News Column

ALLETE INC - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

February 14, 2014

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: "Forward-Looking Statements" located on page 6 and "Risk Factors" located in Item 1A. The risks and uncertainties described in this Form 10-K are not the only 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 143,000 retail customers. Minnesota Power's non-affiliated municipal customers consist of 16 municipalities in Minnesota. SWL&P is also a Wisconsin utility 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. (See Item 1. Business - Regulated Operations - Regulatory Matters.)



Investments and Other is comprised primarily of BNI Coal, our coal mining operations in North Dakota, ALLETE Properties, our Florida real estate investment, and ALLETE Clean Energy, our business aimed at developing or acquiring capital projects that create energy solutions via wind, solar, biomass, midstream gas and oil infrastructure, among other energy-related projects. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately 5,000 acres of land in Minnesota, and earnings on cash and investments.

ALLETE is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of December 31, 2013, 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.



2013 Financial Overview

The following net income discussion summarizes a comparison of the year ended December 31, 2013, to the year ended December 31, 2012.

Consolidated net income attributable to ALLETE for 2013 was $104.7 million, or $2.63 per diluted share, compared to $97.1 million, or $2.58 per diluted share, for 2012. Net income in 2013 included $1.0 million after-tax, or $0.03 per share, of acquisition costs for the ALLETE Clean Energy acquisition which closed on January 30, 2014 (see Note 7. Acquisitions). Net income for 2013 reflected higher kilowatt-hour sales, cost recovery rider revenue, federal production tax credits, transmission revenue and municipal rates. These increases were partially offset by higher operating and maintenance, depreciation, property tax and interest expenses, as well as increased costs under the Square Butte purchased power contract. Earnings per share dilution was $0.15 as a result of additional shares of common stock outstanding in 2013. (See Note 13. Common Stock and Earnings Per Share.) Regulated Operations net income attributable to ALLETE was $104.9 million in 2013, compared to $96.1 million in 2012. Net income for 2013 reflected higher kilowatt-hour sales, cost recovery rider revenue, federal production tax credits, transmission revenue and municipal rates. These increases were partially offset by higher operating and maintenance, depreciation, property tax and interest expenses, as well as increased costs under the Square Butte purchased power contract. Investments and Other reflected a net loss attributable to ALLETE of $0.2 million for 2013, compared to net income of $1.0 million in 2012. The net loss in 2013 included $1.0 million of acquisition costs for the ALLETE Clean Energy acquisition (see Note 7. Acquisitions). The net loss in 2013 also included higher interest and state income tax expense and lower net income at BNI Coal due to a fourth quarter planned outage at Square Butte. These decreases were partially offset by a lower loss at ALLETE Properties due to land sales in 2013 and gains as a result of the exit from a legacy benefit plan and investment sales. ALLETE 2013 Form 10-K 35

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2013 Compared to 2012

(See Note 2. Business Segments for financial results by segment.)

Regulated Operations

Operating Revenue increased $51.1 million, or 6 percent, from 2012 primarily due to a 1.2 percent increase in kilowatt-hour sales, and higher fuel adjustment clause recoveries, transmission revenue, cost recovery rider revenue, gas sales, and municipal rates. Fuel adjustment clause recoveries increased $13.5 million due to higher fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.) Transmission revenue increased $6.3 million primarily due to the commencement of recovery of our transmission investment related to the 230 kV transmission system upgrade that was placed into service in March 2013 (see Outlook - Prospective Additional Load - Nashwauk Public Utilities Commission) and higher MISO Regional Expansion Criteria and Benefits (RECB) revenue related to CapX2020 transmission projects. Cost recovery rider revenue increased $5.3 million primarily due to higher capital expenditures related to our Bison Wind Energy Center, CapX2020 projects and the Boswell Unit 4 environmental upgrade. Our Bison Wind Energy Center was completed in various phases through December 2012. Cost recovery for our Boswell Unit 4 mercury emissions reduction plan was approved by the MPUC in November 2013. Revenue from gas sales at SWL&P increased $4.8 million as heating degree days in 2013 were approximately 22 percent higher than 2012. The increase was also due to higher purchased gas expenses. (See Operating Expenses - Operating and Maintenance Expense.) Revenue from our municipal customers increased $3.8 million as a result of higher rates under the cost-based formula primarily due to higher capital expenditures, as well as period-over-period fluctuations in the true-up for actual costs provisions of the contracts. The rates included in these contracts are calculated using a cost-based formula methodology that is set at July 1 each year using estimated costs and a true-up for actual costs the following year. Revenue from Regulated Operations increased $13.8 million due to a 1.2 percent increase in kilowatt-hour sales. The increase was due primarily to a 14.0 percent increase in kilowatt-hour sales 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. Also contributing to the increase was higher sales to residential and commercial customers. Heating degree days in Duluth, Minnesota were approximately 22 percent higher in 2013 than 2012. Kilowatt-hour sales to industrial customers decreased 2.2 percent from 2012 primarily due to 154 million kilowatt-hours sold in 2012 through a short-term, fixed price contract. Quantity % Kilowatt-hours Sold 2013 2012 Variance Variance Millions Regulated Utility Retail and Municipals Residential 1,177 1,132 45 4.0 Commercial 1,455 1,436 19 1.3 Industrial 7,338 7,502 (164 ) (2.2 ) Municipals 999 1,020 (21 ) (2.1 ) Total Retail and Municipals 10,969 11,090 (121 ) (1.1 ) Other Power Suppliers 2,278 1,999 279 14.0



Total Regulated Utility Kilowatt-hours Sold 13,247 13,089 158 1.2

Revenue from electric sales to taconite customers accounted for 25 percent of consolidated operating revenue in 2013 (26 percent in 2012). Revenue from electric sales to paper, pulp and wood product customers accounted for 8 percent of consolidated operating revenue in 2013 (9 percent in 2012). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2013 (6 percent in 2012). ALLETE 2013 Form 10-K 36 -------------------------------------------------------------------------------- 2013 Compared to 2012 (Continued) Regulated Operations (Continued)



Operating Expenses increased $54.8 million, or 8 percent, from 2012.

Fuel and Purchased Power Expense increased $26.1 million, or 8 percent, from 2012 primarily due to higher company generation, kilowatt-hours sold and purchased power prices. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause (see Operating Revenue). A scheduled major outage in 2013 also increased costs under the Square Butte purchased power contract. Operating and Maintenance Expense increased $12.4 million, or 4 percent, from 2012 primarily due to higher property tax expenses as a result of higher taxable plant and rates, higher transmission expense primarily due to higher MISO RECB expense, higher operating and maintenance expenses related to our Bison Wind Energy Center, which was in service in 2013, and higher purchased gas expenses. Purchased gas expenses increased due to higher gas sales at SWL&P in 2013 as heating degree days in 2013 were approximately 22 percent higher than 2012; purchased gas costs are recovered through a purchased gas adjustment clause from customers (see Operating Revenue).



Depreciation Expense increased $16.3 million, or 17 percent, from 2012 reflecting additional property, plant and equipment in service.

Interest Expense increased $2.3 million, or 6 percent, from 2012 primarily due to higher average long-term debt balances.

Income Tax Expense decreased $14.3 million, or 28 percent, from 2012 primarily due to higher federal production tax credits in 2013 as our Bison Wind Energy Center was completed in various phases through December 2012 and in service in 2013. Investments and Other Operating Revenue increased $6.1 million, or 7 percent, from 2012 primarily due to a $3.6 million increase in revenue at BNI Coal and a $2.3 million increase in revenue at ALLETE Properties. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2013 (see Operating Expenses), which was partially offset by fewer tons sold in 2013. The increase at ALLETE Properties was primarily due to land sales in 2013. ALLETE Properties 2013 2012 Revenue and Sales Activity Acres (a) Amount Acres (a) Amount Dollars in Millions Revenue from Land Sales 293 $3.5 - - Other Revenue (b) 0.9 $2.1 Total ALLETE Properties Revenue $4.4$2.1



(a) Acreage amounts are shown on a gross basis, including wetlands.

(b) For the year ended December 31, 2012, Other Revenue includes wetland mitigation bank credit sales of $1.1 million. Operating Expenses increased $3.5 million, or 4 percent, from 2012 reflecting higher expenses at BNI Coal of $5.0 million primarily due to higher repairs, fuel and labor costs; these costs are recovered through the cost plus contract. (See Operating Revenue.) Operating expenses in 2013 also included $1.0 million of acquisition costs for the ALLETE Clean Energy acquisition and higher cost of land sales at ALLETE Properties. These increases were partially offset by gains as a result of the exit from a legacy benefit plan and lower operating expenses related to our non-rate base generation. Interest Expense increased $2.5 million from 2012 primarily due to the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for our Regulated Operations based on Minnesota Power's rate base and authorized capital structure, and allocate the remaining balance to Investments and Other. Other Income increased $3.7 million from 2012 primarily due to gains on sales of investments. ALLETE 2013 Form 10-K 37

-------------------------------------------------------------------------------- 2013 Compared to 2012 (Continued) Investments and Other (Continued) Income Tax Benefits decreased $5.0 million, or 40 percent, from 2012 primarily due to a decrease in pretax losses and higher state tax expense. State income tax expense was higher in 2013 as more North Dakota income tax credits attributable to our North Dakota capital investments were recognized in 2012.



Income Taxes - Consolidated

For the year ended December 31, 2013, the effective tax rate was 21.5 percent (28.1 percent for the year ended December 31, 2012). The decrease from the year ended December 31, 2012, was primarily due to increased federal production tax credits in 2013 related to additional wind generation assets in service during 2013. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, federal production tax credits, state income tax credits and depletion. (See Note 15. Income Tax Expense.)



2012 Compared to 2011

(See Note 2. Business Segments for financial results by segment.)

Regulated Operations

Operating Revenue increased $22.5 million, or 3 percent, from 2011 primarily due to higher cost recovery rider revenue and transmission revenue, partially offset by lower fuel adjustment clause recoveries, lower revenue from our municipal customers and a 0.7 percent decrease in kilowatt-hours sold.



Cost recovery rider revenue increased $22.1 million due to higher capital expenditures related to our Bison Wind Energy Center and CapX2020 projects.

Transmission revenue increased $7.3 million primarily due to higher MISO Regional Expansion Criteria and Benefits (RECB) revenue related to our investment in CapX2020.

Fuel adjustment clause recoveries decreased $1.7 million due to lower fuel and purchased power costs attributable to our retail and municipal customers. (See Operating Expenses - Fuel and Purchased Power Expense.) Revenue from our municipal customers decreased $1.6 million primarily due to period-over-period fluctuations in the true-up for actual costs provisions of the contracts. The rates included in these contracts are calculated using a cost-based formula methodology that is set at July 1 each year using estimated costs and a true-up for actual costs the following year. Revenue from Regulated Operations decreased $1.1 million due to a 0.7 percent reduction in kilowatt-hour sales. The decrease in kilowatt-hour sales was primarily due to lower sales to residential customers and Other Power Suppliers. Residential sales, as compared to 2011, were down primarily due to unseasonably warm weather during the first four months of 2012; heating degree days in Duluth, Minnesota were approximately 22 percent lower than in the first four months of 2011. Total kilowatt-hour sales to Other Power Suppliers decreased 9.3 percent from 2011. 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. These decreases were partially offset by higher sales to our industrial customers, which increased 1.9 percent over 2011. ALLETE 2013 Form 10-K 38 -------------------------------------------------------------------------------- 2012 Compared to 2011 (Continued) Regulated Operations (Continued) Quantity % Kilowatt-hours Sold 2012 2011 Variance Variance Millions Regulated Utility Retail and Municipals Residential 1,132 1,159 (27 ) (2.3 ) Commercial 1,436 1,433 3 0.2 Industrial 7,502 7,365 137 1.9 Municipals 1,020 1,013 7 0.7 Total Retail and Municipals 11,090 10,970 120 1.1 Other Power Suppliers 1,999 2,205 (206 )



(9.3 ) Total Regulated Utility Kilowatt-hours Sold 13,089 13,175 (86 ) (0.7 )

Revenue from electric sales to taconite customers accounted for 26 percent of consolidated operating revenue in 2012 (26 percent in 2011). Revenue from electric sales to paper, pulp and wood product customers accounted for 9 percent of consolidated operating revenue in 2012 (9 percent in 2011). Revenue from electric sales to pipelines and other industrials accounted for 6 percent of consolidated operating revenue in 2012 (7 percent in 2011).



Operating Expenses increased $19.1 million, or 3 percent, from 2011.

Fuel and Purchased Power Expense increased $2.1 million, or 1 percent, from 2011 primarily due to a $3.2 million increase in the capacity component of our Square Butte PPA; the capacity component is not recovered through our fuel adjustment clause. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause (see Operating Revenue). Operating and Maintenance Expense increased $8.5 million, or 3 percent, from 2011 primarily due to increased salary, benefit, and transmission expenses. Benefit expenses increased primarily due to higher pension expense resulting from lower discount rates. Transmission expenses increased primarily due to higher MISO RECB expense. These increases were partially offset by lower plant outage and maintenance expenses in 2012.



Depreciation Expense increased $8.5 million, or 10 percent, from 2011 reflecting additional property, plant and equipment in service.

Interest Expense increased $4.0 million, or 11 percent, from 2011 primarily due to higher average long-term debt balances, partially offset by higher AFUDC - Debt. Income Tax Expense increased $7.2 million, or 17 percent, from 2011 primarily due to the non-recurring tax benefits recorded in 2011 for 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 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 the PPACA. The 2012 income tax expense was impacted by increased renewable tax credits over 2011.



Investments and Other

Operating Revenue increased $10.5 million, or 14 percent, from 2011 primarily due to a $10.8 million increase in revenue at BNI Coal. BNI Coal, which operates under a cost plus fixed fee contract, recorded higher revenue as a result of higher expenses in 2012. (See Operating Expenses.) ALLETE 2013 Form 10-K 39 -------------------------------------------------------------------------------- 2012 Compared to 2011 (Continued) Investments and Other (Continued) ALLETE Properties 2012 2011 Revenue and Sales Activity Acres (a) Amount Acres (a) Amount Dollars in Millions Revenue from Land Sales - - 3 $0.4 Other Revenue (b) $2.1 0.9 Total ALLETE Properties Revenue $2.1$1.3



(a) Acreage amounts are shown on a gross basis, including wetlands.

(b) For the year ended December 31, 2012, Other Revenue includes wetland

mitigation bank credit sales of $1.1 million. For the year ended December

31, 2011, Other Revenue includes a $0.4 million forfeited deposit due to

the transfer of property back to ALLETE Properties by deed-in-lieu of

foreclosure, in satisfaction of amounts previously owed under long-term

financing receivables. Operating Expenses increased $8.7 million, or 10 percent, from 2011 reflecting higher expenses at BNI Coal of $8.4 million primarily due to higher repairs, fuel costs and new equipment leases; these costs are recovered through the cost plus fixed fee contract. (See Operating Revenue.) The remaining increase was primarily due to higher business development expenses. These increases were partially offset by a $1.7 million pretax impairment charge taken at ALLETE Properties in 2011. Interest Expense decreased $2.1 million, or 27 percent, from 2011 primarily due to an increase in the proportion of ALLETE interest expense allocated to Minnesota Power. We record interest expense for our Regulated Operations based on Minnesota Power's rate base and authorized capital structure, and allocate the remaining balance to Investments and Other. Interest expense also decreased due to the reversal of interest accrued in previous years related to our uncertain tax positions. Income Tax Benefits increased $4.8 million, or 63 percent, from 2011 due to lower state tax expense. State income tax expense was lower in 2012 primarily due to North Dakota income tax credits attributable to our North Dakota capital investment, and recognized as a result of ALLETE's expected generation of future taxable income in excess of that generated by our Regulated Operations.



Income Taxes - Consolidated

For the year ended December 31, 2012, the effective tax rate was 28.1 percent (27.6 percent for the year ended December 31, 2011). The effective tax rate for the year ended December 31, 2011, was lowered by 4.8 percentage points due to the non-recurring reversal of the 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, and by 2.2 percentage points due to the non-recurring 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 the PPACA). The increase in the effective tax rate from the year ended December 31, 2011, was primarily due to the 2011 non-recurring items above, which were offset by increased renewable tax credits in 2012. The effective tax rate deviated from the statutory rate of approximately 41 percent primarily due to deductions for AFUDC - Equity, investment tax credits, renewable tax credits and depletion, and in 2011, for the non-recurring items discussed above. (See Note 15. Income Tax Expense.)



Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires management to make various estimates and assumptions that affect amounts reported in the consolidated financial statements. These estimates and assumptions may be revised, which may have a material effect on the consolidated financial statements. Actual results may differ from these estimates and assumptions. These policies are discussed with the Audit Committee of our Board of Directors on a regular basis. The following represent the policies we believe are most critical to our business and the understanding of our results of operations. ALLETE 2013 Form 10-K 40

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Critical Accounting Policies (Continued)

Regulatory Accounting. Our regulated utility operations are accounted for in accordance with the accounting standards for the effects of certain types of regulation. These standards require us to reflect the effect of regulatory decisions in our financial statements. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral. This assessment considers factors such as, but not limited to, changes in the regulatory environment and recent rate orders to other regulated entities under the same jurisdiction. If future recovery or refund of costs becomes no longer probable, the assets and liabilities would be recognized in current period net income or other comprehensive income. (See Note 5. Regulatory Matters.) 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 several important assumptions, including the expected long-term rate of return on plan assets and the discount rate, among others, in determining our obligations and the annual cost of our pension and postretirement benefits. In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions and, utilizing the target allocation of our plan assets, forecast the expected long-term rate of return. Our pension asset allocation at December 31, 2013, was approximately 52 percent equity securities, 34 percent debt, 9 percent private equity, and 5 percent real estate. Our postretirement health and life asset allocation at December 31, 2013, was approximately 63 percent equity securities, 29 percent debt, and 8 percent private equity. Equity securities consist of a mix of market capitalization sizes with domestic and international securities. In 2013, we used expected long-term rates of return of 8.25 percent in our actuarial determination of our pension expense and 6.60 percent to 8.25 percent in our actuarial determination of our other postretirement expense. The actuarial determination uses an asset smoothing methodology for actual returns to reduce the volatility of varying investment performance over time. We review our expected long-term rate of return assumption annually and will adjust it to respond to changing market conditions. A one-quarter percent decrease in the expected long-term rate of return would increase the annual expense for pension and other postretirement benefits by approximately $1.4 million, pretax. The discount rate is computed using a yield curve adjusted for ALLETE's projected cash flows to match our plan characteristics. The yield curve is determined using high-quality, long-term corporate bond rates at the valuation date. In 2013, we used discount rates of 4.10 percent and 4.13 percent in our actuarial determination of our pension and other postretirement expense, respectively. 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 $2.2 million, pretax. (See Note 17. Pension and Other Postretirement Benefit Plans.) Impairment of Long-Lived Assets. We review our long-lived assets, which include the real estate assets of ALLETE Properties, for indicators of impairment in accordance with the accounting standards for property, plant and equipment on a quarterly basis. In accordance with the accounting standards for property, plant and equipment, if indicators of impairment exist, we test our 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 net 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, the holding period and timing of sales, the method of disposition and the 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, and may vary among, each land parcel or bulk sale. If the excess of undiscounted future net 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. 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 accounting standards for uncertainty in income taxes. We record a valuation allowance against our deferred tax assets to the extent it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. ALLETE 2013 Form 10-K 41 -------------------------------------------------------------------------------- Critical Accounting Policies (Continued) Taxation (Continued) We are subject to income taxes in various jurisdictions. We make assumptions and judgments each reporting period to estimate our income tax assets, liabilities, benefits, and expenses. Judgments and assumptions are supported by historical data and reasonable projections. Our assumptions and judgments include projections of our future federal and state taxable income, and state apportionment, to determine our ability to utilize NOL and credit carryforwards prior to their expiration. Significant changes in assumptions regarding future federal and state taxable income or change in tax rates could require new or increased valuation allowances which could result in a material impact on our results of operations. 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 minimum average earnings per share growth of 5 percent per year (using 2010 as a base year) and maintaining a competitive dividend payout. To accomplish this, Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with legislators and regulators to earn a fair rate of return. In addition, ALLETE expects to pursue new energy-centric initiatives that provide long-term earnings growth potential and balance our exposure to global business cycles and changing demand. The new energy-centric pursuits will be in renewable energy, energy transmission and other energy-related infrastructure or infrastructure services. We believe that, over the long-term, less carbon intensive and more sustainable energy sources will play an increasingly important role in our nation's energy mix. Minnesota Power has developed renewable resources which will be used to meet regulated renewable supply requirements and is adding another 205 MW at the Bison Wind Energy Center (see Regulated Operations - Renewable Energy). In addition, in 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, midstream gas and oil infrastructure, among other energy-related projects. ALLETE Clean Energy intends to market to electric utilities, cooperatives, municipalities, independent power marketers and large end-users across North America through long-term contracts or other sale arrangements, and will be subject to applicable state and federal regulatory approvals. We plan to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. This includes the GNTL, the CapX2020 initiative, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. Transmission investments could be made by Minnesota Power or a subsidiary of ALLETE. (See Regulated Operations - Transmission.) North American energy trends continue to evolve, and may be impacted by emerging technological, environmental, and demand changes. We believe this may create opportunity, and we are exploring investing in other energy-centric businesses related to energy infrastructure and infrastructure services. Our investment criteria focuses on investments with recurring or contractual revenues, differentiated offerings and reasonable barriers to entry. In addition, investments would typically support ALLETE's investment grade credit metrics and dividend policy. Regulated Operations. Minnesota Power's long-term strategy is to be the leading electric energy provider in northeastern Minnesota by providing safe, reliable and cost-competitive electric energy, while complying with environmental permit conditions and renewable requirements. Keeping the cost of energy production competitive enables Minnesota Power to effectively compete in the wholesale power markets and minimizes retail rate increases to help maintain 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 (see Regulated Operations - EnergyForward). We will monitor and review proposed environmental regulations and may challenge those that add considerable cost with limited environmental benefit. Minnesota Power will continue to pursue customer growth opportunities and cost recovery rider approval for environmental, renewable and transmission investments, as well as work with legislators and regulators to earn a fair rate of return. We project that our Regulated Operations will not earn its allowed rate of return in 2014. Regulatory Matters. Entities within our Regulated Operations segment are under the jurisdiction of the MPUC, the FERC or the PSCW. See Item 1. Business - Regulated Operations - Regulatory Matters for discussion of regulatory matters within our Minnesota, FERC, Wisconsin and North Dakota jurisdictions. ALLETE 2013 Form 10-K 42 --------------------------------------------------------------------------------



Outlook (Continued)

Industrial Customers. Electric power is one of several key inputs in the taconite mining, iron concentrate, paper, pulp and wood products, and pipeline industries. In 2013, 55 percent (57 percent in 2012) of our Regulated Utility kilowatt-hour sales were made to our industrial customers in these industries. Minnesota Power provides electric service to five taconite customers capable of producing up to approximately 41 million tons of taconite pellets annually. Taconite pellets produced in Minnesota are primarily shipped to North American steel making facilities that are part of the integrated steel industry. Steel produced from these North American facilities is used primarily in the manufacture of automobiles, appliances, pipe and tube products for the gas and oil industry, and in the construction industry. Historically, less than five percent of Minnesota taconite production is exported outside of North America. There has been a general historical correlation between U.S. steel production and Minnesota taconite production. 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, projected U.S. steel consumption in 2014 will be similar to 2013. The American Iron and Steel Institute (AISI), an association of North American steel producers, reported that U.S. raw steel production operated at approximately 77 percent of capacity in 2013 (75 percent in 2012, 75 percent in 2011). Based on these projections, 2014 taconite production levels in Minnesota are expected to be similar to 2013. The following table reflects Minnesota Power's taconite customers' production levels for the past ten years. Minnesota Power Taconite Customer Production Year Tons (Millions) 2013* 38 2012 39 2011 39 2010 35 2009 17 2008 39 2007 38 2006 39 2005 40 2004 39 Source: Minnesota Department of RevenueNovember 2013 Mining Tax Guide for years 2004 - 2012. * Preliminary data from the Minnesota Department of Revenue. Our taconite customers may experience annual variations in production levels due to such factors as economic conditions, short-term demand changes or maintenance outages. We estimate that a one million ton change in our taconite customers' production would change our annual earnings per share by approximately $0.03, net of expected power marketing sales at 2013 year-end prices. Changes in wholesale electric prices or customer contractual demand nominations could impact this estimate. Long-term reductions in production or a permanent shut down of a taconite customer may lead us to file a rate case to recover lost revenues. Similar to our taconite customers, three of four major paper mills ran at, or very near, full capacity in 2013 and similar levels are expected in 2014. Boise, Inc. (Boise) operates a paper mill in International Falls, Minnesota. In October 2013, Boise permanently shut down two paper machines representing approximately 20 percent of its paper making capacity. Boise's reduction in paper making capacity is not expected to have a material impact on the Company's consolidated financial position, results of operations, or cash flows. Prospective Additional Load. Minnesota Power is pursuing new wholesale and retail loads in and around its service territory. Currently, several companies in northeastern Minnesota continue to progress in the development of natural resource based projects that represent long-term growth potential and load diversity for Minnesota Power. These potential projects are in the ferrous and non-ferrous mining and steel industries and include Essar Steel Minnesota LLC (Essar), PolyMet, Mesabi Nugget, USS Corporation'sKeewatin taconite expansion and Magnetation. We cannot predict the outcome of these projects, but if these projects are constructed, Minnesota Power could serve up to approximately 500 MW of new retail or wholesale load. ALLETE 2013 Form 10-K 43 -------------------------------------------------------------------------------- Outlook (Continued) Industrial Customers (Continued) Nashwauk Public Utilities Commission. In May 2012, the Company entered into a new formula-based wholesale electric sales agreement with the Nashwauk Public Utilities Commission for all of its electric service requirements, effective through June 30, 2024. A new Essar taconite facility is currently under construction in the City of Nashwauk. This facility will result in up to approximately 110 MW of additional load for Minnesota Power. Essar has indicated plans for start-up in early 2015 and a move towards full production capacity levels during 2015. Expansions for additional pellet production, production of direct reduced iron and production of steel slabs are also being considered by Essar for future years. In addition, on February 11, 2013, Essar announced a ten-year iron ore pellet off-take agreement with ArcelorMittal. Under the terms of the agreement, Essar will supply approximately 3 million to 4 million metric tons of pellets annually to ArcelorMittal beginning with their facility startup in 2015. 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 began work on a Supplemental Draft Environmental Impact Statement (SDEIS) in 2010. The SDEIS addresses environmental issues, including those dealing with a land exchange between PolyMet and the U.S. Forest Service (USFS), which is critical to the mine site development. The Minnesota Department of Natural Resources, the U.S. Army Corps of Engineers and the USFS are co-lead agencies in the SDEIS process. The SDEIS was released on December 6, 2013, and the public review and comment period is scheduled to last until March 13, 2014. Assuming successful completion of the SDEIS process, permits could be issued during the latter part of 2014. Construction would commence immediately upon issuance of permits and Minnesota Power could begin to supply between 45 MW and 50 MW of load initially as early as 2016 through a 10-year power supply contract period that would begin upon start-up of the mining operations. Mesabi Nugget. The construction of the initial Mesabi Nugget facility is complete and production began in January 2010. Mesabi Nugget continues to pursue permits for taconite mining activities on lands formerly mined by Erie Mining Company and LTV Steel Mining Company near Hoyt Lakes, Minnesota. Upon receipt of permits to mine, Mesabi Nugget could mine and self-supply its own iron ore concentrate about a year later, which would result in increased electrical loads above our current 20 MW long-term power supply contract with Mesabi Nugget which lasts at least through 2017. In the meantime, Mesabi Nugget will receive iron ore concentrate from a new Mining Resources, LLC facility located near Chisholm, Minnesota. Keewatin Taconite (Keetac). USS Corporation has received environmental permits for a potential future expansion at its Keetac processing facility which could result in over 60 MW of additional load for Minnesota Power. USS Corporation continues to evaluate this project against its capital funding availability and market forecast expectations. Magnetation. Magnetation produces iron ore concentrate from low-grade natural ore tailing basins, already mined stockpiles and newly mined iron formations. Magnetation's facility near Taconite, Minnesota is fully operational. Construction is underway at their newest concentrate facility near Coleraine, Minnesota, with production expected to commence by the end of 2014. On January 27, 2014, Minnesota Power and Magnetation entered into a new ten-year electric service agreement, subject to MPUC approval, for its facility near Coleraine, Minnesota. This agreement will be effective one month following MPUC approval through December 31, 2025. In addition, a transmission service extension is required to be constructed and is expected to be complete in the fourth quarter of 2014. Minnesota Power expects to supply approximately 20 MW of power to this new facility, making it a Large Power Customer of Minnesota Power. The new facility is expected to supply iron ore concentrate to Magnetation's new pellet plant that is under construction in Reynolds, Indiana. The Reynolds pellet plant is expected to come on line in the second half of 2014 and will produce about 3 million tons of taconite pellets annually for AK Steel. ALLETE 2013 Form 10-K 44 --------------------------------------------------------------------------------



Outlook (Continued)

EnergyForward. In January 2013, Minnesota Power announced "EnergyForward", a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes completed and planned investments in wind and hydroelectric power, the addition of natural gas as a generation fuel source, and the installation of emissions control technology. Significant elements of the "EnergyForward" plan include:



Major wind investments in North Dakota. Our Bison Wind Energy Center has

292 MW of nameplate capacity with an additional 205 MW under construction

(see Renewable Energy).

Planned installation of approximately $310 million in emissions control

technology at our Boswell Unit 4 to further reduce emissions of SO2,

particulates and mercury (see Boswell Mercury Emission Reduction Plan).

Planning for the proposed GNTL to deliver hydroelectric power from northern Manitoba by 2020 (see Transmission).



The conversion of Laskin from coal to cleaner-burning natural gas in 2015.

Retiring Taconite Harbor Unit 3, one of three coal-fired units at Taconite

Harbor, in 2015.



Our "EnergyForward" initiatives were included in Minnesota Power's 2013 Integrated Resource Plan, which was approved by the MPUC in an order dated November 12, 2013. (See Item 1. Business - Regulated Operations - Regulatory Matters.)

Boswell Mercury Emissions Reduction Plan. Minnesota Power is implementing a mercury emissions reduction project for Boswell Unit 4 in order to comply with the Minnesota Mercury Emissions Reduction Act and the Federal MATS rule. In August 2012, Minnesota Power filed its mercury emissions reduction plan for Boswell Unit 4 with the MPUC and the MPCA. The plan proposes that Minnesota Power install pollution controls by early 2016 to address both the Minnesota mercury emissions reduction requirements and the Federal MATS rule. Costs to implement the Boswell Unit 4 mercury emissions reduction plan are included in the estimated capital expenditures required for compliance with the MATS rule and are estimated to be approximately $310 million. On November 5, 2013, the MPUC issued an order approving the Boswell Unit 4 mercury emissions reduction plan and cost recovery, establishing an environmental improvement rider. On November 25, 2013, environmental intervenors filed a petition for reconsideration with the MPUC which was subsequently denied in an order dated January 17, 2014. On December 20, 2013, we filed a petition with the MPUC to establish customer billing rates for the approved environmental improvement rider based on actual and estimated investments and expenditures, which is expected to be approved in the second quarter of 2014. Renewable Energy. In February 2007, Minnesota enacted a law requiring 25 percent of Minnesota Power's total retail and municipal energy sales in Minnesota be 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. The law allows the MPUC to modify or delay meeting a milestone if implementation will cause significant ratepayer cost or technical reliability issues. If a utility is not in compliance with a milestone, the MPUC may order the utility to construct facilities, purchase renewable energy or purchase renewable energy credits. Minnesota Power met the 2012 milestone and has developed a plan to meet the future renewable milestones which is included in its 2013 Integrated Resource Plan. Minnesota Power's 2013 Integrated Resource Plan, which was approved by the MPUC in an order dated November 12, 2013, included an update on its plans and progress in meeting the Minnesota renewable energy milestones through 2025. (See EnergyForward.) Minnesota Power continues to execute its renewable energy strategy through key renewable projects that will ensure we meet the identified state mandate at the lowest cost for customers. We expect 19 percent of the Company's total retail and municipal energy sales will be supplied by renewable energy sources in 2014. Wind Energy. Our wind energy facilities consist of the 292 MW Bison Wind Energy Center located in North Dakota and the 25 MW Taconite Ridge Energy Center located in northeastern Minnesota. We also have two long-term wind PPAs with an affiliate of NextEra Energy, Inc. to purchase the output from Oliver Wind I (50 MW) and Oliver Wind II (48 MW) located in North Dakota. We have also commenced construction of Bison 4, a 205 MW wind project in North Dakota, which is an addition to our Bison Wind Energy Center. On September 25, 2013, the NDPSC approved the site permit for Bison 4. The total project investment for Bison 4 is estimated to be approximately $345 million, of which $55.6 million was spent through December 31, 2013. The Bison 4 wind project is expected to be completed by the end of 2014. Customer billing rates for our 292 MW Bison Wind Energy Center were approved by the MPUC in an order dated December 3, 2013. On January 17, 2014, the MPUC approved Minnesota Power's petition seeking cost recovery for investments and expenditures related to Bison 4. We anticipate including Bison 4 as part of our renewable resources rider factor filing along with the Company's other renewable projects in the first quarter of 2014, which upon approval, authorizes updated rates to be included on customer bills. ALLETE 2013 Form 10-K 45 -------------------------------------------------------------------------------- Outlook (Continued) Renewable Energy (Continued) Minnesota Power uses the 465-mile, 250 kV DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota to transport increasing amounts of wind energy from North Dakota while gradually phasing out coal-based electricity delivered to our system over this transmission line from Square Butte's lignite coal-fired generating unit. The DC transmission line capacity can be increased if renewable energy or transmission needs justify investments to upgrade the line. Manitoba Hydro. Minnesota Power has a long-term PPA with Manitoba Hydro that expires in May 2015. Under this agreement Minnesota Power is purchasing 50 MW of capacity and 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 addition, Minnesota Power has a separate PPA with Manitoba Hydro to purchase surplus energy through April 2022. This energy-only agreement primarily consists of surplus hydro energy on Manitoba Hydro's system that is delivered to Minnesota Power on a non-firm basis. The pricing is based on forward market prices. Under this agreement with Manitoba Hydro, Minnesota Power will be purchasing at least one million MWh of energy over the contract term. In May 2011, Minnesota Power and Manitoba Hydro signed an additional long-term PPA, which provides for Manitoba Hydro to sell 250 MW of capacity and energy to Minnesota Power for 15 years beginning in 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. The agreement is subject to construction of additional transmission capacity between Manitoba and Minnesota's Iron Range. (See Regulated Operations - Transmission.) Hydro Operations. In June 2012, record rainfall and flooding occurred near Duluth, Minnesota and surrounding areas. The flooding impacted Minnesota Power'sSt. Louis River hydro system, particularly the Thomson Energy Center, which is currently off-line due to damage to the forebay canal and flooding at the facility. Minnesota Power continues to work in close contact with the appropriate regulatory bodies which oversee the hydro system operations, including dams and reservoirs, on restoring the Thomson facility and to rebuild the forebay embankment. The forebay rebuild cost is estimated to be approximately $25 million. In addition to the forebay work, Minnesota Power is performing restoration and upgrade work on electrical, mechanical and flow line systems at the Thomson facility, which is estimated to cost a total of approximately $40 million (net of anticipated insurance recoveries). Any expenditures to restore and upgrade systems and rebuild the forebay canal will be capitalized. Minnesota Power is working towards returning to partial generation from the Thomson Energy Center by the first half of 2014 and to full generation by the end of 2014. In addition to the work at the Thomson facility, additional work on the Thomson Dam and other facilities in the St. Louis River hydro system are necessary to meet high flow events like that experienced in June 2012, which is estimated to cost approximately $15 million through 2015. A request seeking cost recovery of capital expenditures related to the restoration and repair of the Thomson facility and other related St. Louis River hydro system projects through a renewable resources rider is expected to be filed with the MPUC in 2014. Minnesota Solar Mandate. In May 2013, legislation was enacted by the state of Minnesota requiring at least 1.5 percent of total retail electric sales, excluding sales to certain industrial customers, to be generated by solar energy by the end of 2020. At least ten percent of the 1.5 percent mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less. Minnesota Power is in the process of evaluating the potential impact of this legislation on our operations; however any investment is expected to be recovered in customer rates. Integrated Resource Plan. In an order dated November 12, 2013, the MPUC approved Minnesota Power's 2013 Integrated Resource Plan which details our "EnergyForward" strategic plan (see EnergyForward), and includes an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. Transmission. We plan to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. This includes the GNTL and the CapX2020 initiative, as well as investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others), and our investment in ATC. See also Item 1. Business - Regulated Operations.



Investments and Other

BNI Coal. In 2013, BNI Coal sold 3.7 million tons of coal (4.4 million tons in 2012) and anticipates 2014 sales will be similar to 2012. In 2013, a customer of BNI Coal incurred a scheduled major outage resulting in fewer tons sold. BNI Coal operates under a cost plus fixed fee agreement extending to May 1, 2027. ALLETE 2013 Form 10-K 46

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Outlook (Continued)

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, sell the portfolio when opportunities arise and reinvest the proceeds in our growth initiatives. Market conditions can impact land sales and could result in our inability to cover our operating expenses and fixed carrying costs such as community development district assessments and property taxes. ALLETE does not intend to acquire additional Florida real estate. Our two major development projects are Town Center and Palm Coast Park. Another major project, Ormond Crossings, is in the permitting stage. The City of Ormond Beach, Florida, approved a development agreement for Ormond Crossings which 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 (100% Owned) Residential Non-residential Land Available-for-Sale Acres (a) Units (b) Sq. Ft. (b,c) Current Development Projects Town Center 964 2,485 2,236,700 Palm Coast Park 3,777 3,554 3,096,800 Total Current Development Projects 4,741 6,039 5,333,500 Planned Development Project Ormond Crossings 2,914 2,950 3,215,000 Other Lake Swamp Wetland Mitigation Project 3,044 (d) (d) Total of Development Projects 10,699 8,989 8,548,500



(a) Acreage amounts are approximate and shown on a gross basis, including

wetlands.

(b) Units and square footage are estimated. Density at build out may differ from

these estimates.

(c) Depending on the project, non-residential includes retail commercial,

non-retail commercial, office, industrial, warehouse, storage and

institutional.

(d) The Lake Swamp wetland mitigation bank is a permitted, regionally significant

wetlands mitigation bank. Wetland mitigation credits will be used at Ormond

Crossings and are available-for-sale to developers of other projects that are

located in the bank's service area.

In addition to the three development projects and the mitigation bank, ALLETE Properties has 1,715 acres of other land available-for-sale.

ALLETE Clean Energy. On January 30, 2014, ALLETE Clean Energy acquired wind energy facilities located in Lake Benton, Minnesota (Lake Benton), Storm Lake, Iowa (Storm Lake) and Condon, Oregon (Condon) from The AES Corporation (AES) for approximately $27 million, subject to a working capital adjustment. The acquisition was financed with cash from operations. The necessary FERC approvals were received in December 2013. ALLETE Clean Energy also has an option to acquire a fourth wind facility from AES in Armenia Mountain, Pennsylvania (Armenia Mountain), in June 2015. The Lake Benton, Storm Lake and Condon facilities have 104 MW, 77 MW and 50 MW of generating capability, respectively. Lake Benton and Storm Lake began commercial operations in 1999, while Condon began operations in 2002. All three wind energy facilities have PPAs in place for their entire output, which expire in various years between 2019 and 2032. Pursuant to the acquisition agreement, ALLETE Clean Energy has an option to acquire the 101 MW Armenia Mountain wind energy facility from AES in June 2015. Armenia Mountain began operations in 2009. (See Note 7. Acquisitions.) In August 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. In July 2012, the MPUC issued an order approving certain administrative items related to accounting for shared services and the transfer of meteorological towers, while deferring decisions related to transmission and wind development rights pending the MPUC's further review of Minnesota Power's future retail electric service needs. ALLETE 2013 Form 10-K 47

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Outlook (Continued)

Income Taxes. ALLETE's aggregate federal and multi-state statutory tax rate is approximately 41 percent for 2013. On an ongoing basis, ALLETE has tax credits and other tax adjustments that reduce the statutory rate to the effective tax rate. These tax credits and adjustments historically have included items such as investment tax credits, renewable tax credits, AFUDC-Equity, depletion, as well as other items. The annual effective rate can also be impacted by such items as changes in income 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' tax matters. Due primarily to increased federal production tax credits as a result of wind generation, we expect our effective tax rate to be approximately 22 percent for 2014. We also expect that our effective tax rate will be lower than the statutory rate over the next ten years due to production tax credits attributable to our wind generation.



Liquidity and Capital Resources

Liquidity Position. ALLETE is well-positioned to meet the Company's liquidity needs. As of December 31, 2013, we had cash and cash equivalents of $97.3 million, $401.0 million in available consolidated lines of credit and a debt-to-capital ratio of 45 percent.

Capital Structure. ALLETE's capital structure for each of the last three years is as follows: As of December 31 2013 % 2012 % 2011 % Millions Common Equity $1,342.9 55 $1,201.0 54 $1,079.3 56 Long-Term Debt (Including Current Maturities) 1,110.2 45 1,018.1 46 863.3 44 Short-Term Debt - - - - 1.1 - $2,453.1 100 $2,219.1 100 $1,943.7 100 Cash Flows. Selected information from ALLETE's Consolidated Statement of Cash Flows is as follows: Year Ended December 31 2013 2012 2011 Millions Cash and Cash Equivalents at Beginning of Period $80.8$101.1$44.9 Cash Flows from (for) Operating Activities 239.4 239.6 241.7 Investing Activities (336.6 ) (420.1 ) (240.9 ) Financing Activities 113.7 160.2 55.4 Change in Cash and Cash Equivalents 16.5 (20.3 )



56.2

Cash and Cash Equivalents at End of Period $97.3$80.8$101.1

Operating Activities. Cash from operating activities in 2013 was similar to 2012 as higher net income and lower fuel inventories were offset by decreased other current liabilities due to higher receipts of customer security deposits in 2012 and increased cost recovery rider revenue receivables in 2013.



Cash from operating activities in 2012 was similar to 2011 as lower cash contributions to pension and other postretirement benefit plans ($8.8 million in 2012 and $24.7 million in 2011) were offset by higher cost recovery rider receivables in 2012 and income tax refunds received in 2011.

Investing Activities. The decrease in cash used for investing activities in 2013 from 2012 was primarily due to lower payments for capital expenditures and increased proceeds from sales of available-for-sale securities in 2013.

Cash used for investing activities in 2012 was higher than 2011 primarily due to higher capital expenditures in 2012 primarily related to our Bison Wind Energy Center. ALLETE 2013 Form 10-K 48

-------------------------------------------------------------------------------- Liquidity and Capital Resources (Continued) Cash Flows (Continued) Financing Activities. The decrease in cash from financing activities in 2013 compared to 2012 was primarily due to lower proceeds from long-term debt issuances and increased payments on long-term debt maturing in 2013, partially offset by increased common stock issuances in 2013.



Cash from financing activities was higher in 2012 compared to 2011 primarily due to increased proceeds from long-term debt and common stock issuances.

Working 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. On November 4, 2013, ALLETE entered into a $400.0 million credit agreement (Agreement). (See Note 11. Short-Term and Long-Term Debt.) The Agreement replaced our existing $250.0 million and $150.0 million credit facilities, which were originally scheduled to expire on June 30, 2015, and January 31, 2014, respectively. As of December 31, 2013, we had consolidated bank lines of credit aggregating $406.4 million ($401.0 million available as of December 31, 2013), the majority of which expire in November 2018. In addition, as of December 31, 2013, we have 2.5 million original issue shares of our common stock available for issuance through Invest Direct, our direct stock purchase and dividend reinvestment plan, and 3.1 million original issue shares of common stock available for issuance through a Distribution Agreement with Lampert Capital Markets, Inc. (successor to KCCI, Ltd.) The amount and timing of future sales of our securities will depend upon market conditions and our specific needs. Securities. We entered into a distribution agreement with Lampert Capital Markets, Inc. (successor to KCCI, Ltd.), in February 2008, as amended most recently in February 2014, with respect to the issuance and sale of up to an aggregate of 9.6 million shares of our common stock, without par value, of which 3.1 million shares remain available for issuance. For the year ended December 31, 2013, 1.3 million shares of common stock were issued under this agreement, resulting in net proceeds of $63.4 million (1.3 million shares for net proceeds of $53.1 million for the year ended December 31, 2012). The shares sold in 2011, 2012 and through August 1, 2013, were offered and sold pursuant to Registration Statement No. 333-170289. On August 2, 2013, we filed Registration Statement No. 333-190335, pursuant to which the remaining shares will continue to be offered for sale, from time to time. For the year ended December 31, 2013, we issued a total of 0.7 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 $34.8 million. These shares of common stock were registered under Registration Statement Nos. 333-188315, 333-183051 and 333-162890. On April 2, 2013, we issued $150.0 million of the Company's First Mortgage Bonds (Bonds) in a private placement in three series. (See Note 11. Short-Term and Long-Term Debt.) Proceeds from the sale of the Bonds were used to fund utility capital investments, repay debt, and/or for general corporate purposes. On August 26, 2013, we amended our $75 million Term Loan to extend the maturity date to August 25, 2015, and lower the interest rate from the one-month LIBOR plus 1.00 percent to the one-month LIBOR plus 0.875 percent. (See Note 11. Short-Term and Long-Term Debt.) On December 10, 2013, we agreed to sell $215.0 million in 2014 of ALLETE First Mortgage Bonds (Bonds) in the private placement market in four series. (See Note 11. Short-Term and Long-Term Debt.) Proceeds from the sale of the Bonds will be used to refinance debt, fund utility capital expenditures or for general corporate purposes.



Financial Covenants. See Note 11. Short-Term and Long-Term Debt for information regarding our financial covenants.

Off-Balance Sheet Arrangements. Off-balance sheet arrangements are discussed in Note 12. Commitments, Guarantees and Contingencies.

ALLETE 2013 Form 10-K 49 --------------------------------------------------------------------------------



Liquidity and Capital Resources (Continued)

Contractual Obligations and Commercial Commitments. ALLETE has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Following is a summarized table of contractual obligations and other commercial commitments as of December 31, 2013. Payments Due by Period Contractual Obligations Less than 1 to 3 4 to 5 After As of December 31, 2013 Total 1 Year Years Years 5 Years Millions Long-Term Debt $1,768.3$75.3$304.0$175.2$1,213.8 Pension (a) 379.5 33.9 107.6 76.5 161.5 Other Postretirement Benefit Plans (a) 94.1 7.7 26.4 19.3 40.7 Operating Lease Obligations 78.4 12.1 29.7 13.8 22.8 Uncertain Tax Positions (b) - - - - - Capital Purchase Obligations (c) 358.2 332.5 25.7 - - Other Purchase Obligations (d) 452.3 89.9 131.5 83.6 147.3 $3,130.8$551.4$624.9$368.4$1,586.1



(a) Represents the estimated future benefit payments for our defined benefit

pension and other postretirement plans through 2023.

(b) Excludes $1.2 million of non-current unrecognized tax benefits due to

uncertainty regarding the timing of future cash payments related to uncertain

tax positions.

(c) Consists mostly of capital expenditures related to our Bison 4 project and

the Boswell Unit 4 environmental upgrade.

(d) Excludes the agreement with Manitoba Hydro expiring in 2022, as this contract

is for surplus energy only. Also excludes the agreement with Manitoba Hydro

commencing in 2020, as our obligation under this contract is subject to the

construction of a hydro generation facility by Manitoba Hydro and additional

transmission capacity. Also, excludes Oliver Wind I and Oliver Wind II, as we

only pay for energy as it is delivered to us. (See Item 1. Business - Regulated Operations - Power Supply.) 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 rates in effect at December 31, 2013, remain constant through the remaining term. (See Note 11. Short-Term and Long-Term Debt.) Pension and Other Postretirement Benefit Plans. Our pension and other postretirement benefit plan obligations represent our current estimate of future benefit payments through 2023. Pension contributions will be dependent on several factors including realized asset performance, future discount rate and other actuarial assumptions, IRS and other regulatory requirements, and contributions required to avoid benefit restrictions for the pension plans. Funding for the other postretirement benefit plans is impacted by realized asset performance, future discount rate and other actuarial assumptions, and utility regulatory requirements. These amounts are estimates and will change based on actual market performance, changes in interest rates and any changes in governmental regulations. (See Note 17. Pension and Other Postretirement Benefit Plans.)



Capital Purchase Obligations. Capital purchase obligations represent our purchase obligations for certain capital expenditure projects. It includes capital expenditures related to our Bison 4 project, Boswell Unit 4 environmental upgrade and certain transmission projects. (See Note 12. Commitments, Guarantees and Contingencies.)

Other Purchase Obligations. Other purchase obligations represent our Square Butte, Manitoba Hydro and Minnkota Power purchase power contracts, and minimum purchase commitments under coal and rail contracts. (See Note 12. Commitments, Guarantees and Contingencies.) Under Minnesota 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 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. (See Note 12. Commitments, Guarantees and Contingencies.) ALLETE 2013 Form 10-K 50 -------------------------------------------------------------------------------- Liquidity and Capital Resources (Continued) Contractual Obligations and Commercial Commitments (Continued)



We have a PPA with Manitoba Hydro that expires in May 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 December 2012, Minnesota Power entered into a long-term PPA with Minnkota Power. Under this agreement Minnesota Power will purchase 50 MW of capacity and the energy associated with that capacity over the term June 1, 2016 through May 31, 2020. The agreement includes a fixed capacity charge and energy pricing that escalates at a fixed rate annually over the term. 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. Our current credit ratings are listed in the table below: Credit Ratings Standard & Poor's Moody's Issuer Credit Rating BBB+ A3 Commercial Paper A-2 P-2 Senior Secured First Mortgage Bonds (a) A A1



(a) Includes collateralized pollution control bonds.

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. Common Stock Dividends. ALLETE is committed to providing a competitive dividend to its shareholders while at the same time funding its 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 2013, we paid out 72 percent (71 percent in 2012; 67 percent in 2011) of our per share earnings in dividends. On January 30, 2014, our Board of Directors declared a dividend of $0.49 per share, which is payable on March 1, 2014, to shareholders of record at the close of business on February 14, 2014. ALLETE 2013 Form 10-K 51 --------------------------------------------------------------------------------



Liquidity and Capital Resources (Continued)

Capital Requirements

ALLETE's projected capital expenditures for the years 2014 through 2018 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, capital market conditions or executions of new business strategies.

Capital Expenditures 2014 2015 2016 2017 2018 Total Millions Regulated Utility Operations Base and Other $175$170$145$140$145$775 Cost Recovery (a) Environmental (b) 115 125 5 - - 245 Renewable (c) 285 - - - - 285 Transmission (d) 30 10 35 85 105 265 Total Cost Recovery 430 135 40 85 105 795



Regulated Utility Capital Expenditures 605 305 185 225 250

1,570 Other 35 15 10 25 20 105 Total Capital Expenditures $640$320$195$250$270$1,675



(a) Estimated capital expenditures eligible for cost recovery outside of a rate

case.

(b) Environmental capital expenditures primarily related to compliance with the

MATS rule for Boswell Unit 4 which reflect Minnesota Power's ownership percentage of 80 percent. (See Note 12. Commitments, Guarantees and Contingencies.)



(c) Related to Bison 4. (See Outlook - Regulated Operations.)

(d) Transmission capital expenditures related to construction of the GNTL are

estimated at approximately $230 million through 2018. (See Outlook - Regulated Operations.) Our 2014 projected capital expenditures include significant investments in environmental upgrades (see Outlook - Boswell Mercury Emissions Reduction Plan) and renewable energy (see Outlook - Renewable Energy - Wind Energy). Our 2014 capital expenditures are expected to be incurred ratably over the four quarters of 2014. We are well positioned to meet our financing needs due to adequate operating cash flows, available additional working capital, and access to capital markets. We will finance capital expenditures from a combination of internally generated funds and debt and equity issuance proceeds. We intend to maintain a capital structure with capital ratios near current levels. (See Liquidity and Capital Resources - Capital Structure.) Based on our projected capital expenditures reflected above, we project our rate base to grow by approximately 40 percent from 2013 year-end through 2018.



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 12. Commitments, Guarantees and Contingencies. (See Item 1. Business - Environmental Matters.)



Market Risk

Securities Investments

Available-for-Sale Securities. At December 31, 2013, our available-for-sale securities portfolio consisted of securities established to fund certain employee benefits. (See Note 8. Investments.)

ALLETE 2013 Form 10-K 52 -------------------------------------------------------------------------------- Liquidity and Capital Resources (Continued) Market Risk (Continued) Interest Rate Risk. We are exposed to risks resulting from changes in interest rates as a result of our issuance of variable rate debt. We manage our interest rate risk by varying the issuance and maturity dates of our fixed rate debt, limiting the amount of variable rate debt, and continually monitoring the effects of market changes in interest rates. We may also enter into derivative financial instruments, such as interest rate swaps, to mitigate interest rate exposure. The table below presents the long-term debt obligations and the corresponding weighted average interest rate at December 31, 2013. Expected Maturity



Date

Interest Rate Sensitive Financial Instruments 2014 2015 2016 2017 2018 Thereafter Total Fair Value Dollars in Millions Long-Term Debt Fixed Rate $20.4$52.3$22.3$51.8$1.7$822.9$971.4$996.0 Average Interest Rate - % 6.4 1.9 7.1 5.8 1.4



5.0 5.0

Variable Rate $6.8$90.7 - - - $41.3$138.8$138.8 Average Interest Rate - % (a) 4.5 0.9 - - -



0.1 0.8

(a) The $75 million term loan, which was amended in August 2013, matures in 2015.

It has an effective fixed rate of 1.70 percent through August 2014, and 1.625

percent for the remaining term due to an interest rate swap.

Interest rates on variable rate long-term debt are reset on a periodic basis reflecting prevailing market conditions. Based on the variable rate debt outstanding at December 31, 2013, and assuming no other changes to our financial structure, an increase of 100 basis points in interest rates would impact the amount of pretax interest expense by $0.6 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, 2013. Commodity Price Risk. Our regulated utility operations incur costs for power and fuel (primarily coal and related transportation) in Minnesota and power and natural gas purchased for resale in our regulated service territory in Wisconsin. Our Minnesota regulated utility's exposure to price risk for these commodities is significantly mitigated by the current ratemaking process and regulatory framework, which allows recovery of fuel costs in excess of those included in base rates. Conversely, costs below those in base 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 related transportation costs (Minnesota Power) and natural gas (SWL&P). Power Marketing. Our power marketing activities consist of: (1) purchasing energy in the wholesale market to serve our regulated service territory when energy requirements exceed generation output; 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 municipal customers in our regulated service territory. We actively sell any excess energy to the wholesale market to optimize the value of our generating facilities.



We are exposed to credit risk primarily through our power marketing activities. We use credit policies to manage credit risk, which includes utilizing an established credit approval process and monitoring counterparty limits.

Recently Adopted Accounting Standards.

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.

ALLETE 2013 Form 10-K 53



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Source: Edgar Glimpses


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