NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
Financial Statement Preparation.
References in this report to “we,” “us,” and “our” are to ALLETE and its subsidiaries, collectively. We prepare our financial statements in conformity with 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 the financial statements 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 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 and
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
.
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, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately
6,100
acres of land 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
2012
, Square Butte supplied
50 percent
(
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, sell the portfolio when opportunities arise and reinvest the proceeds in our 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. From time to time, certain contracts with customers allow us to receive participation revenue from land sales to third parties if various formula-based criteria are achieved.
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)
Land inventories are accounted for in accordance with the accounting standards for property, plant and equipment, 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 standards for 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 are recorded and the related assets are adjusted to their estimated fair value. (See Note 7. Investments.)
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 contracts or other sale arrangements, and will be subject to applicable state and federal regulatory approvals.
Non-Controlling Interest in Subsidiaries.
In August 2011, ALLETE purchased the remaining shares of the ALLETE Properties non-controlling interest at book value for
$8.8 million
by issuing
0.2 million
shares of ALLETE common stock. This was accounted for as an equity transaction, and no gain or loss was recognized in net income or comprehensive income.
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
|
|
|
|
Year Ended December 31
|
2012
|
|
2011
|
|
2010
|
|
Millions
|
|
|
|
Cash Paid During the Period for Interest – Net of Amounts Capitalized
|
|
$42.7
|
|
|
$43.2
|
|
|
$35.7
|
|
Cash Received During the Period for Income Taxes
(a)
|
—
|
|
$(11.4)
|
$(54.2)
|
Noncash Investing and Financing Activities
|
|
|
|
Increase in Accounts Payable for Capital Additions to Property, Plant and Equipment
|
|
$20.2
|
|
|
$5.9
|
|
$7.5
|
Capitalized Asset Retirement Costs
|
|
$17.1
|
|
|
$0.3
|
|
|
$2.8
|
|
AFUDC – Equity
|
|
$5.1
|
|
|
$2.5
|
|
|
$4.2
|
|
ALLETE Common Stock Contributed to the Pension Plan
|
—
|
|
$(20.0)
|
—
|
|
|
|
(a)
|
Due to bonus depreciation provisions in 2009 and 2010 federal legislation, NOLs were generated which resulted in little or 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
|
2012
|
|
|
2011
|
|
Millions
|
|
|
|
Trade Accounts Receivable
|
|
|
|
Billed
|
|
$70.4
|
|
|
|
$63.7
|
|
Unbilled
|
17.4
|
|
|
15.6
|
|
Less: Allowance for Doubtful Accounts
|
1.0
|
|
|
0.9
|
|
Total Trade Accounts Receivable
|
86.8
|
|
|
78.4
|
|
Income Taxes Receivable
|
2.2
|
|
|
1.3
|
|
Total Accounts Receivable - Net
|
|
$89.0
|
|
|
|
$79.7
|
|
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Concentration of Credit Risk.
Financial instruments that subject us to concentrations of credit risk consist primarily of accounts receivable. Minnesota Power sells electricity to
9
Large Power Customers. Receivables from these customers totaled
$11.6 million
at
December 31, 2012
(
$9.3 million
at
December 31, 2011
). 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
12.3 percent
of consolidated revenue in 2012 (
12.8 percent
in 2011;
12.5
percent in 2010). In the third quarter of 2011, one of Minnesota Power’s Large Power Customers, NewPage Corporation (NewPage), filed for Chapter 11 bankruptcy protection. In September 2012, NewPage submitted a motion to the bankruptcy court to approve amended and restated service agreements and payment of the pre-petition amount, which was approved on October 16, 2012. The agreement was subsequently approved by the MPUC in a December 10, 2012 order, which resulted in the pre-petition receivable of
$3.2 million
being paid as of
December 31, 2012
. Throughout the bankruptcy proceedings this customer’s operations continued without interruption and we continued to provide electric and steam service to this customer.
Long-Term Finance Receivables.
Long-term finance receivables relating to our real estate operations are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. We assess delinquent finance receivables by comparing the balance of such receivables to the estimated fair value of the collateralized property. If the fair value of the property is less than the finance receivable, we record a reserve for the difference. We estimate fair value based on recent property tax assessed values or current appraisals. (See Note 7. Investments.)
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. 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
|
2012
|
|
|
2011
|
|
Millions
|
|
|
|
Fuel
|
|
$28.0
|
|
|
|
$28.6
|
|
Materials and Supplies
|
41.8
|
|
|
40.5
|
|
Total Inventories
|
|
$69.8
|
|
|
|
$69.1
|
|
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 cost recovery for several large capital projects recently, at which time the recognition of AFUDC ceases. (See Note 3. Property, Plant and Equipment.)
We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed for the recovery of the remaining basis of retired plant assets. In January 2013 we announced the retirement of Taconite Harbor Unit 3 and conversion of Laskin Energy Center to natural gas in 2015, which is subject to MPUC approval. Accordingly, we do not expect any loss as a result of the retirement of Taconite Harbor Unit 3 or conversion of Laskin Energy Center.
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.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
Weak 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 (“Plan”). The Plan is reviewed annually for adjustment or modification and we have concluded that the estimates and assumptions remain appropriate in
2012
. As such, we continue to utilize the Plan when evaluating our land inventory for impairment. 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 anticipated in the 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 2012, impairment analysis’ of estimated future undiscounted cash flows were conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. As a result, there was
no
impairment recorded for the year ended
December 31, 2012
. For the year ended
December 31, 2011
, a
$1.7 million
impairment charge was recorded.
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.
Accounting for Stock-Based Compensation.
We apply the fair value recognition guidance for share-based payments. Under this guidance, we recognize stock-based compensation expense for all share-based payments granted, net of an estimated forfeiture rate. (See Note 16. Employee Stock and Incentive Plans.)
|
|
|
|
|
|
|
|
|
Prepayments and Other Current Assets
|
|
|
|
As of December 31
|
2012
|
|
|
2011
|
|
Millions
|
|
|
|
Deferred Fuel Adjustment Clause
|
|
$22.5
|
|
|
|
$17.5
|
|
Other
|
11.1
|
|
|
9.6
|
|
Total Prepayments and Other Current Assets
|
|
$33.6
|
|
|
|
$27.1
|
|
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
|
|
|
|
|
|
|
|
|
Other Current Liabilities
|
|
|
|
As of December 31
|
2012
|
|
|
2011
|
|
Millions
|
|
|
|
Customer Deposits
(a)
|
|
$28.8
|
|
|
|
$16.3
|
|
Other
|
33.8
|
|
|
29.3
|
|
Total Other Current Liabilities
|
|
$62.6
|
|
|
|
$45.6
|
|
|
|
(a)
|
Customer deposits were higher in 2012 primarily due to customer security deposits for capital expenditures relating to a transmission project.
|
|
|
|
|
|
|
|
|
|
Other Non-Current Liabilities
|
|
|
|
As of December 31
|
2012
|
|
|
2011
|
|
Millions
|
|
|
|
Asset Retirement Obligation
|
|
$77.9
|
|
|
|
$57.0
|
|
Other
|
45.4
|
|
|
48.1
|
|
Total Other Non-Current Liabilities
|
|
$123.3
|
|
|
|
$105.1
|
|
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.
Minnesota Power participates in MISO. MISO transactions are accounted for on a net hourly basis in each of the day-ahead and real-time markets. Minnesota Power records net sales in Operating Revenue and net purchases in Fuel and Purchased Power Expense on our Consolidated Statement of Income. The revenues and charges from MISO related to serving retail and municipal electric customers are recorded on a net basis as Fuel and Purchased Power Expense.
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 which approximates the effective interest method.
Income Taxes.
ALLETE and its subsidiaries file a consolidated federal income tax return and combined and separate state income tax returns. We account for income taxes using the liability method in accordance with the 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. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with the accounting standards for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more-likely-than-not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more-likely-than-not” means more than
50 percent
likely. (See Note 14. Income Tax Expense.)
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Excise Taxes.
We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.
New Accounting Standards.
There are no recently issued accounting standard updates applicable for our adoption in future periods.
NOTE 2. BUSINESS SEGMENTS
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. 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, hydro, natural gas/liquids, shale resources, clean coal and other clean energy innovations. This segment also includes other business development and corporate expenditures, a small amount of non-rate base generation, approximately
6,100
acres of land in Minnesota, and earnings on cash and investments. For a description of our reportable business segments, see Item 1. Business.
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
Regulated Operations
|
Investments and Other
|
Millions
|
|
|
|
2012
|
|
|
|
Operating Revenue
|
|
$961.2
|
|
|
$874.4
|
|
|
$86.8
|
|
Fuel and Purchased Power Expense
|
308.7
|
|
308.7
|
|
—
|
|
Operating and Maintenance Expense
|
397.1
|
|
310.0
|
|
87.1
|
|
Depreciation Expense
|
100.2
|
|
93.9
|
|
6.3
|
|
Operating Income (Loss)
|
155.2
|
|
161.8
|
|
(6.6
|
)
|
Interest Expense
|
(45.5
|
)
|
(39.8
|
)
|
(5.7
|
)
|
Equity Earnings in ATC
|
19.4
|
|
19.4
|
|
—
|
|
Other Income
|
6.0
|
|
5.1
|
|
0.9
|
|
Income (Loss) Before Non-Controlling Interest and Income Taxes
|
135.1
|
|
146.5
|
|
(11.4
|
)
|
Income Tax Expense (Benefit)
|
38.0
|
|
50.4
|
|
(12.4
|
)
|
Net Income
|
97.1
|
|
96.1
|
|
1.0
|
|
Less: Non-Controlling Interest in Subsidiaries
|
—
|
|
—
|
|
—
|
|
Net Income Attributable to ALLETE
|
|
$97.1
|
|
|
$96.1
|
|
|
$1.0
|
|
Total Assets
|
|
$3,253.4
|
|
|
$2,962.4
|
|
|
$291.0
|
|
Capital Additions
|
|
$432.2
|
|
|
$418.2
|
|
|
$14.0
|
|
NOTE 2. BUSINESS SEGMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
Regulated Operations
|
Investments and Other
|
Millions
|
|
|
|
2011
|
|
|
|
Operating Revenue
|
|
$928.2
|
|
|
$851.9
|
|
|
$76.3
|
|
Fuel and Purchased Power Expense
|
306.6
|
|
306.6
|
|
—
|
|
Operating and Maintenance Expense
|
381.2
|
|
301.5
|
|
79.7
|
|
Depreciation Expense
|
90.4
|
|
85.4
|
|
5.0
|
|
Operating Income (Loss)
|
150.0
|
|
158.4
|
|
(8.4
|
)
|
Interest Expense
|
(43.6
|
)
|
(35.8
|
)
|
(7.8
|
)
|
Equity Earnings in ATC
|
18.4
|
|
18.4
|
|
—
|
|
Other Income
|
4.4
|
|
2.6
|
|
1.8
|
|
Income (Loss) Before Non-Controlling Interest and Income Taxes
|
129.2
|
|
143.6
|
|
(14.4
|
)
|
Income Tax Expense (Benefit)
|
35.6
|
|
43.2
|
|
(7.6
|
)
|
Net Income (Loss)
|
93.6
|
|
100.4
|
|
(6.8
|
)
|
Less: Non-Controlling Interest in Subsidiaries
|
(0.2
|
)
|
—
|
|
(0.2
|
)
|
Net Income (Loss) Attributable to ALLETE
|
|
$93.8
|
|
|
$100.4
|
|
$(6.6)
|
Total Assets
|
|
$2,876.0
|
|
|
$2,579.8
|
|
|
$296.2
|
|
Capital Additions
|
|
$246.8
|
|
|
$228.0
|
|
|
$18.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
NOTE 3. PROPERTY, PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
As of December 31
|
2012
|
|
2011
|
Millions
|
|
|
|
Regulated Utility
|
|
$3,232.9
|
|
|
|
$2,794.8
|
|
Construction Work in Progress
|
151.8
|
|
|
155.0
|
|
Accumulated Depreciation
|
(1,102.8
|
)
|
|
(1,024.6
|
)
|
Regulated Utility Plant - Net
|
2,281.9
|
|
|
1,925.2
|
|
Non-Rate Base Energy Operations
|
118.0
|
|
|
106.4
|
|
Construction Work in Progress
|
4.2
|
|
|
2.3
|
|
Accumulated Depreciation
|
(56.7
|
)
|
|
(51.4
|
)
|
Non-Rate Base Energy Operations Plant - Net
|
65.5
|
|
|
57.3
|
|
Other Plant - Net
|
0.2
|
|
|
0.2
|
|
Property, Plant and Equipment - Net
|
|
$2,347.6
|
|
|
|
$1,982.7
|
|
Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.
|
|
|
|
|
|
Estimated Useful Lives of Property, Plant and Equipment
|
|
|
|
|
|
Regulated Utility –
|
Generation
|
3 to 35 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 coal-fired and wind generating facilities and land reclamation at BNI Coal, and are included in other non-current liabilities on our Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.
Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, 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 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, 2010
|
|
|
$50.3
|
|
Accretion Expense
|
|
6.4
|
|
Additional Liabilities Incurred in 2011
|
|
0.3
|
|
Obligation as of December 31, 2011
|
|
57.0
|
|
Accretion Expense
|
|
3.8
|
|
Additional Liabilities Incurred in 2012
|
|
17.1
|
|
Obligation as of December 31, 2012
|
|
|
$77.9
|
|
NOTE 4. JOINTLY-OWNED FACILITIES
Following are our investments in jointly-owned facilities and the related ownership percentages as of
December 31, 2012
:
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Utility Plant
|
Plant in Service
|
Accumulated Depreciation
|
Construction Work in Progress
|
% Ownership
|
Millions
|
|
|
|
|
Boswell Unit 4
|
|
$413.1
|
|
|
$188.1
|
|
|
$25.0
|
|
80
|
CapX2020
|
22.8
|
|
0.4
|
|
25.4
|
|
9.3 - 14.7
|
Total
|
|
$435.9
|
|
|
$188.5
|
|
|
$50.4
|
|
|
We own
80 percent
of the
585
MW Boswell Unit 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 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. We are a participant in the CapX2020 initiative to ensure reliable electric transmission and distribution in the region surrounding our rate-regulated operations in Minnesota, along with other electric cooperatives, municipals, and 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.
2010 Minnesota Rate Case.
Minnesota Power’s current retail rates are based on a 2011 MPUC retail rate order, effective June 1, 2011, that allowed for a
10.38 percent
return on common equity and a
54.29 percent
equity ratio.
In February 2011, Minnesota Power appealed the MPUC’s interim rate decision in the Company’s 2010 rate case to the Minnesota Court of Appeals. The Company appealed the MPUC’s finding of exigent circumstances in the interim rate decision with the primary arguments being 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 (Court). On February 14, 2012, the Court granted the petition for review and oral arguments were held before the Court on October 9, 2012. A decision is expected in early 2013; however, we cannot predict the outcome at this time.
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. Minnesota Power’s formula-based contract with the City of Nashwauk is effective April 1, 2013 through June 30, 2024, and the restated formula-based contracts with the remaining 15 Minnesota municipal customers and SWL&P are effective through June 30, 2019. The rates included in these contracts are calculated using a cost-based formula methodology that is set each July 1, using estimated costs and a rate of return that is equal to our authorized rate of return for Minnesota retail customers (currently
10.38 percent
). The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred. The 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 July 1, 2021. 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 December 31, 2011, this customer submitted a cancellation notice with termination effective on December 31, 2013. The
17
MW of average monthly demand provided to this customer is expected to be used to supply energy to prospective customers beginning in 2014.
2012 Wisconsin Rate Case.
During 2012, SWL&P’s retail rates were based on a 2010 PSCW retail rate order, which was effective
January 1, 2011
. SWL&P’s 2013 retail rates are based on a 2012 PSCW retail rate order, effective January 1, 2013, and allows for a
10.9
percent return on common equity. The new rates reflect an average overall increase of
2.4
percent for retail customers (a
13.8
percent increase in water rates, a
1.2
percent increase in electric rates, and a
2.0
percent decrease in natural gas rates). On an annualized basis, the rate increase will generate approximately
$1.7 million
in additional revenue.
NOTE 5. REGULATORY MATTERS (Continued)
Rapids Energy Center.
On December 19, 2012, Minnesota Power filed with the MPUC for approval to transfer the assets of Rapids Energy Center from non-rate base generation to Minnesota Power’s Regulated Operations. Rapids Energy Center is a generation facility that is located at the UPM, Blandin Paper Mill (Blandin). Minnesota Power and Blandin entered into a new electric service agreement in September 2012 which is also subject to MPUC approval. We expect a decision from the MPUC on these filings in mid-2013.
ALLETE Clean Energy.
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 between the parties, 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. On July 23, 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.
Boswell Mercury Emissions Reduction Plan.
Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 under the Minnesota Mercury Emissions Reduction and the Federal MATS rule. On August 31, 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 between
$350 million
and
$400 million
. The MPCA has 180 days to comment on the mercury emissions reduction plan, which then is reviewed by the MPUC for a decision. We expect a decision by the MPUC on the plan in the third quarter of 2013. After approval by the MPUC we anticipate filing a petition to include investments and expenditures in customer billing rates.
The Patient Protection and Affordable Care Act of 2010 (PPACA).
In March 2010, the 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 which 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 the PPACA. In May 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
in the second quarter of 2011.
Pension.
In December 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
. On February 14, 2013, the MPUC denied the Company's petition for recovery of the pension asset and deferral of expenses outside of a general rate case. The MPUC decision does not impact the results of operations for the year ended December 31, 2012.
Regulatory Assets and Liabilities.
Our regulated utility operations are subject to the accounting guidance for Regulated Operations. We capitalize incurred costs which are probable of recovery in future utility rates as regulatory assets. Regulatory liabilities
represent amounts expected to be refunded or credited to customers in rates. No regulatory assets or liabilities are currently earning a return.
NOTE 5. REGULATORY MATTERS (Continued)
|
|
|
|
|
|
|
|
Regulatory Assets and Liabilities
|
|
|
As of December 31
|
2012
|
2011
|
Millions
|
|
|
Current Regulatory Assets
(a)
|
|
|
Deferred Fuel
|
|
$22.5
|
|
|
$17.5
|
|
Total Current Regulatory Assets
|
22.5
|
|
17.5
|
|
Non-Current Regulatory Assets
|
|
|
Future Benefit Obligations Under
|
|
|
Defined Benefit Pension and Other Postretirement Plans
|
260.7
|
|
292.8
|
|
Income Taxes
|
36.0
|
|
28.6
|
|
Asset Retirement Obligation
|
12.1
|
|
9.8
|
|
Cost Recovery Riders
(b)
|
18.5
|
|
0.7
|
|
PPACA Income Tax Deferral
|
5.0
|
|
5.0
|
|
Conservation Improvement Program
|
4.3
|
|
4.6
|
|
Other
|
3.7
|
|
4.4
|
|
Total Non-Current Regulatory Assets
|
340.3
|
|
345.9
|
|
|
|
|
Total Regulatory Assets
|
|
$362.8
|
|
|
$363.4
|
|
|
|
|
Non-Current Regulatory Liabilities
|
|
|
Income Taxes
|
|
$19.5
|
|
|
$21.9
|
|
Plant Removal Obligations
|
18.1
|
|
15.0
|
|
Wholesale and Retail Contra AFUDC
|
15.5
|
|
1.5
|
|
Other
|
7.0
|
|
5.1
|
|
Total Non-Current Regulatory Liabilities
|
|
$60.1
|
|
|
$43.5
|
|
|
|
(a)
|
Current regulatory assets are included in prepayments and other on our Consolidated Balance Sheet.
|
|
|
(b)
|
The increase in cost recovery rider regulatory assets in 2012 is primarily due to revenues related to our Bison Wind Energy Center.
|
NOTE 6. INVESTMENT IN ATC
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 rates are FERC-approved and 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, 2012
, our equity investment in ATC was
$107.3 million
(
$98.9 million
at
December 31, 2011
). On January 30, 2013, we invested an additional
$0.4 million
in ATC. In total, we expect to invest approximately
$2.0 million
throughout
2013
.
|
|
|
|
|
|
|
|
ALLETE’s Interest in ATC
|
|
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Equity Investment Beginning Balance
|
|
$98.9
|
|
|
$93.3
|
|
Cash Investments
|
4.7
|
|
2.0
|
|
Equity in ATC Earnings
|
19.4
|
|
18.4
|
|
Distributed ATC Earnings
|
(15.7
|
)
|
(14.8
|
)
|
Equity Investment Ending Balance
|
|
$107.3
|
|
|
$98.9
|
|
NOTE 6. INVESTMENT IN ATC (Continued)
|
|
|
|
|
|
|
|
ATC Summarized Financial Data
|
|
|
Balance Sheet Data
|
|
|
As of December 31
|
2012
|
2011
|
Millions
|
|
|
Current Assets
|
|
$63.1
|
|
|
$58.7
|
|
Non-Current Assets
|
3,274.7
|
|
3,053.7
|
|
Total Assets
|
|
$3,337.8
|
|
|
$3,112.4
|
|
Current Liabilities
|
|
$251.5
|
|
|
$298.5
|
|
Long-Term Debt
|
1,550.0
|
|
1,400.0
|
|
Other Non-Current Liabilities
|
95.8
|
|
82.6
|
|
Members’ Equity
|
1,440.5
|
|
1,331.3
|
|
Total Liabilities and Members’ Equity
|
|
$3,337.8
|
|
|
$3,112.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement Data
|
|
|
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Revenue
|
|
$603.2
|
|
|
$567.2
|
|
|
$556.7
|
|
Operating Expense
|
281.0
|
|
261.6
|
|
251.1
|
|
Other Expense
|
84.8
|
|
81.7
|
|
85.9
|
|
Net Income
|
|
$237.4
|
|
|
$223.9
|
|
|
$219.7
|
|
ALLETE’s Equity in Net Income
|
|
$19.4
|
|
|
$18.4
|
|
|
$17.9
|
|
NOTE 7. INVESTMENTS
Investments.
At
December 31, 2012
, 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, and other assets consisting primarily of cash equivalents and land in Minnesota.
|
|
|
|
|
|
|
|
|
Investments
|
|
|
|
As of December 31
|
2012
|
|
2011
|
Millions
|
|
|
|
ALLETE Properties
|
|
$91.1
|
|
|
|
$91.3
|
|
Available-for-sale Securities
|
26.8
|
|
|
24.7
|
|
Other
|
25.6
|
|
|
16.3
|
|
Total Investments
|
|
$143.5
|
|
|
|
$132.3
|
|
NOTE 7. INVESTMENTS (Continued)
|
|
|
|
|
|
|
|
|
ALLETE Properties
|
|
|
|
As of December 31
|
2012
|
|
2011
|
Millions
|
|
|
|
Land Inventory Beginning Balance
|
|
$86.0
|
|
|
|
$86.0
|
|
Deeds to Collateralized Property
|
0.5
|
|
|
1.8
|
|
Land Impairment
|
—
|
|
|
(1.7
|
)
|
Cost of Sales
|
(0.2
|
)
|
|
(0.3
|
)
|
Capitalized Improvements and Other
|
0.2
|
|
|
0.2
|
|
Land Inventory Ending Balance
|
86.5
|
|
|
86.0
|
|
Long-Term Finance Receivables (net of allowances of $0.6 and $0.6)
|
1.4
|
|
|
2.0
|
|
Other
|
3.2
|
|
|
3.3
|
|
Total Real Estate Assets
|
|
$91.1
|
|
|
|
$91.3
|
|
Land Inventory.
Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to fair value. Land values are reviewed for impairment on a quarterly basis. In 2012, impairment analysis’ of estimated future undiscounted cash flows was conducted and indicated that the cash flows were adequate to recover the carrying basis of our land inventory. Consequently, there was
no
impairment recorded for the year ended
December 31, 2012
. For the year ended
December 31, 2011
, a
1.7 million
impairment charge was recorded.
Long-Term Finance Receivables
. As of
December 31, 2012
, long-term finance receivables were
$1.4 million
net of allowance (
$2.0 million
net of allowance as of
December 31, 2011
). 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 finance receivables. Long-term finance receivables are collateralized by property sold, accrue interest at market-based rates and are net of an allowance for doubtful accounts. As of
December 31, 2012
, we had allowance for doubtful accounts of
$0.6 million
(
$0.6 million
as of
December 31, 2011
).
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. Contract purchasers may incur significant costs during due diligence, planning, designing and marketing the property before the contract closes, therefore they may 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. Our auction rate securities of
$6.7 million
were redeemed at carrying value on January 5, 2011.
|
|
|
|
|
|
Available-For-Sale Securities
|
Millions
|
|
Gross Unrealized
|
|
As of December 31
|
Cost
|
Gain
|
(Loss)
|
Fair Value
|
2012
|
$27.4
|
$0.5
|
$(1.1)
|
$26.8
|
2011
|
$27.3
|
$0.1
|
$(2.7)
|
$24.7
|
2010
|
$27.4
|
$0.2
|
$(2.4)
|
$25.2
|
|
|
|
|
|
|
|
Net
|
Gross Realized
|
Net Unrealized
Gain (Loss) in Other
|
Year Ended December 31
|
Proceeds
|
Gain
|
(Loss)
|
Comprehensive Income
|
2012
|
$1.5
|
—
|
—
|
$1.2
|
2011
|
$7.8
|
—
|
—
|
$(0.3)
|
2010
|
$0.6
|
—
|
—
|
$0.8
|
NOTE 8. DERIVATIVES
During the third quarter of 2011, we entered into a variable-to-fixed interest rate swap (Swap), designated as a cash flow hedge, in order to manage the interest 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
8 percent
of the Company’s outstanding long-term debt as of
December 31, 2012
. (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 are expected to be highly effective in offsetting the variable interest expense of the debt attributable to fluctuations in the one-month LIBOR 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 with respect to that derivative.
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, 2012.
The mark-to-market fluctuation on the cash flow hedge was recorded in accumulated other comprehensive income on the Consolidated Balance Sheet. As of
December 31, 2012
, the fair value of the swap was a
$0.7 million
liability (a
$0.4 million
liability as of
December 31, 2011
) and is included in other non-current liabilities on the Consolidated Balance Sheet. Cash flows from derivative activities are presented in the same category as the item being hedged on the Consolidated Statement of Cash Flows. Amounts recorded in other comprehensive income related to cash flow hedges will be recognized in earnings when the hedged 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 interest expense on the Consolidated Statement of Income.
NOTE 9. FAIR VALUE
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily 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.
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 included ARS consisting of guaranteed student loans.
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, 2012
and
December 31, 2011
. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of cash and cash equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore are excluded from the recurring fair value measures in the tables below.
NOTE 9. FAIR VALUE (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of December 31, 2012
|
Recurring Fair Value Measures
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Millions
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
Available-for-sale Securities – Equity Securities
|
|
$18.0
|
|
|
—
|
|
|
—
|
|
|
|
$18.0
|
|
Available-for-sale Securities – Corporate Debt Securities
|
—
|
|
|
|
$8.8
|
|
|
—
|
|
|
8.8
|
|
Cash Equivalents
|
20.7
|
|
|
—
|
|
|
—
|
|
|
20.7
|
|
Total Fair Value of Assets
|
|
$38.7
|
|
|
|
$8.8
|
|
|
—
|
|
|
|
$47.5
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
Deferred Compensation
|
—
|
|
|
|
$14.0
|
|
|
—
|
|
|
|
$14.0
|
|
Derivatives – Interest Rate Swap
|
—
|
|
|
0.7
|
|
|
—
|
|
|
0.7
|
|
Total Fair Value of Liabilities
|
—
|
|
|
|
$14.7
|
|
|
—
|
|
|
|
$14.7
|
|
Total Net Fair Value of Assets (Liabilities)
|
|
$38.7
|
|
|
$(5.9)
|
|
—
|
|
|
|
$32.8
|
|
There was
no
activity in Level 3 during the year ended December 31, 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of December 31, 2011
|
Recurring Fair Value Measures
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Millions
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
Available-for-sale Securities – Equity Securities
|
|
$17.6
|
|
|
—
|
|
|
—
|
|
|
|
$17.6
|
|
Available-for-sale Securities – Corporate Debt Securities
|
—
|
|
|
|
$8.2
|
|
|
—
|
|
|
8.2
|
|
Cash Equivalents
|
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
|
|
|
|
|
|
|
Recurring Fair Value Measures
Activity in Level 3
|
Debt Securities
Issued by States
of the United
States (ARS)
|
Millions
|
|
Balance as of December 31, 2010
|
|
$6.7
|
|
Redeemed During the Period
(a)
|
(6.7
|
)
|
Balance as of December 31, 2011
|
|
$—
|
|
|
|
(a)
|
The ARS were redeemed at carrying value on January 5, 2011.
|
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 years ended
December 31, 2012
and
2011
, there were
no
transfers in or out of Levels 1, 2 or 3.
NOTE 9. FAIR VALUE (Continued)
Fair Value of Financial Instruments.
With the exception of the items listed in the table 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 (Level 2).
|
|
|
|
|
|
|
|
Financial Instruments
|
Carrying Amount
|
Fair Value
|
Millions
|
|
|
Long-Term Debt, Including Current Portion
|
|
|
December 31, 2012
|
|
$1,018.1
|
|
|
$1,143.7
|
|
December 31, 2011
|
|
$863.3
|
|
|
$966.4
|
|
NOTE 10. SHORT-TERM AND LONG-TERM DEBT
Short-Term Debt.
Total short-term debt outstanding as of
December 31, 2012
, was
$84.5 million
(
$6.5 million
at
December 31, 2011
) and consisted of long-term debt due within one year and notes payable. As of December 31, 2012, short-term debt increased from December 31, 2011, primarily due to
$60.0 million
of long-term debt maturing in April 2013.
As of
December 31, 2012
, we had bank lines of credit aggregating
$406.4 million
(
$256.4 million
at
December 31, 2011
), of which
$150.0 million
expires in January 2014, and
$250.0 million
expires in June 2015. These bank lines of credit are available to provide short-term bank loans and liquidity support for ALLETE’s commercial paper program and to issue up to
$50.0 million
in letters of credit. We had
no
outstanding draws on our lines of credit as of
December 31, 2012
(
$1.1 million
at
December 31, 2011
).
On February 1, 2012, ALLETE entered into a
$150.0 million
credit agreement (Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and several other lenders that are parties thereto. The Agreement is unsecured and has a maturity date of January 31, 2014, which may be extended for one year, subject to bank approvals. Advances under the Agreement may be used for general corporate purposes, to provide liquidity support for ALLETE’s commercial paper program and to issue up to
$10.0 million
in letters of credit.
Long-Term Debt.
Total long-term debt outstanding as of
December 31, 2012
, was
$933.6 million
(
$857.9 million
at
December 31, 2011
). The aggregate amount of long-term debt maturing during
2013
is
$84.5 million
(
$94.8 million
in
2014
;
$17.4 million
in
2015
;
$21.7 million
in
2016
;
$51.2 million
in
2017
; and
$748.5 million
thereafter). Substantially all of our electric plant is subject to the lien of the mortgage collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.
On July 2, 2012, we issued
$160.0 million
of the Company’s First Mortgage Bonds (Bonds) in the private placement market in two series as follows:
|
|
|
|
|
Issue Date
|
Maturity Date
|
Principal Amount
|
Interest Rate
|
July 2, 2012
|
July 15, 2026
|
$75 Million
|
3.20%
|
July 2, 2012
|
July 15, 2042
|
$85 Million
|
4.08%
|
We have the option to prepay all or a portion of the
3.20
percent Bonds at our discretion at any time prior to January 15, 2026, subject to a make-whole provision, and at any time on or after January 15, 2026, at par, including, in each case, accrued and unpaid interest. We also have the option to prepay all or a portion of the
4.08
percent Bonds at our discretion at any time prior to January 15, 2042, subject to a make-whole provision, and at any time on or after January 15, 2042, at par, including, in each case, accrued and unpaid interest. The Bonds are subject to the additional terms and conditions of our utility mortgage. In July 2012, we used a portion of the proceeds from the sale of the Bonds to redeem
$6.0 million
of our
6.50 percent
Industrial Development Revenue Bonds and to repay
$14.0 million
in outstanding borrowings on our
$150.0 million
line of credit. The remaining proceeds were used to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to certain institutional accredited investors.
NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
As of December 31
|
2012
|
2011
|
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
|
|
3.20% Series Due 2026
|
75.0
|
|
—
|
|
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
|
|
4.08% Series Due 2042
|
85.0
|
|
—
|
|
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 2013 – 2020
|
27.5
|
|
28.2
|
|
Industrial Development Revenue Bonds 6.5% Due 2025
|
—
|
|
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
|
|
75.0
|
|
Other Long-Term Debt, 1.0% – 8.0% Due 2013 – 2037
|
41.8
|
|
40.3
|
|
Total Long-Term Debt
|
1,018.1
|
|
863.3
|
|
Less: Due Within One Year
|
84.5
|
|
5.4
|
|
Net Long-Term Debt
|
|
$933.6
|
|
|
$857.9
|
|
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 Indebtedness to Total Capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to
0.65 to 1.00
measured quarterly. As of
December 31, 2012
, our ratio was approximately
0.46 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, 2012
, ALLETE was in compliance with its financial covenants.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES
Power Purchase Agreements.
Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs, or where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)
Square Butte PPA.
Minnesota Power has a PPA 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 reserve requirements. Square Butte, a North Dakota cooperative corporation, owns a
455
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.
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, 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 costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of
December 31, 2012
, Square Butte had total debt outstanding of
$416.9 million
. Annual debt service for Square Butte is expected to be approximately
$44 million
in each of the next five years,
2013
through
2017
, of which Minnesota Power’s obligation is
50 percent
. Fuel expenses are recoverable through our fuel adjustment clause and include the cost of coal purchased from BNI Coal, under a long-term contract.
Minnesota Power’s cost of power purchased from Square Butte during
2012
was
$67.1 million
(
$61.2 million
in
2011
;
$55.2 million
in
2010
). This reflects Minnesota Power’s pro rata share of total Square Butte costs based on the
50 percent
output entitlement. Included in this amount was Minnesota Power’s pro rata share of interest expense of
$11.1 million
in
2012
(
$11.1 million
in
2011
;
$10.2 million
in
2010
). 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 December 2009, Minnesota Power entered into a power sales agreement with Minnkota Power. Under the power sales agreement, Minnesota Power will sell a portion of its output from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of
2025
.
No power will be sold under the 2009 agreement until Minnkota Power has placed in service a new AC transmission line, which is anticipated to occur in late
2013
. This new AC transmission line will allow Minnkota Power to transmit its entitlement from Square Butte directly to its customers, which in turn will enable Minnesota Power the ability to transmit additional wind generation on the existing DC transmission line.
Minnkota Power PPA.
On December 12, 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.
Oliver Wind I and II PPAs.
In 2006 and 2007, Minnesota Power entered into 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)—wind facilities located near Center, North Dakota. Each agreement is for
25
years and provides for the purchase of all output from the facilities at fixed energy prices. There are
no
fixed capacity charges and we only pay for energy as it is delivered to us.
Manitoba Hydro PPAs.
Minnesota Power has a long-term 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.
Minnesota Power has a separate long-term 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, Minnesota Power will purchase at least
one million
MWh of energy over the contract term.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)
In May 2011, Minnesota Power and Manitoba Hydro signed an additional 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 is subject to construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. 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.
In February 2012, Minnesota Power and Manitoba Hydro proposed construction of the Great Northern Transmission Line, a
500
kV transmission line between Manitoba and Minnesota’s Iron Range in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy, which is targeted to be in service in 2020. Total project cost and cost allocations are still to be determined.The Great Northern Transmission Line is subject to various federal and state regulatory approvals. In addition, Manitoba Hydro must obtain regulatory and governmental approvals related to new transmission lines and hydroelectric generation development in Canada.
North Dakota Wind Development
.
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.
Our Bison Wind Energy Center in North Dakota consists of
292
MW of nameplate capacity. Bison 1 is an
82
MW wind facility in North Dakota, which was completed in two phases. The first phase was completed in 2010, and the second phase was completed in January 2012. The project also included construction of a
22
-mile,
230
kV transmission line. Bison 1 had a total project cost of
$174.9 million
through
December 31, 2012
, including additional costs related to land restoration and completion of remaining associated upgrades to the
250
kV DC transmission line.
The
105
MW Bison 2 and 105 MW Bison 3 wind facilities in North Dakota were completed in December 2012. Total project costs for Bison 2 and Bison 3 were
$148.6 million
and
$149.8 million
, respectively, through
December 31, 2012
. In September 2011 and November 2011, the MPUC approved Minnesota Power’s petitions seeking cost recovery for investments and expenditures related to Bison 2 and Bison 3, respectively.
Current customer billing rates were approved by the MPUC in a November 2011 order and are based on investments and expenditures associated with Bison 1. We anticipate filing a cost recovery petition with the MPUC in the first half of 2013 to update customer billing rates for Bison 1 and to include investments and expenditures associated with Bison 2 and Bison 3.
Coal, Rail and Shipping Contracts.
We have coal supply agreements providing for the purchase of a significant portion of our coal requirements with expiration dates through 2014. We also have coal transportation agreements in place for the delivery of a significant portion of our coal requirements with expiration dates through 2015. Our minimum annual payment obligation under these supply and transportation agreements is
$51.4 million
for
2013
and
$0.8 million
for
2014
. Our minimum annual payment obligation 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.
Leasing Agreements.
BNI Coal is obligated to make lease payments for a dragline totaling
$2.8 million
annually for the lease term which expires in 2027. BNI Coal has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a
$3.0 million
termination fee. We also lease other properties and equipment under operating lease agreements with terms expiring through 2016. The aggregate amount of minimum lease payments for all operating leases is
$11.5 million
in
2013
,
$11.7 million
in
2014
,
$11.4 million
in
2015
,
$9.3 million
in
2016
,
$8.5 million
in
2017
and
$35.0 million
thereafter. Total rent and lease expense was
$11.5 million
in
2012
(
$9.4 million
in
2011
;
$9.4 million
in
2010
).
Transmission
. We continue 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 (individually or in combination with others), and our investment in ATC.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)
Transmission Investments.
We have an approved cost recovery rider in place for certain transmission investments and 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. In
June 2011
, we filed an updated billing factor that includes additional transmission expenditures, which we expect to be approved in the first quarter of 2013.
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, municipal 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.
Minnesota Power is 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. The
28
-mile
345
kV line between Monticello and St. Cloud was placed into service in December 2011 and the
70
-mile
230
kV line between Bemidji, Minnesota and Minnesota Power’s Boswell Energy Center near Grand Rapids, Minnesota was placed into service in September 2012. In June 2011, the MPUC approved the route permit for the Minnesota portion of the Fargo to St. Cloud project. The North Dakota permitting process was completed on August 12, 2012. The entire
238
-mile,
345
kV line from Fargo to Monticello is expected to be in service by 2015.
Based on projected costs of the three transmission lines and the allocation agreements among participating utilities, Minnesota Power plans to invest between
$100 million
and
$110 million
in the CapX2020 initiative through 2015. A total of
$48.2 million
was spent through
December 31, 2012
, of which
$37.3 million
related to the Fargo, North Dakota to Monticello, Minnesota projects and
$10.9 million
related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project (
$27.8 million
as of
December 31, 2011
of which
$20.4 million
related to the Fargo, North Dakota to Monticello, Minnesota projects and
$7.4 million
related to the Bemidji, Minnesota to Minnesota Power’s Boswell Energy Center project). As future CapX2020 projects are identified, Minnesota Power may elect to participate on a project-by-project basis.
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 Congress and the EPA. Minnesota Power’s fossil fuel facilities will likely be subject to regulation under these proposals. Our intention is to reduce our exposure to these 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 expected future restrictive environmental requirements imposed through legislation and/or rulemaking, we anticipate that potential expenditures for environmental matters will be material and will require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible ranges of future environmental regulations to project power supply trends and impacts on customers.
We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated, based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are charged to expense unless recoverable in rates from customers.
Air.
The electric utility industry is heavily regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, bag houses and low NO
X
technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with applicable emission requirements.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
New Source Review (NSR)
. In August 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell Units 1, 2, 3 and 4 and Laskin Unit 2. The NOV asserts that seven projects undertaken at these coal-fired plants between the years 1981 and 2000 should have been reviewed under the NSR 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. Resolution of the NOVs could result in civil penalties, which we do not believe will be material to our results of operations, and the installation of additional pollution control equipment, some of which is already planned or which has been completed to comply with other regulatory requirements. We are engaged in discussions with the EPA regarding resolution of these matters, but we are unable to estimate the expenditures, or range of expenditures that may be required upon resolution. Any costs of installing additional pollution control equipment would likely be eligible for recovery in rates over time subject to regulatory approval in a rate proceeding.
Cross-State Air Pollution Rule (CSAPR)
. In July 2011, the EPA issued the CSAPR, which replaced the EPA’s 2005 CAIR. However, on August 21, 2012, a three judge panel of the District of Columbia Circuit Court of Appeals vacated the CSAPR, ordering that the CAIR remain in effect while a CSAPR replacement rule is promulgated. The EPA and other parties to the case have until April 24, 2013, to request that the Supreme Court review the matter. The CSAPR would have required states in the CSAPR region, including Minnesota, to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The CSAPR did not directly require the installation of controls. Instead, the rule would have required facilities to have sufficient emission allowances to cover their emissions on an annual basis. These allowances would have been allocated to facilities from each state’s annual budget and would also have been 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. The CAIR also created an allowance allocation and trading program rather than specifying pollution controls. Minnesota participation in the CAIR was stayed by EPA administrative action while the EPA completed a review of air quality modeling issues in conjunction with the development of a final replacement rule. While the CAIR remains in effect, Minnesota participation in the CAIR will continue to be stayed. It remains uncertain if emission restrictions similar to those contained in the CSAPR will become effective for Minnesota utilities due to the August 2012 District of Columbia Circuit Court of Appeals decision.
Since 2006, we have significantly reduced emissions at our Laskin, Taconite Harbor and Boswell generating units. Based on our expected generation, these emission reductions would have satisfied Minnesota Power’s SO
2
and NO
X
emission compliance obligations with respect to the EPA-allocated CSAPR allowances for 2012. Minnesota Power will continue to track the EPA activity related to promulgation of a CSAPR replacement rule. We are unable to predict any additional compliance costs we might incur if the CSAPR is reinstated or if a CSAPR replacement rule is promulgated.
Regional Haze
. The federal Regional Haze Rule requires states to submit SIPs to the EPA to address regional haze visibility impairment in 156 federally-protected parks and wilderness areas. Under the first phase of the Regional Haze Rule, certain large stationary sources, put in place between 1962 and 1977, with emissions contributing to visibility impairment, are required to install emission controls, known as Best Available Retrofit Technology (BART). We have two steam units, Boswell Unit 3 and Taconite Harbor Unit 3, that are subject to BART requirements.
The MPCA requested that companies with BART-eligible units complete and submit a BART emissions control retrofit study, which was completed for Taconite Harbor Unit 3 in November 2008. The retrofit work completed in 2009 at Boswell Unit 3 meets the BART requirements for that unit. In December 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.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
In December 2011, the EPA published in the Federal Register a proposal to approve the trading program in the CSAPR as an alternative to determining BART. However, as a result of the August 2012 District of Columbia Circuit Court of Appeals decision to vacate the CSAPR (See CSAPR), Minnesota Power is now evaluating whether significant additional expenditures at Taconite Harbor Unit 3 will be required to comply with BART requirements under the Regional Haze Rule. If additional regional haze related controls are ultimately required, Minnesota Power will have up to five years from the final rule promulgation to bring Taconite Harbor Unit 3 into compliance with the Regional Haze Rule requirements. It is uncertain what controls would ultimately be required at Taconite Harbor Unit 3 under this scenario. On January 30, 2013, Minnesota Power announced “EnergyForward”, a strategic plan for assuring reliability, protecting affordability and further improving environmental performance. The plan includes retiring Taconite Harbor Unit 3 in 2015, subject to MPUC approval.
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 published the final MATS rule in the Federal Register on February 16, 2012, addressing such emissions from coal-fired utility units greater than 25 MW. There are currently 187 listed HAPs that 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 must be in compliance with the rule by April 2015. States have the authority to grant sources a one-year extension. Minnesota Power was notified by the MPCA that they have approved Minnesota Power’s request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016. Compliance at our Boswell Unit 4 to address the final MATS rule is expected to result in capital expenditures totaling between
$350 million
and
$400 million
through 2016. Our “EnergyForward” plan also includes the conversion of Laskin Units 1 and 2 to natural gas addressing the MATS requirements.
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 in May 2011, to allow the EPA time to consider additional comments received. The EPA re-proposed the rule in December 2011. 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. A final rule based on the December 2011 proposal, which supersedes the March 2011 rule, was released on December 21, 2012. Major sources have three years to achieve compliance with the final rule. Minnesota Power is in the process of assessing the impact of this rule on our affected units including the Hibbard Renewable Energy Center and Rapids Energy Center. Costs for complying with the final rule cannot be estimated at this time.
Minnesota Mercury Emissions Reduction Act
. Under the 2006 Minnesota Mercury Emissions Reduction Act, Minnesota Power is required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. On August 31, 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 to address both the Minnesota mercury emissions reduction requirements and the MATS rule, which also regulates mercury emissions. Minnesota Power's request of an additional year extending the date of compliance for the Boswell Unit 4 retrofit to April 1, 2016, was approved by the MPCA. 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 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 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.
The EPA has proposed to more stringently control emissions that result in ground level ozone. In January 2010, the EPA proposed to revise the 2008 eight-hour ozone standard and to adopt a secondary standard for the protection of sensitive vegetation from ozone-related damage. The EPA was scheduled to decide upon the 2008 eight-hour ozone standard in July 2011, but has since announced that it is deferring revision of this standard until 2013.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Particulate Matter NAAQS.
The EPA finalized the NAAQS Particulate Matter standards in September 2006. Since then, the EPA has established a more stringent 24-hour average fine particulate matter (PM
2.5
) standard; the annual PM
2.5
standard and the 24-hour coarse particulate matter standard have remained unchanged. The United States Court of Appeals for the District of Columbia Circuit remanded the annual PM
2.5
standard to the EPA, requiring consideration of lower annual standard values. The EPA proposed new PM
2.5
standards on June 14, 2012.
On December 14, 2012, the EPA confirmed in a final rule that the current annual PM
2.5
standard, which has been in place since 1997, will be lowered, while retaining the current 24-hour PM
2.5
standard. To implement the new lower annual PM
2.5
standard, the EPA is also revising aspects of relevant monitoring, designations and permitting requirements. New projects and permits must comply with the new lower standard, and compliance with the NAAQS at the facility level is generally demonstrated by modeling. To bridge the transition to the lower standard, the EPA is finalizing a grandfathering provision to ensure that projects and pending permits already underway are not unduly delayed.
Under the final rule, states will be responsible for additional PM
2.5
monitoring, which will likely be accomplished by relocation or repurposing of existing monitors. States are expected to propose attainment designations by December 2013, based on already available monitoring data. The EPA believes that most U.S. counties currently already meet the new standard and plans to finalize designations of attainment by December 2014. For those counties that the EPA does not designate as having already met the requirements of the new standard, specific dates for required attainment will depend on technology availability, state permitting goals, potential legal challenges and other factors.
SO
2
and NO
2
NAAQS.
During 2010, the EPA finalized new one-hour NAAQS for SO
2
and NO
2
. Ambient monitoring data indicates that Minnesota will likely be in compliance with these new standards; however, the one-hour SO
2
NAAQS also require the EPA to evaluate modeling data to determine attainment. The EPA has notified states that their SIPs for attainment of the standard will be required to be submitted to the EPA for approval by June 2013 but will not be required to include the evaluation of modeling data until 2017.
In late 2011, the MPCA initiated modeling activities that included approximately 65 sources within Minnesota that emit greater than 100 tons of SO
2
per year. However, on April 12, 2012, the MPCA notified Minnesota Power that such modeling had been suspended as a result of the EPA’s announcement that the June 2013 SIP submittals would no longer require modeling demonstrations for states, such as Minnesota, where ambient monitors indicate compliance with the new standard. The MPCA is awaiting updated EPA guidance and will communicate with affected sources once the MPCA has more information on how the state will meet the EPA’s SIP requirements. Currently, compliance with these new NAAQS is expected to be required as early as 2017. The costs for complying with the final standards cannot be estimated at this time.
Climate Change.
The scientific community generally accepts that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. 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. We are 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;
|
|
|
•
|
Provide energy conservation initiatives for our customers and engage in other demand side efforts;
|
|
|
•
|
Support research of technologies to reduce carbon emissions from generation facilities and carbon sequestration efforts; and
|
|
|
•
|
Evaluating and developing less carbon intense future generating assets such as efficient and flexible natural gas generating facilities.
|
EPA Regulation of GHG Emissions.
In May 2010, the EPA issued the final Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, at existing facilities that undergo major modifications and at other facilities characterized as major sources under the Clean Air Act’s Title V program. For our existing facilities, the rule does not require amending our existing Title V operating permits to include GHG requirements. However, GHG requirements are likely to be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.
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 that these control technologies could be determined to be BACT on a project-by-project basis.
On March 28, 2012, the EPA announced its proposed rule to apply CO
2
emission New Source Performance Standards (NSPS) to new fossil fuel-fired electric generating units. The proposed NSPS apply only to new or re-powered units and were open for public comment through June 25, 2012. It is anticipated that the EPA will issue NSPS for existing fossil fuel-fired generating units in the future. We cannot predict what CO
2
control measures, if any, may be required by such NSPS.
Legal challenges have been filed with respect to the EPA’s regulation of GHG emissions, including the Tailoring Rule. On June 26, 2012, the United States District Court for the District of Columbia upheld most of the EPA’s proposed regulations, including the Tailoring Rule criteria, finding that the Clean Air Act compels the EPA to regulate in the manner the EPA proposed. Comments to the permitting guidance were 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 GHG emission 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.
Clean Water Act - Aquatic Organisms.
In April 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 and the EPA is obligated to finalize the rule by June 27, 2013. We are unable to predict the compliance costs we might incur under the final rule; however, the costs could be material. We would seek recovery of any additional costs through cost recovery riders or in a general rate case.
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. It is expected that the EPA will publish the proposed new rule in April 2013 and a final rule 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.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Coal Ash Management Facilities
.
Minnesota Power generates coal ash at all five of its coal-fired electric 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. In June 2010, the EPA proposed regulations for coal combustion residuals generated by the electric utility sector. The proposal sought comments on three general regulatory schemes for coal ash. Comments on the proposed rule were due in November 2010. It is estimated that the final rule will be published in 2013. 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.
Other Matters
BNI Coal.
As of
December 31, 2012
, BNI Coal had surety bonds outstanding of
$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, additional assurance is required by federal and state regulations. In addition to the surety bonds, BNI Coal has secured a letter of credit with CoBANK ACB for an additional
$2.6 million
to provide for BNI Coal’s total reclamation liability, which is currently estimated at
$32.4 million
. BNI Coal does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.
ALLETE Properties.
As of
December 31, 2012
, ALLETE Properties, through its subsidiaries, had surety bonds outstanding and letters of credit to governmental entities totaling
$10.2 million
primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is approximately
$7.4 million
, of which
$0.6 million
is the contractual obligation of land purchasers. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.
Community Development District Obligations.
In March 2005, the Town Center District issued
$26.4 million
of tax-exempt,
6
percent capital improvement revenue bonds and in May 2006, the Palm Coast Park District issued
$31.8 million
of tax-exempt,
5.7
percent special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over
31
years (by May 1, 2036 and 2037, respectively) and secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in 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, 2012
, we owned
73
percent of the assessable land in the Town Center District (
73
percent at
December 31, 2011
) and
93
percent of the assessable land in the Palm Coast Park District (
93
percent at
December 31, 2011
). At these ownership levels, our annual assessments are approximately
$1.4 million
for Town Center and
$2.1 million
for Palm Coast Park. As we sell property, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.
Legal Proceedings.
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
$20.0 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, 2012
, because a potential loss is not currently probable or reasonably estimable; however, the Company believes it has adequate insurance coverage for any 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, and 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.
NOTE 12. COMMON STOCK AND EARNINGS PER SHARE
|
|
|
|
|
|
|
Summary of Common Stock
|
Shares
|
Equity
|
|
Thousands
|
Millions
|
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
|
|
Employee Stock Purchase Program
|
20
|
|
0.8
|
|
Invest Direct
|
474
|
|
19.2
|
|
Options and Stock Awards
|
95
|
|
6.0
|
|
Equity Issuance Program
|
1,275
|
|
53.1
|
|
Balance as of December 31, 2012
|
39,377
|
|
|
$784.7
|
|
Equity Issuance Program.
We entered into a distribution agreement with KCCI, Inc., in February 2008, as amended most recently on
August 3, 2012
, 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
4.5 million
remain available for issuance. For the year ended
December 31, 2012
,
1.3 million
shares of common stock were issued under this agreement resulting in net proceeds of
$53.1 million
. During
2011
,
0.4 million
shares of common stock were issued for net proceeds of
$16.0 million
. The shares issued in
2012
and
2011
were, and 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. 333-170289.
Earnings Per Share.
The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock, and performance share awards granted under our Executive and Director Long-Term Incentive Compensation Plans. In
2012
, in accordance with accounting standards for earnings per share,
0.2 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; therefore, their effect would have been anti-dilutive (
0.3 million
shares were excluded in
2011
and
0.5 million
in
2010
).
Purchase of Non-Controlling Interest.
In
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.
Contributions to Pension.
In
2011
, ALLETE contributed approximately
0.5 million
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(a)(2) of the Securities Act of 1933 and had an aggregate value of
$20.0 million
when contributed.
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
|
|
|
|
2012
|
|
|
|
Net Income Attributable to ALLETE
|
|
$97.1
|
|
|
|
|
$97.1
|
|
Average Common Shares
|
37.6
|
|
—
|
|
37.6
|
|
Earnings Per Share
|
|
$2.59
|
|
|
|
|
$2.58
|
|
2011
|
|
|
|
Net Income Attributable to ALLETE
|
|
$93.8
|
|
|
|
|
$93.8
|
|
Average Common Shares
|
35.3
|
|
0.1
|
|
35.4
|
|
Earnings Per Share
|
|
$2.66
|
|
|
|
|
$2.65
|
|
2010
|
|
|
|
Net Income Attributable to ALLETE
|
|
$75.3
|
|
|
|
|
$75.3
|
|
Average Common Shares
|
34.2
|
|
0.1
|
|
34.3
|
|
Earnings Per Share
|
|
$2.20
|
|
|
|
|
$2.19
|
|
NOTE 13. OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
AFUDC – Equity
|
|
$5.1
|
|
|
$2.5
|
|
|
$4.2
|
|
Investment and Other Income
|
0.9
|
|
1.9
|
|
0.4
|
|
Total Other Income
|
|
$6.0
|
|
|
$4.4
|
|
|
$4.6
|
|
NOTE 14. INCOME TAX EXPENSE
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Current Tax Expense (Benefit)
|
|
|
|
Federal
(a)
|
—
|
|
$1.4
|
$(23.0)
|
State
(a)
|
$0.5
|
(1.6
|
)
|
1.3
|
|
Total Current Tax Expense (Benefit)
|
0.5
|
|
(0.2
|
)
|
(21.7
|
)
|
Deferred Tax Expense
|
|
|
|
Federal
(b)
|
38.1
|
|
27.3
|
|
61.4
|
|
State
(b)
|
(1.7
|
)
|
9.5
|
|
5.3
|
|
Change in Valuation Allowance
(c)
|
2.0
|
|
(0.1
|
)
|
0.2
|
|
Investment Tax Credit Amortization
|
(0.9
|
)
|
(0.9
|
)
|
(0.9
|
)
|
Total Deferred Tax Expense
|
37.5
|
|
35.8
|
|
66.0
|
|
Total Income Tax Expense
|
|
$38.0
|
|
|
$35.6
|
|
|
$44.3
|
|
|
|
(a)
|
For the years ended December 31, 2012 and 2011, the federal and state current tax expense (benefit) was due to NOLs which resulted primarily from the bonus depreciation provision of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 and 2011 federal and state NOLs will be carried forward to offset future taxable income. For the year ended December 31, 2010, a federal current tax benefit was recorded 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.
|
|
|
(b)
|
For the year ended December 31, 2012, the state deferred tax benefit of
$1.7 million
is due to state renewable tax credits earned which will be carried forward to offset future state income tax expense. The year ended December 31, 2011, included an income tax benefit for 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 and a 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 result of the PPACA. Included in the year ended December 31, 2010, was a charge of
$4.0 million
as a result of the PPACA. (See Note 5. Regulatory Matters.)
|
|
|
(c)
|
For the year ending December 31, 2012, the change in the valuation allowance is due to state renewable tax credits earned in 2012 which are not expected to be utilized within their allowable tax carryforward period.
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Taxes from Federal Statutory
|
|
|
|
Rate to Total Income Tax Expense
|
|
|
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Income Before Non-Controlling Interest and Income Taxes
|
|
$135.1
|
|
|
$129.2
|
|
|
$119.1
|
|
Statutory Federal Income Tax Rate
|
35
|
%
|
35
|
%
|
35
|
%
|
Income Taxes Computed at 35 percent Statutory Federal Rate
|
|
$47.3
|
|
|
$45.2
|
|
|
$41.7
|
|
Increase (Decrease) in Tax Due to:
|
|
|
|
State Income Taxes – Net of Federal Income Tax Benefit
|
1.2
|
|
6.0
|
|
4.5
|
|
Impact of the PPACA
|
—
|
|
—
|
|
4.0
|
|
Deferred Accounting for Retail Portion of the PPACA
|
—
|
|
(2.9
|
)
|
—
|
|
2010 Rate Case Stipulation Agreement - Deferred Tax Reversal
|
—
|
|
(6.2
|
)
|
—
|
|
Regulatory Differences for Utility Plant
|
(2.2
|
)
|
(1.2
|
)
|
(2.0
|
)
|
Production Tax Credits
|
(7.6
|
)
|
(4.3
|
)
|
(1.6
|
)
|
Other
|
(0.7
|
)
|
(1.0
|
)
|
(2.3
|
)
|
Total Income Tax Expense
|
|
$38.0
|
|
|
$35.6
|
|
|
$44.3
|
|
NOTE 14. INCOME TAX EXPENSE (Continued)
The effective tax rate on income was
28.1 percent
for
2012
(
27.6 percent
for
2011
;
37.2 percent
for
2010
). The 2012 effective rate was primarily impacted by renewable tax credits and by the deduction for AFUDC-Equity (included in Regulatory Differences for Utility Plant, above). The 2011 effective tax rate was primarily impacted by the deduction for AFUDC-Equity, 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, renewable tax credits, and the MPUC’s approval of our request to defer the retail portion of the tax charge taken in 2010 as a result of the PPACA. The 2010 effective tax rate was primarily impacted by the PPACA eliminating the tax deduction for expenses that are reimbursed under Medicare Part D, the deduction for AFUDC-Equity, and renewable tax credits.
|
|
|
|
|
|
|
|
Deferred Tax Assets and Liabilities
|
|
|
As of December 31
|
2012
|
2011
|
Millions
|
|
|
Deferred Tax Assets
|
|
|
Employee Benefits and Compensation
|
|
$120.2
|
|
|
$132.7
|
|
Property Related
|
59.8
|
|
56.4
|
|
NOL Carryforwards
|
90.8
|
|
61.7
|
|
Tax Credit Carryforwards
|
28.3
|
|
12.2
|
|
Other
|
24.6
|
|
20.4
|
|
Gross Deferred Tax Assets
|
323.7
|
|
283.4
|
|
Deferred Tax Asset Valuation Allowance
|
(2.4
|
)
|
(0.4
|
)
|
Total Deferred Tax Assets
|
|
$321.3
|
|
|
$283.0
|
|
Deferred Tax Liabilities
|
|
|
Property Related
|
|
$577.1
|
|
|
$482.7
|
|
Regulatory Asset for Benefit Obligations
|
104.3
|
|
117.9
|
|
Unamortized Investment Tax Credits
|
11.9
|
|
12.8
|
|
Partnership Basis Differences
|
28.6
|
|
24.4
|
|
Other
|
30.1
|
|
24.0
|
|
Total Deferred Tax Liabilities
|
|
$752.0
|
|
|
$661.8
|
|
Net Deferred Income Taxes
|
|
$430.7
|
|
|
$378.8
|
|
Recorded as:
|
|
|
Net Current Deferred Tax Liabilities
(a)
|
|
$6.9
|
|
|
$5.2
|
|
Net Long-Term Deferred Tax Liabilities
|
423.8
|
|
373.6
|
|
Net Deferred Income Taxes
|
|
$430.7
|
|
|
$378.8
|
|
|
|
(a)
|
Included in Other Current Liabilities.
|
|
|
|
|
|
|
|
|
NOL and Tax Credit Carryforwards
|
|
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Federal NOL carryforwards
(a)
|
|
$244.1
|
|
|
$162.0
|
|
Federal tax credit carryforwards
|
$16.0
|
$8.4
|
State NOL carryforwards
(a) (b)
|
$90.6
|
$73.1
|
State tax credit carryforwards
(c)
|
$10.3
|
$3.8
|
|
|
(b)
|
Net of
$0.4 million
valuation allowance.
|
|
|
(c)
|
Net of
$2.0 million
valuation allowance.
|
NOTE 14. INCOME TAX EXPENSE (Continued)
In 2012, we generated federal and various state NOLs and tax credit carryforwards primarily due to the bonus depreciation provisions of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010. The 2012 federal NOL will be utilized by carrying it forward to offset future years’ income. The federal NOL and tax credit carryforward periods expire between 2019 and 2032; included in the federal NOL carryforward are charitable contribution carryforwards which expire between 2014 and 2016. We expect to fully utilize the federal NOL, charitable contributions, and federal tax credit carryforwards; therefore
no
valuation allowance has been recognized as of December 31, 2012.
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 state NOL and tax credit carryforward periods expire between 2024 and 2032; included in the state NOL carryforwards are charitable contribution carryforwards which expire between 2014 and 2016.
|
|
|
|
|
|
|
|
|
|
|
Gross Unrecognized Income Tax Benefits
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Balance at January 1
|
|
$11.4
|
|
|
$12.3
|
|
|
$9.5
|
|
Reductions for Tax Positions Related to the Current Year
|
—
|
|
—
|
|
(0.2
|
)
|
Additions for Tax Positions Related to Prior Years
|
—
|
|
—
|
|
4.4
|
|
Reductions for Tax Positions Related to Prior Years
|
(8.7
|
)
|
(0.9
|
)
|
—
|
|
Reductions for Settlements
|
—
|
|
—
|
|
(0.3
|
)
|
Reductions for Expired Statute of Limitations
|
—
|
|
—
|
|
(1.1
|
)
|
Balance as of December 31
|
|
$2.7
|
|
|
$11.4
|
|
|
$12.3
|
|
Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
The gross unrecognized tax benefits as of
December 31, 2012
, includes
$0.5 million
of net unrecognized tax benefits that, if recognized, would affect the annual effective income tax rate. The decrease in the unrecognized tax benefit balance of
$8.7 million
in 2012 was due to the removal of our uncertain tax position for our tax accounting method change for deductible repairs. During 2012, the IRS issued a directive from its Large Business and International Division to its local examination teams that led to the removal of the repairs uncertain tax position in 2012.
As of
December 31, 2012
, we had
$0.5 million
(
$1.1 million
for
2011
and
$0.7 million
for
2010
) of accrued interest related to unrecognized tax benefits included in our Consolidated Balance Sheet. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses in our Consolidated Statement of Income. In
2012
, we recognized a
$0.6 million
decrease in interest expense (interest expense of
$0.4 million
for
2011
and a reduction of interest expense of
$0.2 million
for
2010
). There were
no
penalties recognized in
2012
,
2011
or
2010
.
ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE 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.
During the next 12 months it is reasonably possible the amount of unrecognized tax benefits could be reduced by
$2.5 million
due to statute expirations and anticipated audit settlements. This amount is primarily due to temporary tax positions.
NOTE 15. 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
2012
, we made total contributions of
$7.3 million
(
$33.8 million
in
2011
, of which
$20.0 million
was contributed in shares of ALLETE common stock). We also have a defined contribution pension plan covering substantially all employees. The
2012
plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled
$7.7 million
(
$7.3 million
for the
2011
plan year.) (See Note 12. Common Stock and Earnings Per Share and Note 16. Employee Stock and Incentive Plans).
In 2006, the non-union defined benefit pension plan was amended to suspend further crediting of service to the plan and to close the plan to new participants. In conjunction with 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 trust. In
2012
,
$1.5 million
was contributed to the VEBAs. In
2011
, we contributed
$10.9 million
to the VEBAs. There were
no
contributions made to the grantor trust in
2012
and
2011
.
Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements, and contributions required to avoid benefit restrictions for the pension plans. Contributions are based on estimates and assumptions which are subject to change. We do
not
expect to make any contributions to the defined benefit pension plan in
2013
. In January 2013, we contributed
$4.8 million
to the defined benefit postretirement health and life plan, of which
$2.0 million
was contributed to an irrevocable grantor trust and
$2.8 million
was contributed to the VEBAs. We do
not
expect to make any additional contributions to the defined benefit postretirement health and life plan in
2013
.
Accounting for defined benefit pension and postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their 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 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 standards 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.
ALLETE 2012 Form 10-K
100
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
|
|
|
|
|
|
|
Pension Obligation and Funded Status
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Accumulated Benefit Obligation
|
|
$598.7
|
|
|
$550.6
|
|
Change in Benefit Obligation
|
|
|
|
|
Obligation, Beginning of Year
|
|
$597.5
|
|
|
$525.6
|
|
Service Cost
|
9.1
|
|
7.6
|
|
Interest Cost
|
26.4
|
|
27.4
|
|
Actuarial Loss
|
38.5
|
|
54.6
|
|
Benefits Paid
|
(30.9
|
)
|
(28.6
|
)
|
Participant Contributions
|
11.5
|
|
10.9
|
|
Obligation, End of Year
|
|
$652.1
|
|
|
$597.5
|
|
Change in Plan Assets
|
|
|
|
|
Fair Value, Beginning of Year
|
|
$432.4
|
|
|
$382.0
|
|
Actual Return on Plan Assets
|
38.7
|
|
33.2
|
|
Employer Contribution
|
19.9
|
|
45.8
|
|
Benefits Paid
|
(30.9
|
)
|
(28.6
|
)
|
Fair Value, End of Year
|
|
$460.1
|
|
|
$432.4
|
|
Funded Status, End of Year
|
$(192.0)
|
$(165.1)
|
|
|
|
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
|
|
|
|
|
Current Liabilities
|
$(1.1)
|
$(1.1)
|
Non-Current Liabilities
|
$(190.9)
|
$(164.0)
|
The pension costs that are reported as a component within our Consolidated Balance Sheet, reflected in long-term regulatory assets and accumulated other comprehensive income, consist of the following:
|
|
|
|
|
|
|
|
Unrecognized Pension Costs
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Net Loss
|
|
$286.8
|
|
|
$269.0
|
|
Prior Service Cost
|
0.7
|
|
1.1
|
|
Total Unrecognized Pension Costs
|
|
$287.5
|
|
|
$270.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of Net Periodic Pension Expense
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Service Cost
|
|
$9.1
|
|
|
$7.6
|
|
|
$6.2
|
|
Interest Cost
|
26.4
|
|
27.4
|
|
26.2
|
|
Expected Return on Plan Assets
|
(35.4
|
)
|
(34.6
|
)
|
(33.7
|
)
|
Amortization of Loss
|
17.5
|
|
12.1
|
|
6.6
|
|
Amortization of Prior Service Cost
|
0.3
|
|
0.3
|
|
0.5
|
|
Net Pension Expense
|
|
$17.9
|
|
|
$12.8
|
|
|
$5.8
|
|
ALLETE 2012 Form 10-K
101
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
|
|
|
|
|
|
|
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income and Regulatory Assets
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Net Loss
|
|
$35.2
|
|
|
$56.1
|
|
Amortization of Prior Service Cost
|
(0.3
|
)
|
(0.3
|
)
|
Amortization of Loss
|
(17.5
|
)
|
(12.2
|
)
|
Total Recognized in Other Comprehensive Income and Regulatory Assets
|
|
$17.4
|
|
|
$43.6
|
|
|
|
|
|
|
|
|
|
Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Projected Benefit Obligation
|
|
$652.1
|
|
|
$597.5
|
|
Accumulated Benefit Obligation
|
|
$598.7
|
|
|
$550.6
|
|
Fair Value of Plan Assets
|
|
$460.1
|
|
|
$432.4
|
|
|
|
|
|
|
|
|
|
Postretirement Health and Life Obligation and Funded Status
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Change in Benefit Obligation
|
|
|
Obligation, Beginning of Year
|
|
$210.6
|
|
|
$204.1
|
|
Service Cost
|
4.2
|
|
3.8
|
|
Interest Cost
|
9.4
|
|
10.8
|
|
Actuarial Gain
|
(43.2
|
)
|
(2.9
|
)
|
Participant Contributions
|
2.6
|
|
2.5
|
|
Plan Amendments
|
(5.3
|
)
|
—
|
|
Benefits Paid
|
(9.5
|
)
|
(7.7
|
)
|
Obligation, End of Year
|
|
$168.8
|
|
|
$210.6
|
|
Change in Plan Assets
|
|
|
Fair Value, Beginning of Year
|
|
$121.0
|
|
|
$114.7
|
|
Actual Return on Plan Assets
|
14.3
|
|
—
|
|
Employer Contribution
|
2.3
|
|
11.4
|
|
Participant Contributions
|
2.5
|
|
2.5
|
|
Benefits Paid
|
(9.1
|
)
|
(7.6
|
)
|
Fair Value, End of Year
|
|
$131.0
|
|
|
$121.0
|
|
Funded Status, End of Year
|
$(37.8)
|
$(89.6)
|
|
|
|
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
|
|
|
Current Liabilities
|
$(0.8)
|
$(0.9)
|
Non-Current Liabilities
|
$(37.0)
|
$(88.7)
|
According to the accounting standards for retirement 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
$22.1 million
in irrevocable grantor trusts included in Other Investments on our Consolidated Balance Sheet at
December 31, 2012
(
$20.3 million
at
December 31, 2011
).
ALLETE 2012 Form 10-K
102
NOTE 15. 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
|
2012
|
2011
|
Millions
|
|
|
Net Loss
|
|
$23.5
|
|
|
$78.5
|
|
Prior Service Credit
|
(13.1
|
)
|
(9.5
|
)
|
Transition Obligation
|
—
|
|
0.1
|
|
Total Unrecognized Postretirement Health and Life Costs
|
|
$10.4
|
|
|
$69.1
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of Net Periodic Postretirement Health and Life Expense
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Service Cost
|
|
$4.2
|
|
|
$3.8
|
|
|
$4.8
|
|
Interest Cost
|
9.4
|
|
10.8
|
|
10.9
|
|
Expected Return on Plan Assets
|
(9.9
|
)
|
(9.7
|
)
|
(9.5
|
)
|
Amortization of Prior Service Credit
|
(1.7
|
)
|
(1.7
|
)
|
(0.1
|
)
|
Amortization of Loss
|
7.5
|
|
8.5
|
|
4.8
|
|
Amortization of Transition Obligation
|
0.1
|
|
0.1
|
|
2.5
|
|
Net Postretirement Health and Life Expense
|
|
$9.6
|
|
|
$11.8
|
|
|
$13.4
|
|
|
|
|
|
|
|
|
Other Changes in Postretirement Benefit Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income and Regulatory Assets
|
Year Ended December 31
|
2012
|
2011
|
Millions
|
|
|
Net (Gain) Loss
|
$(47.5)
|
|
$6.9
|
|
Prior Service Credit Arising During the Period
|
(5.3
|
)
|
—
|
|
Amortization of Prior Service Credit
|
1.7
|
|
1.7
|
|
Amortization of Transition Obligation
|
(0.1
|
)
|
(0.1
|
)
|
Amortization of Loss
|
(7.5
|
)
|
(8.5
|
)
|
Total Recognized in Other Comprehensive Income and Regulatory Assets
|
$(58.7)
|
—
|
|
|
|
|
|
|
|
|
|
Estimated Future Benefit Payments
|
|
|
Postretirement
|
|
Pension
|
Health and Life
|
Millions
|
|
|
2013
|
|
$31.2
|
|
|
$7.6
|
|
2014
|
|
$32.1
|
|
|
$8.2
|
|
2015
|
|
$33.2
|
|
|
$8.9
|
|
2016
|
|
$34.4
|
|
|
$9.4
|
|
2017
|
|
$35.5
|
|
|
$9.7
|
|
Years 2018 – 2022
|
|
$189.4
|
|
|
$52.0
|
|
ALLETE 2012 Form 10-K
103
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
The pension and postretirement health and life costs recorded in regulatory 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, 2013
, are as follows:
|
|
|
|
|
|
|
|
|
Pension
|
Postretirement
Health and Life
|
Millions
|
|
|
Net Loss
|
|
$21.4
|
|
|
$1.6
|
|
Prior Service Cost (Credit)
|
0.3
|
|
(2.5
|
)
|
Total Pension and Postretirement Health and Life Cost (Credit)
|
|
$21.7
|
|
$(0.9)
|
|
|
|
|
Weighted-Average Assumptions Used to Determine Benefit Obligation
|
As of December 31
|
2012
|
2011
|
Discount Rate
|
|
|
Pension
|
4.10%
|
4.54%
|
Postretirement Health and Life
|
4.13%
|
4.56%
|
Rate of Compensation Increase
|
4.3 - 4.6%
|
4.3 - 4.6%
|
Health Care Trend Rates
|
|
|
Trend Rate
|
9.25%
|
10%
|
Ultimate Trend Rate
|
5%
|
5%
|
Year Ultimate Trend Rate Effective
|
2019
|
2018
|
|
|
|
|
|
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs
|
Year Ended December 31
|
2012
|
2011
|
2010
|
Discount Rate
|
4.54 - 4.56%
|
5.36 - 5.40%
|
5.81%
|
Expected Long-Term Return on Plan Assets
|
|
|
|
Pension
|
8.25%
|
8.5%
|
8.5%
|
Postretirement Health and Life
|
6.6 - 8.25%
|
6.8 - 8.5%
|
6.8 - 8.5%
|
Rate of Compensation Increase
|
4.3 - 4.6%
|
4.3 - 4.6%
|
4.3 - 4.6%
|
In establishing the expected long-term rate of return on plan assets, we determine the long-term historical performance of each asset class, adjust these for current economic conditions, and utilizing the target allocation of our plan assets, forecast the expected long-term rate of return.
The discount rate is computed using a 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. 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
|
|
$18.2
|
|
$(15.1)
|
ALLETE 2012 Form 10-K
104
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
|
|
|
|
|
|
|
|
|
Actual Plan Asset Allocations
|
|
Pension
|
Postretirement
Health and Life
(a)
|
|
2012
|
2011
|
2012
|
2011
|
Equity Securities
|
54
|
%
|
52
|
%
|
56
|
%
|
51
|
%
|
Debt Securities
|
28
|
%
|
27
|
%
|
35
|
%
|
39
|
%
|
Private Equity
|
13
|
%
|
16
|
%
|
9
|
%
|
10
|
%
|
Real Estate
|
5
|
%
|
5
|
%
|
—
|
|
—
|
|
|
100
|
%
|
100
|
%
|
100
|
%
|
100
|
%
|
|
|
(a)
|
Includes VEBAs and irrevocable grantor trusts.
|
There were
no
shares of ALLETE common stock included in pension plan equity securities at
December 31, 2012
(
$20.0 million
, approximately
0.5 million
shares, in
2011
).
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
|
52
|
%
|
48
|
%
|
Debt Securities
|
30
|
%
|
34
|
%
|
Real Estate
|
9
|
%
|
9
|
%
|
Private Equity
|
9
|
%
|
9
|
%
|
|
100
|
%
|
100
|
%
|
|
|
(a)
|
Includes VEBAs and irrevocable grantor trusts.
|
Fair Value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes various U.S. equity securities, public mutual funds, and futures. These instruments are valued using the closing price from the applicable exchange or whose value is quoted and readily traded daily.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs. This category includes various bonds and non-public funds whose underlying investments may be level 1 or level 2 securities.
ALLETE 2012 Form 10-K
105
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
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 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of December 31, 2012
|
Recurring Fair Value Measures
|
Level 1
|
Level 2
|
Level 3
|
Total
|
Millions
|
|
|
|
|
Assets:
|
|
|
|
|
Equity Securities:
|
|
|
|
|
U.S. Large-cap
(a)
|
|
$43.0
|
|
|
$36.0
|
|
—
|
|
|
$79.0
|
|
U.S. Mid-cap Growth
(a)
|
18.3
|
|
15.3
|
|
—
|
|
33.6
|
|
U.S. Small-cap
(a)
|
18.3
|
|
15.3
|
|
—
|
|
33.6
|
|
International
|
50.5
|
|
45.9
|
|
—
|
|
96.4
|
|
Debt Securities:
|
|
|
|
|
|
|
|
|
Mutual Funds
|
72.5
|
|
—
|
|
—
|
|
72.5
|
|
Fixed Income
|
10.4
|
|
50.8
|
|
—
|
|
61.2
|
|
Other Types of Investments:
|
|
|
|
|
|
|
|
|
Private Equity Funds
|
—
|
|
—
|
|
|
$58.9
|
|
58.9
|
|
Real Estate
|
—
|
|
—
|
|
24.9
|
|
24.9
|
|
Total Fair Value of Assets
|
|
$213.0
|
|
|
$163.3
|
|
|
$83.8
|
|
|
$460.1
|
|
|
|
(a)
|
The underlying investments classified under U.S. Equity Securities consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and 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
|
|
|
Activity in Level 3
|
Private Equity Funds
|
Real Estate
|
Millions
|
|
|
Balance as of December 31, 2011
|
|
$69.0
|
|
|
$21.7
|
|
Actual Return on Plan Assets
|
(9.7
|
)
|
3.4
|
|
Purchases, sales, and settlements, net
|
(0.4
|
)
|
(0.2
|
)
|
Balance as of December 31, 2012
|
|
$58.9
|
|
|
$24.9
|
|
ALLETE 2012 Form 10-K
106
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 consist of money market funds (Level 1) and actively-managed funds (Level 2), which are combined with futures, and 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
|
|
|
|
Activity in Level 3
|
Equity Securities (ARS)
|
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
|
|
ALLETE 2012 Form 10-K
107
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
Postretirement Health and Life Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of December 31, 2012
|
Recurring Fair Value Measures
|
Level 1
|
Level 2
|
Level 3
|
Total
|
Millions
|
|
|
|
|
Assets:
|
|
|
|
|
Equity Securities:
|
|
|
|
|
U.S. Large-cap
(a)
|
|
$16.7
|
|
—
|
|
—
|
|
|
$16.7
|
|
U.S. Mid-cap Growth
(a)
|
13.2
|
|
—
|
|
—
|
|
13.2
|
|
U.S. Small-cap
(a)
|
13.3
|
|
—
|
|
—
|
|
13.3
|
|
International
|
30.3
|
|
—
|
|
—
|
|
30.3
|
|
Debt Securities:
|
|
|
|
|
|
|
|
|
Mutual Funds
|
25.5
|
|
—
|
|
—
|
|
25.5
|
|
Fixed Income
|
0.2
|
|
|
$18.3
|
|
—
|
|
18.5
|
|
Other Types of Investments:
|
|
|
|
|
|
|
|
|
Private Equity Funds
|
—
|
|
—
|
|
|
$13.5
|
|
13.5
|
|
Total Fair Value of Assets
|
|
$99.2
|
|
|
$18.3
|
|
|
$13.5
|
|
|
$131.0
|
|
|
|
(a)
|
The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).
|
|
|
|
|
|
Recurring Fair Value Measures
|
|
Activity in Level 3
|
Private Equity Funds
|
Millions
|
|
Balance as of December 31, 2011
|
|
$14.0
|
|
Actual Return on Plan Assets
|
0.2
|
|
Purchases, sales, and settlements, net
|
(0.7
|
)
|
Balance as of December 31, 2012
|
|
$13.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
$15.9
|
|
—
|
|
—
|
|
|
$15.9
|
|
U.S. Mid-cap Growth
(a)
|
11.5
|
|
—
|
|
—
|
|
11.5
|
|
U.S. Small-cap
(a)
|
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
|
|
|
|
(a)
|
The underlying investments classified under U.S. Equity Securities consist of mutual funds (Level 1).
|
ALLETE 2012 Form 10-K
108
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Fair Value (Continued)
|
|
|
|
|
Recurring Fair Value Measures
|
|
Activity in Level 3
|
Private Equity Funds
|
Millions
|
|
Balance as of December 31, 2010
|
|
$12.4
|
|
Actual Return on Plan Assets
|
1.1
|
|
Purchases, sales, and settlements, net
|
0.5
|
|
Balance as of December 31, 2011
|
|
$14.0
|
|
Accounting and disclosure requirements for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) provide guidance for employers that sponsor postretirement health care plans that provide prescription drug benefits. We provide a fully insured postretirement health benefit, including a prescription drug benefit, which qualifies us for a federal subsidy under the Act. The federal subsidy is reflected in the premiums charged to us by the insurance company.
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS
Employee Stock Ownership Plan.
We sponsor a leveraged ESOP within the RSOP. Eligible employees may contribute to the RSOP plan as of their date of hire.
In 1990, the ESOP issued a $75.0 million note (term not to exceed 25 years at 10.25 percent) to use 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 the 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
$7.7 million
in
2012
(
$7.4 million
in
2011
;
$7.1 million
in
2010
).
According to the accounting standards 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 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
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
ESOP Shares
|
|
|
|
Allocated
|
2.2
|
|
2.2
|
|
2.2
|
|
Unallocated
|
0.7
|
|
1.0
|
|
1.3
|
|
Total
|
2.9
|
|
3.2
|
|
3.5
|
|
Fair Value of Unallocated Shares
|
|
$28.7
|
|
|
$42.0
|
|
|
$48.4
|
|
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
1.2 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, 2012
.
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. The
1,293
remaining options outstanding at December 31, 2011, were exercised during 2012. There were
no
options outstanding under the Director Plan at
December 31, 2012
.
ALLETE 2012 Form 10-K
109
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
We currently have the following types of share-based awards outstanding:
Non-Qualified Stock Options
. These options allow for the purchase of shares of common stock at a price equal to the market value of our common stock at the date of grant. Options become exercisable beginning one year after the grant date, with one-third vesting each year over three years. Options may be exercised up to ten years following the date of grant. In the case of qualified retirement, death or disability, options vest immediately and the period over which the options can be exercised is three years. Employees have up to three months to exercise vested options upon voluntary termination or involuntary termination without cause. All options are canceled upon termination for cause. All options vest immediately upon retirement, death, disability or a change of control, as defined in the award agreement. We determine the fair value of options using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on the straight-line basis over the options’ vesting periods, or the accelerated vesting period if the employee is retirement eligible. Stock options have not been granted under our Executive Plan since 2008.
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.
Performance Shares.
Under the performance share awards plan, the number of shares earned is contingent upon attaining specific market goals over a three-year performance period. Market 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 rata portion of the award will be earned at the conclusion of the performance period based on the market goals achieved. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be paid based on the greater of actual performance up to the date of the change in control or target performance. The fair value of these awards is determined by the probability of meeting the total shareholder return goals. Compensation cost is recognized over the
three
-year performance period based on our estimate of the number of shares which will be earned by the award recipients.
Restricted Stock Units.
Under the restricted stock units plan, shares for retirement eligible participants vest monthly over a
three
-year period. For non-retirement eligible participants, shares vest at the end of the three-year period. In the case of qualified retirement, death or disability, a pro rata portion of the award will be earned. In the case of termination of employment for any reason other than qualified retirement, death or disability, no award will be earned. If there is a change in control, a pro rata portion of the award will be earned. The fair value of these awards is equal to the grant date fair value. Compensation cost is recognized over the three-year vesting period based on our estimate of the number of shares which will be earned by the award recipients.
Employee Stock Purchase Plan (ESPP).
Under our ESPP, eligible employees may purchase ALLETE common stock at a
5
percent discount from the market price. Because the discount is not greater than
5 percent
, we are not required to apply fair value accounting to these awards.
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
|
2012
|
2011
|
2010
|
Millions
|
|
|
|
Stock Options
|
—
|
|
—
|
|
|
$0.1
|
|
Performance Shares
|
|
$1.4
|
|
|
$1.1
|
|
1.5
|
|
Restricted Stock Units
|
0.7
|
|
0.5
|
|
0.6
|
|
Total Share-Based Compensation Expense
|
|
$2.1
|
|
|
$1.6
|
|
|
$2.2
|
|
Income Tax Benefit
|
|
$0.9
|
|
|
$0.7
|
|
|
$0.9
|
|
ALLETE 2012 Form 10-K
110
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
There were
no
capitalized stock-based compensation costs at
December 31, 2012
,
2011
, or
2010
.
As of
December 31, 2012
, the total unrecognized compensation cost for the performance share awards and restricted stock units not yet recognized in our Consolidated Statements of Income was
$1.3 million
and
$0.6 million
, respectively. These amounts are expected to be recognized over a weighted-average period of
1.7 years
for performance share awards and
1.7 years
for restricted stock units.
Non-Qualified Stock Options.
The following table presents information regarding our outstanding stock options as of
December 31, 2012
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
2011
|
2010
|
|
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,
|
460,234
|
|
|
$41.68
|
|
560,887
|
|
|
$40.69
|
|
646,235
|
|
|
$40.05
|
|
Granted
(a)
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Exercised
|
49,075
|
|
|
$35.84
|
|
80,798
|
|
|
$34.25
|
|
40,769
|
|
|
$27.76
|
|
Forfeited
|
15,481
|
|
|
$44.86
|
|
19,855
|
|
|
$43.96
|
|
44,579
|
|
|
$43.16
|
|
Outstanding as of December 31,
|
395,678
|
|
|
$42.28
|
|
460,234
|
|
|
$41.68
|
|
560,887
|
|
|
$40.69
|
|
Exercisable as of December 31,
|
395,678
|
|
|
$41.71
|
|
460,234
|
|
|
$41.59
|
|
523,491
|
|
|
$39.76
|
|
|
|
(a)
|
Stock options have not been granted since 2008. The weighted-average grant-date intrinsic value of options granted in 2008 was
$6.18
.
|
Cash received from non-qualified stock options exercised was less than
$0.1 million
in
2012
. 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
$0.3 million
during
2012
(
$0.5 million
in
2011
;
$0.3 million
in
2010
).
|
|
|
|
|
|
|
|
|
|
|
|
Range of Exercise Price
|
As of December 31, 2012
|
$23.79 to $26.91
|
$37.76 to $41.35
|
$44.15 to $48.65
|
Options Outstanding and Exercisable:
|
|
|
|
Number Outstanding and Exercisable
|
1,340
|
|
236,052
|
|
158,286
|
|
Weighted Average Remaining Contractual Life (Years)
|
0.1
|
|
3.5
|
|
3.6
|
|
Weighted Average Exercise Price
|
|
$23.79
|
|
|
$39.64
|
|
|
$46.38
|
|
Performance Shares.
The following table presents information regarding our non-vested performance shares as of
December 31, 2012
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
2011
|
2010
|
|
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,
|
128,333
|
|
|
$36.54
|
|
122,489
|
|
|
$38.15
|
|
121,825
|
|
|
$41.96
|
|
Granted
(a)
|
38,764
|
|
|
$44.70
|
|
39,312
|
|
|
$41.00
|
|
49,302
|
|
|
$35.44
|
|
Awarded
|
(41,009
|
)
|
|
$34.25
|
|
(32,368
|
)
|
|
$48.10
|
|
—
|
|
—
|
|
Unearned Grant Award
|
(17,575
|
)
|
|
$34.25
|
|
—
|
|
—
|
|
(22,909
|
)
|
|
$54.50
|
|
Forfeited
|
(614
|
)
|
|
$34.49
|
|
(1,100
|
)
|
|
$34.35
|
|
(25,729
|
)
|
|
$36.45
|
|
Non-vested as of December 31,
|
107,899
|
|
|
$40.73
|
|
128,333
|
|
|
$36.54
|
|
122,489
|
|
|
$38.15
|
|
(a) Shares granted includes accrued dividends.
ALLETE 2012 Form 10-K
111
NOTE 16. EMPLOYEE STOCK AND INCENTIVE PLANS (Continued)
There were
33,525
and
41,332
performance shares granted in January 2012 and 2013, for the
three
-year performance periods ending in 2014 and 2015, respectively. The ultimate issuance is contingent upon the attainment of certain future market goals of ALLETE during the performance periods. The grant date fair value of the performance shares granted was
$1.5 million
and
$2.2 million
, respectively.
There were
41,009
and
18,605
performance shares awarded in February 2012 and 2013, for the
three
-year performance periods ending in 2011 and 2012, respectively. The grant date fair value of the shares awarded was
$1.4 million
and
$0.7 million
, respectively.
Restricted Stock Units.
The following table presents information regarding our available restricted stock units as of
December 31, 2012
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
2011
|
2010
|
|
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,
|
63,464
|
|
|
$32.57
|
|
43,803
|
|
|
$30.61
|
|
28,983
|
|
|
$29.41
|
|
Granted
(a)
|
18,162
|
|
|
$40.83
|
|
20,136
|
|
|
$36.74
|
|
26,589
|
|
|
$31.83
|
|
Awarded
|
(24,707
|
)
|
|
$29.43
|
|
(215
|
)
|
|
$30.30
|
|
(3,091
|
)
|
|
$29.75
|
|
Forfeited
|
(504
|
)
|
|
$31.80
|
|
(260
|
)
|
|
$29.41
|
|
(8,678
|
)
|
|
$30.62
|
|
Available as of December 31,
|
56,415
|
|
|
$36.61
|
|
63,464
|
|
|
$32.57
|
|
43,803
|
|
|
$30.61
|
|
(a) Shares granted includes accrued dividends.
There were
16,355
and
19,193
restricted stock units granted in January 2012 and 2013, for the vesting periods ending in 2014 and 2015, respectively. The grant date fair value of the restricted stock units granted was
$0.7 million
and
$0.8 million
, respectively.
There were
24,707
restricted stock units awarded in 2012. The grant date fair value of the shares awarded was
$0.7 million
.
There were
20,939
restricted stock units awarded in February 2013. The grant date fair value of the shares awarded was
$0.7 million
.
NOTE 17. 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
|
|
|
|
|
2012
|
|
|
|
|
Operating Revenue
|
|
$240.0
|
|
|
$216.4
|
|
|
$248.8
|
|
|
$256.0
|
|
Operating Income
|
|
$38.4
|
|
|
$23.3
|
|
|
$45.6
|
|
|
$47.9
|
|
Net Income Attributable to ALLETE
|
|
$24.4
|
|
|
$14.4
|
|
|
$29.4
|
|
|
$28.9
|
|
Earnings Per Share of Common Stock
|
|
|
|
|
Basic
|
|
$0.66
|
|
|
$0.39
|
|
|
$0.78
|
|
|
$0.76
|
|
Diluted
|
|
$0.66
|
|
|
$0.39
|
|
|
$0.78
|
|
|
$0.75
|
|
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
|
|