |
| /s/ Sidney W. Emery, Jr. | | Director | | February 12, 201015, 2012 |
| Sidney W. Emery, Jr. | | | | |
| | | | | |
| /s/ James S. Haines, Jr | | Director | | February 12, 201015, 2012 |
| James S. Haines, Jr | | | | |
| | | | | |
| /s/ James J. Hoolihan | | Director | | February 12, 201015, 2012 |
| James J. Hoolihan | | | | |
| | | | | |
| /s/ Madeleine W. Ludlow | | Director | | February 12, 201015, 2012 |
| Madeleine W. Ludlow | | | | |
| | | | | |
George L. Mayer | | Director | | February 12, 2010 |
George L. Mayer | | | | |
| | | | |
| /s/ Douglas C. Neve | | Director | | February 12, 201015, 2012 |
| Douglas C. Neve | | | | |
| | | | | |
Jack I. Rajala | | Director | | February 12, 2010 |
Jack I. Rajala | | | | |
| | | | |
| /s/ Leonard C. Rodman | | Director | | February 12, 201015, 2012 |
| Leonard C. Rodman | | | | |
| | | | | |
| /s/ Donald J. Shippar | | Director | | February 15, 2012 |
| Donald J. Shippar | | | | |
| | | | |
| /s/ Bruce W. Stender | | Director | | February 12, 201015, 2012 |
| Bruce W. Stender | | | | |
ALLETE 20092011 Form 10-K
59
Report of Independent Registered Public Accounting Firm
Tothe Board of Directors and Shareholders of ALLETE, Inc,Inc:
In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of ALLETE, Inc. and its subsidiaries (the Company) at December 31, 20092011 and 2008,2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 2011in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the indexappearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Overover Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007.
A company’scompany'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’scompany'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’scompany's assets that could have a material effect on the financial statements.
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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
February 12, 201015, 2012
ALLETE 20092011 Form 10-K
60
Consolidated Financial Statements
ALLETE Consolidated Balance Sheet
| | | As of December 31 | 2009 | 2008 | 2011 |
| 2010 |
|
| Millions | | | |
| Assets | | | |
| Current Assets | | | |
| Cash and Cash Equivalents | $25.7 | $102.0 |
| $101.1 |
|
| $44.9 |
|
| Accounts Receivable (Less Allowance of $0.9 and $0.7) | 118.5 | 76.3 | |
| Short-Term Investments | | — |
| 6.7 |
|
| Accounts Receivable (Less Allowance of $0.9 and $0.9) | | 79.7 |
| 99.5 |
|
| Inventories | 57.0 | 49.7 | 69.1 |
| 60.0 |
|
| Prepayments and Other | 24.3 | 24.3 | 27.1 |
| 28.6 |
|
| Total Current Assets | 225.5 | 252.3 | 277.0 |
| 239.7 |
|
| Property, Plant and Equipment – Net | 1,622.7 | 1,387.3 | 1,982.7 |
| 1,805.6 |
|
| Regulatory Assets | 293.2 | 249.3 | 345.9 |
| 310.2 |
|
| Investment in ATC | 88.4 | 76.9 | 98.9 |
| 93.3 |
|
| Other Investments | 130.5 | 136.9 | 132.3 |
| 126.0 |
|
| Other Assets | 32.8 | 32.1 | |
| Other Non-Current Assets | | 39.2 |
| 34.3 |
|
| Total Assets | $2,393.1 | $2,134.8 |
| $2,876.0 |
|
| $2,609.1 |
|
| | | | |
| Liabilities and Equity | | | |
| Liabilities | | | |
| Current Liabilities | | | |
| Accounts Payable | $62.1 | $75.7 |
| $71.8 |
|
| $75.4 |
|
| Accrued Taxes | 20.6 | 12.9 | 26.4 |
| 22.0 |
|
| Accrued Interest | 11.1 | 8.9 | 12.8 |
| 13.4 |
|
| Long-Term Debt Due Within One Year | 5.2 | 10.4 | 5.4 |
| 13.4 |
|
| Notes Payable | 1.9 | 6.0 | 1.1 |
| 1.0 |
|
| Other | 32.2 | 36.8 | 45.6 |
| 33.7 |
|
| Total Current Liabilities | 133.1 | 150.7 | 163.1 |
| 158.9 |
|
| Long-Term Debt | 695.8 | 588.3 | 857.9 |
| 771.6 |
|
| Deferred Income Taxes | 253.1 | 169.6 | 373.6 |
| 325.2 |
|
| Regulatory Liabilities | 47.1 | 50.0 | 43.5 |
| 43.6 |
|
| Other Liabilities | 325.0 | 339.3 | |
| Defined Benefit Pension and Other Postretirement Benefit Plans | | 253.5 |
| 231.4 |
|
| Other Non-Current Liabilities | | 105.1 |
| 93.4 |
|
| Total Liabilities | 1,454.1 | 1,297.9 | 1,796.7 |
| 1,624.1 |
|
| | | | |
| Commitments and Contingencies (Note 11) | | |
|
| | | | |
| Equity | | | |
| ALLETE’s Equity | | | |
| Common Stock Without Par Value, 80.0 Shares Authorized, 35.2 and 32.6 | | | |
| Common Stock Without Par Value, 80.0 Shares Authorized, 37.5 and 35.8 | | |
| Shares Outstanding | 613.4 | 534.1 | 705.6 |
| 636.1 |
|
| Unearned ESOP Shares | (45.3) | (54.9) | (29.0 | ) | (36.8 | ) |
| Accumulated Other Comprehensive Loss | (24.0) | (33.0) | (28.9 | ) | (23.2 | ) |
| Retained Earnings | 385.4 | 380.9 | 431.6 |
| 399.9 |
|
| Total ALLETE Equity | 929.5 | 827.1 | 1,079.3 |
| 976.0 |
|
| Non-Controlling Interest in Subsidiaries | 9.5 | 9.8 | — |
| 9.0 |
|
| Total Equity | 939.0 | 836.9 | 1,079.3 |
| 985.0 |
|
| Total Liabilities and Equity | $2,393.1 | $2,134.8 |
| $2,876.0 |
|
| $2,609.1 |
|
The accompanying notes are an integral part of these statements.
ALLETE 20092011 Form 10-K
61
ALLETE Consolidated Statement of Income
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions Except Per Share Amounts | | | |
| Operating Revenue | | | |
| Operating Revenue | $766.7 | $801.0 | $841.7 |
| Prior Year Rate Refunds | (7.6) | – | – |
| Total Operating Revenue | 759.1 | 801.0 | 841.7 |
| Operating Expenses | | | |
| Fuel and Purchased Power | 279.5 | 305.6 | 347.6 |
| Operating and Maintenance | 308.9 | 318.1 | 313.9 |
| Depreciation | 64.7 | 55.5 | 48.5 |
| Total Operating Expenses | 653.1 | 679.2 | 710.0 |
| Operating Income | 106.0 | 121.8 | 131.7 |
| Other Income (Expense) | | | |
| Interest Expense | (33.8) | (26.3) | (22.6) |
| Equity Earnings in ATC | 17.5 | 15.3 | 12.6 |
| Other | 1.8 | 15.6 | 15.5 |
| Total Other Income (Expense) | (14.5) | 4.6 | 5.5 |
| | | | |
| Income Before Non-Controlling Interest and Income Taxes | 91.5 | 126.4 | 137.2 |
| Income Tax Expense | 30.8 | 43.4 | 47.7 |
| Net Income | 60.7 | 83.0 | 89.5 |
| Less: Non-Controlling Interest in Subsidiaries | (0.3) | 0.5 | 1.9 |
| Net Income Attributable to ALLETE | $61.0 | $82.5 | $87.6 |
| | | | |
| Average Shares of Common Stock | | | |
| Basic | 32.2 | 29.2 | 28.3 |
| Diluted | 32.2 | 29.3 | 28.4 |
| | | | |
| Basic Earnings Per Share of Common Stock | $1.89 | $2.82 | $3.09 |
| Diluted Earnings Per Share of Common Stock | $1.89 | $2.82 | $3.08 |
| | | | |
| Dividends Per Share of Common Stock | $1.76 | $1.72 | $1.64 |
|
| | | | | | | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions Except Per Share Amounts | | | |
| Operating Revenue | | | |
| Operating Revenue |
| $928.2 |
|
| $907.0 |
|
| $766.7 |
|
| Prior Year Rate Refunds | — |
| — |
| (7.6 | ) |
| Total Operating Revenue | 928.2 |
| 907.0 |
| 759.1 |
|
| Operating Expenses | | | |
| Fuel and Purchased Power | 306.6 |
| 325.1 |
| 279.5 |
|
| Operating and Maintenance | 381.2 |
| 365.6 |
| 308.9 |
|
| Depreciation | 90.4 |
| 80.5 |
| 64.7 |
|
| Total Operating Expenses | 778.2 |
| 771.2 |
| 653.1 |
|
| Operating Income | 150.0 |
| 135.8 |
| 106.0 |
|
| Other Income (Expense) | | | |
| Interest Expense | (43.6 | ) | (39.2 | ) | (33.8 | ) |
| Equity Earnings in ATC | 18.4 |
| 17.9 |
| 17.5 |
|
| Other | 4.4 |
| 4.6 |
| 1.8 |
|
| Total Other Expense | (20.8 | ) | (16.7 | ) | (14.5 | ) |
| Income Before Non-Controlling Interest and Income Taxes | 129.2 |
| 119.1 |
| 91.5 |
|
| Income Tax Expense | 35.6 |
| 44.3 |
| 30.8 |
|
| Net Income | 93.6 |
| 74.8 |
| 60.7 |
|
| Less: Non-Controlling Interest in Subsidiaries | (0.2 | ) | (0.5 | ) | (0.3 | ) |
| Net Income Attributable to ALLETE |
| $93.8 |
|
| $75.3 |
|
| $61.0 |
|
| Average Shares of Common Stock | | | |
| Basic | 35.3 |
| 34.2 |
| 32.2 |
|
| Diluted | 35.4 |
| 34.3 |
| 32.2 |
|
| Basic Earnings Per Share of Common Stock |
| $2.66 |
|
| $2.20 |
|
| $1.89 |
|
| Diluted Earnings Per Share of Common Stock |
| $2.65 |
|
| $2.19 |
|
| $1.89 |
|
| Dividends Per Share of Common Stock |
| $1.78 |
|
| $1.76 |
|
| $1.76 |
|
The accompanying notes are an integral part of these statements.
ALLETE 20092011 Form 10-K
62
ALLETE Consolidated Statement of Cash Flows
| | | Year Ended December 31 | 2009 | 2008 | 2007 | 2011 |
| 2010 |
| 2009 |
|
| Millions | | |
| Operating Activities | | |
| Net Income | $60.7 | $83.0 | $89.5 |
| $93.6 |
|
| $74.8 |
|
| $60.7 |
|
| Allowance for Funds Used During Construction | (5.8) | (3.3) | (3.8) | (2.5 | ) | (4.2 | ) | (5.8 | ) |
| Loss (Income) from Equity Investments, Net of Dividends | 0.1 | (3.1) | (2.7) | (3.2 | ) | (3.1 | ) | 0.1 |
|
| Gain on Real Estate Foreclosure | | (0.5 | ) | (0.7 | ) | — |
|
| Gain on Sale of Assets | (0.2) | (4.8) | (2.2) | (0.9 | ) | — |
| (0.2 | ) |
| Gain on Sale of Available-for-sale Securities | – | (6.4) | – | |
| Loss on Impairment of Assets | 3.1 | – | 0.3 | 1.7 |
| — |
| 3.1 |
|
| Depreciation Expense | 64.7 | 55.5 | 48.5 | 90.4 |
| 80.5 |
| 64.7 |
|
| Amortization of Debt Issuance Costs | 0.9 | 0.8 | 1.0 | 0.9 |
| 0.9 |
| 0.9 |
|
| Deferred Income Tax Expense | 75.2 | 38.8 | 14.0 | 35.8 |
| 66.0 |
| 75.2 |
|
| Stock Compensation Expense | 2.1 | 1.8 | 2.0 | |
| Share-Based Compensation Expense | | 1.6 |
| 2.2 |
| 2.1 |
|
| ESOP Compensation Expense | | 7.4 |
| 7.1 |
| 6.5 |
|
| Defined Benefit Pension and Postretirement Benefit Expense | | 23.6 |
| 18.0 |
| 11.7 |
|
| Bad Debt Expense | 1.3 | 0.7 | 1.0 | 1.2 |
| 1.1 |
| 1.3 |
|
| Changes in Operating Assets and Liabilities | | |
| Accounts Receivable | (43.5) | 2.4 | (6.6) | 18.6 |
| 17.9 |
| (43.5 | ) |
| Inventories | (7.3) | (0.2) | (6.1) | (9.1 | ) | (3.0 | ) | (7.3 | ) |
| Prepayments and Other | – | 11.2 | (11.7) | 1.5 |
| (4.3 | ) | — |
|
| Accounts Payable | 10.5 | (14.1) | 9.4 | (9.5 | ) | 5.8 |
| 10.5 |
|
| Other Current Liabilities | 5.3 | 5.9 | (10.0) | 15.4 |
| 5.2 |
| 5.3 |
|
| Regulatory and Other Assets | (18.3) | (1.8) | 0.9 | |
| Regulatory and Other Liabilities | (11.4) | (12.8) | 0.7 | |
| Cash Contributions to Defined Benefit Pension and Postretirement Plans | | (24.7 | ) | (39.3 | ) | (30.2 | ) |
| Changes in Regulatory and Other Non-Current Assets | | (7.5 | ) | 4.2 |
| (25.6 | ) |
| Changes in Regulatory and Other Non-Current Liabilities | | 7.9 |
| (0.4 | ) | 7.9 |
|
| Cash from Operating Activities | 137.4 | 153.6 | 124.2 | 241.7 |
| 228.7 |
| 137.4 |
|
| Investing Activities | | |
| Proceeds from Sale of Available-for-sale Securities | 8.9 | 62.3 | 449.7 | 7.8 |
| 0.6 |
| 8.9 |
|
| Payments for Purchase of Available-for-sale Securities | (2.2) | (44.8) | (368.3) | (2.3 | ) | (2.3 | ) | (2.2 | ) |
| Investment in ATC | (7.8) | (7.4) | (8.7) | (2.0 | ) | (1.6 | ) | (7.8 | ) |
| Changes to Other Investments | (0.7) | (9.2) | (12.4) | (7.4 | ) | 1.3 |
| (0.7 | ) |
| Additions to Property, Plant and Equipment | (318.5) | (301.1) | (210.2) | (239.2 | ) | (248.9 | ) | (318.5 | ) |
| Proceeds from Sale of Assets | 0.3 | 20.4 | 1.5 | 2.2 |
| — |
| 0.3 |
|
| Other | – | 3.7 | (5.7) | |
| Cash for Investing Activities | (320.0) | (276.1) | (154.1) | (240.9 | ) | (250.9 | ) | (320.0 | ) |
| Financing Activities | | |
| Proceeds from Issuance of Common Stock | 65.2 | 71.1 | 20.6 | 39.1 |
| 20.5 |
| 65.2 |
|
| Proceeds from Issuance of Long-Term Debt | 111.4 | 198.7 | 123.9 | 81.4 |
| 155.0 |
| 111.4 |
|
| Changes in Notes Payable | (4.1) | 6.0 | – | 0.1 |
| (0.9 | ) | (4.1 | ) |
| Reductions of Long-Term Debt | (9.1) | (22.7) | (90.7) | (3.1 | ) | (71.0 | ) | (9.1 | ) |
| Debt Issuance Costs | (0.6) | (1.5) | (1.1) | — |
| (1.4 | ) | (0.6 | ) |
| Dividends on Common Stock | (56.5) | (50.4) | (44.3) | (62.1 | ) | (60.8 | ) | (56.5 | ) |
| Cash from Financing Activities | 106.3 | 201.2 | 8.4 | 55.4 |
| 41.4 |
| 106.3 |
|
| Change in Cash and Cash Equivalents | (76.3) | 78.7 | (21.5) | 56.2 |
| 19.2 |
| (76.3 | ) |
| Cash and Cash Equivalents at Beginning of Period | 102.0 | 23.3 | 44.8 | 44.9 |
| 25.7 |
| 102.0 |
|
| Cash and Cash Equivalents at End of Period | $25.7 | $102.0 | $23.3 |
| $101.1 |
|
| $44.9 |
|
| $25.7 |
|
The accompanying notes are an integral part of these statements.
ALLETE Consolidated Statement of Shareholders’ Equity
|
| | | | | | | | | | | | | |
| | Total Shareholders’ Equity | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Unearned ESOP Shares | Common Stock |
| Millions | | | | | |
| Balance as of December 31, 2008 |
| $827.1 |
|
| $380.9 |
| $(33.0) | $(54.9) |
| $534.1 |
|
| Comprehensive Income | | | | | |
| Net Income | 60.7 |
| 60.7 |
| | | |
| Other Comprehensive Income – Net of Tax | | | | | |
| Unrealized Gain on Securities – Net | 2.8 |
| | 2.8 |
| | |
| Defined Benefit Pension and Other Postretirement Plans | 6.2 |
| | 6.2 |
| | |
| Total Comprehensive Income | 69.7 |
| | | | |
| Non-Controlling Interest in Subsidiaries | 0.3 |
| 0.3 |
| | | |
| Comprehensive Income Attributable to ALLETE | 70.0 |
| | | | |
| Common Stock Issued – Net | 79.3 |
| | | | 79.3 |
|
| Dividends Declared | (56.5 | ) | (56.5 | ) | | | |
| ESOP Shares Earned | 9.6 |
| | | 9.6 |
| |
| Balance as of December 31, 2009 | 929.5 |
| 385.4 |
| (24.0 | ) | (45.3 | ) | 613.4 |
|
| Comprehensive Income | | | | | |
| Net Income | 74.8 |
| 74.8 |
| | | |
| Other Comprehensive Income – Net of Tax | | | | | |
| Unrealized Gain on Securities – Net | 0.8 |
| | 0.8 |
| | |
| Total Comprehensive Income | 75.6 |
| | | | |
| Non-Controlling Interest in Subsidiaries | 0.5 |
| 0.5 |
| | | |
| Comprehensive Income Attributable to ALLETE | 76.1 |
| | | | |
| Common Stock Issued – Net | 22.7 |
| | | | 22.7 |
|
| Dividends Declared | (60.8 | ) | (60.8 | ) | | | |
| ESOP Shares Earned | 8.5 |
| | | 8.5 |
| |
| Balance as of December 31, 2010 | 976.0 |
| 399.9 |
| (23.2 | ) | (36.8 | ) | 636.1 |
|
| Comprehensive Income | | | | | |
| Net Income | 93.6 |
| 93.6 |
| | | |
| Other Comprehensive Income – Net of Tax | | | | | |
| Unrealized Loss on Securities – Net | (0.3 | ) | | (0.3 | ) | | |
| Unrealized Loss on Derivatives – Net | (0.3 | ) | | (0.3 | ) | | |
| Defined Benefit Pension and Other Postretirement Plans – Net | (5.1 | ) | | (5.1 | ) | | |
| Total Comprehensive Income | 87.9 |
| | | | |
| Non-Controlling Interest in Subsidiaries | 0.2 |
| 0.2 |
| | | |
| Comprehensive Income Attributable to ALLETE | 88.1 |
| | | | |
| Common Stock Issued – Net | 69.5 |
| | | | 69.5 |
|
| Dividends Declared | (62.1 | ) | (62.1 | ) | | | |
| ESOP Shares Earned | 7.8 |
| | | 7.8 |
| |
| Balance as of December 31, 2011 |
| $1,079.3 |
|
| $431.6 |
| $(28.9) | $(29.0) |
| $705.6 |
|
The accompanying notes are an integral part of these statements.
ALLETE 20092011 Form 10-K
64
ALLETE Consolidated Statement of Shareholders’ Equity
| | | | Accumulated | | |
| | Total | | Other | Unearned | |
| | Shareholders’ | Retained | Comprehensive | ESOP | Common |
| | Equity | Earnings | Income (Loss) | Shares | Stock |
| Millions | | | | | |
| Balance as of December 31, 2006 | $665.8 | $307.8 | $(8.8) | $(71.9) | $438.7 |
| Comprehensive Income | | | | | |
| Net Income | 89.5 | 89.5 | | | |
| Other Comprehensive Income – Net of Tax | | | | | |
| Unrealized Gains on Securities – Net | 1.1 | | 1.1 | | |
| Defined Benefit Pension and Other Postretirement Plans | 3.2 | | 3.2 | | |
| Total Comprehensive Income | 93.8 | | | | |
| Non-Controlling Interest in Subsidiaries | (1.9) | (1.9) | | | |
| Comprehensive Income Attributable to ALLETE | 91.9 | | | | |
| Adjustment to apply accounting standards for Income Taxes | (0.7) | (0.7) | | | |
| Common Stock Issued – Net | 22.5 | | | | 22.5 |
| Dividends Declared | (44.3) | (44.3) | | | |
| ESOP Shares Earned | 7.4 | | | 7.4 | |
| Balance as of December 31, 2007 | 742.6 | 350.4 | (4.5) | (64.5) | 461.2 |
| Comprehensive Income | | | | | |
| Net Income | 83.0 | 83.0 | | | |
| Other Comprehensive Income – Net of Tax | | | | | |
| Unrealized Loss on Securities – Net | (6.0) | | (6.0) | | |
| Reclassification Adjustment for Gains Included in Income | (3.7) | | (3.7) | | |
| Defined Benefit Pension and Other Postretirement Plans | (18.8) | | (18.8) | | |
| Total Comprehensive Income | 54.5 | | | | |
| Non-Controlling Interest in Subsidiaries | (0.5) | (0.5) | | | |
| Comprehensive Income Attributable to ALLETE | 54.0 | | | | |
| Adjustment to apply change in Pension and Postretirement measurement date | (1.6) | (1.6) | | | |
| Common Stock Issued – Net | 72.9 | | | | 72.9 |
| Dividends Declared | (50.4) | (50.4) | | | |
| ESOP Shares Earned | 9.6 | | | 9.6 | |
| Balance as of December 31, 2008 | 827.1 | 380.9 | (33.0) | (54.9) | 534.1 |
| Comprehensive Income | | | | | |
| Net Income | 60.7 | 60.7 | | | |
| Other Comprehensive Income – Net of Tax | | | | | |
| Unrealized Gain on Securities – Net | 2.8 | | 2.8 | | |
| Defined Benefit Pension and Other Postretirement Plans | 6.2 | | 6.2 | | |
| Total Comprehensive Income | 69.7 | | | | |
| Non-Controlling Interest in Subsidiaries | 0.3 | 0.3 | | | |
| Comprehensive Income Attributable to ALLETE | 70.0 | | | | |
| Common Stock Issued – Net | 79.3 | | | | 79.3 |
| Dividends Declared | (56.5) | (56.5) | | | |
| ESOP Shares Earned | 9.6 | | | 9.6 | |
| Balance as of December 31, 2009 | $929.5 | $385.4 | $(24.0) | $(45.3) | $613.4 |
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”“us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. 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 issuing the financial statements on February 12, 2010.issuance.
Principles of Consolidation. Our consolidated financial statements include the accounts of ALLETE and all of our majority-owned subsidiary companies. All material intercompany balances and transactions have been eliminated in consolidation.
Business Segments. Our Regulated Operations and Investments and Other segments were determined in accordance with the guidance on segment reporting. Segmentation is based on the manner in which we operate, assess, and allocate resources to the business. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Regulated Operationsincludes retail and wholesale rate-regulated electric, natural gas, and water services in northeastern Minnesota and northwestern Wisconsin along with our Investment in ATC.regulated utilities, Minnesota Power provides regulated utility electric service to 144,000 retail customers in northeastern Minnesota.and SWL&P, a wholly-owned subsidiary, provides regulated utility electric, natural gas and water service in northwestern Wisconsin to 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Billings are rendered on a cycle basis. Revenue is accrued for service provided but not billed. 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 customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain environmental and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. Our Investment in ATC includesas well as our approximate 8 percent equity ownership interestinvestment in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATCMinnesota Power provides transmissionregulated utility electric service in northeastern Minnesota to approximately 144,000 retail customers. Minnesota Power's non-affiliated municipal customers consists of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. SWL&P provides regulated electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 12,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under rates regulated by the FERC that are set in accordance with the FERC’s policyjurisdiction of establishing the independent operationstate and ownership of, and investment in, transmission facilities. (See Note 6. Investment in ATC.)federal regulatory authorities.
Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, formed in June 2011, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes a small amount of non-rate base generation, approximately 7,000 acres of land available-for-sale in Minnesota, and earnings on cash and investments.
BNI Coal, a wholly-owned subsidiary, mines and sells lignite coal to two North Dakota mine-mouth generating units, one of which is Square Butte. In 2009,2011, Square Butte supplied approximately 50 percent (227.5 MWs) (227.5 MW) of its output to Minnesota Power under a long-term contract. (See Note 11. Commitments, Guarantees and Contingencies.) Coal sales are recognized when delivered at the cost of production plus a specified profit per ton of coal delivered.
ALLETE Properties represents our Florida real estate investment. Our current strategy for the assets is to complete and maintain key entitlements and infrastructure improvements without requiring significant additional investment, and sell the portfolio over time or in bulk transactions. ALLETE intends to sell its Florida land assets when opportunities arise and reinvest the proceeds in its growth initiatives. ALLETE does not intend to acquire additional Florida real estate.
Full profit recognition is recorded on sales upon closing, provided that cash collections are at least 20 percent of the contract price and the other requirements under the guidance for sales of real estate are met. In certain cases, where there are obligations to perform significant development activities after the date of sale, we recognize profit on a percentage-of-completion basis. PursuantFrom time to this method of accounting, gross profit is recognized based upon the relationship of development costs incurred as of that date to the total estimated development costs of the parcels, including related amenities or common costs of the entire project. Revenue and cost of real estate sold in excess of the amount recognized based on the percentage-of-completion method is deferred and recognized as revenue and cost of real estate sold during the period in which the related development costs are incurred. Deferred revenue and cost of real estate sold are recorded net as Deferred Profit on Sales of Real Estate on our consolidated balance sheet. On December 31, 2009 and 2008, we had no deferred profit recorded on our consolidated balance sheet. Certaintime, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.
Note 1. | Operations and Significant Accounting Policies (Continued) |
In certain cases, we pay fees or construct improvements to mitigate offsite traffic impacts. In return, we receive traffic impact fee credits as a result of some of these expenditures. We recognize revenue from the sale of traffic impact fee credits when payment is received.
| |
| Note 1. | Operations and Significant Accounting Policies (Continued) |
ALLETE Clean Energy, a wholly owned subsidiary of ALLETE, operates independently of Minnesota Power to develop or acquire capital projects aimed at creating energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term PPAs, and will be subject to applicable state and federal regulatory approvals.
Land held-for-sale is recorded atinventories are accounted for in accordance with the lower of cost or fair value determined by the evaluation of individual land parcelsaccounting standards for property, plant and isequipment, and are included in Other Investments on our consolidated balance sheet. Real estate costs include the cost of land acquired, subsequent development costs and costs of improvements, capitalized development period interest, real estate taxes and payroll costs of certain employees devoted directly to the development effort. These real estate costs incurred are capitalized to the cost of real estate parcels based upon the relative sales value of parcels within each development project in accordance with the accounting guidancestandards for Real Estate.real estate. The cost of real estate sold includes the actual costs incurred and the estimate of future completion costs allocated to the real estate sold based upon the relative sales value method. Whenever events or circumstances indicate that the carrying value of the real estate may not be recoverable, impairments would beare recorded and the related assets would beare adjusted to their estimated fair value, less costs to sell.value. (See Note 7. Investments.)
Non-Controlling Interest in Subsidiaries.Property, Plant and Equipment. Property, plant and equipment are recorded In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at original cost and are reported on the balance sheet netbook value for $8.8 million by issuing 0.2 million shares of accumulated depreciation. Expenditures for additions and significant replacements and improvements are capitalized; maintenance and repair costs are expensed as incurred. Expenditures for major plant overhauls are alsoALLETE common stock. This was accounted for using this same policy. Gains or losses on non-rate base property, plantas an equity transaction, and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss iswas recognized pursuant to guidance on accounting for Regulated Operations. Our Regulated Operations capitalize AFUDC, which includes both an interest and equity component. (See Note 3. Property, Plant and Equipment.)in net income or comprehensive income.
Cash and Cash Equivalents.Long-Lived Asset Impairments. We account for our long-lived assets at depreciated historical cost. A long-lived asset is tested for recoverability whenever eventsconsider all investments purchased with original maturities of three months or changes in circumstances indicate that its carrying amount may notless to be recoverable. We conduct this assessment using the accounting guidance for impairment or disposal of long-lived assets. Judgments and uncertainties affecting the application of accounting for asset impairment include economic conditions affecting market valuations, changes in our business strategy, and changes in our forecast of future operating cash flows and earnings. We would recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted future cash flows. Management judgment is involved in both deciding if testing for recoverability is necessary and in estimating undiscounted future cash flows.equivalents.
Supplemental Statement of Cash Flow Information
|
| | | | | | | | | |
| Consolidated Statement of Cash Flows | | | |
| Supplemental Disclosure | | | |
| Year Ended December 31 | 2011 |
| 2010 |
| 2009 |
|
| Millions | | | |
| Cash Paid During the Period for Interest – Net of Amounts Capitalized |
| $43.2 |
|
| $35.7 |
|
| $29.8 |
|
Cash Received During the Period for Income Taxes (a) | $(11.4) | $(54.2) | $(5.6) |
| Noncash Investing and Financing Activities | | | |
| Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment |
| $5.9 |
|
| $7.5 |
| $(24.1) |
| AFUDC – Equity |
| $2.5 |
|
| $4.2 |
|
| $5.8 |
|
| ALLETE Common Stock Contributed to the Pension Plan | $(20.0) | — |
| $(12.0) |
| |
| (a) | Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little to no estimated tax payments, and refunds were received from NOL carrybacks against prior years' taxable income. |
Accounts Receivable. Accounts receivable are reported on the 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 problems and such other factors that, in our judgment, deserve recognition in estimating losses.
| Accounts Receivable | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Trade Accounts Receivable | | |
| Billed | $56.5 | $61.1 |
| Unbilled | 15.1 | 15.9 |
| Less: Allowance for Doubtful Accounts | 0.9 | 0.7 |
| Total Trade Accounts Receivable | 70.7 | 76.3 |
| Income Taxes Receivable | 47.8 | – |
| Total Accounts Receivable – Net | $118.5 | $76.3 |
ALLETE 2011 Form 10-K
66
| |
| Note 1. | Operations and Significant Accounting Policies (Continued) |
|
| | | | | | | |
| Accounts Receivable | | | |
| As of December 31 | 2011 |
| | 2010 |
|
| Millions | | | |
| Trade Accounts Receivable | | | |
| Billed |
| $63.7 |
| |
| $67.6 |
|
| Unbilled | 15.6 |
| | 18.9 |
|
| Less: Allowance for Doubtful Accounts | 0.9 |
| | 0.9 |
|
| Total Trade Accounts Receivable | 78.4 |
| | 85.6 |
|
Income Taxes Receivable (a) | 1.3 |
| | 13.9 |
|
| Total Accounts Receivable - Net |
| $79.7 |
| |
| $99.5 |
|
| |
| (a) | Income Taxes Receivable decreased from 2010 due to the collection of a 2010 NOL carryback claim. (See Note 14. Income Tax Expense.) |
Concentration of Credit Risk. Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to 12 large industrial customers.10 Large Power Customers. Receivables from these customers totaled approximately $10$9.3 million at December 31, 2009 ($112011 ($17.3 million at December 2008)31, 2010). Minnesota Power does not obtain collateral to support utility receivables, but monitors the credit standing of major customers. In addition, our taconite-producing Large Power Customers, which are a part of our Regulated Operations segment, are on a weekly billing cycle, which allows us to closely manage collection of amounts due. One of these customers accounted for 12.8 percent of consolidated revenue in 2011 (12.5 percent in 2010; 8.0 percent in 2009). In the third quarter of 2011, one of Minnesota Power's Large Power Customers, NewPage Corporation, filed for Chapter 11 bankruptcy protection. Minnesota Power had a pre-bankruptcy petition receivable of $3.2 million as of December 31, 2011. Based on our assessment of the facts and circumstances existing as of December 31, 2011, we have determined that it is not probable that the pre-petition receivable has been impaired at this time. We will continue to assess for impairment as the bankruptcy proceeds and as facts and circumstances change. The Duluth mill operations have continued without interruption and we continue to provide electric and steam service to this customer. We have received payment of scheduled post-petition receivable balances and we expect continued payment of all other post-petition receivables.
Long-Term Finance Receivables.Inventories. Inventories Long-term finance receivables relating to our real estate operations are statedcollateralized 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 lowerbalance of cost or market. Amounts removed from inventory are recorded on an average cost basis.
| Inventories | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Fuel | $23.0 | $16.6 |
| Materials and Supplies | 34.0 | 33.1 |
| Total Inventories | $57.0 | $49.7 |
Note 1. | Operations and Significant Accounting Policies (Continued) |
Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized oversuch receivables to the termsestimated fair value of the related debt instruments usingcollateralized property. If the effective interest method.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. (See Note 7. Investments.)
Cash and Cash Equivalents. We consider all investments purchased with original maturities of three months or less to be cash equivalents.
Supplemental Statement of Cash Flow Information
| Consolidated Statement of Cash Flows | |
| Supplemental Disclosure | |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Cash Paid During the Period for | | | |
| Interest – Net of Amounts Capitalized | $29.8 | $25.2 | $26.3 |
| Income Taxes | $1.1 | $6.5 | $34.2 |
| | | | |
| Noncash Investing and Financing Activities | | | |
| Changes in Accounts Payable for Capital Additions to Property, Plant and Equipment | $24.1 | $17.1 | $9.8 |
| AFUDC – Equity | $5.8 | $3.3 | $3.8 |
| ALLETE Common Stock contributed to the Pension Plan | $(12.0) | – | – |
Available-for-Sale Securities.Available-for-sale securities are recorded at fair value with unrealized gains and losses included in accumulated other comprehensive income (loss), net of tax. Unrealized losses that are other than temporary are recognized in earnings. Our auction rate securities (ARS), classified as available-for-sale securities, are recorded at cost because their cost approximates fair market value. 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 the share price trends and the impact of overall market conditions. (See Note 7. Investments.)
Inventories. Inventories are stated at the lower of cost or market. Amounts removed from inventory are recorded on an average cost basis.
|
| | | | | | | |
| Inventories | | | |
| As of December 31 | 2011 |
| | 2010 |
|
| Millions | | | |
| Fuel |
| $28.6 |
| |
| $22.9 |
|
| Materials and Supplies | 40.5 |
| | 37.1 |
|
| Total Inventories |
| $69.1 |
| |
| $60.0 |
|
| |
| Note 1. | Operations and Significant Accounting Policies (Continued) |
Property, Plant and Equipment. Property, plant and equipment are recorded at original cost and are reported on the 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 non-rate base property, plant and equipment are recognized when they are retired or otherwise disposed. When regulated utility property, plant and equipment are retired or otherwise disposed, no gain or loss is recognized in accordance with the accounting standards for Regulated Operations. 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. The MPUC has approved current cost recovery for several large capital projects recently, resulting in lower recognition of AFUDC. (See Note 3. Property, Plant and Equipment.)
Impairment of Long-Lived Assets. We review our long-lived assets for indicators of impairment in accordance with the accounting standards for property, plant and equipmenton a quarterly basis. Long-lived assets that we evaluate include our real estate assets of ALLETE Properties.
In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our real estate 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, which may be by each land parcel, combining various parcels into bulk sales, or other combinations thereof. Our consideration of possible impairment for our real estate assets requires us to make estimates of future cash flows on an undiscounted basis. 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 develop and maintain the operations, including community development district assessments, property taxes and normal operation and maintenance costs. These estimates and expectations are specific to each land parcel or various bulk sales, and may vary among each land parcel or bulk sale.If the excess of undiscounted cash flows over the carrying value of a property is small, there is a greater risk of future impairment in the event of such changes and any resulting impairment charges could be material.
The poor market conditions for real estate in Florida have required us to review our land inventories for impairment. Our undiscounted cash flow analysis was estimated using management's current intent for disposition of each property, which is an estimated selling period of five to ten years based on a December 2011 asset management and disposition plan. Future selling prices have been estimated through management's best estimate of future sales prices in collaboration and consultation with outside advisors, and based on the best use of the properties over the expected period of sale. The undiscounted cash flow analysis assumes two scenarios: retail land sales followed by project bulk sales over a five year period and retail land sales over a ten year period. Our analysis assumes the most likely case of retail land sales followed by project bulk sales over a five year period; however, under both scenarios, except as noted below, the undiscounted cash flows exceeded carrying values. If our major development projects are sold in one bulk sale or if the properties are sold differently than our December 2011 plan, the actual results could be materially different from our undiscounted cash flow analysis.
The results of the impairment analysis are particularly dependent on the estimated future sales prices, method of disposition, and holding period for each property. The estimated holding period is based on management's current intent for the use and disposition of each property, which could be subject to change in future periods if the intentions of the Company as set by management and approved by the Board of Directors were to change.
In the event that projected future undiscounted cash flows are not adequate to recover the carrying value of an asset, impairment is indicated and may require a write down to the asset's fair value. Fair value is determined based on best available evidence including comparable sales, current appraised values, property tax assessed values, and discounted cash flow analysis. If fair value is less than cost, the carrying value of our investments is reduced and an impairment charge is recorded in the current period. In the fourth quarter of 2011, our impairment analysis indicated that the estimated future cash flows were not adequate to recover the carrying basis of certain properties not strategic to our three major development projects. Consequently, we reduced the cost basis to estimated fair value, resulting in a pretax impairment charge of $1.7 million. The remaining cost basis of these properties amounted to $3.0 million as of December 31, 2011.
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 interest rate risk related to certain variable-rate borrowings.
| |
| Note 1. | Operations and Significant Accounting Policies (Continued) |
Accounting for Stock-Based Compensation.We apply the fair value recognition guidance for share-based payments. Under this method,guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate and only for those shares expected to vest over the required service period of the award.rate. (See Note 17. Employee Stock and Incentive Plans.)
|
| | | | | | | |
| Prepayments and Other Current Assets | | | |
| As of December 31 | 2011 |
| | 2010 |
|
| Millions | | | |
| Deferred Fuel Adjustment Clause |
| $17.5 |
| |
| $20.6 |
|
| Other | 9.6 |
| | 8.0 |
|
| Total Prepayments and Other Current Assets |
| $27.1 |
| |
| $28.6 |
|
| Prepayments and Other Current Assets | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Deferred Fuel Adjustment Clause | $15.5 | $13.1 |
| Other | 8.8 | 11.2 |
| Total Prepayments and Other Current Assets | $24.3 | $24.3 |
|
| | | | | | | |
| Other Current Liabilities | | | |
| As of December 31 | 2011 |
| | 2010 |
|
| Millions | | | |
Customer Deposits (a) |
| $16.3 |
| |
| $2.9 |
|
| Other | 29.3 |
| | 30.8 |
|
| Total Other Current Liabilities |
| $45.6 |
| |
| $33.7 |
|
| |
| (a) | Higher customer deposits in 2011 were primarily due to a customer security deposit for capital expenditures relating to a transmission project. |
| Other Liabilities | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Future Benefit Obligation Under Defined Benefit Pension and Other Postretirement Plans | $231.2 | $251.8 |
| Asset Retirement Obligation (See Note 3. Property, Plant and Equipment) | 44.6 | 39.5 |
| Other | 49.2 | 48.0 |
| Total Other Liabilities | $325.0 | $339.3 |
|
| | | | | | | |
| Other Non-Current Liabilities | | | |
| As of December 31 | 2011 |
| | 2010 |
|
| Millions | | | |
| Asset Retirement Obligation |
| $57.0 |
| |
| $50.3 |
|
| Other | 48.1 |
| | 43.1 |
|
| Total Other Non-Current Liabilities |
| $105.1 |
| |
| $93.4 |
|
Environmental Liabilities. We review environmental matters for disclosure 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. These accruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the 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 charged to operating expense unless recoverable in rates from customers. (See Note 11. Commitments, Guarantees and Contingencies.)
Revenue Recognition. Regulated utility rates are under the jurisdiction of Minnesota, Wisconsin and federal regulatory authorities. Customers are billed on a cycle basis. Revenue is accrued for service provided but not billed. 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 customers for the recovery of conservation improvement program expenditures not collected in base rates; and (3) bill customers for the recovery of certain transmission and renewable energy expenditures. Fuel and purchased power expense is deferred to match the period in which the revenue for fuel and purchased power expense is collected from customers pursuant to the fuel adjustment clause. BNI recognizes revenue when coal is delivered.
Unamortized Discount and Premium on Debt. Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using the straight-line method.
ALLETE 20092011 Form 10-K
69
| |
| Note 1. | Operations and Significant Accounting Policies (Continued) |
Derivatives. We review all material power purchase and sales contracts for derivative treatment to determine if they qualify for the normal purchase normal sale exception under the guidance for derivatives and hedging. (See Note 8. Derivatives.)
Income Taxes. We file a consolidated federal income tax return. We account for income taxes using the liability method as prescribed byin accordance with the guidance in accounting standards 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. InvestmentFederal 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. Effective January 1, 2007, we adoptedIn accordance with the guidanceaccounting standards for uncertainty in income taxes. Under this guidancetaxes, 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.percent likely. (See Note 14. Income Tax Expense.)
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 thea net basis.
New Accounting Standards.
Fair Value. Codification. In June 2009, the FASB approved the FASB Accounting Standards Codification (Codification) as the single source of authoritative nongovernmental GAAP. The Codification is an online research system that reorganizes the thousands of GAAP pronouncements into a topical structure. The Codification was launched on July 1, 2009, at which time all existing accounting standards documents were superseded and all existing accounting literature not included in the Codification was considered non-authoritative, except for guidance issued by the SEC, which remains a source of authoritative GAAP. The Codification was effective September 30, 2009.
Subsequent Events.In May 2009,2011, the FASB issued guidancean accounting standards update on accounting for, andfair value measurement. This update requires disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Entities are required to disclose the date through which subsequent events have been evaluateda sensitivity analysis for fair value measurements within Level 3 and the basis for that date. Thevaluation process used. This guidance on subsequent events was adopted on June 30, 2009,will be effective beginning with the quarter ending March 31, 2012, and didis not expected to have a material impact on our consolidated financial position, results of operations or cash flows.
Statement of Comprehensive Income. Non-controlling Interests.In December 2007, the FASB issued amended guidance to improve the relevance, comparability, and transparency of the financial information a reporting entity provides in its consolidated financial statements with regards to non-controlling interests. Non-controlling interest in a subsidiary is defined as an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. The amended guidance changes the presentation of the consolidated income statement by requiring consolidated net income to include amounts attributable to the parent and the non-controlling interest. A single method of accounting was established for changes in a parent’s ownership interest in a subsidiary which do not result in deconsolidation. Expanded disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners of a subsidiary are also required. The guidance for non-controlling interests was adopted on January 1, 2009. ALLETE Properties does have certain non-controlling interests in consolidated subsidiaries. The presentation of our consolidated financial statements was impacted, but the adoption of the guidance for non-controlling interests did not have a material impact on our consolidated financial position, results of operations or cash flows.
Derivatives and Hedging. In March 2008, the FASB issued guidance that amends and expands the disclosure requirements for derivatives and hedging. The guidance requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements are also required. The guidance on derivatives and hedging was adopted on January 1, 2009. As the amended guidance provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows. (See Note 8. Derivatives.)
Financial Instruments. In April 2009, the FASB issued amended guidance to require disclosure about fair value of financial instruments for interim reporting periods of publicly traded companies in addition to annual financial statements. This amended guidance was adopted on June 30, 2009. As the amended guidance provided only disclosure requirements, the adoption of this standard did not have a material impact on our consolidated financial position, results of operations or cash flows. (See Note 9. Fair Value.)
Note 1. | Operations and Significant Accounting Policies (Continued) |
Fair Value. In April 2009, the FASB issued additional guidance for applying the provisions of fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants under current market conditions. This guidance requires an evaluation of whether there has been a significant decrease in the volume and level of activity for the asset or liability in relation to normal market activity for the asset or liability. If there has, transactions or quoted prices may not be indicative of fair value and a significant adjustment may need to be made to those prices to estimate fair value. Additionally, an entity must consider whether the observed transaction was orderly (that is, not distressed or forced). If the transaction was orderly, the obtained price can be considered a relevant observable input for determining fair value. If the transaction is not orderly, other valuation techniques must be used when estimating fair value. This additional guidance on fair value was adopted on June 30, 2009, and did not have a material impact on our consolidated financial position, results of operations or cash flows.
In August 2009,2011, the FASB issued an amendment to the guidance for fair value measurement and disclosure of liabilities. This amendment provides clarification for measuring the fair value of liabilities in circumstances in which a quoted price in an active market for the identical liability is not available. The adoption of this standard on September 30, 2009, did not have an impact on our consolidated financial position, results of operations or cash flows.
In September 2009, the FASB issued an amendment to the fair value measurement and disclosure of investments in certain entities that calculate net asset value per share. This amendment requires disclosures, by major category of investment, about the attributes of investments, such as the nature of any restrictionsaccounting standards update on the investor’s ability to redeem its investments at the measurement date, any unfunded commitments, and the investment strategiespresentation of the investees. The amendedcomprehensive income. This guidance was adopted on December 31, 2009. As the amended guidance provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.
In January 2010, FASB issued an amendment to the fair value measurement and disclosure standard improving disclosures about fair value measurements. This amendment requires disclosure about recurring or nonrecurring fair value measurements, such as transfers in and out of Levels 1 and 2 and activity in Level 3 fair value measurements. Separate disclosures on amounts of significant transfers in and out and reasons for the transfers for Level 1 and Level 2 fair value measurements are required. In Level 3 reconciliations, the activity, such as information about purchases, sales, issuances and settlements, must be presented separately. The guidance for the Level 1 and Level 2 disclosures and clarifications is effective on January 1, 2010. The guidance for the activity in Level 3 disclosures is effective January 1, 2011. As the amended guidance provides only disclosure requirements, the adoption of the amendments will not have an impact on our consolidated financial position, results of operations or cash flows.
Other-Than-Temporary Impairments. In April 2009, the FASB issued amended guidance on other-than-temporary impairments. If it is more likely than not that an impaired security will be sold beforeeffective beginning with the recoveryquarter ending March 31, 2012, and will modify our presentation of its cost basis, either due to the investor’s intent to sell or because it will be required to sell the security, the entire impairment is recognized in earnings. Otherwise, only the portion of the impaired debt security related to estimated credit losses is recognized in earnings, while the remainder of the impairment is recorded in other comprehensive income, and recognized overmoving it to a separate, consecutive statement of comprehensive income immediately following the remaining lifestatement of the debt security. In addition, the guidance expands the presentation and disclosure requirements for other-than-temporary impairments for both debt and equity securities.income. The amended guidance for other-than-temporary impairments was adopted on June 30, 2009, and did not have an impact on our consolidated financial position, resultscomponents of operations or cash flows.
Pensions and Other Postretirement Benefits. In December 2008, the FASB issued guidance that amends employers’ disclosures about pensionsnet income and other postretirement benefits. These changes provide guidance on disclosures about plan assets, investment strategies, major categories of plan assets, concentrations of risk within plan assets,comprehensive income are unchanged and valuation techniques used to measure the fair value of plan assets. These disclosure requirements will be effective for fiscal years ending after December 15, 2009. Upon initial adoption, the requirements within this guidance are not required for earlier periods that are presented for comparative purposes. This amended guidance was adopted on December 31, 2009. As the amended guidance provides only disclosure requirements, the adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows. (See Note 16. Pension and Other Postretirement Benefit Plans.)
Transfers of Financial Assets. In June 2009, the FASB issued amended guidance for the transfers of financial assets. The guidance was issued with the objective of improving the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. Key provisions of the amended guidance include (1) the removal of the concept of qualifying special purpose entities, (2) the introduction of the concept of a participating interest, in circumstances in which a portion of a financial asset has been transferred, and (3) the requirement that to qualify for sale accounting, the transferor must evaluate whether it maintains effective control over transferred financial assets either directly or indirectly. The amended guidance also requires enhanced disclosures about transfers of financial assets and a transferor’s continuing involvement. The amended guidance is effective January 1, 2010, and is requiredearnings per share continues to be applied prospectively. We are currently assessing the impact of the adoptionbased on our consolidated financial position, results of operations and cash flows, but we do not believe it will have a material impact on the Company.
Note 1. | Operations and Significant Accounting Policies (Continued) |
Variable Interest Entities. In June 2009, the FASB issued guidance amending the manner in which entities evaluate whether consolidation is required for variable interest entities (VIEs). A company must first perform a qualitative analysis in determining whether it must consolidate a VIE, and if the qualitative analysis is not determinative, must perform a quantitative analysis. The guidance requires continuous evaluation of VIEs for consolidation, rather than upon the occurrence of triggering events. Additional enhanced disclosures about how an entity’s involvement with a VIE affects its financial statements and exposure to risk will also be required. This guidance is effective January 1, 2010. We are currently assessing the impact of this amended guidance on our consolidated financial position, results of operations and cash flows, but we do not believe it will have a material impact on the Company.net income.
Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota and Illinois. Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, and ALLETE Properties, our Florida real estate investment.investment, and ALLETE Clean Energy, formed in June 2011, aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes a small amount of non-rate base generation, approximately 7,0005,500 acres of land available-for-sale in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.
| | | | Regulated | Investments | | | | | | | |
| | Consolidated | Operations | and Other | Consolidated | Regulated Operations | Investments and Other |
| Millions | | | | |
| 2009 | | | | |
| 2011 | | |
| Operating Revenue | $766.7 | $689.4 | $77.3 |
| $928.2 |
|
| $851.9 |
|
| $76.3 |
|
| Prior Year Rate Refunds | (7.6) | (7.6) | – | |
| Total Operating Revenue | 759.1 | 681.8 | 77.3 | |
| Fuel and Purchased Power | 279.5 | 279.5 | – | |
| Operating and Maintenance | 308.9 | 235.8 | 73.1 | |
| Fuel and Purchased Power Expense | | 306.6 |
| 306.6 |
| — |
|
| Operating and Maintenance Expense | | 381.2 |
| 301.5 |
| 79.7 |
|
| Depreciation Expense | 64.7 | 60.2 | 4.5 | 90.4 |
| 85.4 |
| 5.0 |
|
| Operating Income (Loss) | 106.0 | 106.3 | (0.3) | 150.0 |
| 158.4 |
| (8.4 | ) |
| Interest Expense | (33.8) | (28.3) | (5.5) | (43.6 | ) | (35.8 | ) | (7.8 | ) |
| Equity Earnings in ATC | 17.5 | 17.5 | – | 18.4 |
| 18.4 |
| — |
|
| Other Income (Expense) | 1.8 | 5.8 | (4.0) | |
| Other Income | | 4.4 |
| 2.6 |
| 1.8 |
|
| Income (Loss) Before Non-Controlling Interest and Income Taxes | 91.5 | 101.3 | (9.8) | 129.2 |
| 143.6 |
| (14.4 | ) |
| Income Tax Expense (Benefit) | 30.8 | 35.4 | (4.6) | 35.6 |
| 43.2 |
| (7.6 | ) |
| Net Income (Loss) | 60.7 | 65.9 | (5.2) | 93.6 |
| 100.4 |
| (6.8 | ) |
| Less: Non-Controlling Interest in Subsidiaries | (0.3) | – | (0.3) | (0.2 | ) | — |
| (0.2 | ) |
| Net Income (Loss) Attributable to ALLETE | $61.0 | $65.9 | $(4.9) |
| $93.8 |
|
| $100.4 |
| $(6.6) |
| | | | | |
| Total Assets | $2,393.1 | $2,184.0 | $209.1 |
| $2,876.0 |
|
| $2,579.8 |
|
| $296.2 |
|
| Capital Additions | $303.7 | $299.2 | $4.5 |
| $246.8 |
|
| $228.0 |
|
| $18.8 |
|
ALLETE 20092011 Form 10-K
71
Note 2. Business Segments (Continued) |
| | | | | | | | | |
| | Consolidated | Regulated Operations | Investments and Other |
| Millions | | | |
| 2010 | | | |
| Operating Revenue |
| $907.0 |
|
| $835.5 |
|
| $71.5 |
|
| Fuel and Purchased Power Expense | 325.1 |
| 325.1 |
| — |
|
| Operating and Maintenance Expense | 365.6 |
| 292.3 |
| 73.3 |
|
| Depreciation Expense | 80.5 |
| 76.1 |
| 4.4 |
|
| Operating Income (Loss) | 135.8 |
| 142.0 |
| (6.2 | ) |
| Interest Expense | (39.2 | ) | (32.3 | ) | (6.9 | ) |
| Equity Earnings in ATC | 17.9 |
| 17.9 |
| — |
|
| Other Income | 4.6 |
| 3.8 |
| 0.8 |
|
| Income (Loss) Before Non-Controlling Interest and Income Taxes | 119.1 |
| 131.4 |
| (12.3 | ) |
| Income Tax Expense (Benefit) | 44.3 |
| 51.6 |
| (7.3 | ) |
| Net Income (Loss) | 74.8 |
| 79.8 |
| (5.0 | ) |
| Less: Non-Controlling Interest in Subsidiaries | (0.5 | ) | — |
| (0.5 | ) |
| Net Income (Loss) Attributable to ALLETE |
| $75.3 |
|
| $79.8 |
| $(4.5) |
| Total Assets |
| $2,609.1 |
|
| $2,375.4 |
|
| $233.7 |
|
| Capital Additions |
| $260.0 |
|
| $256.4 |
|
| $3.6 |
|
| | Regulated | Investments |
| | Consolidated | Operations | and Other |
| Millions | | | |
| 2008 | | | |
| Operating Revenue | $801.0 | $712.2 | $88.8 |
| Fuel and Purchased Power | 305.6 | 305.6 | – |
| Operating and Maintenance | 318.1 | 239.3 | 78.8 |
| Depreciation Expense | 55.5 | 50.7 | 4.8 |
| Operating Income | 121.8 | 116.6 | 5.2 |
| Interest Expense | (26.3) | (24.0) | (2.3) |
| Equity Earnings in ATC | 15.3 | 15.3 | – |
| Other Income | 15.6 | 3.6 | 12.0 |
| Income Before Non-Controlling Interest and Income Taxes | 126.4 | 111.5 | 14.9 |
| Income Tax Expense (Benefit) | 43.4 | 43.6 | (0.2) |
| Net Income | 83.0 | 67.9 | 15.1 |
| Less: Non-Controlling Interest in Subsidiaries | 0.5 | – | 0.5 |
| Net Income Attributable to ALLETE | $82.5 | $67.9 | $14.6 |
| | | | |
| Total Assets | $2,134.8 | $1,832.1 | $302.7 |
| Capital Additions | $322.9 | $317.0 | $5.9 |
|
| | | | | | | | | |
| | Consolidated | Regulated Operations | Investments and Other |
| Millions | | | |
| 2009 | | | |
| Operating Revenue |
| $766.7 |
|
| $689.4 |
|
| $77.3 |
|
| Prior Year Rate Refunds | (7.6 | ) | (7.6 | ) | — |
|
| Total Operating Revenue | 759.1 |
| 681.8 |
| 77.3 |
|
| Fuel and Purchased Power Expense | 279.5 |
| 279.5 |
| — |
|
| Operating and Maintenance Expense | 308.9 |
| 235.8 |
| 73.1 |
|
| Depreciation Expense | 64.7 |
| 60.2 |
| 4.5 |
|
| Operating Income (Loss) | 106.0 |
| 106.3 |
| (0.3 | ) |
| Interest Expense | (33.8 | ) | (28.3 | ) | (5.5 | ) |
| Equity Earnings in ATC | 17.5 |
| 17.5 |
| — |
|
| Other Income (Expense) | 1.8 |
| 5.8 |
| (4.0 | ) |
| Income (Loss) Before Non-Controlling Interest and Income Taxes | 91.5 |
| 101.3 |
| (9.8 | ) |
| Income Tax Expense (Benefit) | 30.8 |
| 35.4 |
| (4.6 | ) |
| Net Income (Loss) | 60.7 |
| 65.9 |
| (5.2 | ) |
| Less: Non-Controlling Interest in Subsidiaries | (0.3 | ) | — |
| (0.3 | ) |
| Net Income (Loss) Attributable to ALLETE |
| $61.0 |
|
| $65.9 |
| $(4.9) |
| Total Assets |
| $2,393.1 |
|
| $2,184.0 |
|
| $209.1 |
|
| Capital Additions |
| $303.7 |
|
| $299.2 |
|
| $4.5 |
|
ALLETE 2011 Form 10-K
| | Regulated | Investments |
| | Consolidated | Operations | and Other |
| Millions | | | |
| 2007 | | | |
| Operating Revenue | $841.7 | $723.8 | $117.9 |
| Fuel and Purchased Power | 347.6 | 347.6 | – |
| Operating and Maintenance | 313.9 | 229.3 | 84.6 |
| Depreciation Expense | 48.5 | 43.8 | 4.7 |
| Operating Income | 131.7 | 103.1 | 28.6 |
| Interest Expense | (22.6) | (21.0) | (1.6) |
| Equity Earnings in ATC | 12.6 | 12.6 | – |
| Other Income | 15.5 | 4.1 | 11.4 |
| Income Before Non-Controlling Interest and Income Taxes | 137.2 | 98.8 | 38.4 |
| Income Tax Expense | 47.7 | 36.4 | 11.3 |
| Net Income | 89.5 | 62.4 | 27.1 |
| Less: Non-Controlling Interest in Subsidiaries | 1.9 | – | 1.9 |
| Net Income Attributable to ALLETE | $87.6 | $62.4 | $25.2 |
| | | | |
| Total Assets | $1,644.2 | $1,396.6 | $247.6 |
| Capital Additions | $223.9 | $220.6 | $3.3 |
| |
| Note 3. | Property, Plant and Equipment |
| Property, Plant and Equipment | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Regulated Utility | $2,415.7 | $1,837.2 |
| Construction Work in Progress | 89.6 | 303.0 |
| Accumulated Depreciation | (928.8) | (806.8) |
| Regulated Utility Plant – Net | 1,576.5 | 1,333.4 |
| Non-Rate Base Energy Operations | 87.0 | 94.0 |
| Construction Work in Progress | 3.6 | 3.9 |
| Accumulated Depreciation | (45.5) | (47.2) |
| Non-Rate Base Energy Operations Plant – Net | 45.1 | 50.7 |
| Other Plant – Net | 1.1 | 3.2 |
| Property, Plant and Equipment – Net | $1,622.7 | $1,387.3 |
Note 3. | Property, Plant and Equipment (Continued) |
|
| | | | | | | |
| Property, Plant and Equipment | | | |
| As of December 31 | 2011 | | 2010 |
| Millions | | | |
| Regulated Utility |
| $2,794.8 |
| |
| $2,649.2 |
|
| Construction Work in Progress | 155.0 |
| | 86.6 |
|
| Accumulated Depreciation | (1,024.6 | ) | | (975.8 | ) |
| Regulated Utility Plant - Net | 1,925.2 |
| | 1,760.0 |
|
| Non-Rate Base Energy Operations | 106.4 |
| | 88.4 |
|
| Construction Work-in-Progress | 2.3 |
| | 4.5 |
|
| Accumulated Depreciation | (51.4 | ) | | (48.0 | ) |
| Non-Rate Base Energy Operations Plant - Net | 57.3 |
| | 44.9 |
|
| Other Plant - Net | 0.2 |
| | 0.7 |
|
| Property, Plant and Equipment - Net |
| $1,982.7 |
| |
| $1,805.6 |
|
Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets. The MPUC and the PSCW have approved depreciation rates for our Regulated Utility plant.
|
| | | | |
| Estimated Useful Lives of Property, Plant and Equipment |
| | | | | |
| Regulated Utility – | Generation | 24 to 3435 years | Non-Rate Base Operations | 3 to 61 years |
| | Transmission | 42 to 61 years | Other Plant | 5 to 25 years |
| | Distribution | 14 to 65 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 or development and/or normal operation of the asset. Asset retirement obligations (ARO) relate primarily to the decommissioning of our utility steamcoal-fired generating facilities and land reclamation at BNI Coal, and are included in Other Non-Current Liabilities on our consolidated balance sheet. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives. 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, removal costs have not been recognized because they are considered immaterial to our consolidated financial statements.
Long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries were included in accumulated depreciation. With the adoption of ARO guidance, accumulatedThese plant removal costs were reclassifiedcost recoveries are classified either as AROs or as a regulatory liability for non-ARO obligations. 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 the guidance for AROs. (See Note 5. Regulatory Matters.)
|
| | | | |
| Asset Retirement Obligation | | |
| Millions | | |
Obligation as of December 31, 20072009 | |
| $36.544.6 |
|
| Accretion Expense | 2.0 | 2.9 |
|
Additional Liabilities Incurred in 20082010 | 1.0 | 2.8 |
|
Obligation as of December 31, 20082010 | 39.5 | 50.3 |
|
| Accretion Expense | 2.3 | 6.4 |
|
Additional Liabilities Incurred in 20092011 | 2.8 | 0.3 |
|
Obligation as of December 31, 20092011 | |
| $44.657.0 |
|
| |
| Note 4. | Jointly-Owned Electric FacilityFacilities |
Following are our investments in jointly-owned facilities and the related ownership percentages as of December 31, 2011:
|
| | | | | | | | | | |
| | Plant in Service | Accumulated Depreciation | Construction Work in Progress | % Ownership |
| Millions | | | | |
| Boswell Unit 4 |
| $406.9 |
|
| $177.4 |
|
| $8.8 |
| 80 |
| CapX2020 | 11.9 |
| — |
| 15.9 |
| 9.3 - 14.7 |
| Total |
| $418.8 |
|
| $177.4 |
|
| $24.7 |
| |
We own 80 percent of the 536-MW585 MW Boswell Energy Center Unit 4 (Boswell Unit 4).4. While we operate the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which we and Wisconsin Public Power, Inc.,WPPI Energy, the owner of the remaining 20 percent of Boswell Unit 4, have equal representation and voting rights. Each of us must provide our own financing and is obligated to pay our ownership share of operating costs. Our share of direct operating expenses of Boswell Unit 4 is included in operating expense on our consolidated statement of income. Our 80 percent share ofWe are a participant in the cost of Boswell Unit 4, which is includedCapX2020 initiative to ensure reliable electric transmission and distribution in property, plantthe region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and equipment at December 31, 2009, was $331 million ($328 million at December 31, 2008). The corresponding accumulated depreciation balance was $178 million at December 31, 2009 ($173 million at December 31, 2008).investor-owned utilities. We are currently participating in three CapX2020 projects with varying ownership percentages.
| |
| Note 5. | Regulatory Matters |
Electric Rates. Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, the FERC or the PSCW.
20082010 Rate Case.In May 2008, On November 2, 2010, Minnesota Power filedreceived a written order from the MPUC approving a retail rate increase request with the MPUC seeking additional revenues of approximately $40$53.5 million annually; the request also sought an 11.15, a 10.38 percent return on common equity and a capital structure consisting54.29 percent equity ratio, subject to reconsideration. On May 24, 2011, the MPUC issued an order authorizing Minnesota Power to implement final rates of 54.8 percent equity$53.5 million, effective June 1, 2011. The May 24, 2011 order authorized Minnesota Power to collect a $3.2 million differential between interim rates and 45.2 percent debt. As a resultfinal rates for the period from November 2, 2010 through May 31, 2011, all of which was recorded in 2011.
Under the terms of a May 2009 Orderstipulation and an August 2009 Reconsideration Order,settlement agreement approved by the MPUC grantedas part of this rate case, Minnesota Power agreed to forgo collection of $20.5 million in revenue receivable that it was entitled to under a prior rider for the Boswell Unit 3 environmental retrofit. The agreement required the Company to capitalize, as part of rate base, the $20.5 million to property, plant and equipment representing AFUDC. In conjunction with the settlement agreement, and upon receipt of the final rate order in February 2011, the Company reversed a $6.2 million deferred tax liability related to the revenue increasereceivable Minnesota Power agreed to forgo. The $20.5 million revenue receivable was previously included in regulatory assets on the Company’s consolidated balance sheet.
On February 22, 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case with the Minnesota Court of approximately $20 million, includingAppeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments that the MPUC exceeded its statutory authority, made its decision without the support of a return on equitybody of 10.74 percentrecord evidence and that the decision violated public policy. The Company desires to resolve whether the MPUC’s finding of exigent circumstances was lawful for application in future rate cases. In December 2011, the Minnesota Court of Appeals concluded that the MPUC did not err in finding exigent circumstances and properly exercised its discretion in setting interim rates. On January 4, 2012, the Company filed a capital structure consisting of 54.79 percent equity and 45.21 percent debt. Rates went into effect on November 1, 2009.petition for review at the Minnesota Supreme Court, but cannot predict the outcome at this time.
ALLETE 20092011 Form 10-K
74
| |
| Note 5. | Regulatory Matters (Continued) |
Interim rates, subject to refund, were in effect from August 1, 2008 through October 31, 2009. During 2009, Minnesota Power recorded a $21.7 million liability for refunds of interim rates, including interest, required to be made as a result of the May 2009 Order and the August 2009 Reconsideration Order. In 2009, $21.4 million was refunded, with a remaining $0.3 million balance to be refunded in early 2010; $7.6 million of the refunds required to be made were related to interim rates charged in 2008.
With the May 2009 Order, the MPUC also approved the stipulation and settlement agreement that affirmed the Company’s continued recovery of fuel and purchased power costs under the former base cost of fuel that was in effect prior to the retail rate filing. The transition to the former base cost of fuel began with the implementation of final rates on November 1, 2009. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation.
2010 Rate Case. Minnesota Power previously stated its intention to file for additional revenues to recover the costs of significant investments to ensure current and future system reliability, enhance environmental performance and bring new renewable energy to northeastern Minnesota. As a result, Minnesota Power filed a retail rate increase request with the MPUC on November 2, 2009, seeking a return on equity of 11.50 percent, a capital structure consisting of 54.29 percent equity and 45.71 percent debt, and on an annualized basis, an $81.0 million net increase in electric retail revenue.
Minnesota law allows the collection of interim rates while the MPUC processes the rate filing. On December 30, 2009, the MPUC issued an Order (the Order) authorizing $48.5 million of Minnesota Power’s November 2, 2009, interim rate increase request of $73.0 million. The MPUC cited exigent circumstances in reducing Minnesota Power’s interim rate request. Because the scope and depth of this reduction in interim rates was unprecedented, and because Minnesota law does not allow Minnesota Power to formally challenge the MPUC’s action until a final decision in the case is rendered, on January 6, 2010, Minnesota Power sent a letter to the MPUC expressing its concerns about the Order and requested that the MPUC reconsider its decision on its own motion. Minnesota Power described its belief that the MPUC’s decision violates the law by prejudging the merits of the rate request prior to an evidentiary hearing and results in the confiscation of utility property. Further, the Company is concerned that the decision will have negative consequences on the environmental policy directions of the State of Minnesota by denying recovery for statutory mandates during the pendency of the rate proceeding. The MPUC has not acted in response to Minnesota Power’s letter.
The rate case process requires public hearings and an evidentiary hearing before an administrative law judge, both of which are scheduled for the second quarter of 2010. A final decision on the rate request is expected in the fourth quarter. We cannot predict the final level of rates that may be approved by the MPUC, and we cannot predict whether a legal challenge to the MPUC’s interim rate decision will be forthcoming or successful.
FERC-Approved Wholesale Rates.Minnesota Power’s non-affiliated municipal customers consist of 16 municipalities in Minnesota and 1 private utility in Wisconsin. SWL&P, a wholly-owned subsidiary of ALLETE, is also a private utility in Wisconsin and a customer of Minnesota Power. In 2008, Minnesota Power entered into newformula-based rate contracts with these customers which transitioned customers to formula-based rates, allowing rates to be adjusted annually based on changes in cost.customers. In February 2009,2011, Minnesota Power entered into a new formula-based contract with the FERC approved ourCity of Nashwauk, effective May 1, 2012, through April 30, 2022. In June 2011, Minnesota Power entered into restated contracts, effective July 1, 2011, through June 30, 2019, with the remaining 15 Minnesota municipal customers, and effective August 1, 2011, through June 30, 2019, with SWL&P. The rates included in these contracts which expire December 31, 2013. Under the formula-based rates provision, wholesale rates are calculated using a cost-based formula methodology that is set at the beginning of the year based on expectedeach July using estimated costs and providea rate of return that is equal to our authorized rate of return for Minnesota retail customers (10.38 percent). The formula-based rate methodology also provides for a monthly and yearly true-up calculation for actual costs. Wholesale rate increases totaling approximately $6 millioncosts incurred. Both the new and $10 million annually were implementedrestated contract terms include a termination clause requiring a three-year notice to terminate. Under the City of Nashwauk contract, no termination notice may be given prior to April 30, 2019. Under the restated contracts, no termination notices may be given prior to June 30, 2016. A two-year cancellation notice is required for the one private non-affiliated utility in Wisconsin, and on February 1, 2009 and January 1, 2010, respectively,December 31, 2011, this customer submitted a cancellation notice with approximately $6 million of additional revenues undertermination effective on December 31, 2013. We are currently in negotiations to extend the true-up provision accrued in 2009, which will be billed in 2010.contract with this customer.
20092010 Wisconsin Rate Increase. SWL&P’s current2011 retail rates are based on a December 20082010 PSCW retail rate order, that became effective January 1, 2009, and2011,
that allows for an 11.1a 10.9 percent return on common equity. The new rates reflectedreflect a 3.52.4 percent average increase in retail utility rates for SWL&P customers (a 13.412.8 percent increase in water rates, a 4.72.5 percent increase in electricnatural gas rates and a 0.60.7 percent decrease increase in natural gaselectric rates). On an annualized basis, the rate increase will generate approximately $3$2.0 million in additional revenue.
ALLETE Clean Energy. Deferred On August 26, 2011, the Company filed with the MPUC for approval of certain affiliated interest agreements between ALLETE and ALLETE Clean Energy. These agreements relate to various relationships with ALLETE, including the accounting for certain shared services, as well as the transfer of transmission and wind development rights in North Dakota to ALLETE Clean Energy. These transmission and wind development rights are separate and distinct from those needed by Minnesota Power to meet Minnesota’s renewable energy standard requirements.
The Patient Protection and Affordable Care Act of 2010 (PPACA). In March 2010, PPACA was signed into law. One of the provisions changed the tax treatment for retiree prescription drug expenses by eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, beginning January 1, 2013. Based on this provision, we are subject to additional taxes in the future and were required to reverse previously recorded tax benefits in 2010. Consequently, the reversal of previously recorded tax benefits resulted in a non-recurring charge to net income of $4.0 million in 2010. In October 2010, we submitted a filing with the MPUC requesting deferral of the retail portion of the tax charge taken in 2010 resulting from PPACA. On May 24, 2011, the MPUC approved our request for deferral until the next rate case and as a result we recorded an income tax benefit of $2.9 million and a related regulatory asset of $5.0 million. (See Note 14. Income Tax Expense.)
Pension. On December 22, 2011, the Company filed a petition with the MPUC requesting a mechanism to recover the cost of capital associated with the prepaid pension asset (or liability) created by the required contributions under the pension plan in excess of (or less than) annual pension expense. The Company further requested a mechanism to defer pension expenses in excess of (or less than) those currently being recovered in base rates. If our petition is successful the impact would be deferred in a regulatory asset (or liability) for recovery (or refund) in the Company’s next general rate case.
Regulatory Assets and Liabilities. Our regulated utility operations are subject to the accounting guidancestandards on Regulated Operations. We capitalize, incurred costs, as regulatory assets, incurred costs which are probable of recovery in future utility rates. Regulatory liabilitiesrepresent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.
ALLETE 20092011 Form 10-K
75
| |
| Note 5. | Regulatory Matters (Continued) |
| Deferred Regulatory Assets and Liabilities | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Deferred Regulatory Assets | | |
| Future Benefit Obligations Under | | |
Defined Benefit Pension and Other Postretirement Plans (a) | 235.8 | 216.5 |
Boswell Unit 3 Environmental Rider (b) | 20.9 | 3.8 |
Deferred Fuel (c) | 20.8 | 13.1 |
| Income Taxes | 15.7 | 12.2 |
| Asset Retirement Obligation | 6.3 | 5.1 |
| Deferred MISO Costs | 2.4 | 3.9 |
| Premium on Reacquired Debt | 2.0 | 2.2 |
| Other | 4.8 | 5.6 |
| Total Deferred Regulatory Assets | $308.7 | $262.4 |
| | | |
| Deferred Regulatory Liabilities | | |
| Income Taxes | $25.9 | $28.7 |
| Plant Removal Obligations | 16.9 | 15.9 |
| Accrued MISO Refund | – | 4.7 |
| Other | 4.3 | 0.7 |
| Total Deferred Regulatory Liabilities | $47.1 | $50.0 |
|
| | | | | | | |
| Regulatory Assets and Liabilities | | | |
| As of December 31 | 2011 | | 2010 |
| Millions | | | |
Current Regulatory Assets (a) | | | |
| Deferred Fuel |
| $17.5 |
| |
| $20.6 |
|
| Total Current Regulatory Assets | 17.5 |
| | 20.6 |
|
| Non-Current Regulatory Assets | | | |
| Future Benefit Obligations Under | | | |
| Defined Benefit Pension and Other Postretirement Plans | 292.8 |
| | 257.9 |
|
| Boswell Unit 3 Environmental Rider | — |
| | 20.5 |
|
| Income Taxes | 28.6 |
| | 17.3 |
|
| Asset Retirement Obligation | 9.8 |
| | 7.8 |
|
| PPACA Income Tax Deferral | 5.0 |
| | — |
|
| Conservation Improvement Program | 4.6 |
| | 0.7 |
|
| Other | 5.1 |
| | 6.0 |
|
| Total Non-Current Regulatory Assets | 345.9 |
| | 310.2 |
|
| | | |
| Total Regulatory Assets |
| $363.4 |
| |
| $330.8 |
|
| | | | |
| Non-Current Regulatory Liabilities | | | |
| Income Taxes |
| $21.9 |
| |
| $23.4 |
|
| Plant Removal Obligations | 15.0 |
| | 16.9 |
|
| Other | 6.6 |
| | 3.3 |
|
| Total Non-Current Regulatory Liabilities |
| $43.5 |
| |
| $43.6 |
|
(a) | See Note 16. Pension and Other Postretirement Benefit Plans. |
(b) | MPUC-approved current cost recovery rider. Our 2010 rate case proposes to move this project from a current cost recovery rider to base rates. |
(c) | As of December 31, 2009, $5 million of this balance relates to deferred fuel costs incurred under the former base cost of fuel calculation. Any revenue impact associated with this transition will be identified in a future filing related to the Company’s fuel clause operation. |
| Current and Non-Current Deferred Regulatory Assets and Liabilities | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
Total Current Deferred Regulatory Assets (a) | $15.5 | $13.1 |
| Total Non-Current Deferred Regulatory Assets | 293.2 | 249.3 |
| Total Deferred Regulatory Assets | 308.7 | 262.4 |
| Total Current Deferred Regulatory Liabilities | – | – |
| Total Non-Current Deferred Regulatory Liabilities | 47.1 | 50.0 |
| Total Deferred Regulatory Liabilities | $47.1 | $50.0 |
| (a) | Current deferred regulatory assets are included in prepayments and other on the consolidated balance sheet. |
Investment in ATC. Our wholly-owned subsidiary, Rainy River Energy, owns approximately 8 percent of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in parts of Wisconsin, Michigan, Minnesota, and Illinois. ATC provides transmission service under rates regulated by theare FERC thatapproved and are set in accordance with the FERC’s policy of establishing the independent operation and ownership of, and investment in, transmission facilities.based on a 12.2 percent return on common equity dedicated to utility plant. We account for our investment in ATC under the equity method of accounting. As of December 31, 2009,2011, our equity investment balance in ATC was $88.4$98.9 million ($76.9 ($93.3 million at December 31, 2008)2010). On January 29, 2010,30, 2012, we invested an additional $1.2$0.8 million in ATC. In total, we expect to invest approximately $2$3 million throughout 2010.2012.
| ALLETE’s Interest in ATC | | |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Equity Investment Beginning Balance | $76.9 | $65.7 |
| Cash Investments | 7.8 | 7.4 |
| Equity in ATC Earnings | 17.5 | 15.3 |
| Distributed ATC Earnings | (13.8) | (11.5) |
| Equity Investment Ending Balance | $88.4 | $76.9 |
|
| | | | | | |
| ALLETE’s Interest in ATC | | |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Equity Investment Beginning Balance |
| $93.3 |
|
| $88.4 |
|
| Cash Investments | 2.0 |
| 1.6 |
|
| Equity in ATC Earnings | 18.4 |
| 17.9 |
|
| Distributed ATC Earnings | (14.8 | ) | (14.6 | ) |
| Equity Investment Ending Balance |
| $98.9 |
|
| $93.3 |
|
ALLETE 20092011 Form 10-K
76
| |
| Note 6. | Investment in ATC (Continued) |
|
| | | | | | |
| ATC Summarized Financial Data | | |
| Balance Sheet Data | | |
| As of December 31 | 2011 | 2010 |
| Millions | | |
| Current Assets |
| $58.7 |
|
| $59.9 |
|
| Non-Current Assets | 3,053.7 |
| 2,888.4 |
|
| Total Assets |
| $3,112.4 |
|
| $2,948.3 |
|
| Current Liabilities |
| $298.5 |
|
| $428.4 |
|
| Long-Term Debt | 1,400.0 |
| 1,175.0 |
|
| Other Non-Current Liabilities | 82.6 |
| 84.9 |
|
| Members’ Equity | 1,331.3 |
| 1,260.0 |
|
| Total Liabilities and Members’ Equity |
| $3,112.4 |
|
| $2,948.3 |
|
| ATC Summarized Financial Data | | | |
| Year Ended December 31 | | | |
| Income Statement Data | 2009 | 2008 | 2007 |
| Millions | | | |
| Revenue | $521.5 | $466.6 | $408.0 |
| Operating Expense | 230.3 | 209.0 | 198.2 |
| Other Expense | 77.8 | 69.6 | 55.7 |
| Net Income | $213.4 | $188.0 | $154.1 |
| ALLETE’s Equity in Net Income | $17.5 | $15.3 | $12.6 |
|
| | | | | | | | | |
| Income Statement Data | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Revenue |
| $567.2 |
|
| $556.7 |
|
| $521.5 |
|
| Operating Expense | 261.6 |
| 251.1 |
| 230.3 |
|
| Other Expense | 81.7 |
| 85.9 |
| 77.8 |
|
| Net Income |
| $223.9 |
|
| $219.7 |
|
| $213.4 |
|
ALLETE’s Equity in Net Income |
| $18.4 |
|
| $17.9 |
|
| $17.5 |
|
| Balance Sheet Data | | | |
| Millions | | | |
| Current Assets | $51.1 | $50.8 | $48.3 |
| Non-Current Assets | 2,767.3 | 2,480.0 | 2,189.0 |
| Total Assets | 2,818.4 | 2,530.8 | 2,237.3 |
| | | | |
| Current Liabilities | 285.5 | 252.0 | 317.1 |
| Long-Term Debt | 1,259.6 | 1,109.4 | 899.1 |
| Other Non-Current Liabilities | 76.9 | 120.2 | 108.5 |
| Members’ Equity | 1,196.4 | 1,049.2 | 912.6 |
| Total Liabilities and Members’ Equity | $2,818.4 | $2,530.8 | $2,237.3 |
Investments. At December 31, 2009,2011, our long-term investment portfolio included the real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held to fund employee benefits ARS, and land held-for-saleavailable-for-sale in Minnesota.
| Investments | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| ALLETE Properties | $93.1 | $84.9 |
| Available-for-sale Securities | 29.5 | 32.6 |
| Other | 7.9 | 19.4 |
| Total Investments | $130.5 | $136.9 |
|
| | | | | | | |
| Investments | | | |
| As of December 31 | 2011 | | 2010 |
| Millions | | | |
| ALLETE Properties |
| $91.3 |
| |
| $94.0 |
|
| Available-for-sale Securities | 24.7 |
| | 25.2 |
|
| Other | 16.3 |
| | 6.8 |
|
| Total Investments |
| $132.3 |
| |
| $126.0 |
|
| |
| Note 7. | Investments (Continued) |
| ALLETE Properties | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Land Held-for-Sale Beginning Balance | $71.2 | $62.6 |
| Additions during period: Capitalized Improvements | 5.6 | 10.5 |
| Deductions during period: Cost of Real Estate Sold | (1.9) | (1.9) |
| Land Held-for-Sale Ending Balance | 74.9 | 71.2 |
| Long-Term Finance Receivables | 12.9 | 13.6 |
| Other | 5.3 | 0.1 |
| Total Real Estate Assets | $93.1 | $84.9 |
|
| | | | | | | |
| ALLETE Properties | | | |
| As of December 31 | 2011 | | 2010 |
| Millions | | | |
| Land Inventory Beginning Balance |
| $86.0 |
| |
| $74.9 |
|
Deeds to Collateralized Property (a) | 1.8 |
| | 9.9 |
|
Land Impairment (b) | (1.7 | ) | | — |
|
| Cost of Real Estate Sold | (0.3 | ) | | — |
|
| Capitalized Improvements and Other | 0.2 |
| | 1.2 |
|
| Land Inventory Ending Balance | 86.0 |
| | 86.0 |
|
Long-Term Finance Receivables (net of allowances of $0.6 and $0.8) (a) | 2.0 |
| | 3.7 |
|
| Other | 3.3 |
| | 4.3 |
|
| Total Real Estate Assets |
| $91.3 |
| |
| $94.0 |
|
| |
| (a) | In 2010, the deeds to collateralized property resulted primarily from an entity which filed for Chapter 11 bankruptcy and were recorded at fair value net of estimated selling costs. |
| |
| (b) | The land impairment charge was a result of an impairment analysis conducted in the fourth quarter of 2011 where the cost basis was reduced to the estimated fair value. |
Land Inventory. Land Held-for-Sale. Land held-for-saleinventory is accounted for as held for use and is recorded at cost, unless the lower of cost orcarrying 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 fair value determined by the evaluation of individual land parcels.value. Land values are reviewed for impairment on a quarterly basis. In the fourth quarter of 2011, an impairment analysis of estimated future undiscounted cash flows was conducted and noindicated that the cash flows were not adequate to recover the carrying basis of certain properties not strategic to our three major development projects. Consequently, we reduced the cost basis to estimated fair value resulting in a pretax impairment charge of $1.7 million. Fair value was determined based on property tax assessed values, discounted cash flow analysis, or a combination thereof. No impairments were recorded for the year ended December 31, 2009 (none in 2008)2010.
Note 7. | Investments (Continued) |
Long-Term Finance Receivables.Receivables. As of December 31, 2011, long-term finance receivables were $2.0 million net of allowance ($3.7 million net of allowance as of December 31, 2010). The decrease is primarily the result of the transfer of properties back to ALLETE Properties by deed-in-lieu of foreclosure, in satisfaction of amounts previously owed under long-term financing receivables. Long-term finance receivables which are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accountsaccounts. As of $0.4 million at December 31, 2009 ($0.1 million at December 31, 2008). The2011, we had allowance for doubtful accounts includes $0.3of $0.6 million ($0.8 million as of impairments that were recorded for other receivables during the year ended December 31, 2009.2010). The majority are receivables having maturities updecrease in allowance for doubtful accounts is primarily due to four years. Finance receivables totaling $7.8 million at December 31, 2009, were due from an entity which filed for voluntary Chapter 11 bankruptcy protection in June 2009. The estimated fair valuerecovery of the collateral relating to these receivables was greater than the $7.8 million amount due at December 31, 2009real estate taxes and no impairment was recordedaccrued interest on these receivables. Due to the lack of recent market activity, we estimated fair value based primarily on recent property tax assessed values. This valuation technique constitutes a Level 3 non-recurring fair value measurement.previously delinquent notes receivable.
If a purchaser defaults on a sales contract, the legal remedy is usually limited to terminating the contract and retaining the purchaser’s deposit. The property is then available for resale. In many cases, contract purchasers incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they have substantially more at risk than the deposit.
Available-for-Sale Investments. We account for our available-for-sale portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits and auction rate securities.
| Available-For-Sale Securities |
| Millions | | Gross Unrealized | |
| As of December 31 | Cost | Gain | (Loss) | Fair Value |
| | | | | |
| 2009 | $33.1 | $0.1 | $(3.7) | $29.5 |
| 2008 | $40.5 | – | $(7.9) | $32.6 |
| 2007 | $45.3 | $8.4 | $(0.1) | $53.6 |
|
| | | | | | | | | | |
| Available-For-Sale Securities |
| Millions | | Gross Unrealized | |
| As of December 31 | Cost |
| Gain |
| (Loss) | Fair Value |
|
| 2011 |
| $27.3 |
|
| $0.1 |
| $(2.7) |
| $24.7 |
|
| 2010 |
| $27.4 |
|
| $0.2 |
| $(2.4) |
| $25.2 |
|
| 2009 |
| $33.1 |
|
| $0.1 |
| $(3.7) |
| $29.5 |
|
| |
| Note 7. | Investments (Continued) |
|
| | | | | | | | | | |
| | Net | Gross Realized | Net Unrealized Gain (Loss) in Other |
| Year Ended December 31 | Proceeds | Gain | (Loss) | Comprehensive Income |
| 2011 |
| $5.5 |
| — |
| — |
| $(0.4) |
| 2010 | $(1.7) | — |
| — |
|
| $1.4 |
|
| 2009 |
| $6.7 |
| — |
| — |
|
| $4.5 |
|
Auction Rate Securities. As of December 31, 2010, our ARS were classified as a short-term investment as the remaining balance of $6.7 million was redeemed at carrying value on January 5, 2011.
| | | | Net Unrealized |
| | Net | Gross Realized | Gain (Loss) in Other |
| Year Ended December 31 | Proceeds | Gain | (Loss) | Comprehensive Income |
| | | | | |
| 2009 | $6.7 | – | – | $4.5 |
| 2008 | $17.5 | $6.5 | $(0.1) | $(9.7) |
| 2007 | $81.4 | – | – | $1.4 |
Auction Rate Securities. Included in Available-for-Sale Securities as of December 31, 2009, is an auction rate municipal bond of $6.7 million ($15.2 million at December 31, 2008) with a stated maturity date of March 1, 2024. The ARS consists of guaranteed student loans insured or reinsured by the federal government. ARS were historically auctioned every 35 days to set new rates and provided a liquidating event in which investors could either buy or sell securities. Beginning in 2008, the auctions have been unable to sustain themselves due to the overall lack of market liquidity and we have been unable to liquidate all of our ARS. As a result, we have classified our ARS as long-term investments and have the ability to hold these securities to maturity, until called by the issuer, or until liquidity returns to this market.
The Company used a discounted cash flow model to determine the estimated fair value of its investment in the ARS as of December 31, 2009. The assumptions used in preparing the discounted cash flow model include the following: the effective interest rate, amount of cash flows, and expected holding periods of the ARS. These inputs reflect the Company’s judgments about assumptions that market participants would use in pricing ARS including assumptions about risk.
Of the remaining ARS outstanding as of December 31, 2009, approximately $0.3 million was called at par value effective March 1, 2010. We anticipate the remainder of our ARS will be redeemed in the second quarter of 2010, as we received a Notice of Contemplated Refunding on January 29, 2010. The investment remains classified as long-term until officially called by the bondholders.
During 2009 we entered into financial derivative instruments to manage price risk for certain power marketing contracts. Outstanding derivative contracts at December 31, 2009, consist of cash flow hedges for an energy sale that includes pricing based on daily natural gas prices, and Financial Transmission Rights (FTRs) purchased to manage congestion risk for forward power sales contracts. These derivative instruments are recorded on our consolidated balance sheet at fair value. During 2009, we purchased $2.4 million of FTRs and expensed $1.7 million through our consolidated statement of income. As of December 31, 2009, approximately $0.7 million remains in other assets on our consolidated balance sheet. These derivative instruments settle monthly throughout the first five months of 2010.
Note 8. | Derivatives (Continued) |
Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria is met. Favorable changes in fair value of $0.3 million and $0.1 million were recorded in operating revenue in the first and second quarters of 2009, respectively; and a $0.4 million decrease was recorded in the third quarter of 2009 when2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the corresponding energyinterest rate risk associated with a $75.0 million Term Loan. The Term Loan has a variable interest rate equal to the one-month LIBOR plus 1.00 percent, has a maturity of August 25, 2014, and represents approximately 9 percent of the Company’s outstanding long-term debt as of December 31, 2011. (See Note 10. Short-Term and Long-Term Debt.) The Swap agreement has a notional amount equal to the underlying debt principal and matures on August 25, 2014. The Swap agreement involves the receipt of variable rate amounts in exchange for fixed rate interest payments over the life of the agreement without an exchange of the underlying notional amount. The variable rate of the Swap is equal to the one-month LIBOR and the fixed rate is equal to 0.825 percent. Cash flows from the interest rate swap contract ended.
are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the LIBOR benchmark interest rate over the life of the Swap. If it is determined that a derivative is not or has ceased to be effective as a hedge, the Company prospectively discontinues hedge accounting. The shortcut method is used to assess hedge effectiveness. At inception, all shortcut method requirements were satisfied; thus changes in value of the Swap designated as the hedging instrument will be deemed 100 percent effective. As a result, there was no ineffectiveness recorded for the year ended December 31, 2011.The mark-to-market fluctuationsfluctuation on the cash flow hedge werewas recorded in accumulated other comprehensive income on the consolidated balance sheet;sheet. As of December 31, 2011, a $0.1$0.4 million increase decrease in fair value was recorded and is included in other non-current liabilities on the consolidated balance sheet. Cash flows from derivative activities are presented in the first quartersame category as the item being hedged on the consolidated statement of 2009, and a decrease of $0.1 million wascash flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the second quarterhedged transactions occur or when it is probable that the hedged transactions will not occur. Gains or losses on interest rate hedging transactions are reflected as a component of 2009. There were no mark-to-market changes ininterest expense on the third or fourth quartersconsolidated statement of 2009.income.
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 mutual fund investments held to fund employee benefits.
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, fixed income securities, and derivative instruments consisting of cash flow hedges.
| |
| Note 9. | Fair Value (Continued) |
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 ARS consisting of guaranteed student loans and derivative instruments consisting of FTRs.financial transmission rights.
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, 20092011 and December 31, 2008.2010. 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, andwhich may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
| | At Fair Value as of December 31, 2009 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities | $17.8 | – | – | $17.8 |
| Corporate Debt Securities | – | $6.4 | – | 6.4 |
| Derivatives | – | – | $0.7 | 0.7 |
| Debt Securities Issued by States of the United States (ARS) | – | – | 6.7 | 6.7 |
| Money Market Funds | 1.4 | – | – | 1.4 |
| Total Fair Value of Assets | $19.2 | $6.4 | $7.4 | $33.0 |
| | | | | |
| Liabilities: | | | | |
| Deferred Compensation | – | $14.6 | – | $14.6 |
| Total Fair Value of Liabilities | – | $14.6 | – | $14.6 |
| | | | | |
| Total Net Fair Value of Assets (Liabilities) | $19.2 | $(8.2) | $7.4 | $18.4 |
Note 9. | Fair Value (Continued) |
|
| | | | | | | | | | | | | | |
| | At Fair Value as of December 31, 2011 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Total |
| Millions | | | | | | | |
| Assets: | | | | | | | |
| Equity Securities |
| $17.6 |
| | — |
| | — |
| |
| $17.6 |
|
| Available-for-sale Securities – Corporate Debt Securities | — |
| |
| $8.2 |
| | — |
| | 8.2 |
|
| Money Market Funds | 11.4 |
| | — |
| | — |
| | 11.4 |
|
| Total Fair Value of Assets |
| $29.0 |
| |
| $8.2 |
| | — |
| |
| $37.2 |
|
| | | | | | | | |
| Liabilities: | | | | | | | |
| Deferred Compensation | — |
| |
| $12.8 |
| | — |
| |
| $12.8 |
|
| Derivatives - Interest Rate Swap | — |
| | 0.4 |
| | — |
| | 0.4 |
|
| Total Fair Value of Liabilities | — |
| |
| $13.2 |
| | — |
| |
| $13.2 |
|
| Total Net Fair Value of Assets (Liabilities) |
| $29.0 |
| | $(5.0) | | — |
| |
| $24.0 |
|
| | | Debt Securities |
| | | Issued by the States |
| Recurring Fair Value Measures | | of the United States |
| Activity in Level 3 | Derivatives | (ARS) |
| Millions | | |
| Balance as of December 31, 2008 | – | $15.2 |
Purchases, sales, issuances and settlements, net (a) | $0.7 | (8.5) |
| Level 3 transfers in | – | – |
| Balance as of December 31, 2009 | $0.7 | $6.7 |
(a) | ARS called during 2009 at par value. |
| | At Fair Value as of December 31, 2008 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities | $13.5 | – | – | $13.5 |
| Corporate Debt Securities | – | $3.3 | – | 3.3 |
| Debt Securities Issued by States of the United States (ARS) | – | – | $15.2 | 15.2 |
| Money Market Funds | 10.6 | – | – | 10.6 |
| Total Fair Value of Assets | $24.1 | $3.3 | $15.2 | $42.6 |
| | | | | |
| Liabilities: | | | | |
| Deferred Compensation | – | $13.5 | – | $13.5 |
| Total Fair Value of Liabilities | – | $13.5 | – | $13.5 |
| | | | | |
| Total Net Fair Value of Assets (Liabilities) | $24.1 | $(10.2) | $15.2 | $29.1 |
| Debt Securities |
| Issued by the States | | |
| Recurring Fair Value Measures | of the United States |
Activity in Level 3 | Debt Securities
Issued by States
of the United
States (ARS) |
| Millions | |
Balance as of December 31, 20072010 | –
| $6.7 |
|
| Settled During the Period | — |
|
Purchases, sales, issuances and settlements, net Redeemed During the Period (a)
| $(10.0) |
Level 3 transfers in(6.7 | 25.2) |
Balance as of December 31, 20082011 | $15.2— |
|
| |
| (a) | The ARS were redeemed at carrying value on January 5, 2011. |
| |
| Note 9. | Fair Value (Continued) |
|
| | | | | | | | | | | | | | | |
| | At Fair Value as of December 31, 2010 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Total |
| Millions | | | | | | | |
| Assets: | | | | | | | |
| Equity Securities |
| $19.4 |
| | — |
| | — |
| |
| $19.4 |
|
| Available-for-sale Securities | | | | | | | |
| Corporate Debt Securities | — |
| |
| $7.5 |
| | — |
| | 7.5 |
|
| Debt Securities Issued by States of the United States (ARS) | — |
| | — |
| |
| $6.7 |
| | 6.7 |
|
| Total Available-for-sale Securities | — |
| | 7.5 |
| | 6.7 |
| | 14.2 |
|
| Money Market Funds | 0.8 |
| | — |
| | — |
| | 0.8 |
|
| Total Fair Value of Assets |
| $20.2 |
| |
| $7.5 |
| |
| $6.7 |
| |
| $34.4 |
|
| | | | | | | | |
| Liabilities: | | | | | | | |
| Deferred Compensation | — |
| |
| $13.3 |
| | — |
| |
| $13.3 |
|
| Total Fair Value of Liabilities | — |
| |
| $13.3 |
| | — |
| |
| $13.3 |
|
| | | | | | | | |
| Total Net Fair Value of Assets (Liabilities) |
| $20.2 |
| | $(5.8) | |
| $6.7 |
| |
| $21.1 |
|
|
| | | | | | | |
Recurring Fair Value Measures
Activity in Level 3 | Derivatives | | Debt Securities
Issued by States
of the United
States (ARS) |
| Millions | | | |
| Balance as of December 31, 2009 |
| $0.7 |
| |
| $6.7 |
|
Settled During the Period (a) | (0.7 | ) | | — |
|
| Redeemed During the Period | — |
| | — |
|
| Balance as of December 31, 2010 | — |
| |
| $6.7 |
|
| |
| (a) | 2008 includes a $5.2During the second quarter of 2010, the $0.7 million transfer of ARS to our Voluntary Employee Benefit Association trust used to fund postretirement health and life benefits.financial transmission rights derivatives were settled. |
The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. For the year ended December 31, 2011 and 2010, there were no transfers in or out of Levels 1, 2 or 3.
Fair Value of Financial Instruments. With the exception of the items listed below, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the items below were based on quoted market prices for the same or similar instruments.
| | | Financial Instruments | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
| Millions | | | |
| Long-Term Debt, Including Current Portion | | | |
| December 31, 2009 | $701.0 | $734.8 | |
| December 31, 2008 | $598.7 | $561.6 | |
| December 31, 2011 | |
| $863.3 |
|
| $966.4 |
|
| December 31, 2010 | |
| $785.0 |
|
| $796.7 |
|
| |
| Note 10. | Short-Term and Long-Term Debt |
Short-Term Debt.Total short-term debt outstanding as of December 31, 2009,2011, was $5.2$6.5 million ($10.4 ($14.4 million at December 31, 2008)2010) and consisted of long-term debt due within one year. (See ALLETE consolidated balance sheet.)year and notes payable.
Note 10. | Short-Term and Long-Term Debt (Continued) |
As of December 31, 2009,2011, we had bank lines of credit aggregating $157.0$256.4 million ($160.5 ($154.0 million at December 31, 2008)2010), the majority$250.0 million of which expireexpires in January 2012.June 2015. These bank lines of credit make financingare available throughto provide short-term bank loans and provide creditliquidity support for ALLETE's commercial paper.paper program. At December 31, 2009, $69.22011, $1.1 million ($7.3 ($1.0 million at December 31, 2008)2010) was drawn on our lines of credit leaving a $87.8$255.3 million balance available for use ($153.2($153.0 million at December 31, 2008)2010). In December 2009, we drew $65.0 million on our $150.0 million syndicated revolving credit facility to temporarily fund the purchase of the 250 kV DC transmission line. In December 2009, we agreed to sell $80.0 million of First Mortgage Bonds in February 2010 (see Long-Term Debt, below). We intend to use proceeds from these bonds to repay the amount drawn on the line, resulting in $65.0 million of our line of credit being classified as long-term at December 31, 2009.
On November 12, 2009, BNI Coal replacedFebruary 1, 2012, ALLETE entered into a $6.0$150.0 million Promissory Note credit agreement (Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and Supplement (Line of Credit) with CoBANK, ACB with a $3.0 million Line of Creditseveral other lenders that are parties thereto. The Agreement is unsecured and a $3.0 million term loan with CoBANK, ACB. The Line of Credit has a variable interest rate withmaturity date of January 31, 2014, which may be extended for one year, subject to bank approvals. Advances from the option to fix the rate based on LIBOR plus a certain spread. The term of the Line of Credit is 24 months. The Line of Credit is beingAgreement may be used for general corporate purposes. Aspurposes, to provide liquidity support for ALLETE’s commercial paper program and to issue up to $10.0 million in letters of December 31, 2009, $1.9 million was drawn on the Line of Credit. The $3.0 million term loan has a fixed interest rate of 5.19 percent and is payable in 28 equal quarterly installments commencing January 20, 2010, and ending on October 20, 2016.credit.
On May 25, 2011, ALLETE entered into a $250.0 million credit agreement (Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and several other lenders that are parties thereto. The Agreement was effective July 1, 2011, and replaced our previous $150.0 million credit facility. The Agreement is unsecured and has a maturity date of June 30, 2015, which may be extended for one year. Such extension is subject to bank approvals. Advances from the Agreement may be used for general corporate purposes, to provide liquidity support for ALLETE’s commercial paper program and to issue up to $40.0 million in letters of credit.
Long-Term Debt. The aggregate amount of long-term debt maturing during 20102012 is $5.2$5.4 million ($13.9 ($83.8 million in 2011; $3.32013; $94.1 million in 2012; $73.92014; $16.7 million in 2013; $19.62015; $21.0 million in 2014;2016; and $520.1$642.3 million thereafter). Substantially all of our electric plant is subject to the lien of the mortgagesmortgage collateralizing variousoutstanding 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.
In January 2009,On August 25, 2011, ALLETE entered into a $75.0 million term loan agreement with JPMorgan Chase Bank, N.A., as administrative agent and a lender, and Bank of America, N.A., as a lender (Term Loan). The Term Loan is an unsecured, single-draw loan that is due on August 25, 2014. The interest rate on the Term Loan is equal to the one-month LIBOR plus 1 percent; however, we issued $42.0 million in principal amountalso entered into an interest rate swap agreement which effectively fixed the interest rate at 1.825 percent over the term of unregistered First Mortgage Bonds (Bonds) in the private placement market. The Bonds mature January 15, 2019, and carry a coupon rate of 8.17 percent. We used the proceedsloan. (See Note 8. Derivatives.) Proceeds from the sale of the Bonds to fund utility capital investments andTerm Loan were used for general corporate purposes. As of December 31, 2011, there was $75.0 million outstanding on the Term Loan.
In December 2009, we agreedOn November 14, 2011, ALLETE Properties renewed an $8.3 million line of credit with RBC Bank extending the maturity of the line of credit to sell $80.0November 2013. The previous line of credit was $10.0 million in principal amount which ALLETE Properties reduced by $1.7 million million at the time of First Mortgage Bonds (Bonds) in the private placement market in three series as follows:renewal.
Issue Date
(on or about)
| Maturity | Principal Amount | Coupon |
February 17, 2010 | April 15, 2021 | $15 Million | 4.85% |
February 17, 2010 | April 15, 2025 | $30 Million | 5.10% |
February 17, 2010 | April 15, 2040 | $35 Million | 6.00% |
We expect to use the proceeds from the February 2010 saleOn October 7, 2011, ALLETE Properties renewed a $3.0 million line of Bonds to pay down the syndicated revolving credit facility, to fund utility capital investments or for general corporate purposes.
For the January 2009 and the February 2010 bond issuances (the Bonds), we have the option to prepay all or a portionwith Intracoastal Bank, extending maturity of the Bonds at our discretion, subject
line to a make-whole provision. The Bonds are subject to theOctober 2013, with all other terms and conditions of our utility mortgage. The Bonds were sold or will be sold in reliance on an exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, to institutional accredited investors.remaining unchanged.
ALLETE 20092011 Form 10-K
82
Note 10. | Note 10. Short-Term and Long-Term Debt (Continued) |
| Long-Term Debt | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| First Mortgage Bonds | | |
| 4.86% Series Due 2013 | $60.0 | $60.0 |
| 6.94% Series Due 2014 | 18.0 | 18.0 |
| 7.70% Series Due 2016 | 20.0 | 20.0 |
| 8.17% Series Due 2019 | 42.0 | – |
| 5.28% Series Due 2020 | 35.0 | 35.0 |
| 4.95% Pollution Control Series F Due 2022 | 111.0 | 111.0 |
| 6.02% Series Due 2023 | 75.0 | 75.0 |
| 5.99% Series Due 2027 | 60.0 | 60.0 |
| 5.69% Series Due 2036 | 50.0 | 50.0 |
| SWL&P First Mortgage Bonds | | |
| 7.25% Series Due 2013 | 10.0 | 10.0 |
| Senior Unsecured Notes 5.99% Due 2017 | 50.0 | 50.0 |
| Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2009 – 2020 | 28.3 | 28.3 |
| Industrial Development Revenue Bonds 6.5% Due 2025 | 6.0 | 6.0 |
| Industrial Development Variable Rate Demand Refunding | | |
| Revenue Bonds Series 2006 Due 2025 | 27.8 | 27.8 |
Line of Credit Facility (a) | 65.0 | – |
| Other Long-Term Debt, 2.0% – 8.0% Due 2009 – 2037 | 42.9 | 47.6 |
| Total Long-Term Debt | 701.0 | 598.7 |
| Less: Due Within One Year | 5.2 | 10.4 |
| Net Long-Term Debt | $695.8 | $588.3 |
(a) | The $80 million First Mortgage Bonds due in 2021, 2025 and 2040 to be issued on or about February 17, 2010, will replace the balance due on the Line of Credit Facility as of December 31, 2009. |
|
| | | | | | |
| Long-Term Debt | | |
| As of December 31 | 2011 | 2010 |
| Millions | | |
| First Mortgage Bonds | | |
| 4.86% Series Due 2013 |
| $60.0 |
|
| $60.0 |
|
| 6.94% Series Due 2014 | 18.0 |
| 18.0 |
|
| 7.70% Series Due 2016 | 20.0 |
| 20.0 |
|
| 8.17% Series Due 2019 | 42.0 |
| 42.0 |
|
| 5.28% Series Due 2020 | 35.0 |
| 35.0 |
|
| 4.85% Series Due 2021 | 15.0 |
| 15.0 |
|
| 4.95% Pollution Control Series F Due 2022 | 111.0 |
| 111.0 |
|
| 6.02% Series Due 2023 | 75.0 |
| 75.0 |
|
| 4.90% Series Due 2025 | 30.0 |
| 30.0 |
|
| 5.10% Series Due 2025 | 30.0 |
| 30.0 |
|
| 5.99% Series Due 2027 | 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 |
|
| SWLP& First Mortgage Bonds 7.25% Series Due 2013 | 10.0 |
| 10.0 |
|
| Senior Unsecured Notes 5.99% Due 2017 | 50.0 |
| 50.0 |
|
| Variable Demand Revenue Refunding Bonds Series 1997 A, B, and C Due 2013 – 2020 | 28.2 |
| 28.3 |
|
| Industrial Development Revenue Bonds 6.5% Due 2025 | 6.0 |
| 6.0 |
|
| Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006 Due 2025 | 27.8 |
| 27.8 |
|
| Unsecured Term Loan Variable Rate Due 2014 | 75.0 |
| — |
|
| Other Long-Term Debt, 1.0% – 8.0% Due 2012 – 2037 | 40.3 |
| 36.9 |
|
| Total Long-Term Debt | 863.3 |
| 785.0 |
|
| Less: Due Within One Year | 5.4 |
| 13.4 |
|
| Net Long-Term Debt |
| $857.9 |
|
| $771.6 |
|
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 covenant requires ALLETE to maintain a ratio of its Funded DebtIndebtedness to Total CapitalCapitalization (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, 2009,2011, our ratio was approximately 0.410.44 to 1.00.1.00. 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. None of ALLETE’s long-term debt arrangements or credit facilities contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. As of December 31, 2009,2011, ALLETE was in compliance with its financial covenants.
| |
| Note 11. | Commitments, Guarantees and Contingencies |
Off-Balance Sheet Arrangements
Power Purchase Agreements.Our long-term power purchase agreements (PPA)PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPA, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the following factors: we have no equity investment in these facilities and do not incur actual or expected losses related to the loss of facility value, andfact that we do not have significantboth control over activities that are most significant to the operations of each of these facilities.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 fixed capacity and energy payments.
| |
| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Power Purchase Agreements (Continued)
Square Butte Power Purchase Agreement.PPA. Minnesota Power has a power purchase agreementPPA with Square Butte that extends through 2026 (Agreement). It provides a long-term supply of energy to customers in our electric service territory and enables Minnesota Power to meet power pool reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a 455-MW455 MW coal-fired generating unit (Unit) near Center, North Dakota. The Unit is adjacent to a generating unit owned by Minnkota Power, a North Dakota cooperative corporation whose Class A members are also members of Square Butte. Minnkota Power serves as the operator of the Unit and also purchases power from Square Butte.
Note 11. Commitments, Guarantees and Contingencies (Continued)
Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on Minnesota Power’s entitlement to Unit output. Our output entitlement under the Agreement is 50 percent for the remainder of the contract.contract, subject to the provisions of the Minnkota power sales agreement described below. 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 fixed costs consist primarily of debt service. At service, operating and maintenance, depreciation and fuel expenses. As of December 31, 2009,2011, Square Butte had total debt outstanding of $351.0 million.$451.4 million. Annual debt service for Square Butte is expected to be approximately $34$44 million in each of the five years, 20102012 through 2014. Variable operating costs2016, of which Minnesota Power's obligation is 50 percent. Fuel expenses are recoverable through our fuel adjustment clause and include the pricecost of coal purchased from BNI Coal, our subsidiary, under a long-term contract.
Minnesota Power’s cost of power purchased from Square Butte during 20092011 was $53.9$61.2 million ($56.7 ($55.2 million in 2008; $57.32010; $53.9 million in 2007)2009). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the 50 percent output entitlement in 2009, the 55 percent output entitlement in 2008 and the 60 percent output entitlement in 2007.entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of $11.0$11.1 million in 2009 ($11.62011 ($10.2 million in 2008; $11.02010; $11.0 million in 2007)2009). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.
Minnkota Power Sales Agreement.In conjunction with the purchase of the existing 250 kV DC transmission line purchasefrom Square Butte in December 2009, Minnesota Power entered into a contingent new Power Sales Agreementpower sales agreement with Minnkota Power. Under the new Power Sales Agreement,power sales agreement, Minnesota Power will be able to sell a portion of ourits output from Square Butte to Minnkota Power, resulting in Minnkota’sMinnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of 2025.2025.
No power will be sold under this agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late 2013.2013. This new AC transmission line will allow Minnkota Power to transmit theirits entitlement from Square Butte directly to theirits customers, andwhich, in turn, will allow Minnesota Power the ability to transmit additional capacitywind generation on the recently acquired DC line to transmit new wind generation.transmission line.
Wind PPAs. In 2006 and 2007, Minnesota Power Purchase Agreements.entered into We have two long-term wind power purchase agreementsPPAs with an affiliate of NextEra Energy, Inc. to purchase the output from two wind facilities, Oliver Wind I (50 MWs)(50 MW) and Oliver Wind II (48 MWs)(48 MW), wind facilities located near Center, North Dakota. Each agreement is for 25 years and provides for the purchase of all output from the facilities.facilities at fixed prices. There are no fixed capacity charges, and we only pay for energy as it is delivered to us.
Hydro PPAs. Minnesota Power Purchase Agreement. We also havehas a power purchase agreementPPA with Manitoba Hydro that began in May 2009 and expires in April 2015.2015. Under thethis agreement, with Manitoba Hydro, Minnesota Power will purchase 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.
Minnesota Power has a separate PPA with Manitoba Hydro to purchase surplus energy from May 2011 through April 2022. This energy-only transaction 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. On March 31, 2011, the MPUC approved this PPA with Manitoba Hydro.
On May 19, 2011, Minnesota Power and Manitoba Hydro signed a long-term PPA. The PPA calls for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 2020 and requires construction of additional transmission capacity between Manitoba and the U.S. The capacity price is adjusted annually until 2020 by a change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed price component adjusted for a change in a governmental inflationary index and a natural gas index, as well as market prices. On January 26, 2012, the MPUC approved this PPA with Manitoba Hydro.
| |
| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
North Dakota Wind Project.Development On December 31, 2009, we purchased an existing . Minnesota Power uses the 465-mile, 250 kV DC transmission line from Square Butte for $69.7 million. The 465-mile transmission line that runs from Center, North Dakota, to Duluth, Minnesota. We expect to use this lineMinnesota to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity currently being delivered to our system over this transmission line from Square Butte’s lignite coal-fired generating unit. Acquisition of this transmission line was approved by an MPUC order dated December 21, 2009. In addition, the FERC issued an order on November 24, 2009, authorizing acquisition of the transmission facilities and conditionally accepting, upon compliance and other filings, the proposed tariff revisions, interconnection agreement and other related agreements.
On July 7, Bison 1 is an 82 MW wind project in North Dakota. All permitting has been received, the first phase was completed in 2010, and the second phase was completed in January 2012. Phase one included construction of a 22-mile, 230 kV transmission line and the installation of sixteen2.3 MW wind turbines. Phase two consisted of the installation of fifteen3.0 MW wind turbines. Bison 1 is expected to have a total project cost of $177 million, of which $171.5 million was spent through December 31, 2011. In 2009, the MPUC approved ourMinnesota Power’s petition seeking current cost recovery offor investments and expenditures related to Bison I1, and associated transmission upgrades.in July 2010, the MPUC approved our petition establishing rates effective August 1, 2010. On November 3, 2011, the MPUC issued an order approving our petition to update the rates for additional investments and expenditures related to Bison I is the first portion of several hundred MWs of our1.
Bison 2 and Bison 3 are both 105 MW wind projects in North Dakota Wind Project, which upon completion will help fulfillare expected to be completed by the 2025 renewable energy supply requirementend of 2012. Site preparation is currently underway for our retail load.both projects and the total project costs for Bison I, located near Center, North Dakota, will2 and Bison 3 are estimated to be comprisedapproximately $160 million each, of 33 wind turbines withwhich $37.0 million and $14.7 million, respectively, was spent through December 31, 2011. On September 8, 2011, and November 2, 2011, the MPUC approved Minnesota Power's petition seeking current cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively. On August 10, 2011, and October 12, 2011, the NDPSC issued a total nameplate capacityCertificate of 75.9 MWsSite Compatibility for Bison 2 and will be phased into service in late 2010 and 2011.Bison 3, respectively, which authorized site construction to commence. We anticipate filing a petitionpetitions with the MPUC in the first quarter 2010half of 2012 to establish customer billing rates for the approved cost recovery.
On September 29, 2009, the NDPSC authorized site construction for Bison I. On October 2, 2009, Minnesota Power filed a route permit application with the NDPSC for a 22 mile, 230 kV Bison I transmission line that will connect Bison I to the DC transmission line at the Square Butte Substation in Center, North Dakota. An order is expected in the first quarter 2010.
Leasing Agreements. BNI Coal is obligated to make lease payments for a dragline totaling $2.8$2.8 million annually for the lease term which expires in 2027.2027. BNI Coal has the option at the end of the lease term to renew the lease at a fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a $3.0$3 million termination fee. We lease other properties and equipment under operating lease agreements with terms expiring through 2016.2016. The aggregate amount of minimum lease payments for all operating leases is $8.8$10.9 million in 2010, $8.92012, $11.1 million in 2011, $9.02013, $11.4 million in 2012, $8.52014, $11.2 million in 2013, $8.22015, $9.2 million in 20142016 and $45.7$43.0 million thereafter. Total rent and lease expense was $9.3$9.4 million in 2009 ($8.52011 ($9.4 million in 2008; $8.42010; $9.3 million in 2007)2009).
Note 11. Commitments, Guarantees and Contingencies (Continued)
Coal, Rail and Shipping Contracts. We have two primary coal supply agreements providing for the purchase of a significant portion of our coal requirements which expire in 2012 and 2013. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through December 2011. We also have rail and shipping agreements for the transportation of all of our coal, with expiration dates through January 2012. Two of our rail and shipping agreements contain options to extend the agreements, which options Minnesota Power may exercise unilaterally. The term extensions are for an additional two year term and an additional four year term.2015. Our minimum annual payment obligationsobligation under these coal, railsupply and shippingtransportation agreements are currently $35.7for 2012 is $55.4 million in 2010, and $7.62013 is $27.0 million in 2011, with no specific commitments beyond 2011.. Our minimum annual payment obligations will increase when annual nominations are made for coal deliveries in future years. The delivered costs of fuel for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.
Transmission. We are making investments in Upper Midwest transmission opportunities that strengthen or enhance the regional transmission grid. This includes the CapX2020 initiative, investments in our own transmission assets, investments in other regional transmission assets (by ourselves or in combination with others), and our investment in ATC.
Transmission Investments. We have an approved cost recovery rider in place for certain transmission expenditures and the continued use of our 2009 billing factor was approved by the MPUC in May 2011. The billing factor allows us to charge our retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. On June 29, 2011, we filed an updated billing factor that includes additional transmission projects and expenses, which we expect to be approved in 2012.
CapX2020. Minnesota Power is a participant in the CapX2020 initiative which represents an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consists of electric cooperatives, municipals and investor-owned utilities, including Minnesota’s largest transmission owners, has assessed the transmission system and projected growth in customer demand for electricity through 2020. Studies show that the region's transmission system will require major upgrades and expansion to accommodate increased electricity demand as well as support renewable energy expansion through 2020.
Note 11. Commitments, Guarantees and Contingencies (Continued)
Transmission (Continued)
Minnesota Power is currently participating in three CapX2020 projects: the Fargo, North Dakota to St. Cloud, Minnesota project, the Monticello, Minnesota to St. Cloud, Minnesota project, which together total a 238-mile, 345 kV line from Fargo, North Dakota to Monticello, Minnesota, and the 70-mile, 230 kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota. Based on projected costs of the three transmission lines and the percentage agreements among participating utilities, Minnesota Power plans to invest between $100 million and $125 million in the CapX2020 initiative through 2015, of which $27.8 million was spent through December 31, 2011. As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.
In July 2010, the MPUC granted a route permit for the 28-mile 345 kV line between Monticello and St. Cloud. The project was completed and placed into service in December 2011. On June 10, 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process is underway. The entire 238-mile, 345 kV line from St. Cloud to Fargo is expected to be in service by 2015.
In November 2010, the MPUC approved a route permit for the Bemidji to Grand Rapids, Minnesota line and construction for the 230 kV line project commenced in January 2011. The Leech Lake Band of Ojibwe (LLBO) subsequently requested the MPUC suspend or revoke the route permit and also served the CapX2020 owners with a complaint filed in Leech Lake Tribal Court asserting adjudicatory and regulatory authority over the project. The CapX2020 owners filed a request for declaratory judgment in the United States District Court for the District of Minnesota (District Court) that the project does not require LLBO consent to cross non-tribal land within the reservation. On June 22, 2011, the federal judge issued a preliminary injunction directing the LLBO to cease and desist its claims of tribal court jurisdiction or from taking other actions to interfere with regulatory review, approval or project construction. The LLBO abandoned its motion to dismiss the declaratory action because the District Court’s injunction order had already dismissed the basis for the motion, namely, that the District Court did not have jurisdiction to hear the CapX2020 owners’ action. The parties are now proceeding with discovery and the CapX2020 owners do not anticipate any actions by the District Court until after the completion of discovery closes on May 31, 2012. The MPUC has taken no action in the matter in light of ongoing litigation in federal and tribal courts. The CapX2020 utilities are vigorously defending against the LLBO actions.
Environmental Matters.Matters
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. Currently, a number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements are under consideration by both the Congress and the EPA. Most notably, clean energy technologies and the regulation of GHGs have taken a lead in these discussions. Minnesota Power’sPower's fossil fueledfuel facilities will likely to be subject to regulation under these climate change policies.proposals. Our intention is to reduce our exposure to possible future carbon and GHG legislationthese requirements by reshaping our generation portfolio over time to reduce our reliance on coal.
We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits to conduct such operations have been obtained. Due to future restrictive environmental requirements through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments.
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. These accrualsAccruals are adjusted periodically as assessment and remediation efforts progress or as additional technical or legal information become 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 charged to expense unless recoverable in rates from customers.
Air.Clean Air Act. The electric utility industry is heavily regulated both at the federal Clean Air Act Amendments of 1990 (Clean Air Act) established the acid rain program which created emission allowances for SO2and system-wide average NOX limits.state level to address air emissions. Minnesota Power’sPower's generating facilities mainly burn low-sulfur western sub-bituminous coal. Square Butte, located in North Dakota, burns lignite coal. All of theseMinnesota Power's coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses or electrostatic precipitators. Minnesota Power’s generatingand low NOX technologies. At this time, under currently applicable environmental regulations, these facilities are currently in compliancesubstantially compliant with applicable emission requirements.
| |
| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Environmental Matters (Continued)
New Source Review. Review (NSR)On. In August 8, 2008, Minnesota Power received a Notice of Violation (NOV) from the United States EPA asserting violations of the New Source Review (NSR)NSR requirements of the Clean Air Act at Boswell Units 1-41, 2, 3 and 4 and Laskin Unit 2. The NOV also asserts that the Boswell Unit 4 Title V permit was violated, and that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR requirements.requirements and that the Boswell Unit 4 Title V permit was violated. In April 2011, Minnesota Power received a NOV 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 believes the projects specified in the NOVs were in full compliance with the Clean Air Act, NSR requirements and applicable permits.
We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Since 2006, Minnesota Power has significantly reduced, and continues to reduce, emissions at Boswell and Laskin.
The resolution could result in civil penalties and the installation of control technology, some of which is already planned or completed for other regulatory requirements. Any costs of installing pollution control technology would likely be eligible for recovery in rates over time subject to MPUC and FERC approval in a rate proceeding. We are unable to predict the ultimate financial impact or the resolution of these matters at this time.
EPA CleanCross-State Air Interstate Rule.Pollution Rule (CSAPR) In March 2005,. On July 6, 2011, the EPA announcedissued the CSAPR, which went into effect on October 7, 2011. The final rule replaced the EPA's 2005 Clean Air Interstate Rule (CAIR) that sought to reduce and permanently cap emissions of SO2, NOX, and particulates in the eastern United States. Minnesota was included as one of the 28 states considered as “significantly contributing” to air quality standards non-attainment in other downwind states. On July 11, 2008,. However, on December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit (Court) vacatedissued a ruling staying implementation of the CSAPR, pending judicial review, and ordered that the CAIR and remandedremain in place while the rulemakingCSAPR is stayed.
If the CSAPR is reinstated after judicial review, it will require states in the CSAPR region to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. These regulations do not directly require the installation of controls. Instead, they require facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would be allocated to facilities annually by the EPA for reconsiderationand will also be able to be bought and sold.
The CAIR regulations similarly require certain states to improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. Minnesota participation in the CAIR was stayed by EPA administrative action while also granting our petition that the EPA reconsider includingcompleted a review of air quality modeling issues in conjunction with the development of a final replacement rule. In its final determination, the EPA listed Minnesota as a CAIR state. In September 2008, the EPA and others petitioned the Court for a rehearing or alternatively requested thatCSAPR-affected state based on new 24-hour fine particulate NAAQS analysis. While the CAIR be remanded without a court order. In December 2008, the Court granted the request thatremains in effect, Minnesota participation in the CAIR will continue to be remanded without a court order, effectively reinstating a January 1, 2009stayed. It is uncertain if the CSAPR-related emission restrictions will become effective for Minnesota utilities.
Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Our analysis, based on our expected generation rates, indicates that these recent emission reductions would satisfy Minnesota Power's SO2 and NOX emission compliance date for the CAIR, including Minnesota. However, in the May 12, 2009 Federal Register the EPA issued a proposed rule that would amend the CAIR to stay its effectivenessobligations with respect to Minnesota until completionthe EPA-allocated CSAPR allowances for 2012. We will continue to evaluate our compliance strategy under CSAPR and if any capital investments or allowance purchases are required, we would likely seek recovery of the EPA’s determination of whether Minnesota should be included as a CAIR state. The formal administrative stay of CAIR for Minnesota was published in the November 3, 2009, Federal Register with an effective date of December 3, 2009.those costs. We are unable to predict any additional CSAPR compliance costs we might incur at this time if CSAPR is reinstated.
Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Environmental Matters (Continued)
Minnesota Regional Haze. The federal regional haze rule requires states to submit state implementation plans (SIPs) to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the regional haze rule, certain large stationary sources, that were put in place between 1962 and 1977, with emissions contributing to visibility impairment, are required to install emission controls, known as best available retrofit technologyBest Available Retrofit Technology (BART). We have certaintwo steam units, Boswell Unit 3 and Taconite Harbor Unit 3, which are subject to BART requirements.
Pursuant to the regional haze rule, Minnesota was required to develop its SIP by December 2007. As a mechanism for demonstrating progress towards meeting the long-term regional haze goal, in April 2007, the MPCA advanced a draft conceptual SIP which relied on the implementation of CAIR. However, a formal SIP was nevernot filed at that time due to the Court’s reviewUnited States Court of CAIR as more fully described above under “EPA Clean Air Interstate Rule.”Appeals for the District of Columbia Circuit's remand of CAIR. Subsequently, the MPCA requested that companies with BART eligibleBART-eligible units complete and submit a BART emissions control retrofit study, which was done oncompleted for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirementrequirements for that unit. OnIn December 15, 2009, the MPCA approved the Minnesota SIP for submittal to the EPA for its review and approval. The Minnesota SIP incorporates information from the BART emissions control retrofit studies that were completed as requested by the MPCA.
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| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Environmental Matters (Continued)
On December 30, 2011, the EPA published in the Federal Register a proposal to revise the regional haze rule. This proposal would approve the trading program in the CSAPR as an alternative to determining BART. If adopted, states in the CSAPR region could substitute participation in CSAPR for source-specific BART requirements for SO2 and NOX emissions from power plants. On January 2, 2012, the MPCA submitted to the EPA a supplemental Minnesota regional haze SIP stating that it wishes to rely on the CSAPR to satisfy BART requirements for SO2 and NOx for electric generating units.
On January 25, 2012, the EPA published in the Federal Register a proposal to approve the Minnesota SIP, including the supplemental Minnesota SIP. If the Minnesota SIP, the supplemental Minnesota SIP, and the EPA's regional haze rule revisions are finalized as currently proposed, and the CSAPR rule is reinstated, then Minnesota Power does not foresee a need to make significant additional expenditures at Taconite Harbor Unit 3 to comply with the regional haze rule.
If controls are ultimately required, Minnesota Power will have up to five years from the final promulgation deadline to bring Taconite Harbor Unit 3 into compliance with the regional haze rule requirements. It is uncertain what controls willwould ultimately be required at Taconite Harbor Unit 3 under this scenario, in connection with the regional haze rule.
EPA National EmissionMercury and Air Toxics Standards for Hazardous Air Pollutants. In March 2005,(MATS) Rule (formerly known as the EPA also announced the Clean Air Mercury Rule (CAMR) that would have reduced and permanently capped electric utility mercury emissions in the continental United States through a cap-and-trade program. In February 2008, the United States Court of Appeals for the District of Columbia Circuit vacated the CAMR and remanded the rulemaking to the EPA for reconsideration. In October 2008, the EPA petitioned the Supreme Court to review the Court’s decision in the CAMR case. In January 2009, the EPA withdrew its petition, paving the way for possible regulation of mercury and other hazardous air pollutant emissions throughElectric Generating Unit Maximum Achievable Control Technology (MACT) Rule). Under Section 112 of the Clean Air Act, setting Maximum Achievable Control Technologythe EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The EPA released a proposed MATS rule on March 16, 2011, addressing such emissions from coal-fired utility units greater than 25 MW. The final rule was issued on December 21, 2011. There are currently 188 listed HAPs which the EPA is required to evaluate for establishment of MACT standards. In the final MATS rule, the EPA established categories of HAPs, including mercury, trace metals other than mercury, acid gases, dioxin/furans, and organics other than dioxin/furans. The EPA also established emission limits for the first three categories of HAPs, and work practice standards for the utility sector. In December 2009, Minnesota Power and other utilities received an Information Collection Request fromremaining categories. Affected sources would have to be in compliance with the EPA, requiring that emissions data be provided and stack testing be performedrule three years after it is published in orderthe Federal Register. States have the authority to develop an improved database with whichgrant sources a one-year extension. Compliance at our Boswell Unit 4 to base future regulations. Cost estimatesaddress the final MATS rule is expected to result in capital expenditures between $300 million to $400 million over the next five years. Some additional controls for complying with potential future mercury and other hazardous air pollutant regulations under the Clean Air Actrule at our remaining coal-fired generating units may be required, the costs of which cannot be estimated at this time.
EPA National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and Institutional Boilers and Process Heaters. In March 2011, a final rule was published in the Federal Register for industrial boiler maximum achievable control technology (Industrial Boiler MACT). The rule was stayed by the EPA on May 16, 2011, to allow the EPA time to consider additional comments received. The EPA re-proposed the rule in December 2011. A final rule is expected in April 2012. On January 9, 2012, the United States District Court for the District of Columbia ruled that the EPA stay of the Industrial Boiler MACT was unlawful, effectively reinstating the March 2011 rule and associated compliance deadlines. Major sources are expected to have three years to achieve compliance with the final rule. It is not known yet whether the final rule from the December 2011 proposal, expected in April 2012, will establish new compliance deadlines. This rule may result in additional control measures being required at Rapids Energy Center and Hibbard. Costs for complying with the final rule cannot be estimated at this time.
Minnesota Mercury Emission Reduction Act.Act This legislation requires. Under Minnesota Power to file mercury emission reduction plans for Boswell Units 3 and 4, withlaw, a goal of 90 percent reduction in mercury emissions. The Boswell Unit 3 emission reduction plan was filed with the MPCA in October 2006. Mercury control equipment has been installed and was placed into service in November 2009. (See Item 1. Business – Regulated Operations – Minnesota Public Utilities Commission – Emission Reduction Plans.) A mercury emissions reduction plan for Boswell Unit 4 is required to be submitted by July 1, 2011,2015, with implementation no later than December 31, 2014.2018. The legislationstatute also calls for an evaluation of a mercury control alternative which provides for environmental and public health benefits without imposing excessive costs on the utility’sutility's customers. Cost estimatesUntil Minnesota Power files its mercury emission reduction plan for Boswell Unit 4, it must file an annual report updating the MPUC and other stakeholders on the status of emission reduction planning for Boswell Unit 4. The first update was filed with the MPUC on June 30, 2011.
Mercury emission limits have also been included in the recently finalized MATS rule. We anticipate that the emission reduction plan implemented to comply with the MATS rule will satisfy the mercury emission limits under Minnesota law. Costs for the Boswell Unit 4 emission reduction plan are not available at this time.included in the estimated capital expenditures required for compliance with the MATS rule discussed above.
OzoneProposed and Finalized National Ambient Air Quality Standards (NAAQS). The EPA is attemptingrequired to control,review the NAAQS every five years. If the EPA determines that a state's air quality is not in compliance with a NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. These state plans often include more stringent air emission limitations on sources of air pollutants than the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.
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| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Environmental Matters (Continued)
Ozone NAAQS. The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to reducerevise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA projects stating ruleswas scheduled to address attainmentdecide upon the 2008 eight-hour ozone standard in July 2011, but has announced that it is deferring revision of these new, more stringent standards will not be requiredthis standard until December 2013.
Particulate Matter NAAQS.The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA established a more stringent 24-hour average fine particulate matter (PM2.5) standard and kept the annual average fine particulate matter standard and the 24-hour coarse particulate matter standard unchanged. The United States Court of Appeals for the District of Columbia Circuit has remanded the PM2.5 standard to the EPA, requiring consideration of lower annual average standard values. The EPA expects to propose the new PM2.5 standards in June 2012 with a goal to finalize the rule by June 2013. State attainment status determination will occur after the rule is finalized. It is not known when affected sources would have to take additional control measures if modeling demonstrates non-compliance at their property boundary. The EPA has indicated that ambient air quality monitoring for 2008 through 2010 will be used as a basis for states to characterize their attainment status.
SO2 and NO2 NAAQS. During 2010, the EPA finalized new one-hour NAAQS for SO2 and NO2. Monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO2 NAAQS also requires the EPA to evaluate modeling data to determine attainment. The MPCA intends to complete this initial modeling effort by the end of the first quarter of 2012, using facility data from sources that emit more than 100 tons per year of SO2. Minnesota Power provided such data for all of our steam generating facilities. It is unclear what the outcome of this evaluation will be.
These NAAQS modeling efforts could result in more stringent emission limits on our coal-fired generating facilities, and possibly additional control measures on some of our units. The MPCA has informed affected sources that compliance strategies required as a result of these modeling results must be agreed to with the MPCA by February 2013. One-hour SO2 NAAQS attainment is required by 2017.
We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.
Climate Change. The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. These physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and the intensity and frequency of extreme weather events. These all have the potential to affect the Company's business and operations. Minnesota Power is addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers' requirements:
Expand our renewable energy supply;
Improve the efficiency of our coal-based generation facilities, as well as other process efficiencies;
Provide energy conservation initiatives for our customers and engage in other demand side efforts; and
Support research of technologies to reduce carbon emissions from generation facilities and support carbon sequestration efforts.
EPA Greenhouse Gas Reporting RuleRegulation of GHG Emissions.. On September 22, 2009, In May 2010, the EPA issued the final rule mandating that certain GHG emission sources, including electric generating units, are required to report emission levels. The rule is intended to allow the EPA to collect accurate and timely data on GHG emissions that can be used to form future policy decisions. The rule was effective January 1, 2010, and all GHG emissions must be reported on an annual basis by March 31 of the following year. Currently, we have the equipment and data tools necessary to report our 2010 emissions to comply with this rule.
Title V Greenhouse Gas Tailoring Rule. On October 27, 2009, the EPA issued the proposed Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring rule. This proposed regulation addresses the six primary greenhouse gases and newRule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds for when permits will be required to address GHG emissions for new facilities, andat existing facilities whichthat undergo major modifications. The rule would require large industrialmodifications and at other facilities including power plants, to obtain construction and operating permits that demonstrate Best Available Control Technologies (BACT) are being used atcharacterized as major sources under the facility to minimize GHG emissions. The EPA is expected to propose BACT standards for GHG emissions from stationary sources.Clean Air Act's Title V program.
For our existing facilities, the proposed rule does not require amending our existing Title V Operating Permits to include GHG requirements. Implementation of the requirement to add GHG provisions to permits will be completed at the state level in Minnesota by the MPCA when the Title V permits are renewed. However, installation of new units or modification of existing units resulting in a significant increase in GHG emissions will require obtaining PSD permits and amending our operating permits to include BACT for GHGs. However, modifying or installing units with GHG emissionsdemonstrate that triggerBest Available Control Technology (BACT) is being used at the PSD permitting requirements could require amending operating permits to incorporate BACTfacility to control GHG emissions. The EPA has defined significant emissions increase for existing sources as a GHG increase of 75,000 tons or more per year of total GHG on a CO2 equivalent basis.
ALLETE 20092011 Form 10-K
89
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| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Environmental Matters (Continued)
In late 2010, the EPA issued guidance to permitting authorities and affected sources to facilitate incorporation of the Tailoring Rule permitting requirements into the Title V and PSD permitting programs. The guidance stated that the project-specific top-down BACT determination process used for other pollutants will also be used to determine BACT for GHG emissions. Through sector-specific white papers, the EPA also provided examples and technical summaries of GHG emission control technologies and techniques the EPA considers available or likely to be available to sources. It is possible these control technologies could be determined to be BACT on a project-by-project basis. In the near term, one option appears to be energy efficiency maximization.
Legal challenges to the EPA's regulation of GHG emissions, including the Tailoring Rule, have been filed by others and are awaiting judicial determination. Comments to the permitting guidance were also submitted by Minnesota Power and others and may be addressed by the EPA in the form of revised guidance documents.
We are unable to predict the compliance costs we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.
Water. The Clean Water Act requires 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. We are in substantial compliance with these permits.
Clean Water Act - Aquatic Organisms. On April 20, 2011, the EPA published in the Federal Register proposed regulations under Section 316(b) of the Clean Water Act that set standards applicable to cooling water intake structures for the protection of aquatic organisms. The proposed regulations would 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 killed when they are pinned against the facility's intake structure or that are drawn into the facility's cooling system. The Section 316(b) standards would be implemented through NPDES permits issued to the covered facilities. The Section 316(b) proposed rule comment period ended in August 2011. The EPA is obligated to finalize the rule by July 27, 2012. Minnesota Power is in the process of evaluating the potential impacts the proposed rule may have on its facilities. We are unable to predict the compliance cost we might incur; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.
EPA Endangerment Findings.Steam Electric Power Generating Effluent Guidelines. On December 15, In late 2009, the EPA published its findingsannounced that it will be reviewing and reissuing the federal effluent guidelines for steam electric stations. These are the underlying federal water discharge rules that apply to all steam electric stations. The EPA has indicated that the emissions of six GHG, including CO2, methane,new rule promulgating these guidelines will be proposed in 2012 and nitrous oxide, endanger human health or welfare. This finding may resultfinalized in regulations that establish motor vehicle GHG emissions standards in 2010. There is also a possibility that the endangerment finding will enable expansion2014. As part of the review phase for this new rule, the EPA regulation underissued an Information Collection Request (ICR) in June 2010, to most thermal electric generating stations in the Clean Air Actcountry, including all five of Minnesota Power's generating stations. The ICR was completed and submitted to include GHGs emitted from stationary sources. A petitionthe EPA in September 2010 for reviewBoswell, Laskin, Taconite Harbor, Hibbard, and Rapids Energy Center. The ICR was designed to gather extensive information on the nature and extent of all water discharge and related wastewater handling at power plants. The information gathered through the ICR will form a basis for development of the EPA’s endangerment findings was filed byeventual new rule, which could include more restrictive requirements on wastewater discharge, flue gas desulfurization, and wet ash handling operations. We are unable to predict the Coalition for Responsible Regulation, et. al.costs we might incur to comply with the United States District Court Circuit Court of Appeals on December 23, 2009.potential future water discharge regulations at this time.
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.
Coal Ash Management Facilities.Facilities. Minnesota Power generates coal ash at all five of its steamcoal-fired electric stations.generating facilities. Two facilities store ash in onsite impoundments (ash ponds) with engineered liners and containment dikes. Another facility stores dry ash in a landfill with an engineered liner and leachate collection system. Two facilities generate a combined wood and coal ash that is either land applied as an approved beneficial use or trucked to state permitted landfills. Minnesota Power continues to monitor state and federal legislative andIn June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory activities that may affect its ash management practices. The USEPA is expected to propose new regulationsschemes for coal ash. Comments on the proposed rule were due in February 2010, pertaining to the management of coal ash by electric utilities.November 2010. It is unknown how potential coal ash managementestimated that the final rule changes will affect Minnesota Power’s facilities. On March 9, 2009,be published in late 2012 or early 2013. We are unable to predict the EPA requested information from Minnesota Power (and other utilities) on its ash storage impoundments at Boswell and Laskin. On June 22, 2009, Minnesota Power received ancompliance cost we might incur; however, the costs could be material. We would seek recovery of any additional EPA information request pertaining to Boswell. Minnesota Power responded to both these information requests. On August 19, 2009, Dam Safety officials from the Minnesota DNR visited both the Boswell and Laskin ash ponds. The purpose of the inspection was to assess the structural integrity of the ash ponds, as well as review operational and maintenance procedures. There were no significant findingscosts through cost recovery riders or concerns from the DNR staff during the inspections.in a general rate case.
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| Note 11. | Commitments, Guarantees and Contingencies (Continued) |
Environmental Matters (Continued)
Manufactured Gas Plant Site.We are reviewing and addressing environmental conditions at a former manufactured gas plant site withinin the City of Superior, Wisconsin, and formerly operated by SWL&P. We have been working with the WDNR to determine the extent of contamination and the remediation of contaminated locations. At As of December 31, 20092011, we have a $0.5$0.5 million liability for this site and a corresponding regulatory asset as we expect recovery of remediation costs to be allowed by the PSCW.
Other Matters
BNI Coal. As of December 31, 2009,2011, BNI Coal had surety bonds outstanding of $18.4$29.8 million related to the reclamation liability for closing costs associated with its mine and mine facilities. Although the coal supply agreements obligate the customers to provide for the closing costs, an additional guaranteeassurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a Letterletter of Creditcredit with CoBANK ACB for an additional $10.0$2.6 million of which $6.7 million is needed to meet the requirementsprovide for BNI’sBNI Coal’s total reclamation liability currently estimated at $25.1 million.$32.4 million. BNI Coal does not believe it is likely that any of these outstanding surety bonds will be drawn upon.
ALLETE Properties.As of December 31, 2009,2011, ALLETE Properties, through its subsidiaries, had surety bonds outstanding of $19.1$10.2 million primarily related to performance and maintenance obligations to governmental entities to construct improvements in the company’sCompany's various projects. The remaining work to be completed on these improvements is estimated to be approximately $10.2$8.0 million and ALLETE Properties does not believe it is likely that any of these outstanding surety bonds will be drawn upon.
Community Development District Obligations. In March 2005, the Town Center District issued $26.4$26.4 million of tax-exempt, 6 percent Capital Improvement Revenue Bonds, Series 2005; capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued $31.8$31.8 million of tax-exempt, 5.7 percent Special Assessment Bonds, Series 2006. special assessment bonds. The Capital Improvement Revenue Bondscapital improvement revenue bonds and the Special Assessment Bondsspecial assessment bonds are payable through property taxover 31 years (by May 1, 2036, and 2037, respectively) and secured by special assessments on the land owners over 31 years (by May 1, 2036, and 2037, respectively).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 bonds are payable from and secured by the revenue derived from assessments imposed, levied and collected by each district. The assessments were billed to the landowners beginning in November 2006, for Town Center, and November 2007, for Palm Coast Park. To the extent that we still own land at the time of the assessment, we will incur the cost of our portion of these assessments, based upon our ownership of benefited property. At December 31, 2009,2011, we owned 6973 percent of the assessable land in the Town Center District (69(69 percent at December 31, 2008)2010) and 8693 percent of the assessable land in the Palm Coast Park District (86(93 percent at December 31, 2008)2010). At these ownership levels, our annual assessments are $1.4$1.5 million for Town Center and $1.9$2.2 million for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. Under current accounting rules, these bonds are not reflected as debt on our consolidated balance sheet.
Legal Proceedings. In January 2011, the Company was named as a defendant in a lawsuit in the Sixth Judicial District for the State of Minnesota by one of our customer’s (United Taconite, LLC) property and business interruption insurers. In October 2006, United Taconite experienced a fire as a result of the failure of certain electrical protective equipment. The equipment at issue in the incident was not owned, designed, or installed by Minnesota Power, but Minnesota Power had provided testing and calibration services related to the equipment. The lawsuit alleges approximately $20 million in damages related to the fire. The Company believes that it has strong defenses to the lawsuit and intends to vigorously assert such defenses. An accrual related to any damages that may result from the lawsuit has not been recorded as of December 31, 2011, because a potential loss is not currently probable; however, the Company believes it has adequate insurance coverage for potential loss.
Other. 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, compliance with regulations, rate base and cost of service issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these matters are expected to materially change our present liquidity position, or have a material adverse effect on our financial condition.
ALLETE 20092011 Form 10-K
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| Note 12. | Common Stock and Earnings Per Share |
|
| | | | | |
| Summary of Common Stock | Shares | Equity |
| | Thousands | Millions |
| Balance as of December 31, 2008 | 32,585 |
|
| $534.1 |
|
| Employee Stock Purchase Program | 24 |
| 0.7 |
|
| Invest Direct | 456 |
| 13.6 |
|
| Options and Stock Awards | 8 |
| 1.1 |
|
| Equity Issuance Program | 1,685 |
| 51.9 |
|
| Contributions to Pension | 463 |
| 12.0 |
|
| Balance as of December 31, 2009 | 35,221 |
|
| $613.4 |
|
| Employee Stock Purchase Program | 19 |
| 0.6 |
|
| Invest Direct | 346 |
| 11.7 |
|
| Options and Stock Awards | 51 |
| 4.4 |
|
| Equity Issuance Program | 180 |
| 6.0 |
|
| Balance as of December 31, 2010 | 35,817 |
|
| $636.1 |
|
| Employee Stock Purchase Program | 20 |
| 0.8 |
|
| Invest Direct | 437 |
| 17.2 |
|
| Options and Stock Awards | 109 |
| 6.7 |
|
| Equity Issuance Program | 400 |
| 16.0 |
|
| Purchase of Non-Controlling Interest | 222 |
| 8.8 |
|
| Contributions to Pension | 508 |
| 20.0 |
|
| Balance as of December 31, 2011 | 37,513 |
|
| $705.6 |
|
| Summary of Common Stock | Shares | Equity |
| | Thousands | Millions |
| Balance as of December 31, 2006 | 30,436 | $438.7 |
| 2007 Employee Stock Purchase Plan | 17 | 0.7 |
| Invest Direct | 331 | 15.1 |
| Options and Stock Awards | 43 | 6.7 |
| Balance as of December 31, 2007 | 30,827 | $461.2 |
| 2008 Employee Stock Purchase Plan | 17 | 0.6 |
| Invest Direct | 161 | 6.9 |
| Options and Stock Awards | 24 | 4.6 |
| Equity Issuance Program | 1,556 | 60.8 |
| Balance as of December 31, 2008 | 32,585 | $534.1 |
| 2009 Employee Stock Purchase Plan | 24 | 0.7 |
| Invest Direct | 456 | 13.6 |
| Options and Stock Awards | 8 | 1.1 |
| Equity Issuance Program | 1,685 | 51.9 |
| Contributions to Pension | 463 | 12.0 |
| Balance as of December 31, 2009 | 35,221 | $613.4 |
Equity Issuance Program. We entered into a Distribution Agreementdistribution agreement with KCCI, Inc., originating in February 2008, and subsequentlyas amended, in February 2009, with respect to the issuance and sale of up to an aggregate of 6.6 million shares of our common stock, without par value. For the year ended December 31, 2011, 0.4 million shares of common stock were issued under this agreement resulting in net proceeds of $16.0 million. During 2010, 0.2 million shares of common stock were issued for net proceeds of $6.0 million. As of December 31, 2011, approximately 2.7 million shares of common stock remain available for issuance pursuant to the amended distribution agreement. The shares issued in 2011 and 2010 were offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement Nos. 333-170289 and 333-147965. The remaining shares may be offered for sale, from time to time, in accordance with the terms of the amended distribution agreement pursuant to Registration Statement No. 333-147965. During 2009, 1.7 million shares of common stock were issued under this agreement resulting in net proceeds of $51.9 million. In 2008, 1.6 million shares were issued for net proceeds of $60.8 million. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.)333-170289.
Contributions to Pension. In March 2009, we contributed 0.5 shares of ALLETE common stock, with an aggregate value of $12.0 million, to our pension plan. On May 19, 2009, we registered the 0.5 shares of ALLETE common stock with the SEC pursuant to Registration Statement No. 333-147965. (See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.)
Authorized Common Stock. On May 12, 2009, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 43.3 million to 80.0 million.
Shareholder Rights Plan. On July 25, 1996, ALLETE adopted a shareholder rights plan, which was amended and restated on July 12, 2006 (collectively, the “Rights Plan”). The amendment to the Rights Plan, among other things, extended the final expiration date of the Rights Plan to July 11, 2009. The Rights Plan expired according to its terms on July 11, 2009. As a result, ALLETE’s preferred share purchase rights issued in accordance with the Rights Plan are no longer outstanding.
Earnings Per Share. The difference between basic and diluted earnings per share, arises, if any, arises from outstanding stock options, non-vested restricted stock, and performance share awards granted under our Executive Long-Term Incentive Compensation Plan and Director Long-Term Incentive Compensation Plans.Plan. In2011, in accordance with accounting standards for earnings per share, for 2009, 0.60.3 million options to purchase shares of common stock were excluded from the computation of diluted earnings per share because the option exercise prices were greater than the average market prices, and therefore, their effect would be anti-dilutive (0.6(0.5 million shares were excluded for 20082010 and 0.6 million in 2009).
Purchase of Non-Controlling Interest. In the third quarter of 2011, the remaining shares of the ALLETE Properties non-controlling interest were purchased at book value for $8.8 million by issuing 0.2 million unregistered shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss is recognized in 2007).net income or comprehensive income.
Contributions to Pension. On December 15, 2011, ALLETE contributed approximately 507,600 shares of ALLETE common stock to its pension plan. These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(2) of the Securities Act of 1933 and had an aggregate value of $20.0 million when contributed. (See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.)
ALLETE 20092011 Form 10-K
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| |
| Note 12. | 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 | | | |
| | | | |
| 2009 | | | |
| Net Income Attributable to ALLETE | $61.0 | – | $61.0 |
| Common Shares | 32.2 | – | 32.2 |
| Per Share of Common Stock | $1.89 | – | $1.89 |
| | | | |
| 2008 | | | |
| Net Income Attributable to ALLETE | $82.5 | – | $82.5 |
| Common Shares | 29.2 | 0.1 | 29.3 |
| Per Share of Common Stock | $2.82 | – | $2.82 |
| | | | |
| 2007 | | | |
| Net Income Attributable to ALLETE | $87.6 | – | $87.6 |
| Common Shares | 28.3 | 0.1 | 28.4 |
| Per Share of Common Stock | $3.09 | – | $3.08 |
|
| | | | | | | | |
| Reconciliation of Basic and Diluted | | | |
| Earnings Per Share | | Dilutive |
| |
| Year Ended December 31 | Basic | Securities |
| Diluted |
| Millions Except Per Share Amounts | | | |
| 2011 | | | |
| Net Income Attributable to ALLETE |
| $93.8 |
|
|
|
| $93.8 |
|
| Common Shares | 35.3 |
| 0.1 |
| 35.4 |
|
| Per Share of Common Stock |
| $2.66 |
|
|
|
| $2.65 |
|
| 2010 | | | |
| Net Income Attributable to ALLETE |
| $75.3 |
|
|
|
| $75.3 |
|
| Common Shares | 34.2 |
| 0.1 |
| 34.3 |
|
| Per Share of Common Stock |
| $2.20 |
|
|
|
| $2.19 |
|
| 2009 | | | |
| Net Income Attributable to ALLETE |
| $61.0 |
|
|
|
| $61.0 |
|
| Common Shares | 32.2 |
| — |
| 32.2 |
|
| Per Share of Common Stock |
| $1.89 |
|
|
|
| $1.89 |
|
| |
| Note 13. | Other Income (Expense) |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Loss on Emerging Technology Investments | $(4.6) | $(0.7) | $(1.3) |
| AFUDC - Equity | 5.8 | 3.3 | 3.8 |
Investments and Other Income (a) | 0.6 | 13.0 | 13.0 |
| Total Other Income | $1.8 | $15.6 | $15.5 |
(a) | In 2008, Investment and Other Income included a gain from the sale of certain available-for-sale securities. The gain was triggered when securities were sold to reallocate investments to meet defined investment allocations based upon an approved investment strategy. In 2007, Investment and Other Income primarily included earnings on excess cash and Minnesota land sales. |
|
| | | | | | | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| AFUDC - Equity |
| $2.5 |
|
| $4.2 |
|
| $5.8 |
|
| Investment and Other Income (Expense) | 1.9 |
| 0.4 |
| (4.0 | ) |
| Total Other Income |
| $4.4 |
|
| $4.6 |
|
| $1.8 |
|
Note 14. Income Tax Expense
| |
| Note 14. | Income Tax Expense |
| Income Tax Expense | | | |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Current Tax Expense (Benefit) | | | |
Federal (a) | $(42.6) | $6.2 | $26.5 |
| State | (1.8) | (1.6) | 7.2 |
| Total Current Tax Expense (Benefit) | (44.4) | 4.6 | 33.7 |
| Deferred Tax Expense | | | |
| Federal | 66.0 | 29.3 | 10.7 |
| State | 10.3 | 13.4 | 4.7 |
| Change in Valuation Allowance | (0.1) | (2.9) | (0.3) |
| Investment Tax Credit Amortization | (1.0) | (1.0) | (1.1) |
| Total Deferred Tax Expense | 75.2 | 38.8 | 14.0 |
| Total Income Tax Expense | $30.8 | $43.4 | $47.7 |
|
| | | | | | | | | |
| Income Tax Expense | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Current Tax Expense (Benefit) | | | |
Federal (a) |
| $1.4 |
| $(23.0) | $(42.6) |
State (a) | (1.6 | ) | 1.3 |
| (1.8 | ) |
| Total Current Tax Expense (Benefit) | (0.2 | ) | (21.7 | ) | (44.4 | ) |
| Deferred Tax Expense | | | |
Federal (b) | 27.3 |
| 61.4 |
| 66.0 |
|
State (b) | 9.5 |
| 5.3 |
| 10.3 |
|
| Change in Valuation Allowance | (0.1 | ) | 0.2 |
| (0.1 | ) |
| Investment Tax Credit Amortization | (0.9 | ) | (0.9 | ) | (1.0 | ) |
| Total Deferred Tax Expense | 35.8 |
| 66.0 |
| 75.2 |
|
| Total Income Tax Expense |
| $35.6 |
|
| $44.3 |
|
| $30.8 |
|
| |
| (a) | DueFor the year ended December 31, 2011, the federal and state current tax expense (benefit) of $1.4 million and $(1.6) million, respectively, was due to an NOL which resulted primarily from the bonus depreciation provision of the Tax Relief Unemployment Insurance Reauthorization and Job Creation Act of 2010. The 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, we recorded a federal current tax benefit as a result of tax planning initiatives and the bonus depreciation provision in the Small Business Jobs Act of 2010. The 2010 federal NOL was partially utilized by carrying it back against prior years' income with the remainder carried forward to offset future years' income. The 2009 federal current tax benefit was primarily due to the bonus depreciation provisions inprovision of the American Recovery and Reinvestment Act of 2009, we are2009. |
| |
| (b) | The year ended December 31, 2011, included an income tax benefit of $2.9 million related to the MPUC approval of our request to defer the retail portion of the tax charge taken in 2010 as a net operating loss positionresult of PPACA and a benefit for 2009. The loss will be utilized by carrying it back against prior years’ taxable income.the reversal of a $6.2 million deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. Included in the year ended December 31, 2010, was a charge of $4.0 million as a result of PPACA. (See Note 5. Regulatory Matters.) |
|
| | | | | | | | | |
| Reconciliation of Taxes from Federal Statutory | | | |
| Rate to Total Income Tax Expense | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Income Before Non-Controlling Interest and Income Taxes |
| $129.2 |
|
| $119.1 |
|
| $91.5 |
|
| Statutory Federal Income Tax Rate | 35 | % | 35 | % | 35 | % |
| Income Taxes Computed at 35 percent Statutory Federal Rate |
| $45.2 |
|
| $41.7 |
|
| $32.0 |
|
| Increase (Decrease) in Tax Due to: | | | |
| State Income Taxes – Net of Federal Income Tax Benefit | 6.0 |
| 4.5 |
| 5.4 |
|
| Impact of PPACA | — |
| 4.0 |
| — |
|
| Deferred Accounting for Retail Portion of PPACA | (2.9 | ) | — |
| — |
|
| 2010 Rate Case Stipulation Agreement - Deferred Tax Reversal | (6.2 | ) | — |
| — |
|
| Regulatory Differences for Utility Plant | (1.2 | ) | (2.0 | ) | (2.5 | ) |
| Production Tax Credits | (4.3 | ) | (1.6 | ) | (1.2 | ) |
| Other | (1.0 | ) | (2.3 | ) | (2.9 | ) |
| Total Income Tax Expense |
| $35.6 |
|
| $44.3 |
|
| $30.8 |
|
ALLETE 20092011 Form 10-K
94
| |
| Note 14. | Income Tax Expense (Continued) |
| Reconciliation of Taxes from Federal Statutory | | | |
| Rate to Total Income Tax Expense | | | |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Income Before Non-Controlling Interest and Income Taxes | $91.5 | $126.4 | $137.2 |
| Statutory Federal Income Tax Rate | 35% | 35% | 35% |
| Income Taxes Computed at 35 percent Statutory Federal Rate | $32.0 | $44.2 | $48.0 |
| Increase (Decrease) in Tax Due to: | | | |
| Amortization of Deferred Investment Tax Credits | (1.0) | (1.0) | (1.1) |
| State Income Taxes – Net of Federal Income Tax Benefit | 5.4 | 4.8 | 7.4 |
| Depletion | (0.9) | (0.8) | (0.9) |
| Regulatory Differences for Utility Plant | (2.5) | (1.6) | (2.2) |
| Production Tax Credit | (1.2) | (0.4) | – |
| Positive Resolution of Audit Issues | – | – | (1.6) |
| Other | (1.0) | (1.8) | (1.9) |
| Total Income Tax Expense | $30.8 | $43.4 | $47.7 |
The effective tax rate on income from continuing operations before non-controlling interest was 27.6 percent for 2011 (37.2 percent for 2010; 33.7 percent for 2009; (34.3 percent for 2008; 34.8 percent for 2007)2009). The 20092011 effective tax rate was primarily impacted by deductions for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above), investmentrenewable tax credits, wind productionthe MPUC's approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of PPACA, and the reversal of a deferred tax liability related to a revenue receivable that Minnesota Power agreed to forgo as part of a stipulation and settlement agreement in its 2010 rate case. The 2010 effective tax rate was primarily impacted by deductions for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above), renewable tax credits and depletion.the impact of PPACA eliminating the tax deduction for expenses that are reimbursed under Medicare Part D. The 20082009 effective tax rate was impacted by deductions for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above), investment tax credits, and wind production tax credits, depletion, recognition of a benefit on the reversal of a previously uncertain tax position ($1.7 million included in Other, above) and a benefit for the reversal of a state income tax valuation allowance ($2.9 million included in State Income Taxes, above).credits.
| Deferred Tax Assets and Liabilities | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Deferred Tax Assets | | |
Employee Benefits and Compensation (a) | $118.2 | $125.2 |
| Property Related | 46.5 | 36.4 |
| Investment Tax Credits | 10.0 | 10.7 |
| Other | 14.4 | 16.3 |
| Gross Deferred Tax Assets | 189.1 | 188.6 |
| Deferred Tax Asset Valuation Allowance | (0.3) | (0.4) |
| Total Deferred Tax Assets | $188.8 | $188.2 |
| Deferred Tax Liabilities | | |
| Property Related | $294.1 | $235.6 |
| Regulatory Asset for Benefit Obligations | 96.5 | 87.7 |
| Unamortized Investment Tax Credits | 14.1 | 15.1 |
| Partnership Basis Differences | 14.6 | 3.7 |
| Other | 28.2 | 16.8 |
| Total Deferred Tax Liabilities | $447.5 | $358.9 |
| Net Deferred Income Taxes | $258.7 | $170.7 |
| | | |
| Recorded as: | | |
Net Current Deferred Tax Liabilities (b) | $5.6 | $1.1 |
| Net Long-Term Deferred Tax Liabilities | 253.1 | 169.6 |
| Net Deferred Income Taxes | $258.7 | $170.7 |
|
| | | | | | |
| Deferred Tax Assets and Liabilities | | |
| As of December 31 | 2011 | 2010 |
| Millions | | |
| Deferred Tax Assets | | |
| Employee Benefits and Compensation |
| $132.7 |
|
| $121.8 |
|
| Property Related | 56.4 |
| 51.1 |
|
| NOL and Tax Credit Carryforward | 78.1 |
| 28.2 |
|
| Investment Tax Credits | 9.0 |
| 9.7 |
|
| Other | 7.2 |
| 12.7 |
|
| Gross Deferred Tax Assets | 283.4 |
| 223.5 |
|
| Deferred Tax Asset Valuation Allowance | (0.4 | ) | (0.5 | ) |
| Total Deferred Tax Assets |
| $283.0 |
|
| $223.0 |
|
| Deferred Tax Liabilities | | |
| Property Related |
| $482.7 |
|
| $387.2 |
|
| Regulatory Asset for Benefit Obligations | 117.9 |
| 105.8 |
|
| Unamortized Investment Tax Credits | 12.8 |
| 13.7 |
|
| Partnership Basis Differences | 24.4 |
| 19.4 |
|
| Other | 24.0 |
| 27.3 |
|
| Total Deferred Tax Liabilities |
| $661.8 |
|
| $553.4 |
|
| Net Deferred Income Taxes |
| $378.8 |
|
| $330.4 |
|
| Recorded as: | | |
Net Current Deferred Tax Liabilities (a) |
| $5.2 |
|
| $5.2 |
|
| Net Long-Term Deferred Tax Liabilities | 373.6 |
| 325.2 |
|
| Net Deferred Income Taxes |
| $378.8 |
|
| $330.4 |
|
(a) | Includes Unfunded Employee Benefits |
(b)(a) | Included in Other Current Liabilities. |
|
| | | | | | |
| NOL and Tax Credit Carryforwards | | |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
Federal NOL carryforward (a) |
| $162.0 |
|
| $62.0 |
|
| Federal tax credit carryforwards | 8.4 |
| 3.7 |
|
State NOL carryforwards (a, b) | 73.1 |
| 71.7 |
|
| State tax credit carryforwards, net of federal offset | 3.8 |
| 1.7 |
|
| |
| (b) | State NOL carryforwards include Minnesota, North Dakota and Florida. |
In 2011, we had agenerated federal net operating loss of $85.7 millionand various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provisions inof the American RecoveryTax Relief, Unemployment Insurance Reauthorization and ReinvestmentJob Creation Act of 2009. In 2010, this2010. The 2011 federal net operating lossNOL will be fully utilized by carrying it back against prior years’ taxable income. We also have various state net operating loss carryforwards totaling $23.8 million availableforward to reduceoffset future taxableyears' income. We expect to fully utilize the federal NOL and tax benefit of these losses priorcredit carryforwards; therefore a deferred tax asset has been recorded to their expirations in 2024 through 2029.recognize the resulting tax benefit.
ALLETE 20092011 Form 10-K
95
| |
| Note 14. | Income Tax Expense (Continued) |
| Gross Unrecognized Income Tax Benefits | 2009 | 2008 | 2007 |
| Millions | | | |
| Balance at January 1 | $8.0 | $5.3 | $10.4 |
| Additions for Tax Positions Related to the Current Year | 0.5 | 0.7 | 0.8 |
| Reductions for Tax Positions Related to the Current Year | – | – | – |
| Additions for Tax Positions Related to Prior Years | 1.0 | 4.5 | – |
| Reduction for Tax Positions Related to Prior Years | – | (2.5) | (2.4) |
| Settlements | – | – | (3.5) |
| Balance as of December 31 | $9.5 | $8.0 | $5.3 |
The state NOLs and tax credits will be carried forward to future tax years. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration.
The federal NOL and tax credit carryforward periods expire between 2019 and 2031; included in the federal NOL carryforward is $3.0 million of charitable contributions carryforward which expire between 2014 and 2015. The state NOL and tax credit carryforward periods expire between 2024 and 2031; included in the state NOL carryforwards is $2.8 million of charitable contributions carryforward which expires between 2014 and 2015.
|
| | | | | | | | | |
| Gross Unrecognized Income Tax Benefits | 2011 | 2010 | 2009 |
| Millions | | | |
| Balance at January 1 |
| $12.3 |
|
| $9.5 |
|
| $8.0 |
|
| Additions for Tax Positions Related to the Current Year | — |
| — |
| 0.5 |
|
| Reductions for Tax Positions Related to the Current Year | — |
| (0.2 | ) | — |
|
| Additions for Tax Positions Related to Prior Years | — |
| 4.4 |
| 1.0 |
|
| Reductions for Tax Positions Related to Prior Years | (0.9 | ) | — |
| — |
|
| Settlements | — |
| (0.3 | ) | — |
|
| Lapse of Statute | — |
| (1.1 | ) | — |
|
| Balance as of December 31 |
| $11.4 |
|
| $12.3 |
|
| $9.5 |
|
The gross amount of unrecognized tax benefits as of December 31, 2009,2011, includes $1.5$0.6 million of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate.
As of December 31, 2009,2011, we had $0.9$1.1 million ($0.6 ($0.7 million for 2008)2010 and $0.9 million for 2009) of accrued interest related to unrecognized tax benefits included in the consolidated balance sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in the consolidated statement of income. In 2009,2011, we recognized $0.4 million of interest expense ($of $0.4 million (interest reduction of $0.2 million for 20082010 and $0.1interest expense of $0.4 million for 2007)2009). There were no penalties recognized for 2009, 20082011, 2010 or 2007.2009.
We file a consolidated federal income tax return in the United StatesU.S. and state income tax returns in various state jurisdictions. ALLETE is currently under examination by the IRS for the tax years 2005 through 2009. ALLETE is no longer subject to federal or state examination for years before 2005 or state examinations for years before 2004.2005.
During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by $3.6$5.0 million due to statute expirations and anticipated audit settlements. This amount is primarily due to timing issues.
| |
| Note 15. | Other Comprehensive Income (Loss) |
|
| | | | | | | | | |
| Comprehensive Income (Loss) | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Net Income |
| $93.6 |
|
| $74.8 |
|
| $60.7 |
|
| Other Comprehensive Income | | | |
Unrealized Gain (Loss) on Securities Net of income taxes of $(0.1), $0.6, and $1.7 | (0.3 | ) | 0.8 |
| 2.8 |
|
Unrealized Loss on Derivatives Net of income taxes of $(0.2), $-, and $- | (0.3 | ) | — |
| — |
|
Defined Benefit Pension and Other Postretirement Plans Net of income taxes of $(3.6), $-, and $4.1 | (5.1 | ) | — |
| 6.2 |
|
| Total Other Comprehensive Income (Loss) | (5.7 | ) | 0.8 |
| 9.0 |
|
| Total Comprehensive Income |
| $87.9 |
|
| $75.6 |
|
| $69.7 |
|
| Less: Non-Controlling Interest in Subsidiaries | (0.2 | ) | (0.5 | ) | (0.3 | ) |
| Comprehensive Income Attributable to ALLETE |
| $88.1 |
|
| $76.1 |
|
| $70.0 |
|
| |
| Note 15. | Comprehensive Income (Loss) (Continued) |
| Other Comprehensive Income (Loss) | | | |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Net Income | $60.7 | $83.0 | $89.5 |
| Other Comprehensive Income | | | |
Unrealized Gain on Securities Net of income taxes of $1.7, $(3.7), and $0.3 | 2.8 | (6.0) | 1.1 |
Reclassification Adjustment for Losses Included in Income Net of income taxes of $–, $(2.7), and $– | – | (3.7) | – |
Defined Benefit Pension and Other Postretirement Plans Net of income taxes of $4.1, $(13.3), and $2.3 | 6.2 | (18.8) | 3.2 |
| Total Other Comprehensive Income (Loss) | 9.0 | (28.5) | 4.3 |
| Total Comprehensive Income | $69.7 | $54.5 | $93.8 |
| Less: Non-Controlling Interest in Subsidiaries | (0.3) | 0.5 | 1.9 |
| Comprehensive Income Attributable to ALLETE | $70.0 | $54.0 | $91.9 |
|
| | | | |
| Accumulated Other Comprehensive Income (Loss) | | |
| As of December 31 | 2011 | 2010 |
| Millions | | |
| Unrealized Loss on Securities | $(1.3) | $(1.0) |
| Unrealized Loss on Derivatives | (0.3 | ) | — |
|
| Defined Benefit Pension and Other Postretirement Plans | (27.3 | ) | (22.2 | ) |
| Total Accumulated Other Comprehensive Loss | $(28.9) | $(23.2) |
| Accumulated Other Comprehensive Income (Loss) | | |
| As of December 31 | 2009 | 2008 |
| Millions | | |
| Unrealized Gain (Loss) on Securities | $(1.8) | $(4.6) |
| Defined Benefit Pension and Other Postretirement Plans | (22.2) | (28.4) |
| Total Accumulated Other Comprehensive Loss | $(24.0) | $(33.0) |
Note 16. Pension and Other Postretirement Benefit Plans
| |
| Note 16. | Pension and Other Postretirement Benefit Plans |
We have noncontributory union and non-union defined benefit pension plans covering eligible employees. The plans provide defined benefits based on years of service and final average pay. In 2009,2011, we made a total contributions of $32.9$33.8 million ($10.9 million in 2008) in contributions to ALLETE’s defined benefit pension plans, of which $12.0$20.0 million was contributed in shares of ALLETE common stock.stock (total contributions of $26.5 million in 2010). We also have a defined contribution pension plansplan covering substantially all employees. The 20092011 plan year employer contributions, which are made through ourthe employee stock ownership plan portion of the RSOP, totaled $9.1$7.3 million ($7.1 ($7.2 million for the 20082010 plan year.) (See Note 12. Common Stock and Earnings Per Share and Note 17. Employee Stock and Incentive Plans)
Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
.
In 2006, amendments were made to the non-union defined benefit pension plan and the Retirement Savings and stock Ownership Plan (RSOP). The non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and closedto close the plan to new participants. In conjunction with the change,those amendments, contributions were increased to the RSOP. In 2010, the Minnesota Power union defined benefit pension plan was amended to close the plan to new participants beginning February 1, 2011.
We have postretirement health care and life insurance plans covering eligible employees. In 2010, our postretirement health plan was amended to close the plan to employees hired after January 31, 2011. The full eligibility requirement was also amended in 2010, to age 55 with 10 years of participation in the plan. The postretirement health 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 an irrevocable grantor trusts.trust. In 20092011, $10.9 million was contributed to the VEBAs. In 2010, we contributed $12.8 million to the VEBAs. There were no contributions made a net contribution of $0.3 million to the grantor trust in 2011and $9.3 million to the VEBAs. In 2008 $3.7 million was contributed to the VEBAs.2010.
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. Estimated defined benefit pension and postretirement health and life contributions for years 2010 through 20142012 are expected to be up to $25$1.0 million per year, and$13.9 million, respectively. Contributions are based on estimates and assumptions thatwhich are subject to change. Funding for the other postretirement benefit plans is impacted by utility regulatory requirements. Estimated postretirement health and life contributions for years 2010 through 2014 are approximately $11 million per year, and are based on estimates and assumptions that are subject to change.
Accounting for Defined Benefit Pensiondefined benefit pension and Postretirement Benefit Planspostretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their consolidated 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 that are not recognized as components of net periodic benefit cost.
The defined benefit pension and postretirement health and life benefit costs recognized annually by our regulated companies are expected to be recovered 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 on our consolidated balance sheet, in accordance with the accounting requirementsstandards for Regulated Operations. The defined benefit pension and postretirement health and life benefit costs associated with our other non-rate base operations are recognized in accumulated other comprehensive income.
During the year ended December 31, 2008, we were required to change our measurement date from September 30 to December 31. On January 1, 2008, ALLETE recorded three months of pension expense as a reduction to retained earnings in the amount of $1.6 million, net of tax, to reflect the impact of this measurement date change. Also on January 1, 2008, we recorded $0.8 million relating to three months of amortization for transition obligations, prior service costs, and prior gains and losses within accumulated other comprehensive income.2011 Form 10-K
97
| Pension Obligation and Funded Status |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Accumulated Benefit Obligation | $435.9 | $406.6 |
| | | |
| Change in Benefit Obligation | | |
| Obligation, Beginning of Year | $440.4 | $421.9 |
| Service Cost | 5.7 | 7.3 |
| Interest Cost | 26.2 | 31.8 |
| Actuarial Loss (Gain) | 14.6 | 3.2 |
| Benefits Paid | (25.5) | (29.9) |
| Participant Contributions | 3.9 | 6.1 |
| Obligation, End of Year | $465.3 | $440.4 |
| Change in Plan Assets | | |
| Fair Value, Beginning of Year | $273.7 | $405.6 |
| Actual Return on Plan Assets | 41.6 | (120.2) |
| Employer Contribution | 37.8 | 18.2 |
| Benefits Paid | (25.5) | (29.9) |
| Fair Value, End of Year | $327.6 | $273.7 |
| Funded Status, End of Year | $(137.7) | $(166.7) |
| | | |
| Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of: | | |
| Current Liabilities | $(0.9) | $(0.9) |
| Noncurrent Liabilities | $(136.8) | $(165.8) |
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
|
| | | | | | |
| Pension Obligation and Funded Status |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Accumulated Benefit Obligation |
| $550.6 |
|
| $485.6 |
|
| Change in Benefit Obligation | |
| |
|
| Obligation, Beginning of Year |
| $525.6 |
|
| $465.2 |
|
| Service Cost | 7.6 |
| 6.2 |
|
| Interest Cost | 27.4 |
| 26.2 |
|
| Actuarial Loss | 54.6 |
| 47.1 |
|
| Benefits Paid | (28.6 | ) | (27.2 | ) |
| Participant Contributions | 10.9 |
| 8.1 |
|
| Obligation, End of Year |
| $597.5 |
|
| $525.6 |
|
| Change in Plan Assets | |
| |
|
| Fair Value, Beginning of Year |
| $382.0 |
|
| $327.6 |
|
| Actual Return on Plan Assets | 33.1 |
| 45.6 |
|
| Employer Contribution | 45.8 |
| 36.0 |
|
| Benefits Paid | (28.5 | ) | (27.2 | ) |
| Fair Value, End of Year |
| $432.4 |
|
| $382.0 |
|
| Funded Status, End of Year | $(165.1) | $(143.6) |
| | | |
| Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of: | |
| |
|
| Current Liabilities | $(1.1) | $(0.8) |
| Non-Current Liabilities | $(164.0) | $(142.8) |
The pension costs that are reported as a component within our consolidated balance sheet, reflected in long-term regulatory long-term assets and accumulated other comprehensive income, consist of the following:
| Unrecognized Pension Costs |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Net Loss | $196.5 | $193.2 |
| Prior Service Cost | 1.8 | 2.4 |
| Transition Obligation | – | – |
| Total Unrecognized Pension Costs | $198.3 | $195.6 |
|
| | | | | | |
| Unrecognized Pension Costs |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Net Loss |
| $269.0 |
|
| $225.1 |
|
| Prior Service Cost | 1.1 |
| 1.4 |
|
| Total Unrecognized Pension Costs |
| $270.1 |
|
| $226.5 |
|
|
| | | | | | | | | |
| Components of Net Periodic Pension Expense |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Service Cost |
| $7.6 |
|
| $6.2 |
|
| $5.7 |
|
| Interest Cost | 27.4 |
| 26.2 |
| 26.2 |
|
| Expected Return on Plan Assets | (34.6 | ) | (33.7 | ) | (33.8 | ) |
| Amortization of Loss | 12.1 |
| 6.6 |
| 3.4 |
|
| Amortization of Prior Service Costs | 0.3 |
| 0.5 |
| 0.6 |
|
| Net Pension Expense |
| $12.8 |
|
| $5.8 |
|
| $2.1 |
|
| Components of Net Periodic Pension Expense |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Service Cost | $5.7 | $5.8 | $5.3 |
| Interest Cost | 26.2 | 25.4 | 23.4 |
| Expected Return on Plan Assets | (33.8) | (32.5) | (30.6) |
| Amortization of Loss | 3.4 | 1.6 | 4.9 |
| Amortization of Prior Service Costs | 0.6 | 0.6 | 0.6 |
| Net Pension Expense | $2.1 | $0.9 | $3.6 |
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Net Loss (Gain) | $6.8 | $164.0 |
| Amortization of Prior Service Costs | (0.6) | (0.6) |
| Amortization of Loss (Gain) | (3.4) | (1.6) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets | $2.8 | $161.8 |
| Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Projected Benefit Obligation | $465.3 | $440.4 |
| Accumulated Benefit Obligation | $435.9 | $406.6 |
| Fair Value of Plan Assets | $327.6 | $273.7 |
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
| Postretirement Health and Life Obligation and Funded Status |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Change in Benefit Obligation | | |
| Obligation, Beginning of Year | $166.9 | $153.7 |
| Service Cost | 4.1 | 5.0 |
| Interest Cost | 10.0 | 11.7 |
| Actuarial Loss | 18.4 | 4.0 |
| Participant Contributions | 1.7 | 2.0 |
| Plan Amendments | (1.3) | – |
| Benefits Paid | (7.7) | (9.5) |
| Obligation, End of Year | $192.1 | $166.9 |
| Change in Plan Assets | | |
| Fair Value, Beginning of Year | $78.6 | $90.9 |
| Actual Return on Plan Assets | 13.9 | (25.2) |
| Employer Contribution | 9.9 | 20.3 |
| Participant Contributions | 1.6 | 1.9 |
| Benefits Paid | (7.6) | (9.3) |
| Fair Value, End of Year | $96.4 | $78.6 |
| Funded Status, End of Year | $(95.7) | $(88.3) |
| | | |
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of: | | |
| Current Liabilities | $(0.8) | $(0.7) |
| Noncurrent Liabilities | $(94.8) | $(87.6) |
|
| | | | | | |
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Net Loss |
| $56.1 |
|
| $35.2 |
|
| Amortization of Prior Service Cost | (0.3 | ) | (0.5 | ) |
| Amortization of Gain | (12.2 | ) | (6.6 | ) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets |
| $43.6 |
|
| $28.1 |
|
|
| | | | | | |
| Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Projected Benefit Obligation |
| $597.5 |
|
| $525.6 |
|
| Accumulated Benefit Obligation |
| $550.6 |
|
| $485.6 |
|
| Fair Value of Plan Assets |
| $432.4 |
|
| $382.0 |
|
|
| | | | | | |
| Postretirement Health and Life Obligation and Funded Status |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Change in Benefit Obligation | | |
| Obligation, Beginning of Year |
| $204.1 |
|
| $192.1 |
|
| Service Cost | 3.8 |
| 4.8 |
|
| Interest Cost | 10.8 |
| 10.9 |
|
| Actuarial Loss (Gain) | (2.9 | ) | 17.6 |
|
| Participant Contributions | 2.5 |
| 2.1 |
|
| Plan Amendments | — |
| (14.2 | ) |
| Benefits Paid | (7.7 | ) | (9.2 | ) |
| Obligation, End of Year |
| $210.6 |
|
| $204.1 |
|
| Change in Plan Assets | | |
| Fair Value, Beginning of Year |
| $114.7 |
|
| $96.4 |
|
| Actual Return on Plan Assets | — |
| 12.0 |
|
| Employer Contribution | 11.4 |
| 13.4 |
|
| Participant Contributions | 2.5 |
| 2.0 |
|
| Benefits Paid | (7.6 | ) | (9.1 | ) |
| Fair Value, End of Year |
| $121.0 |
|
| $114.7 |
|
| Funded Status, End of Year | $(89.6) | $(89.4) |
| | | |
| Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of: | | |
| Current Liabilities | $(0.9) | $(0.8) |
| Non-Current Liabilities | $(88.7) | $(88.6) |
According to the accounting guidancestandards for Retirement Benefitsretirement benefits, only assets in the VEBAs are treated as plan assets in the above table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had $18.2$20.3 million in irrevocable grantor trusts is included in Other Investments on our consolidated balance sheet at December 31, 2009 ($14.12011 ($19.8 million at December 31, 2008)2010).
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
The postretirement health and life costs that are reported as a component within our consolidated balance sheet, reflected in regulatory long-term assets and accumulated other comprehensive income, consist of the following:
| Unrecognized Postretirement Health and Life Costs |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Net Loss | $69.6 | $59.2 |
| Prior Service Cost | (1.3) | – |
| Transition Obligation | 6.9 | 9.4 |
| Total Unrecognized Postretirement Health and Life Costs | $75.2 | $68.6 |
|
| | | | | | |
| Unrecognized Postretirement Health and Life Costs |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Net Loss |
| $78.5 |
|
| $80.1 |
|
| Prior Service Cost | (9.5 | ) | (11.2 | ) |
| Transition Obligation | 0.1 |
| 0.2 |
|
| Total Unrecognized Postretirement Health and Life Costs |
| $69.1 |
|
| $69.1 |
|
|
| | | | | | | | | |
| Components of Net Periodic Postretirement Health and Life Expense |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Service Cost |
| $3.8 |
|
| $4.8 |
|
| $4.1 |
|
| Interest Cost | 10.8 |
| 10.9 |
| 10.0 |
|
| Expected Return on Plan Assets | (9.7 | ) | (9.5 | ) | (8.3 | ) |
| Amortization of Prior Service Cost | (1.7 | ) | (0.1 | ) | — |
|
| Amortization of Loss | 8.5 |
| 4.8 |
| 2.5 |
|
| Amortization of Transition Obligation | 0.1 |
| 2.5 |
| 2.5 |
|
| Net Postretirement Health and Life Expense |
| $11.8 |
|
| $13.4 |
|
| $10.8 |
|
|
| | | | | | |
Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets |
| Year Ended December 31 | 2011 | 2010 |
| Millions | | |
| Net Loss |
| $6.9 |
|
| $15.3 |
|
| Prior Service Cost (Credit) Arising During the Period | — |
| (14.2 | ) |
| Amortization of Prior Service Cost | 1.7 |
| 0.1 |
|
| Amortization of Transition Obligation | (0.1 | ) | (2.5 | ) |
| Amortization of Loss | (8.5 | ) | (4.8 | ) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets | — |
| $(6.1) |
|
| | | | | | |
| Estimated Future Benefit Payments |
| | | Postretirement |
| | Pension | Health and Life |
| Millions | | |
| 2012 |
| $29.2 |
|
| $8.3 |
|
| 2013 |
| $30.0 |
|
| $9.2 |
|
| 2014 |
| $31.2 |
|
| $10.2 |
|
| 2015 |
| $32.3 |
|
| $11.2 |
|
| 2016 |
| $33.4 |
|
| $11.9 |
|
| Years 2017 – 2021 |
| $181.4 |
|
| $66.6 |
|
| Components of Net Periodic Postretirement Health and Life Expense |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| Service Cost | $4.1 | $4.0 | $4.2 |
| Interest Cost | 10.0 | 9.4 | 7.8 |
| Expected Return on Plan Assets | (8.3) | (7.2) | (6.5) |
| Amortization of Loss | 2.5 | 1.4 | 1.0 |
| Amortization of Transition Obligation | 2.5 | 2.5 | 2.4 |
| Net Postretirement Health and Life Expense | $10.8 | $10.1 | $8.9 |
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
Note 16. Pension and Other Postretirement Benefit Plans (Continued)
Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income and Regulatory Assets |
| Year Ended December 31 | 2009 | 2008 |
| Millions | | |
| Net Loss (Gain) | $12.9 | $38.3 |
| Prior Service Cost (Credit) Arising During the Period | (1.3) | – |
| Amortization of Transition Obligation | (2.5) | (2.5) |
| Amortization of Loss (Gain) | (2.5) | (1.4) |
| Total Recognized in Other Comprehensive Income and Regulatory Assets | $6.6 | $34.4 |
| Estimated Future Benefit Payments |
| | | Postretirement |
| | Pension | Health and Life |
| Millions | | |
| 2010 | $26.4 | $7.5 |
| 2011 | $26.9 | $8.4 |
| 2012 | $27.8 | $9.2 |
| 2013 | $28.8 | $10.0 |
| 2014 | $29.9 | $10.9 |
| Years 2015 – 2019 | $165.0 | $65.5 |
The pension and postretirement health and life costs recorded in otherregulatory long-term assets 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, 2010,2012, are as follows:
| | | Postretirement |
| | Pension | Health and Life |
| Millions | | |
| Net Loss | $6.6 | $4.8 |
| Prior Service Costs | $0.5 | $(0.1) |
| Transition Obligations | – | $2.5 |
| Total Pension and Postretirement Health and Life Costs | $7.1 | $7.2 |
|
| | | | | | |
| | Pension | Postretirement Health and Life |
| Millions | | |
| Net Loss |
| $17.5 |
|
| $7.5 |
|
| Prior Service Costs |
| $0.3 |
|
| ($1.7 | ) |
| Transition Obligations | — |
|
| $0.1 |
|
| Total Pension and Postretirement Health and Life Costs |
| $17.8 |
|
| $5.9 |
|
| | Weighted-Average Assumptions Used to Determine Benefit Obligation | | Year Ended December 31 | 2009 | 2008 | 2011 | 2010 |
| Discount Rate | 5.81% | 6.12% | |
| Pension | | 4.54 | % | 5.36 | % |
| Postretirement Health and Life | | 4.56 | % | 5.40 | % |
| Rate of Compensation Increase | 4.3 – 4.6% | 4.3 – 4.6% | 4.3 - 4.6% |
| 4.3 - 4.6% |
|
| Health Care Trend Rates | | | | |
|
| Trend Rate | 8.5% | 9% | 10 | % | 10 | % |
| Ultimate Trend Rate | 5% | 5% | 5 | % | 5 | % |
| Year Ultimate Trend Rate Effective | 2017 | 2012 | 2018 |
| 2018 |
|
| Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs |
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Discount Rate | 6.12% | 6.25% | 5.75% |
| Expected Long-Term Return on Plan Assets | | | |
| Pension | 8.5% | 9.0% | 9.0% |
| Postretirement Health and Life | 6.8 – 8.5% | 7.2 – 9.0% | 5.0 – 9.0% |
| Rate of Compensation Increase | 4.3 – 4.6% | 4.3 – 4.6% | 4.3 – 4.6% |
89 |
| | | | | | |
| Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Discount Rate | 5.36 - 5.40% |
| 5.81 | % | 6.12 | % |
Expected Long-Term Return on Plan Assets (a) | | | |
| Pension | 8.5 | % | 8.5 | % | 8.5 | % |
| Postretirement Health and Life | 6.8 - 8.5% |
| 6.8 - 8.5% |
| 6.8 - 8.5% |
|
| Rate of Compensation Increase | 4.3 - 4.6% |
| 4.3 - 4.6% |
| 4.3 - 4.6% |
|
Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
(a) The expected long-term rate of return used to determine net periodic benefit expenses for 2012 has been reduced to 8.25 percent.
In establishing the expected long-term return on plan assets, we take into account the actual long-term historical performance of our plan assets, the actual long-term historical performance for the type of securities we are invested in, and apply the historical performance utilizing the target allocation of our plan assets to forecast an expected long-term return. Our expected rate of return is then selected after considering the results of each of those factors, in addition to considering the impact of current economic conditions, if applicable, on long-term historical returns.
The discount rate is computed using the Citigroup Pension Discount Curvea yield curve adjusted for ALLETE’s projected cash flows to match our plan characteristics. The Citigroup Pension Discount Curveyield curve is determined using high-quality long-term corporate bond rates at the valuation date. We believe the adjusted discount curve used in this comparison does not materially differ in duration and cash flows from our pension obligation.
|
| | | | |
| Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates |
| | One Percent | One Percent |
| | Increase | Decrease |
| Millions | | |
| Effect on Total of Postretirement Health and Life Service and Interest Cost |
| $2.0 |
| $(1.6) |
| Effect on Postretirement Health and Life Obligation |
| $25.1 |
| $(20.7) |
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
| Sensitivity of a One-Percentage-Point Change in Health Care Trend Rates |
| | One Percent | One Percent |
| | Increase | Decrease |
| Millions | | |
| Effect on Total of Postretirement Health and Life Service and Interest Cost | $2.1 | $(1.8) |
| Effect on Postretirement Health and Life Obligation | $23.6 | $(20.9) |
|
| | | | | | | | |
| Actual Plan Asset Allocations |
| | Pension | Postretirement Health and Life (a) |
| | 2011 | 2010 | 2011 | 2010 |
| Equity Securities | 52 | % | 52 | % | 51 | % | 58 | % |
| Debt Securities | 27 | % | 29 | % | 39 | % | 33 | % |
| Real Estate | 5 | % | 5 | % | — |
| — |
|
| Private Equity | 16 | % | 14 | % | 10 | % | 9 | % |
| | 100 | % | 100 | % | 100 | % | 100 | % |
| Actual Plan Asset Allocations |
| | Pension | Postretirement Health and Life (a) |
| | 2009 | 2008 | 2009 | 2008 |
| Equity Securities | 53% | 46% | 54% | 47% |
| Debt Securities | 28% | 32% | 38% | 40% |
| Real Estate | 5% | 6% | – | – |
| Private Equity | 14% | 16% | 8% | 9% |
| Cash | – | – | – | 4% |
| | 100% | 100% | 100% | 100% |
| |
| (a) | Includes VEBAs and irrevocable grantor trusts. |
Pension plan equity securities included $9.9There was $20.0 million or 3.0 percent, (approximately 507,600 shares) of ALLETE common stock included in pension plan equity securities at December 31, 2009 (none at December 31, 2008)2011 (none in 2010).
To achieve strong returns within managed risk, we diversify our asset portfolio to approximate the target allocations in the table below. 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.
| Plan Asset Target Allocations |
| | | Postretirement |
| | Pension | Health and Life (a) |
| Equity Securities | 50% | 48% |
| Debt Securities | 30% | 34% |
| Real Estate | 10% | 9% |
| Private Equity | 10% | 9% |
| | 100% | 100% |
|
| | | | |
| Plan Asset Target Allocations |
| | | Postretirement |
| | Pension | Health and Life (a) |
| Equity Securities | 52 | % | 48 | % |
| Debt Securities | 30 | % | 34 | % |
| Real Estate | 9 | % | 9 | % |
| Private Equity | 9 | % | 9 | % |
| | 100 | % | 100 | % |
(a) | |
| (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:
Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
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, such as commodity options priced using observable forward pricesinputs. This category includes various bonds and volatilities.non-public funds whose underlying investments may be level 1 or level 2 securities.
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
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.
Pension Fair Value
| | At Fair Value as of December 31, 2009 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities | | | | |
U.S. Large-cap (a) | $23.2 | $27.5 | $5.2 | $55.9 |
U.S. Mid-cap Growth (a) | 8.9 | 10.6 | 2.0 | 21.5 |
U.S. Small-cap (a) | 8.6 | 10.1 | 1.9 | 20.6 |
| International | – | 66.4 | – | 66.4 |
| ALLETE | 9.9 | – | – | 9.9 |
| Debt Securities: | | | | |
| Mutual Funds | 32.0 | – | – | 32.0 |
| Fixed Income | – | 59.3 | – | 59.3 |
| Other Types of Investments: | | | | |
| Private Equity Funds | – | – | 44.7 | 44.7 |
| Real Estate | – | – | 17.3 | 17.3 |
| Total Fair Value of Assets | $82.6 | $173.9 | $71.1 | $327.6 |
|
| | | | | | | | | | | | |
| | At Fair Value as of December 31, 2011 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities: | | | | |
U.S. Large-cap (a) |
| $32.1 |
|
| $37.3 |
| — |
|
| $69.4 |
|
U.S. Mid-cap Growth (a) | 13.5 |
| 15.8 |
| — |
| 29.3 |
|
U.S. Small-cap (a) | 13.1 |
| 15.2 |
| — |
| 28.3 |
|
| International | — |
| 75.1 |
| — |
| 75.1 |
|
| ALLETE | 21.3 |
| — |
| — |
| 21.3 |
|
| Debt Securities: | |
| |
| |
| |
|
| Mutual Funds | 72.8 |
| — |
| — |
| 72.8 |
|
| Fixed Income | — |
| 45.5 |
| — |
| 45.5 |
|
| Other Types of Investments: | |
| |
| |
| |
|
| Private Equity Funds | — |
| — |
|
| $69.0 |
| 69.0 |
|
| Real Estate | — |
| — |
| 21.7 |
| 21.7 |
|
| Total Fair Value of Assets |
| $152.8 |
|
| $188.9 |
|
| $90.7 |
|
| $432.4 |
|
(a) The underlying investments classified under U.S. Equity Securities represent | |
| (a) | The underlying investments classified under U.S. Equity Securities consist of Money Market Funds and U.S. Government Bonds (Level 1), and U.S. Government Bonds (Level 1), Hedge Funds (Level 2), and Auction Rate Securities (Level 3), which are combined with futures, which settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, 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 | Equity Securities | | |
| Activity in Level 3 | (Auction Rate Securities) | Private Equity Funds | Real Estate |
| Millions | | | |
| Balance as of December 31, 2010 |
| $6.7 |
|
| $50.7 |
|
| $20.1 |
|
| Actual Return on Plan Assets | — |
| 30.9 |
| 3.5 |
|
| Purchases, sales, and settlements, net | (6.7 | ) | (12.6 | ) | (1.9 | ) |
| Balance as of December 31, 2011 | — |
|
| $69.0 |
|
| $21.7 |
|
| Recurring Fair Value Measures | Equity Securities | | |
| Activity in Level 3 | (Auction Rate Securities) | Private Equity Funds | Real Estate |
| Millions | | | |
| Balance as of December 31, 2008 | $10.2 | $43.2 | $17.0 |
| Actual Return on Plan Assets | 0.1 | (8.7) | (8.6) |
| Purchases, sales, and settlements, net | (1.1) | 10.2 | 8.9 |
| Balance as of December 31, 2009 | $9.1 | $44.7 | $17.3 |
Note 16. | |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
|
| | | | | | | | | | | | |
| | At Fair Value as of December 31, 2010 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities: | | | | |
U.S. Large-cap (a) |
| $30.4 |
|
| $29.9 |
|
| $3.5 |
|
| $63.8 |
|
U.S. Mid-cap Growth (a) | 14.0 |
| 13.7 |
| 1.6 |
| 29.3 |
|
U.S. Small-cap (a) | 13.7 |
| 13.5 |
| 1.6 |
| 28.8 |
|
| International | — |
| 77.1 |
| — |
| 77.1 |
|
| Debt Securities: | |
| |
| |
| |
|
| Mutual Funds | 46.5 |
| — |
| — |
| 46.5 |
|
| Fixed Income | — |
| 65.7 |
| — |
| 65.7 |
|
| Other Types of Investments: | |
| |
| |
| |
|
| Private Equity Funds | — |
| — |
| 50.7 |
| 50.7 |
|
| Real Estate | — |
| — |
| 20.1 |
| 20.1 |
|
| Total Fair Value of Assets |
| $104.6 |
|
| $199.9 |
|
| $77.5 |
|
| $382.0 |
|
| |
| (a) | The underlying investments classified under U.S. Equity Securities consist of Money Market Funds and U.S. Government Bonds (Level 1), Funds (Level 2), and Auction Rate Securities (Level 3), which are combined with futures, which settle daily, in a portable alpha program to achieve the returns of the U.S. Equity Securities Large-cap, 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 | Equity Securities | | |
| Activity in Level 3 | (Auction Rate Securities) | Private Equity Funds | Real Estate |
| Millions | | | |
| Balance as of December 31, 2009 |
| $9.1 |
|
| $44.7 |
|
| $17.3 |
|
| Actual Return on Plan Assets | — |
| (4.1 | ) | (6.1 | ) |
| Purchases, sales, and settlements, net | (2.4 | ) | 10.1 |
| 8.9 |
|
| Balance as of December 31, 2010 |
| $6.7 |
|
| $50.7 |
|
| $20.1 |
|
Postretirement Health and Life Fair Value
| | At Fair Value as of December 31, 2009 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities | | | | |
| U.S. Large-cap | $13.4 | – | – | $13.4 |
| U.S. Mid-cap Growth | 9.0 | – | – | 9.0 |
| U.S. Small-cap | 6.3 | – | – | 6.3 |
| International | 21.4 | – | – | 21.4 |
| Debt Securities: | | | | |
| Mutual Funds | 5.5 | – | – | 5.5 |
| Fixed Income | – | $31.4 | – | 31.4 |
| Other Types of Investments: | | | | |
| Private Equity Funds | – | – | $9.4 | 9.4 |
| Total Fair Value of Assets | $55.6 | $31.4 | $9.4 | $96.4 |
|
| | | | | | | | | | | | |
| | At Fair Value as of December 31, 2011 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities: | | | | |
| U.S. Large-cap |
| $15.9 |
| — |
| — |
|
| $15.9 |
|
| U.S. Mid-cap Growth | 11.5 |
| — |
| — |
| 11.5 |
|
| U.S. Small-cap | 11.2 |
| — |
| — |
| 11.2 |
|
| International | 25.1 |
| — |
| — |
| 25.1 |
|
| Debt Securities: | |
| |
| |
| |
|
| Mutual Funds | 24.1 |
| — |
| — |
| 24.1 |
|
| Fixed Income | 0.3 |
|
| $18.9 |
| — |
| 19.2 |
|
| Other Types of Investments: | |
| |
| |
| |
|
| Private Equity Funds | — |
| — |
|
| $14.0 |
| 14.0 |
|
| Total Fair Value of Assets |
| $88.1 |
|
| $18.9 |
|
| $14.0 |
|
| $121.0 |
|
| |
| Note 16. | Pension and Other Postretirement Benefit Plans (Continued) |
|
| | | |
| Recurring Fair Value Measures | |
| Activity in Level 3 | Private Equity Funds |
| Millions | |
Balance as of December 31, 20082010 |
| $7.912.4 |
|
| Actual Return on Plan Assets | (1.1)1.1 |
|
| Purchases, sales, and settlements, net | 2.60.5 |
|
| Balance as of December 31, 2011 |
| $14.0 |
|
|
| | | | | | | | | | | | |
| | At Fair Value as of December 31, 2010 |
| Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total |
| Millions | | | | |
| Assets: | | | | |
| Equity Securities: | | | | |
| U.S. Large-cap |
| $15.7 |
| — |
| — |
|
| $15.7 |
|
| U.S. Mid-cap Growth | 11.4 |
| — |
| — |
| 11.4 |
|
| U.S. Small-cap | 11.5 |
| — |
| — |
| 11.5 |
|
| International | 26.8 |
| — |
| — |
| 26.8 |
|
| Debt Securities: | |
| |
| |
| |
|
| Mutual Funds | 9.0 |
| — |
| — |
| 9.0 |
|
| Fixed Income | — |
|
| $27.9 |
| — |
| 27.9 |
|
| Other Types of Investments: | |
| |
| |
| |
|
| Private Equity Funds | — |
| — |
|
| $12.4 |
| 12.4 |
|
| Total Fair Value of Assets |
| $74.4 |
|
| $27.9 |
|
| $12.4 |
|
| $114.7 |
|
|
| | | |
| Recurring Fair Value Measures | |
| Activity in Level 3 | Private Equity Funds |
| Millions | |
| Balance as of December 31, 2009 |
| $9.4 |
|
| Actual Return on Plan Assets | 1.4 |
|
| Purchases, sales, and settlements, net | 1.6 |
|
| Balance as of December 31, 2010 |
| $12.4 |
|
Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) providesprovide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide postretirement health benefits that include prescription drug benefits, which qualify us for the federal subsidy under the Act. The expected reimbursement for Medicare health subsidies reduced our after-tax postretirement medical expense by $2.0 million for 2009 ($1.2 million for 2008; $2.3 million in 2007). In 2005 we enrolled with the Centers for Medicare and Medicaid Services’ (CMS) and began recovering the subsidy in 2007. We received a reimbursement of $0.6 million in 2009 and $0.3 million in 2007.
| |
| Note 17. | Employee Stock and Incentive Plans |
Employee Stock Ownership Plan. We sponsor a leveraged employee stock ownership plan (ESOP)ESOP within the RSOP. As of their date of hire, alleligible employees of ALLETE, SWL&P and Minnesota Power Affiliate Resources are eligible tomay contribute to the RSOP plan. In 1990, the ESOP issued a $75$75.0 million note (term not to exceed 25 years at 10.25 percent) to ususe as consideration for 2.8 million shares (1.9 million shares adjusted for stock splits) of our newly issued common stock. The note was refinanced in 2006 at 6 percent. We make annual contributions to the ESOP equal to the ESOP’s debt service less available dividends received by the ESOP. The majority of dividends received by the ESOP are used to pay debt service, with the balance distributed to participants. The ESOP shares were initially pledged as collateral for its debt. As the debt is repaid, shares are released from collateral and allocated to participants based on the proportion of debt service paid in the year. As shares are released from collateral, we report compensation expense equal to the current market price of the shares less dividends on allocated shares. Dividends on allocated ESOP shares are recorded as a reduction of retained earnings; available dividends on unallocated ESOP shares are recorded as a reduction of debt and accrued interest. ESOP compensation expense was $6.5$7.4 million in 2009 ($10.12011 ($7.1 million in 2008; $9.22010; $6.5 million in 2007)2009).
Note 17. | Employee Stock and Incentive Plans (Continued) |
According to the accounting guidancestandards for stock compensation, unallocated shares of ALLETE common stock currently held and purchased by the ESOP will be treated as unearned ESOP shares and not considered as outstanding for earnings per share computations. ESOP shares are included in earnings per share computations after they are allocated to participants.
| Year Ended December 31 | 2009 | 2008 | 2007 |
| Millions | | | |
| ESOP Shares | | | |
| Allocated | 2.2 | 2.0 | 1.8 |
| Unallocated | 1.5 | 1.9 | 2.2 |
| Total | 3.7 | 3.9 | 4.0 |
| Fair Value of Unallocated Shares | $49.0 | $61.3 | $87.1 |
|
| | | | | | | | | |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| ESOP Shares | | | |
| Allocated | 2.2 |
| 2.2 |
| 2.2 |
|
| Unallocated | 1.0 |
| 1.3 |
| 1.5 |
|
| Total | 3.2 |
| 3.5 |
| 3.7 |
|
| Fair Value of Unallocated Shares |
| $42.0 |
|
| $48.4 |
|
| $49.0 |
|
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, stock appreciation rights and other awards. There are 1.41.3 million shares of common stock reserved for issuance under the Executive Plan, with 0.6 million of these shares available for issuance as of December 31, 2009.2011.
We had a Director Long-Term Stock Incentive Plan (Director Plan) which expired on January 1, 2006. No grants have been made since 2003 under the Director Plan. Approximately 3,8791,293 options were outstanding under the Director Plan at December 31, 2009.2011.
We currently have the following types of share-based awards outstanding:
Non-Qualified Stock Options. The 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 cancelledcanceled 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 retirement eligible.
In 2009, no stock Stock options werehave not been granted under our Executive Long-Term Incentive Compensation Plan. The following assumptions were used in determining the fair value of stock options granted during 2008 and 2007, respectively, under the Black-Scholes option-pricing model:
| | 2008 | 2007 |
| Risk-Free Interest Rate | 2.8% | 4.8% |
| Expected Life | 5 Years | 5 Years |
| Expected Volatility | 20% | 20% |
| Dividend Growth Rate | 4.4% | 5.0% |
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 17. | Employee Stock and Incentive Plans (Continued) |
Performance Shares. Under the performance share awards plan, the number of shares earned is contingent upon attaining specific performance targetsmarket goals over a three-year performance period. PerformanceMarket goals are measured by total shareholder return relative to a group of peer companies. In the case of qualified retirement, death or disability during a performance period, a pro-ratapro rata portion of the award will be earned at the conclusion of the performance period based on the performancemarket 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-ratapro 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 by 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.
Note 17. | Employee Stock and Incentive Plans (Continued) |
Restricted Stock Units. Under the restricted stock units plan, shares vest at the end ofmonthly over a three-year period, at which time the restrictions will be removed.three-year period. In the case of qualified retirement, death or disability, a pro-ratapro rata portion of the award will be earned at the conclusion of the vesting period.earned. In the case of termination of employment for any other reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro-ratapro rata portion of the award will be paid. 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, we are not required to apply fair value accounting to these awards.
RSOPRetirement Savings & Stock Ownership Plan (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 | 2009 | 2008 | 2007 |
| Millions | | | |
| Stock Options | $0.3 | $0.7 | $0.8 |
| Performance Shares | 1.5 | 1.1 | 1.0 |
| Restricted Stock Units | 0.3 | – | – |
| Total Share-Based Compensation Expense | $2.1 | $1.8 | $1.8 |
| Income Tax Benefit | $0.8 | $0.7 | $0.7 |
|
| | | | | | | | | |
| Share-Based Compensation Expense |
| Year Ended December 31 | 2011 | 2010 | 2009 |
| Millions | | | |
| Stock Options | — |
|
| $0.1 |
|
| $0.3 |
|
| Performance Shares |
| $1.1 |
| 1.5 |
| 1.5 |
|
| Restricted Stock Units | 0.5 |
| 0.6 |
| 0.3 |
|
| Total Share-Based Compensation Expense |
| $1.6 |
|
| $2.2 |
|
| $2.1 |
|
| Income Tax Benefit |
| $0.7 |
|
| $0.9 |
|
| $0.8 |
|
There were no capitalized stock-based compensation costs at December 31, 2009, 2008,2011, 2010, or 2007.2009.
As of December 31, 2009,2011, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our consolidated statements of income was $1.8$1.3 million and $0.5$0.6 million, respectively. These amounts are expected to be recognized over a weighted-average period of 1.7 years and 2.01.6 years for performance share awards and restricted stock units, respectively.
Non-Qualified Stock Options.The following table presents information regarding our outstanding stock options as of December 31, 2009.2011.
| | | | | Weighted-Average |
| | | Weighted-Average | Aggregate | Remaining |
| | Number of | Exercise | Intrinsic | Contractual |
| | Options | Price | Value | Term |
| | | | Millions | |
| Outstanding as of December 31, 2008 | 672,419 | $39.99 | $(5.2) | 6.9 years |
Granted (a) | – | – | | |
| Exercised | 4,508 | $18.85 | | |
| Forfeited | 21,676 | $42.62 | | |
| Outstanding as of December 31, 2009 | 646,235 | $40.05 | $(4.8) | 5.9 years |
| Exercisable as of December 31, 2009 | 512,743 | $37.34 | $(3.7) | 5.4 years |
ALLETE 2011 Form 10-K
107
| |
| Note 17. | Employee Stock and Incentive Plans (Continued) |
(a) Restricted stock units were issued in 2009, instead of stock options. |
| | | | | | | | | | | | | | | |
| | 2011 | 2010 | 2009 |
| | 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, | 560,887 |
|
| $40.69 |
| 646,235 |
|
| $40.05 |
| 672,419 |
|
| $39.99 |
|
Granted (a) | — |
| — |
| — |
| — |
| — |
| — |
|
| Exercised | 80,798 |
|
| $34.25 |
| 40,769 |
|
| $27.76 |
| 4,508 |
|
| $18.85 |
|
| Forfeited | 19,855 |
|
| $43.96 |
| 44,579 |
|
| $43.16 |
| 21,676 |
|
| $42.62 |
|
| Outstanding as of December 31, | 460,234 |
|
| $41.68 |
| 560,887 |
|
| $40.69 |
| 646,235 |
|
| $40.05 |
|
| Exercisable as of December 31, | 460,234 |
|
| $41.59 |
| 523,491 |
|
| $39.76 |
| 512,743 |
|
| $37.34 |
|
| |
| (a) | Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was $6.18. |
The weighted-average grant-date fair value ofCash received from non-qualified stock options exercised was $6.18 for 2009 ($6.18 for 2008; $6.92 for 2007)less than $0.1 million in 2011. 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$0.5 million during 2009 ($0.22011 ($0.3 million in 2008; $0.42010; $0.1 million in 2007)2009).
Note 17. | Employee Stock and Incentive Plans (Continued) |
As of December 31, 2009, options outstanding consisted of 0.1 million with exercise prices ranging from $18.85 to $29.79, 0.4 million with exercise prices ranging from $37.76 to $41.35 and 0.2 million with exercise prices ranging from $44.15 to $48.65. The options with exercise prices ranging from $18.85 to $29.79 have an average remaining contractual life of 2.1 years; all were exercisable as of December 31, 2009, at a weighted average price of $27.34. The options with exercise prices ranging from $37.76 to $41.35 have an average remaining contractual life of 6.3 years; 0.2 million were exercisable as of December 31, 2009, at a weighted average price of $39.47. The options with exercise prices ranging from $44.15 to $48.65 have an average remaining contractual life of 6.5 years; less than 0.2 million were exercisable as of December 31, 2009, at a weighted average price of $46.36. |
| | | | | | | | | |
| | Range of Exercise Price |
| As of December 31, 2011 | $18.85 to $29.79 | $37.76 to $41.35 | $44.15 to $48.65 |
| Options Outstanding and Exercisable: | | | |
| Number Outstanding and Exercisable | 11,672 |
| 279,133 |
| 169,429 |
|
| Weighted Average Remaining Contractual Life (Years) | 1.1 |
| 4.5 |
| 4.5 |
|
| Weighted Average Exercise Price |
| $24.14 |
|
| $39.57 |
|
| $46.37 |
|
Performance Shares. The following table presents information regarding our non-vested performance shares as of December 31, 2009.2011.
| | | Weighted-Average |
| | Number of | Grant Date |
| | Shares | Fair Value |
| Non-vested as of December 31, 2008 | 79,238 | $47.94 |
| Granted | 69,800 | $35.06 |
| Unearned Grant Award | (24,615) | $41.97 |
| Forfeited | (2,598) | $38.78 |
| Non-vested as of December 31, 2009 | 121,825 | $41.96 |
|
| | | | | | | | | | | | | | | |
| | 2011 | 2010 | 2009 |
| | 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, | 122,489 |
|
| $38.15 |
| 121,825 |
|
| $41.96 |
| 79,238 |
|
| $47.94 |
|
Granted (a) | 39,312 |
|
| $41.00 |
| 49,302 |
|
| $35.44 |
| 69,800 |
|
| $35.06 |
|
| Awarded | (32,368 | ) |
| $48.10 |
| — |
| — |
| — |
| — |
|
| Unearned Grant Award | — |
| — |
| (22,909 | ) |
| $54.50 |
| (24,615 | ) |
| $41.97 |
|
| Forfeited | (1,100 | ) |
| $34.35 |
| (25,729 | ) |
| $36.45 |
| (2,598 | ) |
| $38.78 |
|
| Non-vested as of December 31, | 128,333 |
|
| $28.00 |
| 122,489 |
|
| $38.15 |
| 121,825 |
|
| $41.96 |
|
(a) Shares granted includes accrued dividends.
Less than 0.1 million performance shareshares were granted in February 2009January 2011 for the three-year performance period ending in 2011.2013. The ultimate issuance is contingent upon the attainment of certain future performancemarket goals of ALLETE during the performance periods. The grant date fair value of the performance share awardsshares granted was $2.2 million.$1.4 million.
NoLess than 0.1 million performance shares were awarded in February 20102011 for the three-yearthree-year performance period ending in 2009, as performance targets were not met. However, in accordance with2010. The grant date fair value of the accounting guidance for stock compensation, no compensation expense previously recognized in connection with those grants will be reversed.shares awarded was $1.6 million.
Restricted Stock Units. The following table presents information regarding our non-vested restricted stock units as of December 31, 2009.
| | | Weighted-Average |
| | Number of | Grant Date |
| | Shares | Fair Value |
| Non-vested as of December 31, 2008 | – | – |
| Granted | 30,465 | $29.41 |
| Forfeited | (1,482) | $29.41 |
| Non-vested as of December 31, 2009 | 28,983 | $29.41 |
Less than 0.1 million restricted stock units performance shares were grantedawarded in February 20092012 for the vestingthree-year performance period ending in 2011. The grant date fair value of the shares awarded was $1.4 million.
| |
| Note 17. | Employee Stock and Incentive Plans (Continued) |
Restricted Stock Units. The following table presents information regarding our available restricted stock unit awardsunits as of December 31, 2011.
|
| | | | | | | | | | | | | | | |
| | 2011 | 2010 | 2009 |
| | 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, | 43,803 |
|
| $30.61 |
| 28,983 |
|
| $29.41 |
| — |
| — |
|
Granted (a) | 20,136 |
|
| $36.74 |
| 26,589 |
|
| $31.83 |
| 30,465 |
|
| $29.41 |
|
| Awarded | (215 | ) |
| $30.30 |
| (3,091 | ) |
| $29.75 |
| — |
| — |
|
| Forfeited | (260 | ) |
| $29.41 |
| (8,678 | ) |
| $30.62 |
| (1,482 | ) |
| $29.41 |
|
| Available as of December 31, | 63,464 |
|
| $22.88 |
| 43,803 |
|
| $30.61 |
| 28,983 |
|
| $29.41 |
|
(a) Shares granted includes accrued dividends.
Less than 0.1 million restricted stock units were granted in January 2011 for the vesting period ending in 2013. The grant date fair value of the restricted stock units granted was $0.9 million.$0.6 million.
Less than 0.1 million restricted stock units were awarded in February 2011. The grant date fair value of the shares awarded was less than $0.1 million.
Less than 0.1 million restricted stock units were awarded in February 2012. The grant date fair value of the shares awarded was $0.8 million.
| |
| Note 18. | 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 | | | | |
| 2009 | | | | |
| Operating Revenue | $199.6 | $164.7 | $178.8 | $216.0 |
| Operating Income | $31.1 | $15.7 | $25.4 | $33.8 |
| Net Income Attributable to ALLETE | $16.9 | $9.4 | $16.0 | $18.7 |
| Earnings Per Share of Common Stock | | | | |
| Basic | $0.55 | $0.29 | $0.49 | $0.56 |
| Diluted | $0.55 | $0.29 | $0.49 | $0.56 |
| 2008 | | | | |
| Operating Revenue | $213.4 | $189.8 | $201.7 | $196.1 |
| Operating Income | $31.3 | $17.5 | $33.2 | $39.8 |
| Net Income Attributable to ALLETE | $23.6 | $10.7 | $24.7 | $23.5 |
| Earnings Per Share of Common Stock | | | | |
| Basic | $0.82 | $0.37 | $0.85 | $0.78 |
| Diluted | $0.82 | $0.37 | $0.85 | $0.78 |
|
| | | | | | | | | | | | |
| Quarter Ended | Mar. 31 | Jun. 30 | Sept. 30 | Dec. 31 |
| Millions Except Earnings Per Share | | | | |
| 2011 | | | | |
| Operating Revenue |
| $242.2 |
|
| $219.9 |
|
| $226.9 |
|
| $239.2 |
|
| Operating Income |
| $50.8 |
|
| $26.1 |
|
| $38.9 |
|
| $34.2 |
|
| Net Income Attributable to ALLETE |
| $37.2 |
|
| $17.0 |
|
| $20.5 |
|
| $19.1 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $1.07 |
|
| $0.49 |
|
| $0.57 |
|
| $0.53 |
|
| Diluted |
| $1.07 |
|
| $0.48 |
|
| $0.57 |
|
| $0.53 |
|
| 2010 | | | | |
| Operating Revenue |
| $233.6 |
|
| $211.2 |
|
| $224.1 |
|
| $238.1 |
|
| Operating Income |
| $46.1 |
|
| $31.7 |
|
| $35.3 |
|
| $22.7 |
|
| Net Income Attributable to ALLETE |
| $23.0 |
|
| $19.4 |
|
| $19.6 |
|
| $13.3 |
|
| Earnings Per Share of Common Stock | | | | |
| Basic |
| $0.68 |
|
| $0.57 |
|
| $0.57 |
|
| $0.38 |
|
| Diluted |
| $0.68 |
|
| $0.57 |
|
| $0.56 |
|
| $0.38 |
|
ALLETE 20092011 Form 10-K
109
Schedule II
ALLETE
Valuation and Qualifying Accounts and Reserves
|
| | | | | | | | | | | | | | | |
| | Balance at Beginning of Period | | Additions Charged Other to Income Charges | Deductions from
Reserves (a) | Balance at End of
Period |
| |
| Millions | | | | | | |
| Reserve Deducted from Related Assets | | | | | | |
| Reserve For Uncollectible Accounts | | | | | | |
| 2009 Trade Accounts Receivable |
| $0.7 |
| |
| $1.3 |
| — |
|
| $1.1 |
|
| $0.9 |
|
| Finance Receivables – Long-Term |
| $0.1 |
| |
| $0.3 |
| — |
| — |
|
| $0.4 |
|
| 2010 Trade Accounts Receivable |
| $0.9 |
| |
| $1.1 |
| — |
|
| $1.1 |
|
| $0.9 |
|
| Finance Receivables – Long-Term |
| $0.4 |
| |
| $0.8 |
| — |
|
| $0.4 |
|
| $0.8 |
|
| 2011 Trade Accounts Receivable |
| $0.9 |
| |
| $1.3 |
| — |
|
| $1.3 |
|
| $0.9 |
|
| Finance Receivables – Long-Term |
| $0.8 |
| |
| $0.1 |
| — |
|
| $0.3 |
|
| $0.6 |
|
| Deferred Asset Valuation Allowance | | | | | | |
| 2009 Deferred Tax Assets |
| $0.4 |
| | $(0.1) | — |
| — |
|
| $0.3 |
|
| 2010 Deferred Tax Assets |
| $0.3 |
| |
| $0.2 |
| — |
| — |
|
| $0.5 |
|
| 2011 Deferred Tax Assets |
| $0.5 |
| | $(0.1) | — |
| — |
|
| $0.4 |
|
| | Balance at | Additions | Deductions | Balance at |
| | Beginning | Charged | Other | from | End of |
| Year Ended December 31 | of Year | to Income | Changes | Reserves (a) | Period |
| Millions | | | | | |
| Reserve Deducted from Related Assets | | | | | |
| Reserve For Uncollectible Accounts | | | | | |
| 2007 Trade Accounts Receivable | $1.1 | $1.0 | – | $1.1 | $1.0 |
| Finance Receivables – Long-Term | 0.2 | – | – | – | 0.2 |
| 2008 Trade Accounts Receivable | 1.0 | 1.0 | – | 1.3 | 0.7 |
| Finance Receivables – Long-Term | 0.2 | – | – | 0.1 | 0.1 |
| 2009 Trade Accounts Receivable | 0.7 | 1.3 | – | 1.1 | 0.9 |
| Finance Receivables – Long-Term | 0.1 | 0.3 | – | – | 0.4 |
| Deferred Asset Valuation Allowance | | | | | |
| 2007 Deferred Tax Assets | 3.6 | (0.3) | – | – | 3.3 |
| 2008 Deferred Tax Assets | 3.3 | (2.9) | – | – | 0.4 |
| 2009 Deferred Tax Assets | 0.4 | (0.1) | – | – | 0.3 |
| |
| (a) | Includes uncollectible accounts written off. |
ALLETE 20092011 Form 10-K
110