NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
|
|
|
|
|
|
|
|
|
|
Operating Expenses – Other
|
|
|
|
Year Ended December 31
|
2017
|
|
2016
|
|
2015
|
|
Millions
|
|
|
|
Impairment of Real Estate
(a)
|
—
|
|
—
|
|
|
$36.3
|
|
Impairment of Goodwill
(b)
|
—
|
|
|
$3.3
|
|
—
|
|
Change in Fair Value of Contingent Consideration
(c)
|
$(0.7)
|
(13.6
|
)
|
—
|
|
Total Operating Expenses – Other
|
$(0.7)
|
$(10.3)
|
|
$36.3
|
|
|
|
(a)
|
See Impairment of Long-Lived Assets.
|
|
|
(b)
|
See Goodwill and Intangible Assets.
|
|
|
(c)
|
See Note 9. Fair Value.
|
Unamortized Discount and Premium on Debt.
Discount and premium on debt are deferred and amortized over the terms of the related debt instruments using a method which approximates the effective interest method.
Income Taxes.
ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns. We account for income taxes using the liability method in accordance with GAAP for income taxes. Under the liability method, deferred income tax assets and liabilities are established for all temporary differences in the book and tax basis of assets and liabilities, based upon enacted tax laws and rates applicable to the periods in which the taxes become payable.
Due to the effects of regulation on Minnesota Power and SWL&P, certain adjustments made to deferred income taxes are, in turn, recorded as regulatory assets or liabilities. Federal investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property. In accordance with GAAP for uncertainty in income taxes, we are required to recognize in our financial statements the largest tax benefit of a tax position that is “more‑likely‑than‑not” to be sustained on audit, based solely on the technical merits of the position as of the reporting date. The term “more‑likely‑than‑not” means more than
50 percent
likely. (See Note 13. Income Tax Expense.)
Tax Cuts and Jobs Act of 2017
. On December 22, 2017, the TCJA was enacted into law. The TCJA has significantly changed the U.S. Internal Revenue Code (IRC) and the taxation of corporations. The more significant provisions that impact our Company include a reduction in the corporate federal income tax rate from
35 percent
to
21 percent
, and provisions related to our regulated utilities which generally allow for the continued deductibility of interest expense, the elimination of full expensing for property acquired after September 27, 2017, and the continuation of normalization requirements for accelerated tax depreciation taken by regulated utilities. The TCJA allows for full expensing for property and imposes an interest expense limitation on non‑regulated operations. The interest expense limitation is not expected to have a material impact on the Company.
Under ASC 740, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. ASC 740 requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, as of the date of enactment, the Company’s deferred income tax assets and liabilities were remeasured based upon the new tax rate. For our Regulated Operations segment, the change in deferred income taxes was recorded as regulatory assets, regulatory liabilities and a change to our investment in ATC. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the IRC over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. The decrease in our investment in ATC is expected to be amortized into earnings over time. For our ALLETE Clean Energy and U.S. Water Services segments as well as our Corporate and Other businesses, the change in deferred income taxes is recorded in income tax expense on the Consolidated Statement of Income.
On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118) which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete, and provides for up to a one year period in which to complete the required analyses and accounting (the measurement period). SAB 118 describes three scenarios associated with a company’s status of accounting for the TCJA: (1) a company is complete with its accounting for certain effects, (2) a company is able to determine a reasonable estimate for certain effects and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted.
ALLETE, Inc. 2017 Form 10-K
87
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Income Taxes (Continued)
The Company has made a provisional estimate for the measurement and accounting of the effects of the TCJA, which have been reflected in the Consolidated Financial Statements as of December 31, 2017. The measurement and accounting of the effects of the TCJA resulted in a decrease to Income Tax Expense of
$13.0 million
for the year ended December 31, 2017, as well as a decrease to Deferred Income Taxes of
$353.6 million
, a decrease to Investment in ATC of
$27.9 million
, an increase to Regulatory Assets of
$80.9 million
and an increase to Regulatory Liabilities of
$393.6 million
as of December 31, 2017. The provisional amounts incorporate assumptions made based upon the Company’s current interpretation of the TCJA, and may change as the Company receives additional clarification and implementation guidance. Any adjustments recorded to the provisional amounts in 2018 will be included in income from operations as an adjustment to income tax expense.
As provided for under SAB 118, the Company has not estimated the impact for items for which it cannot predict, such as guidance that has not yet been provided, or for which federal or state regulatory treatment is still uncertain. The determination of the impact of the income tax effects of these types of items will occur when more information is available to the Company.
Excise Taxes.
We collect excise taxes from our customers levied by government entities. These taxes are stated separately on the billing to the customer and recorded as a liability to be remitted to the government entity. We account for the collection and payment of these taxes on a net basis.
Purchase Accounting.
In accordance with the authoritative accounting guidance, the purchase price of an acquired business is generally allocated to the assets acquired and liabilities assumed at their estimated fair values on the date of acquisition. Any unallocated purchase price amount is recognized as goodwill on the Consolidated Balance Sheet if it exceeds the estimated fair value and as a bargain purchase gain on the Consolidated Income Statement if it is below the estimated fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts as well as the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. (See Note 6. Acquisitions.)
New Accounting Pronouncements.
Recently Adopted Pronouncements
Simplifying the Measurement of Inventory.
In 2015, the FASB issued an accounting standards update which requires entities that measure inventory using the first-in, first-out or average cost methods to measure inventory at the lower of cost or net realizable value. Net realizable value is defined as estimated selling price in the ordinary course of business less reasonably predictable costs of completion, disposal and transportation. This accounting guidance was adopted in the first quarter of 2017 and did not have a material impact on our Consolidated Financial Statements.
Improvements to Employee Share-Based Payment Accounting.
In March 2016, the FASB issued guidance to simplify the accounting for share-based payment transactions by requiring all excess tax benefits and deficiencies to be recognized in income tax expense or benefit in earnings, thus eliminating the requirement to classify the excess tax benefit and deficiencies as additional paid-in capital. Under the new guidance, an entity makes an accounting policy election to either estimate the expected forfeiture awards or account for forfeitures as they occur. This accounting guidance was adopted in the first quarter of 2017. The adoption of this guidance is expected to result in a less than
$1 million
impact to income tax expense (benefit) annually.
Clarifying the Definition of a Business.
In January 2017, the FASB issued clarifying guidance on the definition of a business and provided additional guidance to assist with evaluating whether transactions are to be accounted for as an acquisition or disposal of a group of assets or a business. The clarifying guidance will also impact other areas including the accounting for goodwill and consolidation. This accounting guidance was adopted in the first quarter of 2017 and did not have an impact on our Consolidated Financial Statements.
ALLETE, Inc. 2017 Form 10-K
88
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements (Continued)
Stock Compensation: Scope of Modification Accounting.
In May 2017, the FASB issued additional clarifying guidance regarding circumstances where changes to the terms or conditions of share-based payment awards require an entity to apply modification accounting under ASC 718. The guidance provides specific situations that would be excluded from effects of a modification including if the fair value, vesting conditions, and classification are the same before and after modification. The amendments in this update will be applied prospectively to awards modified on or after adoption. This accounting guidance was adopted by the Company in the second quarter of 2017 and did not have an impact on our Consolidated Financial Statements.
Recently Issued Pronouncements
Simplifying the Test for Goodwill Impairment
. In January 2017, the FASB issued updated guidance which simplifies the measurement of goodwill impairment by removing step two of the goodwill impairment test that requires the determination of the fair value of individual assets and liabilities of a reporting unit. The updated guidance requires goodwill impairment to be measured as the amount by which a reporting unit’s carrying value exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This guidance is effective for the Company beginning in the first quarter of 2020, with early adoption permitted on a prospective basis.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.
In March 2017, the FASB issued guidance to improve the presentation of net periodic pension and postretirement benefit costs. Under the revised guidance of ASC 715, an entity shall present the service cost component of the net periodic benefit cost in the same income statement line as other employee compensation costs arising from services rendered during the period. The guidance also allows only the service cost component of the periodic cost to be eligible for capitalization. The standard will be applied retrospectively for income statement presentation, and prospectively for capitalization of service cost components. We do not expect there to be a material impact on the Consolidated Financial Statements with the adoption of the updated guidance which is effective for the Company beginning in the first quarter of 2018.
Revenue from Contracts with Customers.
In 2014, the FASB issued amended revenue recognition guidance that clarifies the principles for recognizing revenue from contracts with customers by providing a single comprehensive model to determine the measurement of revenue and timing of recognition. The guidance requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. The guidance also requires expanded disclosures relating to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Additionally, qualitative and quantitative disclosures are required regarding customer contracts, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. As of December 31, 2017, the Company has reviewed all of its revenue streams and contracts for its regulated, energy infrastructure and related services, and corporate and other businesses, completing the evaluations of the impact of this new guidance. Based on these evaluations, the Company has determined the new guidance does not materially alter the amount or timing of revenue recognition from the current methodology nor does it have a material transition adjustment upon adoption. Additionally, management does not expect the recognition of any assets from the costs to obtain a contract. Management continues to draft and refine the additional disclosures needed to meet the requirements of the new standard following adoption. The Company will adopt and implement the new guidance on a modified retrospective basis which requires application of standards to all contracts with customers effective January 1, 2018, with the cumulative impact on contracts with performance obligations not yet satisfied as of December 31, 2017, recognized as an adjustment to Retained Earnings on the Consolidated Balance Sheet.
Leases.
In February 2016, the FASB issued an accounting standard update which revises the existing guidance for leases. Under the revised guidance, lessees will be required to recognize a “right-of-use” asset and a lease liability for all leases with a term greater than 12 months. The new standard also requires additional quantitative and qualitative disclosures by lessees and lessors to enable users of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The accounting for leases by lessors and the recognition, measurement, and presentation of expenses and cash flows from leases are not expected to significantly change as a result of the new guidance. As of December 31, 2017, ALLETE expects to make
$79.9 million
in minimum lease payments due in future years (undiscounted). The revised guidance is effective for the Company beginning in the first quarter of 2019 with early adoption permitted. We are currently evaluating the impact of the revised lease guidance on our Consolidated Financial Statements.
ALLETE, Inc. 2017 Form 10-K
89
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements (Continued)
Financial Instruments.
In January 2016, the FASB issued an accounting standard update which requires entities to measure their investments at fair value and recognize any changes in fair value in net income unless the investments qualify for the practicability exception. The practicability exception will be available for equity investments that do not have readily determinable fair values. The updated guidance is effective for the Company beginning in the first quarter of 2018 and will result in a cumulative-effect adjustment to Retained Earnings on the Consolidated Balance Sheet in the fiscal year of adoption. We have performed a preliminary evaluation of the impact of this update, and based on that evaluation, we do not expect the adoption of the update to have a material impact on our Consolidated Financial Statements.
Classification of Certain Cash Receipts and Cash Payments.
In August 2016, the FASB issued an accounting standard update which addresses the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero‑coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. This accounting guidance is effective for the Company beginning in the first quarter of 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.
Statement of Cash Flows: Restricted Cash.
In November 2016, the FASB issued an accounting standard update related to the presentation of restricted cash in the Company’s Consolidated Statement of Cash Flows. The update requires that the Consolidated Statement of Cash Flows explain the change during the period in cash, cash equivalents, and restricted cash. Restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Consolidated Statement of Cash Flows. This accounting guidance is effective for the Company beginning in the first quarter of 2018 and will be applied retrospectively to all periods presented. The guidance will result in changes to the Company’s Consolidated Statement of Cash Flows such that restricted cash amounts will be included in the beginning-of-period and end‑of‑period cash and cash equivalents totals when adopted for our fiscal year beginning January 1, 2018. We do not expect the adoption of the update to have a material impact on our Consolidated Statement of Cash Flows.
Revision of Prior Balance Sheet.
During the first quarter of 2017, the Company identified an error related to the deferred income tax treatment associated with its Wholesale and Retail Contra AFUDC Regulatory Liability. The Company evaluated the materiality of the error and concluded that it was not material to any previously issued historical financial statements. The Company has revised its Consolidated Balance Sheet as of December 31, 2016, by decreasing Regulatory Assets and Deferred Income Taxes by
$29.5 million
. The correction had no impact on our Consolidated Statement of Income.
Reclassification of Prior Income Statement.
Beginning with the second quarter of 2017, the Company enhanced its presentation of Operating Revenue and certain Operating Expenses on the Consolidated Statement of Income by presenting the caption Operating Revenue separately as Operating Revenue – Utility and Operating Revenue – Non-utility. In conformity with the current presentation, we now present
$1,007.7 million
and
$991.2 million
of Operating Revenue as Operating Revenue – Utility for the years ended
December 31, 2016
, and
2015
, respectively, as it is generated from our regulated utility operations. Non-utility revenue of
$339.0 million
and
$495.2 million
for the years ended
December 31, 2016
, and
2015
respectively, is now presented as Operating Revenue – Non-utility. In addition, the captions Fuel and Purchased Power and Cost of Sales have been updated to Fuel, Purchased Power and Gas – Utility and Cost of Sales – Non-utility. As a result, we have reclassified
$7.0 million
relating to the cost of gas sales at SWL&P from the historic caption Cost of Sales to Fuel, Purchased Power and Gas – Utility for the year ended
December 31, 2016
, and
$7.9 million
for the year ended
December 31, 2015
.
ALLETE, Inc. 2017 Form 10-K
90
NOTE 2. PROPERTY, PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
As of December 31
|
2017
|
|
|
2016
|
|
Millions
|
|
|
|
Regulated Operations
|
|
|
|
Property, Plant and Equipment in Service
|
|
$4,523.7
|
|
|
|
$4,437.0
|
|
Construction Work in Progress
|
121.6
|
|
|
84.2
|
|
Accumulated Depreciation
|
(1,520.5
|
)
|
|
(1,426.1
|
)
|
Regulated Operations – Net
|
3,124.8
|
|
|
3,095.1
|
|
ALLETE Clean Energy
|
|
|
|
Property, Plant and Equipment in Service
|
482.5
|
|
|
472.3
|
|
Construction Work in Progress
|
144.9
|
|
|
101.0
|
|
Accumulated Depreciation
|
(60.8
|
)
|
|
(41.0
|
)
|
ALLETE Clean Energy – Net
|
566.6
|
|
|
532.3
|
|
U.S. Water Services
|
|
|
|
Property, Plant and Equipment in Service
|
24.8
|
|
|
19.5
|
|
Accumulated Depreciation
|
(10.4
|
)
|
|
(6.9
|
)
|
U.S. Water Services – Net
|
14.4
|
|
|
12.6
|
|
Corporate and Other
(a)
|
|
|
|
Property, Plant and Equipment in Service
|
204.7
|
|
|
179.8
|
|
Construction Work in Progress
|
5.0
|
|
|
2.8
|
|
Accumulated Depreciation
|
(93.1
|
)
|
|
(81.4
|
)
|
Corporate and Other – Net
|
116.6
|
|
|
101.2
|
|
Property, Plant and Equipment – Net
|
|
$3,822.4
|
|
|
|
$3,741.2
|
|
|
|
(a)
|
Primarily includes BNI Energy and a small amount of non-rate base generation.
|
Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of assets.
|
|
|
|
|
|
Estimated Useful Lives of Property, Plant and Equipment
|
Regulated Operations
|
|
|
ALLETE Clean Energy
(a)
|
5 to 35 years
|
Generation
|
5 to 50 years
|
|
U.S. Water Services
|
3 to 39 years
|
Transmission
|
44 to 67 years
|
|
Corporate and Other
|
3 to 50 years
|
Distribution
|
18 to 65 years
|
|
|
|
|
|
(a)
|
ALLETE Clean Energy’s Property, Plant and Equipment consists primarily of WTGs with estimated useful lives ranging from 30 years to 35 years.
|
Asset Retirement Obligations.
We recognize, at fair value, obligations associated with the retirement of certain tangible, long‑lived assets that result from the acquisition, construction, development or normal operation of the asset. Asset retirement obligations (AROs) relate primarily to the decommissioning of our coal-fired and wind energy facilities, and land reclamation at BNI Energy. AROs are included in Other Non-Current Liabilities on the Consolidated Balance Sheet. The associated retirement costs are capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. Removal costs associated with certain distribution and transmission assets have not been recognized, as these facilities have indeterminate useful lives.
Conditional asset retirement obligations have been identified for treated wood poles and remaining polychlorinated biphenyl and asbestos-containing assets; however, removal liabilities 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 authorities have allowed provisions for future plant removal costs in depreciation rates. These plant removal cost recoveries are classified either as AROs or as a regulatory liability for non-AROs. To the extent annual accruals for plant removal costs differ from accruals under approved depreciation rates, a regulatory asset has been established in accordance with GAAP for AROs. (See Note 4. Regulatory Matters.)
ALLETE, Inc. 2017 Form 10-K
91
NOTE 2. PROPERTY, PLANT AND EQUIPMENT (Continued)
|
|
|
|
|
|
Asset Retirement Obligations
|
|
|
Millions
|
|
|
Obligation as of December 31, 2015
|
|
|
$131.4
|
|
Accretion
|
|
8.0
|
|
Liabilities Settled
|
|
(6.5
|
)
|
Revisions in Estimated Cash Flows
|
|
3.7
|
|
Obligation as of December 31, 2016
|
|
136.6
|
|
Accretion
|
|
7.6
|
|
Liabilities Settled
|
|
(5.9
|
)
|
Revisions in Estimated Cash Flows
|
|
(15.6
|
)
|
Obligation as of December 31, 2017
|
|
|
$122.7
|
|
NOTE 3. JOINTLY-OWNED FACILITIES AND PROJECTS
Boswell Unit 4.
Minnesota Power owns
80 percent
of the
585
MW Boswell Unit 4. While Minnesota Power operates the plant, certain decisions about the operations of Boswell Unit 4 are subject to the oversight of a committee on which it and WPPI Energy, the owner of the remaining
20 percent
, have equal representation and voting rights. Each owner must provide its own financing and is obligated to its ownership share of operating costs. Minnesota Power’s share of operating expenses for Boswell Unit 4 is included in Operating Expenses on the Consolidated Statement of Income.
CapX2020.
Minnesota Power was a participant in the CapX2020 initiative which represented an effort to ensure electric transmission and distribution reliability in Minnesota and the surrounding region for the future. CapX2020, which consisted of electric cooperatives and municipal and investor-owned utilities, including Minnesota’s largest transmission owners, assessed the transmission system and projected growth in customer demand for electricity through 2020. Minnesota Power participated in
three
CapX2020 projects which were completed and placed in service in 2011, 2012 and 2015.
Minnesota Power’s investments in jointly-owned facilities and projects and the related ownership percentages are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Utility Plant
|
Plant in Service
|
Accumulated Depreciation
|
Construction Work in Progress
|
% Ownership
|
Millions
|
|
|
|
|
As of December 31, 2017
|
|
|
|
|
Boswell Unit 4
|
|
$668.2
|
|
|
$222.8
|
|
|
$8.2
|
|
80
|
CapX2020 Projects
|
101.0
|
|
8.4
|
|
—
|
|
9.3 - 14.7
|
Total
|
|
$769.2
|
|
|
$231.2
|
|
|
$8.2
|
|
|
As of December 31, 2016
|
|
|
|
|
Boswell Unit 4
|
|
$668.1
|
|
|
$211.2
|
|
|
$8.1
|
|
80
|
CapX2020 Projects
|
101.2
|
|
5.9
|
|
—
|
|
9.3 - 14.7
|
Total
|
|
$769.3
|
|
|
$217.1
|
|
|
$8.1
|
|
|
NOTE 4. REGULATORY MATTERS
Electric Rates.
Entities within our Regulated Operations segment file for periodic rate revisions with the MPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for transmission, renewable and environmental investments and expenditures. (See
Transmission Cost Recovery Rider, Renewable Cost Recovery Rider
and
Environmental Improvement Rider
.) Revenue from cost recovery riders was
$96.9 million
in
2017
(
$97.1 million
in
2016
;
$89.6 million
in
2015
).
ALLETE, Inc. 2017 Form 10-K
92
NOTE 4. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
2016 Minnesota General Rate Case.
In November 2016, Minnesota Power filed a retail rate increase request with the MPUC seeking an average increase of approximately
9 percent
for retail customers. The rate filing sought a return on equity of
10.25
percent and a
53.81 percent
equity ratio. On an annualized basis, the requested final rate increase would have generated approximately
$55 million
in additional revenue. In December 2016, Minnesota Power filed a request to modify its original interim rate proposal reducing its requested interim rate increase to
$34.7 million
from the original request of approximately
$49 million
due to a change in its electric sales forecast. In December 2016 orders, the MPUC accepted the November 2016 filing as complete and authorized an annual interim rate increase of
$34.7 million
beginning
January 1, 2017
.
On February 23, 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an order dated April 13, 2017, the MPUC approved Minnesota Power’s updated retail rate request resulting in a reduction in the annual interim rate increase to
$32.2 million
beginning May 1, 2017. As a result of working with intervenors and further developments as the rate review progressed, Minnesota Power’s final rate request was adjusted to approximately
$49 million
on an annualized basis. At a hearing on January 18, 2018, the MPUC made determinations regarding Minnesota Power’s general rate case including allowing a return on common equity of
9.25 percent
and a
53.81
percent equity ratio. Upon commencement of final rates, we expect additional revenue of approximately
$13 million
on an annualized basis. Final rates are expected to commence in the fourth quarter of 2018; interim rates will be collected through this period which will be fully offset by the recognition of a corresponding reserve. As a result of the MPUC’s decisions on January 18, 2018, Minnesota Power has recorded a reserve for an interim rate refund of approximately
$32 million
as of
December 31, 2017
. The MPUC also disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a
$19.5 million
pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. An order from the MPUC setting forth the effective date of final rates is expected by March 12, 2018. Minnesota Power will review this order for potential reconsideration of certain issues at that time.
As part of its decision in Minnesota Power’s 2016 general rate case, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050 primarily to mitigate rate increases for our customers, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense of approximately
$25 million
pre-tax in 2017.
Energy-Intensive Trade-Exposed Customer Rates.
An EITE customer ratemaking law was enacted in 2015 which established that it is the energy policy of Minnesota to have competitive rates for certain industries such as mining and forest products. In 2015, Minnesota Power filed a rate schedule petition with the MPUC for EITE customers and a corresponding rider for EITE cost recovery. In a March 2016 order, the MPUC dismissed the petition without prejudice. In June 2016, Minnesota Power filed a revised EITE petition with the MPUC which included additional information on the net benefits analysis, limits on eligible customers and term lengths for the EITE discount. The rate adjustments were intended to be revenue and cash flow neutral to Minnesota Power. The MPUC approved a reduction in rates for EITE customers in a December 2016 order and subsequently approved cost recovery in an order dated April 20, 2017; collection of the discount was subject to the MPUC’s review of Minnesota Power’s compliance filing implementing approval of a recovery mechanism, with the subsequent order issued on October 13, 2017, that modified the order dated April 20, 2017. During 2017, Minnesota Power provided discounts of
$8.6 million
which were recorded as a receivable. On September 29, 2017, Minnesota Power informed its EITE customers that it has suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing on September 7, 2017, as well as the interim rate reduction and decisions in its 2016 general rate case. Based on the MPUC’s decisions at a hearing on January 18, 2018, as part of Minnesota Power’s 2016 general rate case, Minnesota Power reinstated the EITE discount effective January 1, 2018. Minnesota Power expects the discount to EITE customers to be approximately
$15 million
annually based on EITE customer current operating levels. While interim rates are in effect for Minnesota Power’s 2016 general rate case, EITE discounts will offset interim rate refund reserves for non-EITE customers.
FERC-Approved Wholesale Rates.
Minnesota Power has
16
non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. All wholesale contracts include a termination clause requiring a
three
-year notice to terminate.
ALLETE, Inc. 2017 Form 10-K
93
NOTE 4. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
Minnesota Power’s wholesale electric contract with the Nashwauk Public Utilities Commission is effective through at least December 31, 2032. No termination notice may be given for this contract prior to July 1, 2029. The wholesale electric service contracts with SWL&P and another municipal customer are effective through at least February 28, 2021, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided a contract termination notice in June 2016. Minnesota Power currently provides approximately
29
MW of average monthly demand to this customer. The rates included in these three contracts are set each July 1 based on a cost-based formula methodology, using estimated costs and a rate of return that is equal to Minnesota Power’s authorized rate of return for Minnesota retail customers. The formula-based rate methodology also provides for a yearly true-up calculation for actual costs incurred.
Minnesota Power’s wholesale electric contracts with
14
municipal customers are effective through at least December 31, 2024. No termination notices may be given prior to three years before maturity. These contracts include fixed capacity charges through 2018; beginning in 2019, the capacity charge will be determined using a cost-based formula methodology with limits on the annual change from the previous year’s capacity charge. The base energy charge for each year of the contract term will be set each January 1, subject to monthly adjustment, and will also be determined using a cost-based formula methodology.
Transmission Cost Recovery Rider.
Minnesota Power has an approved cost recovery rider in place for certain transmission investments and expenditures. In a February 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates which allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain transmission facilities plus a return on the capital invested. As a result of the MPUC approval of the certificate of need for the GNTL in 2015, the project is eligible for cost recovery under the existing transmission cost recovery rider. Minnesota Power is funding the construction of the GNTL with a subsidiary of Manitoba Hydro (see
Great Northern Transmission Line
), and anticipates including its portion of the investments and expenditures for the GNTL in future transmission bill factor filings.
Renewable Cost Recovery Rider.
Minnesota Power has an approved cost recovery rider in place for investments and expenditures related to Bison, and the restoration and repair of Thomson. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of constructing certain renewable investments plus a return on the capital invested. Updated customer billing rates for the renewable cost recovery rider were approved by the MPUC in an order dated November 8, 2017.
In a November 2016 order, the MPUC directed Minnesota Power to attribute all North Dakota investment tax credits realized from Bison to Minnesota Power regulated retail customers. As a result of the adverse regulatory outcome, Minnesota Power recorded a regulatory liability and a reduction in Operating Revenue of approximately
$15 million
in 2016. The North Dakota investment tax credits previously recognized as income tax credits in Corporate and Other were reversed in 2016 resulting in an
$8.8 million
charge to net income in 2016. In December 2016, Minnesota Power submitted a request for reconsideration with the MPUC. In an order dated February 14, 2017, the MPUC decided to reconsider its November 2016 order.
In an order dated December 7, 2017, the MPUC modified its November 2016 order to allow Minnesota Power to account for North Dakota investment tax credits based on the long-standing regulatory precedents of stand-alone allocation methodology of accounting for income taxes. As a result of the favorable regulatory outcome, Minnesota Power recorded a reduction in its regulatory liability and an increase in Operating Revenue of approximately
$14 million
in 2017. The North Dakota investment tax credits were reestablished as income tax credits in Corporate and Other, resulting in a
$7.9 million
increase to net income in 2017.
The stand-alone method provides that income taxes (and credits) are calculated as if Minnesota Power was the only entity included in ALLETE’s consolidated federal and unitary state income tax returns. Minnesota Power has recorded a regulatory liability for North Dakota investment tax credits generated by its jurisdictional activity and expected to be realized in the future. North Dakota investment tax credits attributable to ALLETE’s apportionment and income of ALLETE’s other subsidiaries are included in Corporate and Other operations.
Minnesota Power also has approval for current cost recovery of investments and expenditures related to compliance with the Minnesota Solar Energy Standard. (See
Minnesota Solar Energy Standard.
) Currently, there is no approved customer billing rate for solar costs.
ALLETE, Inc. 2017 Form 10-K
94
NOTE 4. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
Environmental Improvement Rider
. Minnesota Power has an approved environmental improvement rider in place for investments and expenditures related to the implementation of the Boswell Unit 4 mercury emissions reduction plan completed in 2015. Updated customer billing rates for the environmental improvement rider were approved by the MPUC in a December 2016 order; however, in an order dated March 22, 2017, the MPUC approved a request by Minnesota Power to delay implementation of the updated rates until resolution of its 2016 general rate case. (See
2016 Minnesota General Rate Case.)
Fuel Adjustment Clause Reform Pilot
. In an order dated December 19, 2017, the MPUC adopted a three-year pilot program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order changes the method of accounting for all Minnesota electric utilities to a monthly budgeted, forwarded-looking FAC with an annual prudence review and true-up to actual allowed costs. The MPUC is seeking input from Minnesota electric utilities and other stakeholders on the implementation and transition accounting needed to adopt the change. The three-year pilot program is expected to begin in 2019. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of the forward-looking fuel adjustment clause methodology in this proceeding resulting in a
$19.5 million
pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017.
Tax Cuts and Jobs Act of 2017
. On December 29, 2017, the MPUC opened a docket to review the effects of the TCJA on electric and natural gas rates and services in Minnesota, including the legislation’s impact on tax rates and utilities’ deferred income tax assets and liabilities. On January 19, 2018, the MPUC issued a notice of request for information and established comment periods with an initial filing required by March 2, 2018. On January 10, 2018, the PSCW also opened a docket to review the effects of this legislation and directed Wisconsin utilities to defer its impacts until further direction is provided by the PSCW. We have recorded the impact of the remeasurement of deferred income tax assets and liabilities resulting from the federal income tax rate change of the TCJA for Minnesota Power and SWL&P as regulatory assets and liabilities as the benefits of the TCJA are expected to be passed back to our customers over time. (See
Regulatory Assets and Liabilities
.) The final amount and timing over which the benefits of the TCJA will be passed back to customers is expected to be determined in these dockets; however, we are unable to predict the outcome of these regulatory proceedings.
2016 Wisconsin General Rate Case.
SWL&P’s current retail rates are based on a 2017 PSCW retail rate order effective August 14, 2017, that allows for a
10.5 percent
return on common equity and a
55 percent
equity ratio. SWL&P’s retail rates prior to August 14, 2017, were based on a 2012 PSCW retail rate order that provided for a
10.9 percent
return on equity. The 2017 PSCW retail rate order authorizes SWL&P to collect on average a
2.9 percent
increase in rates for retail customers (
3.8 percent
increase in electric rates;
4.8 percent
decrease in natural gas rates; and
9.8 percent
increase in water rates). On an annualized basis, SWL&P expects to collect additional revenue of
$2.5 million
.
Integrated Resource Plan.
In 2015, Minnesota Power filed its 2015 IRP with the MPUC which included an analysis of a variety of existing and future energy resource alternatives and a projection of customer cost impact by class. The 2015 IRP also contained steps in Minnesota Power’s
EnergyForward
strategic plan including the economic idling of Taconite Harbor Units 1 and 2 which occurred in September 2016, the ceasing of coal-fired operations at Taconite Harbor in 2020, and the addition of between
200
MW and
300
MW of natural gas-fired generation in the next decade. In a July 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for Taconite Harbor, directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022, required an analysis of generation and demand response alternatives to be filed with a natural gas resource proposal, and required Minnesota Power to conduct request for proposals for additional wind, solar and demand response resource additions subject to further MPUC approvals. In October 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired in 2018.
On July 28, 2017, Minnesota Power submitted a resource package to the MPUC requesting approval of PPAs for the output of a
250
MW wind energy facility and a
10
MW solar energy facility as well as approval of a
250
MW natural gas energy PPA. These agreements will be subject to MPUC approval of the construction of a
525
MW to
550
MW combined-cycle natural gas-fired generating facility which will be jointly owned by Dairyland Power Cooperative and a subsidiary of ALLETE. Minnesota Power would purchase approximately
50 percent
of the facility's output starting in 2025. In an order dated September 19, 2017, the MPUC approved Minnesota Power’s request to extend the next IRP filing deadline until October 1, 2019, and Minnesota Power’s request that approval for the natural gas energy PPA be decided through an administrative law judge process. The administrative law judge is expected to provide a recommendation by July 2018, and the Company anticipates a MPUC decision in the second half of 2018.
The MPUC did not take any action regarding the wind and solar energy PPAs which will be refiled separately from the natural gas energy PPA.
ALLETE, Inc. 2017 Form 10-K
95
NOTE 4. REGULATORY MATTERS (Continued)
Great Northern Transmission Line
.
Minnesota Power and Manitoba Hydro have proposed construction of the GNTL, an approximately
220
-mile
500
-kV transmission line between Manitoba and Minnesota’s Iron Range. In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings.
(
See
Transmission Cost Recovery Rider.)
Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between
$560 million
and
$710 million
, of which Minnesota Power’s portion is expected to be between
$300 million
and
$350 million
; the difference will be recovered from a subsidiary of Manitoba Hydro as contributions in aid of construction. Total project costs of
$152.4 million
have been incurred through
December 31, 2017
, of which
$67.6 million
has been recovered from a subsidiary of Manitoba Hydro.
Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. In December 2016, Manitoba Hydro filed an application with the National Energy Board in Canada requesting authorization to construct and operate an international transmission line. Both provincial and federal approvals are pending. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014 and is anticipated to be in service by early 2021.
Conservation Improvement Program.
Minnesota requires electric utilities to spend a minimum of
1.5 percent
of gross operating revenues from service provided in the state on energy CIPs each year and establish an annual energy-savings goal of
1.5 percent
of annual retail energy sales. These investments are recovered from certain retail customers through a combination of the conservation cost recovery charge included in retail base rates and a conservation program adjustment, which is adjusted annually through the CIP consolidated filing. The MPUC allows utilities to accumulate, in a deferred account for future cost recovery, all CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge on the deferred account balance. Minnesota Power refers to its conservation programs collectively as the “Power of One”. On November 16, 2017, the Minnesota Department of Commerce approved Minnesota Power’s modified CIP triennial filing for 2017 through 2019, which outlines Minnesota Power’s CIP spending and energy-saving goals for 2017 through 2019. Minnesota Power’s CIP investment goal was
$10.3 million
for
2017
(
$7.3 million
for
2016
;
$7.1 million
for
2015
), with actual spending of
$8.1 million
in
2017
(
$7.4 million
in
2016
;
$6.6 million
in
2015
). The investment goals for 2018 and 2019 are
$10.3 million
and
$10.5 million
, respectively.
On April 3, 2017, Minnesota Power submitted its 2016 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of
$5.5 million
based upon MPUC procedures. In an order dated June 22, 2017, the MPUC approved Minnesota Power’s CIP consolidated filing, including the requested CIP financial incentive which was recorded as revenue and as a regulatory asset in 2017. The approved financial incentive will be recovered through customer billing rates in 2017 and 2018. In 2016 and 2015, the CIP financial incentives recognized were
$7.5 million
and
$6.2 million
, respectively. CIP financial incentives are recognized in the period in which the MPUC approves the filing.
MISO Return on Equity Complaints.
In 2013, several customer groups located within the MISO service area filed complaints with the FERC requesting, among other things, a reduction in the base return on equity used by MISO transmission owners, including ALLETE and ATC, to
9.15 percent
. In 2015, a federal administrative law judge ruled on the complaint proposing a reduction in the base return on equity to
10.32 percent
, or
10.82 percent
including an incentive adder for participation in a regional transmission organization. In September 2016, the FERC issued an order affirming the administrative law judge’s recommendation.
In 2015, an additional complaint was filed with the FERC seeking an order to further reduce the base return on equity to
8.67
percent. In June 2016, a federal administrative law judge ruled on the additional complaint proposing a further reduction in the base return on equity to
9.70 percent
, or
10.20 percent
including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending, which is not expected to have a material impact on our Consolidated Financial Statements.
ALLETE, Inc. 2017 Form 10-K
96
NOTE 4. REGULATORY MATTERS (Continued)
Minnesota Solar Energy Standard.
Minnesota law requires at least
1.5 percent
of total retail electric sales, excluding sales to certain customers, to be generated by solar energy by the end of 2020. At least
10
percent of the
1.5 percent
mandate must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of
40
kW or less and community solar garden subscriptions. In a 2016 order, the MPUC approved Camp Ripley, a
10
MW utility scale solar project at the Camp Ripley Minnesota Army National Guard base and training facility near Little Falls, Minnesota, as eligible to meet the solar energy standard and for current cost recovery. Camp Ripley was completed in the fourth quarter of 2016. In a July 2016 order, the MPUC approved a community solar garden project in northeastern Minnesota, which is comprised of a
1
MW solar array owned and operated by a third party with the output purchased by Minnesota Power and a 40 kW solar array that is owned and operated by Minnesota Power. Minnesota Power believes Camp Ripley and the community solar garden arrays will meet approximately one‑third of the overall mandate. Additionally, in an order dated February 10, 2017, the MPUC approved Minnesota Power’s proposal to increase the amount of solar rebates available for customer-sited solar installations and recover costs of the program through Minnesota Power’s renewable cost recovery rider. The proposal to incentivize customer‑sited solar installations and the community solar garden subscriptions is expected to meet a portion of the required small scale solar mandate.
Regulatory Assets and Liabilities.
Our regulated utility operations are subject to accounting guidance for the effect of certain types of regulation. Regulatory assets represent incurred costs that have been deferred as they are probable for recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. The Company assesses quarterly whether regulatory assets and liabilities meet the criteria for probability of future recovery or deferral.
No regulatory assets or liabilities are currently earning a return.
The recovery, refund or credit to rates for these regulatory assets and liabilities will occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.
ALLETE, Inc. 2017 Form 10-K
97
NOTE 4. REGULATORY MATTERS (Continued)
|
|
|
|
|
|
|
|
Regulatory Assets and Liabilities
|
|
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Current Regulatory Assets
(a)
|
|
|
Deferred Fuel Adjustment Clause
|
—
|
|
|
$18.6
|
|
Non-Current Regulatory Assets
|
|
|
Defined Benefit Pension and Other Postretirement Benefit Plans
(b)
|
$220.3
|
226.1
|
|
Income Taxes
(c)(d)
|
112.8
|
|
33.8
|
|
Asset Retirement Obligations
(e)
|
29.6
|
|
26.0
|
|
Manufactured Gas Plant
(f)
|
8.1
|
|
1.0
|
|
PPACA Income Tax Deferral
|
5.0
|
|
5.0
|
|
Conservation Improvement Program
(g)
|
3.3
|
|
4.0
|
|
Cost Recovery Riders
(h)
|
—
|
|
30.5
|
|
Other
|
5.6
|
|
3.7
|
|
Total Non-Current Regulatory Assets
|
384.7
|
|
330.1
|
|
Total Regulatory Assets
|
|
$384.7
|
|
|
$348.7
|
|
Non-Current Regulatory Liabilities
|
|
|
Income Taxes
(d)
|
|
$411.2
|
|
|
$19.1
|
|
Wholesale and Retail Contra AFUDC
(i)
|
57.9
|
|
56.8
|
|
Provision for Interim Rate Refund
(j)
|
23.7
|
|
—
|
|
Plant Removal Obligations
|
20.3
|
|
19.1
|
|
North Dakota Investment Tax Credits
(k)
|
14.1
|
|
28.2
|
|
Cost Recovery Riders
(h)
|
2.2
|
|
—
|
|
Other
|
2.6
|
|
2.6
|
|
Total Non-Current Regulatory Liabilities
|
|
$532.0
|
|
|
$125.8
|
|
|
|
(a)
|
Current regulatory assets are presented within Prepayments and Other on the Consolidated Balance Sheet. At a hearing on January 18, 2018, the MPUC disallowed recovery of Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs resulting in a
$19.5 million
pre-tax charge to Fuel, Purchased Power and Gas – Utility in 2017. (See 2016 Minnesota General Rate Case.)
|
|
|
(b)
|
Defined benefit pension and other postretirement items included in our Regulated Operations, which are otherwise required to be recognized in accumulated other comprehensive income as actuarial gains and losses as well as prior service costs and credits, are recognized as regulatory assets or regulatory liabilities on the Consolidated Balance Sheet. The asset or liability will decrease as the deferred items are amortized and recognized as components of net periodic benefit cost. (See Note 15. Pension and Other Postretirement Benefit Plans.)
|
|
|
(c)
|
See Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.
|
|
|
(d)
|
These costs represent the difference between deferred income taxes recognized for financial reporting purposes and amounts previously billed to our customers. The increase in 2017 is primarily due to the remeasurement of deferred income tax assets and liabilities for our Regulated Operations resulting from the TCJA. The benefits of the TCJA for Minnesota Power and SWL&P are expected to be passed back to customers over time primarily based upon the normalization provisions of the U.S. Internal Revenue Code over the life of the related property, plant and equipment with the remainder passed back based upon the determinations of regulatory authorities. (See Note 1. Operations and Significant Accounting Policies, and Tax Cuts and Jobs Act of 2017.) The balances not related to remeasurement will decrease over the remaining life of the related temporary differences and flow through current income taxes.
|
|
|
(e)
|
Asset retirement obligations will accrete and be amortized over the lives of the related property with asset retirement obligations.
|
|
|
(f)
|
The manufactured gas plant regulatory asset represents costs of remediation for a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. We expect recovery of these remediation costs to be allowed by the PSCW in rates over time.
|
|
|
(g)
|
The conservation improvement program regulatory asset represents CIP expenditures, any financial incentive earned for cost-effective program achievements and a carrying charge deferred for future cost recovery over the next year following MPUC approval.
|
|
|
(h)
|
The cost recovery rider regulatory assets and liabilities are revenues not yet collected from our customers and cash collections from our customers in excess of the revenue recognized, respectively, primarily due to capital expenditures related to Bison, investment in CapX2020 projects, the Boswell Unit 4 environmental upgrade and the GNTL, and are recognized in accordance with the accounting standards for alternative revenue programs. The cost recovery rider regulatory assets and liabilities as of
December 31, 2017
, will be recovered or returned within the next two years.
|
|
|
(i)
|
Wholesale and Retail Contra AFUDC represents amortization to offset AFUDC Equity and Debt recorded during the construction period of our cost recovery rider projects prior to placing the projects in service. The regulatory liability will decrease over the remaining depreciable life of the related asset.
|
|
|
(j)
|
This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes
$8.6 million
of EITE discounts that will be offset against interim rate refunds. (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)
|
|
|
(k)
|
North Dakota investment tax credits expected to be realized from Bison that will be credited to Minnesota Power’s regulated retail customers through future renewable cost recovery rider fillings as the tax credits are utilized.
|
ALLETE, Inc. 2017 Form 10-K
98
NOTE 5. INVESTMENT IN ATC
Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately
8 percent
of ATC, a Wisconsin-based utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. We account for our investment in ATC under the equity method of accounting. As of
December 31, 2017
, our equity investment in ATC was
$118.7 million
(
$135.6 million
as of
December 31, 2016
). On January 31, 2018, we invested an additional
$1.6 million
in ATC. In total, we expect to invest approximately
$6 million
throughout
2018
.
|
|
|
|
|
|
|
|
ALLETE’s Investment in ATC
|
|
|
Year Ended December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Equity Investment Beginning Balance
|
|
$135.6
|
|
|
$124.5
|
|
Cash Investments
|
7.8
|
|
5.4
|
|
Equity in ATC Earnings
|
22.5
|
|
18.5
|
|
Distributed ATC Earnings
|
(19.3
|
)
|
(12.8
|
)
|
Remeasurement of Deferred Income Taxes
(a)
|
(27.9
|
)
|
—
|
|
Equity Investment Ending Balance
|
|
$118.7
|
|
|
$135.6
|
|
|
|
(a)
|
Impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)
|
|
|
|
|
|
|
|
|
ATC Summarized Financial Data
|
|
|
Balance Sheet Data
|
|
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Current Assets
|
|
$87.7
|
|
|
$75.8
|
|
Non-Current Assets
|
4,598.9
|
|
4,312.9
|
|
Total Assets
|
|
$4,686.6
|
|
|
$4,388.7
|
|
Current Liabilities
|
|
$767.2
|
|
|
$495.1
|
|
Long-Term Debt
|
1,790.6
|
|
1,865.3
|
|
Other Non-Current Liabilities
|
240.3
|
|
271.5
|
|
Members’ Equity
|
1,888.5
|
|
1,756.8
|
|
Total Liabilities and Members’ Equity
|
|
$4,686.6
|
|
|
$4,388.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement Data
|
|
|
|
Year Ended December 31
|
2017
|
|
2016
|
|
2015
|
|
Millions
|
|
|
|
Revenue
|
|
$721.6
|
|
|
$650.8
|
|
|
$615.8
|
|
Operating Expense
|
344.9
|
|
322.5
|
|
319.3
|
|
Other Expense
|
104.1
|
|
95.5
|
|
96.1
|
|
Net Income
|
|
$272.6
|
|
|
$232.8
|
|
|
$200.4
|
|
ALLETE’s Equity in Net Income
|
|
$22.5
|
|
|
$18.5
|
|
|
$16.3
|
|
In September 2016, the FERC issued an order reducing ATC’s authorized return on equity to
10.32 percent
, or
10.82 percent
including an incentive adder for participation in a regional transmission organization. Prior to this order, ATC had been allowed a return on equity of
12.2 percent
which had been impacted by reductions for estimated refunds related to complaints filed with the FERC by several customers located within the MISO service area.
In June 2016, a federal administrative law judge ruled on an additional complaint proposing a further reduction in the base return on equity to
9.70 percent
, or
10.20 percent
including an incentive adder for participation in a regional transmission organization, subject to approval or adjustment by the FERC. A final decision from the FERC on the administrative law judge’s recommendation is pending. (See Note 4. Regulatory Matters.)
ALLETE, Inc. 2017 Form 10-K
99
NOTE 6. ACQUISITIONS
The following acquisitions are consistent with ALLETE’s stated strategy of investing in energy infrastructure and related services businesses to complement its regulated businesses, balance exposure to business cycles and changing demand, and provide potential long-term earnings growth.
The pro forma impact of the following acquisitions was
not significant
, either individually or in the aggregate, to the results of the Company for the years ended
December 31, 2017
,
2016
and
2015
.
2017 Activity.
Tonka Water.
On Septemb
er 1, 2017, U.S. Water Services acquired
100 percent
of
Tonka Water
. Total consideration for the transaction was
$19.2 million
, including a working capital adjustment. Consideration of
$19.0 million
was p
aid in cash on the acquisition date and a
working capital adjustment of
$0.2 million
was pa
id in the fourth quarter of 2017. Tonka Water is a supplier of municipal and industrial water treatment systems and will expand U.S. Water Services’ geographic and customer markets.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The allocation of the purchase price is subject to judgment and the preliminary estimated fair value of the assets acquired and the liabilities assumed may be adjusted when the valuation analysis is complete in subsequent periods. Preliminary estimates subject to adjustment in subsequent periods relate primarily to income tax liabilities; subsequent adjustments could impact the amount of goodwill recorded. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.
|
|
|
|
|
Millions
|
|
Assets Acquired
|
|
Accounts Receivable
|
$5.1
|
Other Current Assets
|
5.1
|
|
Trade Names
(a)
|
0.9
|
|
Goodwill
(a)(b)
|
16.9
|
|
Other Non-Current Assets
|
0.2
|
|
Total Assets Acquired
|
|
$28.2
|
|
Liabilities Assumed
|
|
Current Liabilities
|
|
$9.0
|
|
Total Liabilities Assumed
|
|
$9.0
|
|
Net Identifiable Assets Acquired
|
|
$19.2
|
|
(a) Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)
|
|
(b)
|
Recognized goodwill is attributable to the assembled workforce and anticipated synergies. For tax purposes, the purchase price allocation resulted in
$4.1 million
of deductible goodwill.
|
Acquisition-related costs were immaterial, expensed as incurred during 2017 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
2016 Activity.
Acquisition of Non-Controlling Interest.
In April 2016, ALLETE Clean Energy acquired the non-controlling interest in the limited liability company that owns its Condon wind energy facility for
$8.0 million
. This transaction was accounted for as an equity transaction, and
no
gain or loss was recognized in net income or other comprehensive income. As a result of the acquisition, the Condon wind energy facility is now a wholly-owned subsidiary of ALLETE Clean Energy.
WEST.
In
October 2016
, U.S. Water Services acquired
100 percent
of
Water & Energy Systems Technology of Nevada, Inc.
(WEST). Total consideration for the transaction was
$6.7 million
. Consideration of
$5.9 million
was paid in cash on the acquisition date, working capital adjustments of
$0.2 million
were paid in the first six months of 2017 and a
$0.6 million
payment is due in April 2018. WEST is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southwestern United States.
ALLETE, Inc. 2017 Form 10-K
100
NOTE 6. ACQUISITIONS (Continued)
2016 Activity (Continued)
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in the second quarter of 2017, is shown in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.
|
|
|
|
|
Millions
|
|
Assets Acquired
|
|
Cash and Cash Equivalents
|
|
$0.1
|
|
Other Current Assets
|
1.0
|
|
Customer Relationships
(a)
|
2.8
|
|
Goodwill
(a)(b)
|
4.2
|
|
Other Non-Current Assets
|
0.1
|
|
Total Assets Acquired
|
|
$8.2
|
|
Liabilities Assumed
|
|
Current Liabilities
|
|
$0.3
|
|
Non-Current Liabilities
|
1.2
|
|
Total Liabilities Assumed
|
|
$1.5
|
|
Net Identifiable Assets Acquired
|
|
$6.7
|
|
|
|
(a)
|
Presented within Goodwill and Intangible Assets – Net on the Consolidated Balance Sheet. (See Note 7. Goodwill and Intangible Assets.)
|
|
|
(b)
|
For tax purposes, the purchase price allocation resulted in
no
allocation to goodwill.
|
Acquisition-related costs were
immaterial
, expensed as incurred during 2016 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
2015 Activity.
U.S. Water Services.
In
2015
, ALLETE acquired
U.S. Water Services
. Total consideration for the transaction was
$202.3 million
, which included payment of
$166.6 million
in cash and an estimated fair value of earnings-based contingent consideration of
$35.7 million
, as estimated at the date of acquisition, to be paid through 2019. The contingent consideration is presented within Other Non-Current Liabilities on the Consolidated Balance Sheet. The Consolidated Statement of Income reflects
100
percent of the results of operations for U.S. Water Services since the acquisition date as the Company has acquired
100
percent of U.S. Water Services.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
ALLETE, Inc. 2017 Form 10-K
101
NOTE 6. ACQUISITIONS (Continued)
2015 Activity (Continued)
|
|
|
|
|
Millions
|
|
Assets Acquired
|
|
Cash and Cash Equivalents
|
|
$0.9
|
|
Accounts Receivable
|
16.8
|
|
Inventories
(a)
|
13.4
|
|
Other Current Assets
(b)
|
5.3
|
|
Property, Plant and Equipment
|
10.6
|
|
Intangible Assets
(c)
|
83.0
|
|
Goodwill
(d)
|
122.9
|
|
Other Non-Current Assets
|
0.2
|
|
Total Assets Acquired
|
|
$253.1
|
|
Liabilities Assumed
|
|
Current Liabilities
|
|
$19.2
|
|
Non-Current Liabilities
|
31.6
|
|
Total Liabilities Assumed
|
|
$50.8
|
|
Net Identifiable Assets Acquired
|
|
$202.3
|
|
|
|
(a)
|
Included in Inventories was
$2.7 million
of fair value adjustments relating to work in progress and finished goods inventories which were recognized as Cost of Sales within one year from the acquisition date.
|
|
|
(b)
|
Included in Other Current Assets was
$1.6 million
relating to the fair value of sales backlog. Sales backlog was recognized as Cost of Sales within one year from the acquisition date. Also included in Other Current Assets was restricted cash of
$2.1 million
relating to cash pledged as collateral for standby letters of credit.
|
|
|
(c)
|
Intangible Assets include customer relationships, patents, non-compete agreements, and trademarks and trade names. (See Note 7. Goodwill and Intangible Assets.)
|
|
|
(d)
|
For tax purposes, the purchase price allocation resulted in
$2.9 million
of deductible goodwill.
|
Acquisition-related costs of
$3.0 million
after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
Chanarambie/Viking.
In
2015
, ALLETE Clean Energy acquired
100 percent
of wind energy facilities in southern Minnesota (
Chanarambie/Viking
) from EDF Renewable Energy, Inc. for
$48.0 million
.
The facilities have a combined
97.5
MW of generating capability. The wind energy facilities began commercial operations in 2003 and have PSAs in place for their entire output, which expire in 2018 (
12
MW) and 2023 (
85.5
MW).
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
ALLETE, Inc. 2017 Form 10-K
102
NOTE 6. ACQUISITIONS (Continued)
2015 Activity (Continued)
|
|
|
|
|
Millions
|
|
Assets Acquired
|
|
Current Assets
|
|
$4.8
|
|
Property, Plant and Equipment
|
103.0
|
|
Other Non-Current Assets
(a)
|
1.0
|
|
Total Assets Acquired
|
|
$108.8
|
|
Liabilities Assumed
|
|
Current Liabilities
(b)
|
|
$6.7
|
|
PSAs
|
49.0
|
|
Non-Current Liabilities
|
5.1
|
|
Total Liabilities Assumed
|
|
$60.8
|
|
Net Identifiable Assets Acquired
|
|
$48.0
|
|
|
|
(a)
|
Included in Other Non-Current Assets was
$0.3 million
of goodwill. For tax purposes, the purchase price allocation resulted in
no
allocation to goodwill.
|
|
|
(b)
|
Current Liabilities included
$5.9 million
related to the current portion of PSAs.
|
Acquisition-related costs of
$0.2 million
after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
Armenia Mountain.
In
2015
, ALLETE Clean Energy acquired
100
percent of a wind energy facility located near Troy, Pennsylvania (
Armenia Mountain
) from The AES Corporation and a minority shareholder for
$111.1 million
, plus the assumption of existing debt.
The facility has
100.5
MW of generating capability, began commercial operations in 2009, and has PSAs in place for its entire output, which expire in 2024.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
|
|
|
|
|
Millions
|
|
Assets Acquired
|
|
Current Assets
(a)
|
|
$9.0
|
|
Property, Plant and Equipment
|
156.2
|
|
Other Non-Current Assets
(b)
|
14.4
|
|
Total Assets Acquired
|
|
$179.6
|
|
Liabilities Assumed
|
|
Current Liabilities
|
|
$2.9
|
|
Long-Term Debt Due Within One Year
|
5.9
|
|
Long-Term Debt
|
55.0
|
|
Other Non-Current Liabilities
|
4.7
|
|
Total Liabilities Assumed
|
|
$68.5
|
|
Net Identifiable Assets Acquired
|
|
$111.1
|
|
|
|
(a)
|
Included in Current Assets was
$1.0 million
related to the current portion of PSAs and
$6.0 million
of restricted cash related to collateral deposits required under its loan agreement.
|
|
|
(b)
|
Included in Other Non-Current Assets was
$8.2 million
related to the non-current portion of PSAs,
$6.1 million
of restricted cash related to collateral deposits required under its loan agreements and an
immaterial
amount of goodwill. For tax purposes, the purchase price allocation resulted in
no
allocation to goodwill.
|
ALLETE, Inc. 2017 Form 10-K
103
NOTE 6. ACQUISITIONS (Continued)
2015 Activity (Continued)
Acquisition-related costs of
$1.6 million
after-tax were expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
A and W Technologies.
In
2015
, U.S. Water Services acquired
100 percent
of
A and W Technologies, Inc.
(AWT). Total consideration for the transaction was
$9.3 million
, which included payment of
$8.3 million
in cash and a
$1.0 million
payment made in April 2017. AWT, similar to U.S. Water Services, is an integrated water management company and was acquired to expand U.S. Water Services’ regional footprint in the Southeastern United States.
The acquisition was accounted for as a business combination and the purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalized in 2015, is reflected in the following table. Fair value measurements were valued primarily using the discounted cash flow method.
|
|
|
|
|
Millions
|
|
Assets Acquired
|
|
Current Assets
|
|
$1.0
|
|
Property, Plant and Equipment
|
0.1
|
|
Intangible Assets
(a)
|
3.9
|
|
Goodwill
(b)
|
4.4
|
|
Total Assets Acquired
|
|
$9.4
|
|
Liabilities Assumed
|
|
Current Liabilities
|
|
$0.1
|
|
Total Liabilities Assumed
|
|
$0.1
|
|
Net Identifiable Assets Acquired
|
|
$9.3
|
|
|
|
(a)
|
Intangible Assets include customer relationships and non-compete agreements. (See Note 7. Goodwill and Intangible Assets.)
|
|
|
(b)
|
For tax purposes, the purchase price allocation resulted in
$4.4 million
of deductible goodwill.
|
Acquisition-related costs were
immaterial
, expensed as incurred during 2015 and recorded in Operating and Maintenance on the Consolidated Statement of Income.
ALLETE, Inc. 2017 Form 10-K
104
NOTE 7. GOODWILL AND INTANGIBLE ASSETS
The following table summarizes changes to goodwill by reportable segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ALLETE Clean Energy
|
|
|
U.S. Water Services
|
|
|
Total
|
|
Millions
|
|
|
|
|
|
Balance as of December 31, 2015
|
|
$3.3
|
|
|
|
$127.3
|
|
|
|
$130.6
|
|
Acquired Goodwill
(a)
|
—
|
|
|
3.9
|
|
|
3.9
|
|
Impairment Charge
(b)
|
(3.3
|
)
|
|
—
|
|
|
(3.3
|
)
|
Balance as of December 31, 2016
|
—
|
|
|
131.2
|
|
|
131.2
|
|
Acquired Goodwill
(a)
|
—
|
|
|
16.9
|
|
|
16.9
|
|
Other Adjustments
(c)
|
—
|
|
|
0.2
|
|
|
0.2
|
|
Balance as of December 31, 2017
|
—
|
|
|
|
$148.3
|
|
|
|
$148.3
|
|
|
|
(a)
|
See Note 6. Acquisitions.
|
|
|
(b)
|
The facts and circumstances that led to an impairment of ALLETE Clean Energy’s goodwill primarily relate to lower estimated energy prices in periods not under PSAs. Impairment Charge is included in Operating Expenses – Other on the Consolidated Statement of Income. (See Note 1. Operations and Significant Accounting Policies.) ALLETE Clean Energy’s goodwill was primarily related to the acquisition of Storm Lake II in 2014.
|
|
|
(c)
|
Finalization of purchase price accounting for U.S. Water Services’ acquisition of WEST was completed in 2017 resulting in an adjustment to the goodwill recorded at the time of the initial acquisition.
|
The following table summarizes changes to intangible assets, net, for the year ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2016
|
|
|
Additions
(a)
|
|
Amortization
|
|
December 31,
2017
|
|
Millions
|
|
|
|
|
|
|
|
Intangible Assets
|
|
|
|
|
|
|
|
Definite-Lived Intangible Assets
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$59.3
|
|
|
—
|
|
|
$(4.6)
|
|
|
$54.7
|
|
Developed Technology and Other
(b)
|
6.3
|
|
|
|
$0.9
|
|
|
(0.9)
|
|
6.3
|
|
Total Definite-Lived Intangible Assets
|
65.6
|
|
|
0.9
|
|
|
(5.5)
|
|
61.0
|
|
Indefinite-Lived Intangible Assets
|
|
|
|
|
|
|
|
Trademarks and Trade Names
|
16.6
|
|
|
—
|
|
|
n/a
|
|
16.6
|
|
Total Intangible Assets
|
|
$82.2
|
|
|
|
$0.9
|
|
|
$(5.5)
|
|
|
$77.6
|
|
|
|
(a)
|
Additions resulting from the September 1, 2017, acquisition of Tonka Water. (See Note 6. Acquisitions.)
|
|
|
(b)
|
Developed Technology and Other includes patents, non-compete agreements, land easements and trade names with finite lives.
|
Customer relationships have a remaining useful life of approximately
20
years, and developed technology and other have remaining useful lives ranging from approximately
1
year to approximately
11
years (weighted average of approximately
7
years). The weighted average remaining useful life of all definite-lived intangible assets as of
December 31, 2017
, is approximately
19
years.
Amortization expense of intangible assets for the year ended
December 31, 2017
, was
$5.5 million
(
$5.2 million
in
2016
;
$4.0 million
in
2015
). Accumulated amortization was
$14.8 million
and
$9.3 million
as of
December 31, 2017
, and
December 31, 2016
, respectively. Estimated amortization expense for definite-lived intangible assets is
$5.3 million
in
2018
,
$5.0 million
in
2019
,
$4.7 million
in
2020
,
$4.6 million
in
2021
,
$4.3 million
in
2022
and
$37.1 million
thereafter.
ALLETE, Inc. 2017 Form 10-K
105
NOTE 8. INVESTMENTS
Investments.
As of
December 31, 2017
, the investment portfolio included the legacy real estate assets of ALLETE Properties, debt and equity securities consisting primarily of securities held in other postretirement plans to fund employee benefits, the cash equivalents within these plans and other assets consisting primarily of land in Minnesota.
|
|
|
|
|
|
|
|
Other Investments
|
|
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
ALLETE Properties
|
|
$26.4
|
|
|
$31.7
|
|
Available-for-sale Securities
(a)
|
19.1
|
|
18.8
|
|
Cash Equivalents
|
3.8
|
|
1.3
|
|
Other
|
3.8
|
|
3.8
|
|
Total Other Investments
|
|
$53.1
|
|
|
$55.6
|
|
|
|
(a)
|
As of
December 31, 2017
, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was
$0.7 million
, in one year to less than three years was
$3.2 million
, in three years to less than five years was
$3.6 million
, and in five or more years was
$1.4 million
.
|
Land Inventory.
Land inventory is accounted for as held for use and is recorded at cost, unless the carrying value is determined not to be recoverable in accordance with the accounting standards for property, plant and equipment, in which case the land inventory is written down to estimated fair value. Land values are reviewed for indicators of impairment on a quarterly basis and
no
impairment was recorded in
2017
(
none
in
2016
;
$36.3 million
in
2015
). (See Note 1. Operations and Significant Accounting Policies.)
Available-for-Sale Securities.
We account for our available-for-sale securities portfolio in accordance with the guidance for certain investments in debt and equity securities. Our available-for-sale securities portfolio consisted primarily of securities held in other postretirement plans to fund employee benefits.
Gross realized and unrealized gains and losses on our available-for-sale securities were immaterial in
2017
,
2016
and
2015
.
NOTE 9. FAIR VALUE
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs, which are used to measure fair value, are prioritized through the fair value hierarchy. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes primarily equity securities.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. This category includes deferred compensation and fixed income securities.
Level 3 — Significant inputs that are generally less observable from objective sources. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value. This category includes the U.S. Water Services contingent consideration liability.
ALLETE, Inc. 2017 Form 10-K
106
NOTE 9. FAIR VALUE (Continued)
The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of
December 31, 2017
, and
December 31, 2016
. Each asset and liability is classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of these assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of Cash and Cash Equivalents listed on the Consolidated Balance Sheet approximates the carrying amount and therefore is excluded from the recurring fair value measures in the following tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of December 31, 2017
|
Recurring Fair Value Measures
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Millions
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Investments
(a)
|
|
|
|
|
|
|
|
Available-for-sale – Equity Securities
|
|
$10.2
|
|
|
—
|
|
|
—
|
|
|
|
$10.2
|
|
Available-for-sale – Corporate and Governmental Debt Securities
|
—
|
|
|
|
$8.9
|
|
|
—
|
|
|
8.9
|
|
Cash Equivalents
|
3.8
|
|
|
—
|
|
|
—
|
|
|
3.8
|
|
Total Fair Value of Assets
|
|
$14.0
|
|
|
|
$8.9
|
|
|
—
|
|
|
|
$22.9
|
|
|
|
|
|
|
|
|
|
Liabilities:
(b)
|
|
|
|
|
|
|
|
Deferred Compensation
|
—
|
|
|
|
$18.2
|
|
|
—
|
|
|
|
$18.2
|
|
U.S. Water Services Contingent Consideration
|
—
|
|
|
—
|
|
|
|
$5.4
|
|
|
5.4
|
|
Total Fair Value of Liabilities
|
—
|
|
|
|
$18.2
|
|
|
|
$5.4
|
|
|
|
$23.6
|
|
Total Net Fair Value of Assets (Liabilities)
|
|
$14.0
|
|
|
$(9.3)
|
|
$(5.4)
|
|
$(0.7)
|
|
|
(a)
|
Included in Other Investments on the Consolidated Balance Sheet.
|
|
|
(b)
|
Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of December 31, 2016
|
Recurring Fair Value Measures
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Millions
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Investments
(a)
|
|
|
|
|
|
|
|
Available-for-sale – Equity Securities
|
|
$7.1
|
|
|
—
|
|
|
—
|
|
|
|
$7.1
|
|
Available-for-sale – Corporate and Governmental Debt Securities
|
—
|
|
|
|
$11.7
|
|
|
—
|
|
|
11.7
|
|
Cash Equivalents
|
1.3
|
|
|
—
|
|
|
—
|
|
|
1.3
|
|
Total Fair Value of Assets
|
|
$8.4
|
|
|
|
$11.7
|
|
|
—
|
|
|
|
$20.1
|
|
|
|
|
|
|
|
|
|
Liabilities:
(b)
|
|
|
|
|
|
|
|
Deferred Compensation
|
—
|
|
|
|
$16.0
|
|
|
—
|
|
|
|
$16.0
|
|
U.S. Water Services Contingent Consideration
|
—
|
|
|
—
|
|
|
|
$25.0
|
|
|
25.0
|
|
Total Fair Value of Liabilities
|
—
|
|
|
|
$16.0
|
|
|
|
$25.0
|
|
|
|
$41.0
|
|
Total Net Fair Value of Assets (Liabilities)
|
|
$8.4
|
|
|
$(4.3)
|
|
$(25.0)
|
|
$(20.9)
|
|
|
(a)
|
Included in Other Investments on the Consolidated Balance Sheet.
|
|
|
(b)
|
Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
|
ALLETE, Inc. 2017 Form 10-K
107
NOTE 9. FAIR VALUE (Continued)
The following table provides a reconciliation of the beginning and ending balances of the U.S. Water Services Contingent Consideration measured at fair value using Level 3 measurements as of
December 31, 2017
, and
December 31, 2016
. The acquisition contingent consideration was recorded at the acquisition date at its estimated fair value. The acquisition date fair value was measured based on the consideration expected to be transferred, discounted to present value. The discount rate was determined at the time of measurement in accordance with generally accepted valuation methods. The fair value of the acquisition contingent consideration is remeasured to arrive at estimated fair value each reporting period with the change in fair value recognized as income or expense in the Consolidated Statement of Income. Changes to the fair value of the acquisition contingent consideration can result from changes in discount rates, timing of milestones that trigger payments, and the timing and amount of earnings estimates. Using different valuation assumptions, including earnings projections or discount rates, may result in different fair value measurements and expense (or income) in future periods. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate. The acquisition contingent consideration was measured at
$5.4 million
as of
December 31, 2017
.
|
|
|
|
|
Recurring Fair Value Measures
|
|
Activity in Level 3
|
|
Millions
|
|
Balance as of December 31, 2015
|
|
$36.6
|
|
Accretion
(a)
|
2.8
|
|
Payments
|
(0.8
|
)
|
Changes in Cash Flow Projections
(b)
|
(13.6
|
)
|
Balance as of December 31, 2016
|
|
$25.0
|
|
Accretion
(a)
|
0.8
|
|
Payments
(c)
|
(19.7
|
)
|
Changes in Cash Flow Projections
(c)
|
(0.7
|
)
|
Balance as of December 31, 2017
|
|
$5.4
|
|
|
|
(a)
|
Included in Interest Expense on the Consolidated Statement of Income.
|
|
|
(b)
|
During the fourth quarter of 2016, management assessed earnings estimates used in calculating the fair value of the U.S. Water Services contingent consideration liability and determined an adjustment was necessary to the liability’s carrying amount based on its assessment. As a result, we recorded a reduction of
$13.6 million
to the liability’s carrying amount which resulted in an after-tax gain of the same amount presented within Operating Expenses – Other in the Consolidated Statement of Income.
|
|
|
(c)
|
Payments and changes in cash flow projections reflect the impact of a modification to the shareholder agreement in the first quarter of 2017 which provided participants a one-time election to sell shares at a determined price. Participants representing approximately half of the outstanding contingent consideration shares made the election, and were paid in the first half of 2017.
|
The Company’s policy is to recognize transfers in and transfers out of Levels as of the actual date of the event or change in circumstances that caused the transfer. For the years ended
December 31, 2017
and
2016
, there were
no
transfers in or out of Levels 1, 2 or 3.
Fair Value of Financial Instruments.
With the exception of the item listed in the following table, the estimated fair value of all financial instruments approximates the carrying amount. The fair value for the item listed in the following table was based on quoted market prices for the same or similar instruments (Level 2).
|
|
|
|
|
Financial Instruments
|
Carrying Amount
|
|
Fair Value
|
Millions
|
|
|
|
Long-Term Debt, Including Long-Term Debt Due Within One Year
|
|
|
|
December 31, 2017
|
$1,513.3
|
|
$1,627.6
|
December 31, 2016
|
$1,569.1
|
|
$1,653.8
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis.
Non-financial assets such as equity method investments, goodwill, intangible assets, and property, plant and equipment are measured at fair value when there is an indicator of impairment and recorded at fair value only when an impairment is recognized.
ALLETE, Inc. 2017 Form 10-K
108
NOTE 9. FAIR VALUE (Continued)
Equity Method Investment.
Our wholly-owned subsidiary, ALLETE Transmission Holdings, owns approximately
8 percent
of ATC. (See Note 5. Investment in ATC.) The aggregate carrying amount of the investment was
$118.7 million
as of
December 31, 2017
(
$135.6 million
as of
December 31, 2016
). The Company assesses our investment in ATC for impairment whenever events or changes in circumstances indicate that the carrying amount of our investment in ATC may not be recoverable. For the years ended
December 31, 2017
and
2016
, there were
no
indicators of impairment.
Goodwill.
The Company assesses the impairment of goodwill annually in the fourth quarter and whenever an event occurs or circumstances change that would indicate that the carrying amount may be impaired. The Company’s goodwill is a result of the U.S. Water Services acquisition in 2015 as well as U.S. Water Services’ subsequent acquisitions. (See Note 6. Acquisitions.) The aggregate carrying amount of goodwill was
$148.3 million
as of
December 31, 2017
, and
$131.2 million
as of
December 31, 2016
.
Impairment testing for goodwill is done at the reporting unit level. An impairment loss is recognized when the carrying amount of the reporting unit’s net assets exceeds the estimated fair value of the reporting unit. The test for impairment requires us to make several estimates about fair value, most of which are based on projected future cash flows. The Company calculates the excess of the reporting unit's fair value over its carrying amount, including goodwill, utilizing a discounted cash flow analysis. Our annual impairment test for U.S. Water Services indicated that the estimated fair value of U.S. Water Services exceeded its carrying value, and
no
impairment existed for the year ended
December 31, 2017
(
none
in 2016 and in 2015). As part of the
2016
annual impairment analysis, the Company recognized a non-cash impairment charge of
$3.3 million
for ALLETE Clean Energy’s goodwill primarily related to the acquisition of Storm Lake II in
2014
. The charge, which is presented within Operating Expenses – Other in the Consolidated Statement of Income, eliminated all goodwill for the ALLETE Clean Energy reporting unit. (See Note 1. Operations and Significant Accounting Policies.)
Intangible Assets.
The Company assesses indefinite-lived intangible assets for impairment annually in the fourth quarter. The Company also assesses indefinite-lived and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable. Substantially all of the Company’s intangible assets are a result of the U.S. Water Services acquisition in 2015 as well as U.S. Water Services’ subsequent acquisitions. The aggregate carrying amount of intangible assets was
$77.6 million
as of
December 31, 2017
(
$82.2 million
as of
December 31, 2016
). When events or changes in circumstances indicate that the carrying amount of an intangible asset may not be recoverable, the Company calculates the excess of an intangible asset's carrying amount over its undiscounted future cash flows. If the carrying amount is not recoverable, an impairment loss is recorded based on the amount by which the carrying amount exceeds the fair value. The inputs used in the fair value analysis fall within Level 3 of the fair value hierarchy due to the use of significant unobservable inputs to determine fair value. As of
December 31, 2017
, there have been
no
events or changes in circumstance which would indicate impairment of our intangible assets.
Property, Plant and Equipment.
The Company assesses the impairment of property, plant, and equipment whenever events or changes in circumstances indicate that the carrying amount of property, plant, and equipment assets may not be recoverable. The impairment of ALLETE Clean Energy’s goodwill in
2016
, primarily due to lower estimated energy prices in periods not under PSAs, caused management to review ALLETE Clean Energy’s WTGs for impairment. Based on the results of the undiscounted cash flow analysis, the undiscounted future cash flows were adequate to recover the carrying value of the WTGs. In
2015
, the Company implemented a revised strategy for its real estate assets and recorded a non-cash impairment charge of
$36.3 million
for ALLETE Properties, reducing the carrying value of the real estate to its estimated fair value. (See Note 1. Operations and Significant Accounting Policies.) For the year ended
December 31, 2017
, there were
no
indicators of impairment.
We believe that long-standing ratemaking practices approved by applicable state and federal regulatory commissions allow for the recovery of the remaining book value of retired plant assets. In 2015, Minnesota Power retired Taconite Harbor Unit 3 and converted Laskin to operate on natural gas which were actions included in Minnesota Power’s MPUC-approved 2013 IRP. In a July 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The 2015 IRP contains steps in Minnesota Power’s
EnergyForward
plan including the economic idling of Taconite Harbor Units 1 and 2 in September 2016, and the ceasing of coal-fired operations at Taconite Harbor in 2020. (See Note 4. Regulatory Matters.) The MPUC order for the 2015 IRP also directed Minnesota Power to retire Boswell Units 1 and 2 no later than 2022. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018. We do not expect to record any impairment charge as a result of the retirement of Taconite Harbor Unit 3, the ceasing of coal-fired operations at Taconite Harbor Units 1 and 2, or the conversion of Laskin to operate on natural gas. In addition, we expect to be able to continue depreciating these assets for at least their established remaining useful lives; however, we are unable to predict the impact of regulatory outcomes resulting in changes to their established remaining useful lives.
ALLETE, Inc. 2017 Form 10-K
109
NOTE 10. SHORT-TERM AND LONG-TERM DEBT
Short-Term Debt.
As of
December 31, 2017
, total short-term debt outstanding was
$64.1 million
(
$187.7 million
as of
December 31, 2016
), consisted of long-term debt due within one year and included
$0.5 million
of unamortized debt issuance costs.
As of
December 31, 2017
, we had consolidated bank lines of credit aggregating
$407.0 million
(
$409.0 million
as of
December 31, 2016
), the majority of which expire in October 2020. We had
$11.9 million
outstanding in standby letters of credit and
no
outstanding draws under our lines of credit as of
December 31, 2017
(
$11.1 million
in standby letters of credit and
no
outstanding draws as of
December 31, 2016
).
Long-Term Debt.
As of
December 31, 2017
, total long-term debt outstanding was
$1,439.2 million
(
$1,370.4 million
as of
December 31, 2016
) and included
$9.5 million
of unamortized debt issuance costs. The aggregate amount of long-term debt maturing in
2018
is
$64.6 million
;
$57.6 million
in
2019
;
$143.0 million
in
2020
;
$97.8 million
in
2021
;
$88.0 million
in
2022
; and
$1,062.3 million
thereafter. Substantially all of our regulated electric plant is subject to the lien of the mortgages collateralizing outstanding first mortgage bonds. The mortgages contain non-financial covenants customary in utility mortgages, including restrictions on our ability to incur liens, dispose of assets, and merge with other entities.
Minnesota Power is obligated to make financing payments for the Camp Ripley solar array totaling
$1.4 million
annually during the financing term, which expires in 2027. Minnesota Power has the option at the end of the financing term to renew for a
two
‑year term, or to purchase the solar array for approximately
$4 million
. Minnesota Power anticipates exercising the purchase option when the term expires.
On June 1, 2017, ALLETE issued
$80.0 million
of its senior unsecured notes (the Notes) to certain institutional buyers in the private placement market. The Notes were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors. The Notes bear interest at
3.11 percent
and mature on June 1, 2027. Interest on the Notes is payable semi-annually in June and December of each year, commencing on December 1, 2017. ALLETE has the option to prepay all or a portion of the Notes at its discretion, subject to a make-whole provision. The Notes are subject to additional terms and conditions which are customary for these types of transactions. Proceeds from the sale of the Notes were used to redeem debt, fund corporate growth opportunities and for general corporate purposes.
On August 25, 2017, ALLETE entered into a
$40.0 million
term loan agreement (Term Loan). The Term Loan is an unsecured, single draw loan that is due on August 25, 2020, and may be prepaid at any time subject to a make-whole provision. Interest on the Term Loan is payable quarterly at a rate per annum equal to
LIBOR
plus
1.025 percent
. Proceeds from the Term Loan were used for general corporate purposes.
On November 2, 2017, ALLETE entered into a bond purchase agreement providing for the issuance and sale of
$60.0 million
of its First Mortgage Bonds (the Bonds) that bear interest at
4.07 percent
. The Bonds will be issued on or about April 1, 2018, and will mature in April 2048. Interest on the Bonds will be payable semi-annually in April and October of each year, commencing on October 16, 2018. ALLETE has the option to prepay all or a portion of the Bonds at its discretion, subject to a make-whole provision. The Bonds are subject to additional terms and conditions which are customary for these types of transactions. The company intends to use the proceeds from the sale of the Bonds to fund utility capital expenditures and for general corporate purposes. The Bonds were sold in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended, to institutional accredited investors.
ALLETE, Inc. 2017 Form 10-K
110
NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)
Long-Term Debt (Continued)
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
First Mortgage Bonds
|
|
|
1.83% Series Due 2018
|
|
$50.0
|
|
|
$50.0
|
|
8.17% Series Due 2019
|
42.0
|
|
42.0
|
|
5.28% Series Due 2020
|
35.0
|
|
35.0
|
|
2.80% Series Due 2020
|
40.0
|
|
40.0
|
|
4.85% Series Due 2021
|
15.0
|
|
15.0
|
|
3.02% Series Due 2021
|
60.0
|
|
60.0
|
|
3.40% Series Due 2022
|
75.0
|
|
75.0
|
|
6.02% Series Due 2023
|
75.0
|
|
75.0
|
|
3.69% Series Due 2024
|
60.0
|
|
60.0
|
|
4.90% Series Due 2025
|
30.0
|
|
30.0
|
|
5.10% Series Due 2025
|
30.0
|
|
30.0
|
|
3.20% Series Due 2026
|
75.0
|
|
75.0
|
|
5.99% Series Due 2027
|
60.0
|
|
60.0
|
|
3.30% Series Due 2028
|
40.0
|
|
40.0
|
|
3.74% Series Due 2029
|
50.0
|
|
50.0
|
|
3.86% Series Due 2030
|
60.0
|
|
60.0
|
|
5.69% Series Due 2036
|
50.0
|
|
50.0
|
|
6.00% Series Due 2040
|
35.0
|
|
35.0
|
|
5.82% Series Due 2040
|
45.0
|
|
45.0
|
|
4.08% Series Due 2042
|
85.0
|
|
85.0
|
|
4.21% Series Due 2043
|
60.0
|
|
60.0
|
|
4.95% Series Due 2044
|
40.0
|
|
40.0
|
|
5.05% Series Due 2044
|
40.0
|
|
40.0
|
|
4.39% Series Due 2044
|
50.0
|
|
50.0
|
|
Unsecured Term Loan Variable Rate Due 2017
|
—
|
|
125.0
|
|
Senior Unsecured Notes 5.99% Due 2017
|
—
|
|
50.0
|
|
Variable Demand Revenue Refunding Bonds Series 1997 A Due 2020
|
13.5
|
|
13.5
|
|
Unsecured Term Loan Variable Rate Due 2020
|
40.0
|
|
—
|
|
Armenia Mountain Senior Secured Notes 3.26% Due 2024
|
65.9
|
|
74.6
|
|
Industrial Development Variable Rate Demand Refunding Revenue Bonds Series 2006, Due 2025
|
27.8
|
|
27.8
|
|
Senior Unsecured Notes 3.11% Due 2027
|
80.0
|
|
—
|
|
SWL&P First Mortgage Bonds 4.15% Series Due 2028
|
15.0
|
|
15.0
|
|
Other Long-Term Debt, 3.11% – 5.37% Due 2018 – 2037
|
69.1
|
|
61.2
|
|
Unamortized Debt Issuance Costs
|
(10.0
|
)
|
(11.0
|
)
|
Total Long-Term Debt
|
1,503.3
|
|
1,558.1
|
|
Less: Due Within One Year
|
64.1
|
|
187.7
|
|
Net Long-Term Debt
|
|
$1,439.2
|
|
|
$1,370.4
|
|
ALLETE, Inc. 2017 Form 10-K
111
NOTE 10. SHORT-TERM AND LONG-TERM DEBT (Continued)
Financial Covenants.
Our long-term debt arrangements contain customary covenants. In addition, our lines of credit and letters of credit supporting certain long-term debt arrangements contain financial covenants. Our compliance with financial covenants is not dependent on debt ratings. The most restrictive financial covenant requires ALLETE to maintain a ratio of indebtedness to total capitalization (as the amounts are calculated in accordance with the respective long-term debt arrangements) of less than or equal to
0.65 to 1.00
, measured quarterly. As of
December 31, 2017
, our ratio was approximately
0.42 to 1.00
. Failure to meet this covenant would give rise to an event of default if not cured after notice from the lender, in which event ALLETE may need to pursue alternative sources of funding. Some of ALLETE’s debt arrangements contain “cross-default” provisions that would result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that would result in an acceleration of payments due. ALLETE has no significant restrictions on its ability to pay dividends from retained earnings or net income. As of
December 31, 2017
,
ALLETE was in compliance with its financial covenants.
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES
The following table details the estimated minimum payments for certain long-term commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
|
|
|
|
|
Millions
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Coal, Rail and Shipping Contracts
|
|
$29.0
|
|
|
$1.8
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Leasing Agreements
|
|
$14.2
|
|
|
$12.8
|
|
|
$9.5
|
|
|
$7.3
|
|
|
$6.1
|
|
|
$30.0
|
|
Long-term Service Agreements
(a)
|
|
$11.0
|
|
|
$0.9
|
|
—
|
|
—
|
|
|
$1.0
|
|
|
$11.0
|
|
PPAs
(b)
|
|
$104.5
|
|
|
$107.1
|
|
|
$115.0
|
|
|
$144.8
|
|
|
$144.7
|
|
|
$1,667.0
|
|
|
|
(a)
|
Consists of long-term service agreements for wind energy facilities.
|
|
|
(b)
|
Does not include the agreement with Manitoba Hydro expiring in 2022, as this contract is for surplus energy only; Oliver Wind I and Oliver Wind II, as Minnesota Power only pays for energy as it is delivered; and the agreement with Tenaska commencing in 2020 as it is subject to approval of the construction of a
525
MW to
550
MW combined-cycle natural gas-fired facility. (See Power Purchase Agreements.)
|
Coal, Rail and Shipping Contracts.
Minnesota Power has coal supply agreements providing for the purchase of a significant portion of its coal requirements through December 2018 and a portion of its coal requirements through December 2021. Minnesota Power also has coal transportation agreements in place for the delivery of a significant portion of its coal requirements through December 2018. The costs of fuel and related transportation costs for Minnesota Power’s generation are recoverable from Minnesota Power’s utility customers through the fuel adjustment clause.
Leasing Agreements.
BNI Energy is obligated to make lease payments for a dragline totaling
$2.8 million
annually during the lease term, which expires in 2027. BNI Energy has the option at the end of the lease term to renew the lease at fair market value, to purchase the dragline at fair market value, or to surrender the dragline and pay a
$3.0 million
termination fee. We also lease other properties and equipment under operating lease agreements with a majority of terms expiring through 2024. Total lease expense was
$17.5 million
in
2017
(
$17.1 million
in
2016
;
$17.3 million
in
2015
).
ALLETE, Inc. 2017 Form 10-K
112
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
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.
Square Butte PPA.
Minnesota Power has a PPA with Square Butte that extends through
2026
(Agreement). Minnesota Power is obligated to pay its pro rata share of Square Butte’s costs based on its entitlement to the output of Square Butte’s
455
MW coal‑fired generating unit. Minnesota Power’s output entitlement under the Agreement is
50 percent
for the remainder of the Agreement, subject to the provisions of the Minnkota Power PSA described in the following table. Minnesota Power’s payment obligation will be suspended if Square Butte fails to deliver any power, whether produced or purchased, for a period of one year. Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses. As of
December 31, 2017
, Square Butte had total debt outstanding of
$330.0 million
. Annual debt service for Square Butte is expected to be approximately
$49 million
in each of the next five years,
2018
through
2022
, of which Minnesota Power’s obligation is
50
percent. Fuel expenses are recoverable through Minnesota Power’s fuel adjustment clause and include the cost of coal purchased from BNI Energy under a long-term contract.
Minnesota Power’s cost of power purchased from Square Butte during
2017
was
$75.7 million
(
$73.3 million
in
2016
;
$77.8 million
in
2015
). 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
$9.4 million
in
2017
(
$9.6 million
in
2016
;
$10.1 million
in
2015
). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.
ALLETE, Inc. 2017 Form 10-K
113
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Power Purchase Agreements (Continued)
Minnesota Power has also entered into the following agreements for the purchase or sale of capacity and energy as of
December 31, 2017
:
|
|
|
|
|
|
|
Counterparty
|
Quantity
|
Product
|
Commencement
|
Expiration
|
Pricing
|
PPAs
|
|
|
|
|
|
Great River Energy
|
|
|
|
|
|
PPA 1
|
50 MW
|
Capacity / Energy
|
June 2016
|
May 2020
|
(a)
|
PPA 2
|
50 MW
|
Capacity
|
June 2016
|
May 2020
|
Fixed
|
PPA 3
|
50 MW
|
Capacity
|
June 2017
|
May 2020
|
Fixed
|
Manitoba Hydro
|
|
|
|
|
|
PPA 1
|
(b)
|
Energy
|
May 2011
|
April 2022
|
Forward Market Prices
|
PPA 2
|
50 MW
|
Capacity / Energy
|
June 2015
|
May 2020
|
(c)
|
PPA 3
|
50 MW
|
Capacity
|
June 2017
|
May 2020
|
Fixed
|
PPA 4
(d)
|
250 MW
|
Capacity / Energy
|
June 2020
|
May 2035
|
(e)
|
PPA 5
(d)
|
133 MW
|
Energy
|
(f)
|
(f)
|
Forward Market Prices
|
Minnkota Power
|
50 MW
|
Capacity / Energy
|
June 2016
|
May 2020
|
(g)
|
Oliver Wind I
|
(h)
|
Energy
|
December 2006
|
December 2031
|
Fixed
|
Oliver Wind II
|
(h)
|
Energy
|
December 2007
|
December 2032
|
Fixed
|
Shell Energy
|
50 MW
|
Energy
|
January 2017
|
December 2019
|
Fixed
|
TransAlta
|
(i)
|
Energy
|
January 2017
|
December 2019
|
Fixed
|
Tenaska
(j)
|
(j)
|
Capacity / Energy
|
June 2020
|
June 2040
|
Fixed
|
PSAs
|
|
|
|
|
|
Basin
|
|
|
|
|
|
PSA 1
|
100 MW
|
Capacity / Energy
|
May 2010
|
April 2020
|
(k)
|
PSA 2
|
100 MW
|
Capacity
|
June 2016
|
May 2018
|
Fixed
|
PSA 3
|
50 MW
|
Capacity
|
June 2017
|
May 2019
|
Fixed
|
Minnkota Power
|
(l)
|
Capacity / Energy
|
June 2014
|
December 2026
|
(l)
|
Silver Bay Power
|
(m)
|
Energy
|
January 2017
|
December 2031
|
(n)
|
|
|
(a)
|
The capacity price is fixed and the energy price is based on a formula that includes an annual fixed price component adjusted for changes in a natural gas index, as well as market prices.
|
|
|
(b)
|
The energy purchased consists primarily of surplus hydro energy on Manitoba Hydro's system and is delivered on a non-firm basis. Minnesota Power will purchase at least
one million
MWh of energy over the contract term.
|
|
|
(c)
|
The capacity and energy prices are adjusted annually by the change in a governmental inflationary index.
|
|
|
(d)
|
Agreements are subject to the construction of additional transmission capacity between Manitoba and the U.S., along with construction of new hydroelectric generating capacity in Manitoba. (See Great Northern Transmission Line.)
|
|
|
(e)
|
The capacity price is adjusted annually until 2020 by the change in a governmental inflationary index. The energy price is based on a formula that includes an annual fixed component adjusted for the change in a governmental inflationary index and a natural gas index, as well as market prices.
|
|
|
(f)
|
The contract term shall be the
20
-year period beginning on the in-service date for the GNTL. (See Great Northern Transmission Line.)
|
|
|
(g)
|
The agreement includes a fixed capacity charge and energy prices that escalate at a fixed rate annually over the term.
|
|
|
(h)
|
The PPAs provide for the purchase of all output from the
50
MW Oliver Wind I and
48
MW Oliver Wind II wind energy facilities.
|
|
|
(i)
|
The energy purchased under the
50
MW PPA is during off-peak hours and the
100
MW PPA is during on-peak hours.
|
|
|
(j)
|
The PPA provides for the purchase of all output from a
250
MW wind energy facility to be constructed in southwest Minnesota and is subject to approval of the construction of a
525
MW to
550
MW combined-cycle natural gas-fired facility. (See Note 4. Regulatory Matters.)
|
|
|
(k)
|
The capacity charge is based on a fixed monthly schedule with a minimum annual escalation provision. The energy charge is based on a fixed monthly schedule and provides for annual escalation based on the cost of fuel. The agreement also allows Minnesota Power to recover a pro rata share of increased costs related to emissions that occur during the last five years of the contract.
|
|
|
(l)
|
Minnesota Power is selling a portion of its entitlement from Square Butte to Minnkota Power, resulting in Minnkota Power’s net entitlement increasing and Minnesota Power’s net entitlement decreasing until Minnesota Power’s share is eliminated at the end of
2025
. Of Minnesota Power’s
50 percent
output entitlement, it sold to Minnkota Power approximately
28 percent
in
2017
(
28 percent
in
2016
and in
2015
). (See Square Butte PPA.)
|
|
|
(m)
|
Silver Bay Power supplies approximately
90
MW of load to Northshore Mining, an affiliate of Silver Bay Power, which has been served predominately through self-generation by Silver Bay Power. In the years 2016 through 2019, Minnesota Power is supplying Silver Bay Power with at least
50
MW of energy and Silver Bay Power has the option to purchase additional energy. On December 31, 2019, Silver Bay Power will cease self-generation and Minnesota Power will supply the energy requirements for Silver Bay Power.
|
|
|
(n)
|
The energy pricing is fixed through 2019 with pricing in later years escalating at a fixed rate annually and adjusted for changes in a natural gas index.
|
ALLETE, Inc. 2017 Form 10-K
114
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission
. We continue to make investments in transmission opportunities that strengthen or enhance the transmission grid or take advantage of our geographical location between sources of renewable energy and end users. These include the GNTL, investments to enhance our own transmission facilities, investments in other transmission assets (individually or in combination with others) and our investment in ATC.
Great Northern Transmission Line.
As a condition of the
250
MW long-term PPA entered into with Manitoba Hydro, construction of additional transmission capacity is required. As a result, Minnesota Power and Manitoba Hydro proposed construction of the GNTL, an approximately
220
-mile
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.
In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Note 4. Regulatory Matters.) Also in 2015, the FERC approved our request to recover on construction work in progress related to the GNTL from Minnesota Power’s wholesale customers. In an April 2016 order, the MPUC approved the route permit for the GNTL which largely follows Minnesota Power’s preferred route, including the international border crossing, and in November 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.-Canadian border, which was the final major regulatory approval needed before construction in the U.S. could begin. Site clearing and pre-construction activities commenced in the first quarter of 2017 with construction expected to be completed in 2020. Total project cost in the U.S., including substation work, is estimated to be between
$560 million
and
$710 million
, of which Minnesota Power’s portion is expected to be between
$300 million
and
$350 million
; the difference will be recovered from a subsidiary of Manitoba Hydro as contributions in aid of construction. Total project costs of
$152.4 million
have been incurred through
December 31, 2017
, of which
$67.6 million
has been recovered from a subsidiary of Manitoba Hydro.
Manitoba Hydro must obtain regulatory and governmental approvals related to a new transmission line in Canada. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the transmission line in Canada to the Manitoba Conservation and Water Stewardship for regulatory approval. In December 2016, Manitoba Hydro filed an application with the National Energy Board in Canada requesting authorization to construct and operate an international transmission line. Both provincial and federal approvals are pending. Construction of Manitoba Hydro’s hydroelectric generation facility commenced in 2014 and is anticipated to be in service by early 2021.
Environmental Matters.
Our businesses are subject to regulation of environmental matters by various federal, state and local authorities. A number of regulatory changes to the Clean Air Act, the Clean Water Act and various waste management requirements have recently been promulgated by both the EPA and state authorities. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology and advocates for sound science and policy during rulemaking implementation.
We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and may require significant capital investments. Minnesota Power has evaluated various environmental compliance scenarios using possible outcomes of environmental regulations to project power supply trends and impacts on customers.
We review environmental matters on a quarterly basis. Accruals for environmental matters are recorded when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated based on current law and existing technologies. Accruals are adjusted as assessment and remediation efforts progress, or as additional technical or legal information becomes available. Accruals for environmental liabilities are included in the Consolidated Balance Sheet at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Costs related to environmental contamination treatment and cleanup are expensed unless recoverable in rates from customers.
Air.
The electric utility industry is regulated both at the federal and state level to address air emissions. Minnesota Power’s generating facilities mainly burn low-sulfur western sub-bituminous coal. All of Minnesota Power’s coal-fired generating facilities are equipped with pollution control equipment such as scrubbers, baghouses and low NO
X
technologies. Under currently applicable environmental regulations, these facilities are substantially compliant with emission requirements.
ALLETE, Inc. 2017 Form 10-K
115
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
New Source Review (NSR).
In 2008, Minnesota Power received a Notice of Violation (NOV) from the EPA asserting violations of the NSR requirements of the Clean Air Act at Boswell and Laskin Unit 2 between the years of 1981 and 2001. Minnesota Power received an additional NOV in 2011 alleging that two projects undertaken at Rapids Energy Center in 2004 and 2005 should have been reviewed under the NSR requirements and that the Rapids Energy Center’s Title V permit was violated. Minnesota Power reached a settlement with the EPA regarding these NOVs and entered into a Consent Decree which was approved by the U.S. District Court for the District of Minnesota in 2014. The Consent Decree provided for, among other requirements, more stringent emissions limits at all affected units, the option of refueling, retrofitting or retiring certain small coal units, and the addition of
200
MW of wind energy. Provisions of the Consent Decree require that, by no later than December 31, 2018, Boswell Units 1 and 2 must be retired, refueled, repowered, or emissions rerouted through existing emission control technology at Boswell. In October 2016, Minnesota Power announced that Boswell Units 1 and 2 will be retired in 2018 as part of its
EnergyForward
strategic plan. We believe that costs to retire Boswell Units 1 and 2 will be eligible for recovery in rates over time, subject to regulatory approval in a rate proceeding.
Cross-State Air Pollution Rule (CSAPR).
The CSAPR requires certain states in the eastern half of the U.S., including Minnesota, to reduce power plant emissions that contribute to ozone or fine particulate pollution in other states. The CSAPR does not require installation of controls; rather it requires facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the NO
x
and SO
2
allowances issued and pending issuance, we currently expect generation levels and emission rates will result in continued compliance with the CSAPR.
Mercury and Air Toxics Standards (MATS) Rule.
Under Section 112 of the Clean Air Act, the EPA is required to set emission standards for hazardous air pollutants (HAPs) for certain source categories. The final MATS rule addressed such emissions from coal-fired utility units greater than 25 MW and established categories of HAPs, including mercury, trace metals other than mercury, and acid gases. The EPA established emission limits for these categories of HAPs and work practice standards for the remaining categories. Construction on the project to implement the Boswell Unit 4 mercury emissions reduction plan to position the unit for MATS compliance was completed in 2015. Investments and compliance work previously completed at Boswell Unit 3, including emission reduction investments completed in 2009, meet the requirements of the MATS rule. The conversion of Laskin Units 1 and 2 to operate on natural gas in 2015 positioned those units for MATS compliance.
Minnesota Mercury Emissions Reduction Act/Rule.
Minnesota Power was required to implement a mercury emissions reduction project for Boswell Unit 4 by December 31, 2018. The Boswell Unit 4 environmental upgrade discussed above (see
Mercury and Air Toxics Standards (MATS) Rule
) fulfills the requirements of the Minnesota Mercury Emissions Reduction Act.
National Ambient Air Quality Standards (NAAQS).
The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.
|
|
•
|
Ozone NAAQS.
All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data; however, some areas in the metropolitan Twin Cities and southwest portion of the state are close to exceeding the standard. As a result, voluntary efforts to reduce ground-level ozone continue in the state.
No
additional costs for compliance are anticipated at this time.
|
|
|
•
|
Particulate Matter NAAQS.
The EPA has designated the entire state of Minnesota as unclassifiable/attainment; however, Minnesota sources may ultimately be required to reduce their emissions to assist with attainment in neighboring states. In September 2016, environmental groups filed a lawsuit against the EPA in the U.S. District Court for the Northern District of California alleging the EPA had failed to fully implement the PM
2.5
standards in certain states, including Minnesota, by not enforcing states’ submittals of required infrastructure implementation plans for the 2012 PM
2.5
NAAQS. The outcome of this litigation is uncertain, and as such, any costs for complying with the final Particulate Matter NAAQS cannot be estimated at this time.
|
|
|
•
|
NO
2
NAAQS.
Ambient monitoring data indicates that Minnesota is likely in compliance with the one-hour NAAQS standard for NO
2
. On July 16, 2017, the EPA proposed retaining the current one-hour and annual NO
2
NAAQS. Additional compliance costs for the one-hour NO
2
NAAQS are
not
expected at this time.
|
ALLETE, Inc. 2017 Form 10-K
116
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
|
|
•
|
SO
2
NAAQS.
In 2015, the EPA finalized the SO
2
data requirements rule (DRR) for the 2010 one-hour NAAQS to assist the states in implementing the standard. The MPCA initially informed Minnesota Power that compliant SO
2
modeling completed at Minnesota Power's Boswell and Taconite Harbor facilities would satisfy the DRR obligations and no further modeling would be required; however, the DRR also require facilities have federally-enforceable permit limits at which the one-hour SO
2
NAAQS compliance was modeled by January 13, 2017. Taconite Harbor was issued an amended air permit in September 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 13, 2017, deadline to amend the Boswell permit. The MPCA is in discussions with the EPA on alternate compliance pathways to use existing completed modeling at current limits. On August 21, 2017, the EPA proposed retaining the current primary SO
2
one-hour NAAQS. Compliance costs for the one-hour SO
2
NAAQS are not expected to be material.
|
Climate Change.
The scientific community generally accepts that emissions of GHG are linked to global climate change which creates physical and financial risks. Physical risks could include, but are not limited to: increased or decreased precipitation and water levels in lakes and rivers; increased temperatures; and changes in the intensity and frequency of extreme weather events. These all have the potential to affect the Company’s business and operations. We are addressing climate change by taking the following steps that also ensure reliable and environmentally compliant generation resources to meet our customers’ requirements:
|
|
•
|
Expanding our renewable power supply;
|
|
|
•
|
Providing energy conservation initiatives for our customers and engaging in other demand side management efforts;
|
|
|
•
|
Improving efficiency of our generating facilities;
|
|
|
•
|
Supporting research of technologies to reduce carbon emissions from generating facilities and carbon sequestration efforts; and
|
|
|
•
|
Evaluating and developing less carbon intensive future generating assets such as efficient and flexible natural gas‑fired generating facilities.
|
EPA Regulation of GHG Emissions.
In 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). The Tailoring Rule establishes permitting thresholds required to address GHG emissions for new facilities, existing facilities that undergo major modifications and 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 may be added to our existing Title V operating permits by the MPCA as these permits are renewed or amended.
In 2014, the U.S. Supreme Court invalidated the aspect of the Tailoring Rule that established higher permitting thresholds for GHG than for other pollutants subject to PSD; however, the court also upheld the EPA’s ability to require best available control technology (BACT) for GHG from sources already subject to regulation under PSD. Minnesota Power’s coal-fired generating facilities are already subject to regulation under PSD, so we anticipate that ultimately PSD for GHG will apply to our facilities, but the timing of the promulgation of a replacement for the Tailoring Rule is uncertain. The PSD applies to existing facilities only when they undertake a major modification that increases emissions.
In October 2016, the EPA published a proposed rule in the Federal Register to revise its PSD and Title V regulatory provisions concerning GHG emissions. In this proposed rule, the EPA proposes to amend its regulations to clarify that a source’s obligation to obtain a PSD or Title V permit is triggered only by non-GHG pollutants. If the PSD or Title V permitting requirements are triggered by non-GHG, NSR pollutants, then these programs will also apply to the source’s GHG emissions. The proposed rule, as currently written, is not expected to have a material impact on the Title V permitting for current operations.
In 2014, the EPA announced a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred to as the Clean Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation plan and a model rule for emissions trading. In February 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In September 2016, the U.S. Court of Appeals for the District of Columbia heard oral arguments and is currently deliberating. If the CPP is upheld at the completion of the appellate process, all of the CPP regulatory deadlines are expected to be reset based on the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force; however, the MPCA has been holding a series of meetings on the CPP for educational and planning purposes in the interim. Minnesota Power has been actively involved in these MPCA meetings, and is closely monitoring the appeals process.
ALLETE, Inc. 2017 Form 10-K
117
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
If upheld, the CPP would establish uniform CO
2
emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO
2
emissions from the power sector. State goals were determined based on CPP source-specific performance emission rates and each state’s mix of power plants. The EPA has filed a motion with the U.S. Court of Appeals for the District of Columbia Circuit to hold CPP-related litigation in suspension while the EPA is reviewing the rule. On October 10, 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. On December 28, 2017, an Advanced Notice of Proposed Rulemaking (ANPRM) for a CPP replacement rule was published in the Federal Register.
Minnesota Power is currently evaluating the CPP rescission and recently proposed ANPRM for a CPP replacement rule as it relates to the State of Minnesota as well as its potential impact on the Company. Minnesota has already initiated several measures consistent with those called for under the CPP. Minnesota Power is implementing its
EnergyForward
strategic plan that provides for significant emission reductions and diversifying its electricity generation mix to include more renewable and natural gas energy. (See Note 4. Regulatory Matters.)
We are unable to predict the GHG emission compliance costs we might incur; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Water.
The Clean Water Act requires National Pollutant Discharge Elimination System (NPDES) permits be obtained from the EPA (or, when delegated, from individual state pollution control agencies) for any wastewater discharged into navigable waters. We have obtained all necessary NPDES permits, including NPDES storm water permits for applicable facilities, to conduct our operations.
Clean Water Act - Aquatic Organisms.
In 2014, EPA regulations under Section 316(b) of the Clean Water Act setting standards applicable to cooling water intake structures for the protection of aquatic organisms became effective. The regulations require existing large power plants and manufacturing facilities that withdraw greater than 25 percent of water from adjacent water bodies for cooling purposes and have a design intake flow of greater than 2 million gallons per day, to limit the number of aquatic organisms that are impacted by the facility’s intake structure or cooling system. The Section 316(b) rule will be implemented through NPDES permits issued to covered facilities. No NPDES permits for Minnesota Power facilities have been re-issued containing Section 316(b) requirements since the final rule became effective. Should the MPCA require significant modifications to Minnesota Power’s intake structures, a preliminary assessment indicates that Minnesota Power could incur costs of compliance up to
$15 million
over the next five years. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Steam Electric Power Generating Effluent Guidelines.
In 2015, the EPA issued revised federal effluent limit guidelines (ELG) for steam electric power generating stations under the Clean Water Act. It set effluent limits and prescribed BACT for several wastewater streams, including flue gas desulphurization (FGD) water, bottom ash transport water and coal combustion landfill leachate. On September 13, 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders bottom ash transport water and FGD wastewater provisions.
The final ELG rule’s potential impact on Minnesota Power operations is primarily at Boswell. Boswell currently discharges bottom ash contact water through its NPDES permit, and also has a closed-loop FGD system that does not discharge, but may do so in the future. Under the existing ELG rule, bottom ash transport water discharge must cease no later than December 31, 2023. Bottom ash contact water will either need to be re-used in a closed-loop process, routed to a FGD scrubber, or the bottom ash handling system will need to be converted to a dry process. If FGD wastewater is discharged in the future, it will require additional wastewater treatment. The ELG rule provision regarding these two waste-streams are being reconsidered and may change prior to November 1, 2020. Efforts have been underway at Boswell for several years to reduce the amount of water discharged and evaluate potential re-use options in its plant processes.
At this time, we cannot estimate what compliance costs we might incur related to these or other potential future water discharge regulations; however, the costs could be material, including costs associated with retrofits for bottom ash handling, pond dewatering, pond closure, and wastewater treatment and reuse. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Solid and Hazardous Waste.
The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit the necessary reports to the EPA.
ALLETE, Inc. 2017 Form 10-K
118
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Coal Ash Management Facilities.
Minnesota Power stores or disposes coal ash at four of its electric generating facilities by the following methods: storing ash in lined onsite impoundments (ash ponds), disposing of dry ash in a lined dry ash landfill which has been idled and has a temporary landfill cover in place, applying ash to land as an approved beneficial use and trucking ash to state permitted landfills.
Coal Combustion Residuals from Electric Utilities (CCR).
In 2015, the EPA published the final rule regulating CCR as nonhazardous waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) in the Federal Register. The rule includes additional requirements for new landfill and impoundment construction as well as closure activities related to certain existing impoundments. Costs of compliance for Boswell and Laskin are expected to occur primarily over the next 10 years and be between approximately
$65 million
and
$100 million
. The EPA has indicated to Minnesota Power that the Taconite Harbor landfill is a CCR unit, based on the EPA’s interpretation of the CCR rule language. Minnesota Power has agreed to post the required CCR information for the Taconite Harbor landfill on Minnesota Power’s website while the CCR issue is resolved. Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR-related waters. On September 13, 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA. Compliance costs, if any, for CCR at Taconite Harbor cannot be estimated at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Other Environmental Matters
Manufactured Gas Plant Site.
We are reviewing and addressing environmental conditions at a former manufactured gas plant site located in Superior, Wisconsin, and formerly operated by SWL&P. SWL&P has been working with the Wisconsin Department of Natural Resources (WDNR) in determining the extent and location of contamination at the site and surrounding properties. In December 2017, the WDNR authorized SWL&P to transition from site investigation into the remedial design process. As of
December 31, 2017
, we have recorded a liability of approximately
$8 million
for remediation costs at this site, and a corresponding regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expect to incur these costs over the next four years.
Other Matters
ALLETE Clean Energy.
ALLETE Clean Energy’s wind energy facilities have PSAs in place for their entire output and expire in various years between 2018 and 2032. As of
December 31, 2017
, ALLETE Clean Energy has
$15.4 million
outstanding in standby letters of credit.
U.S. Water Services.
As of
December 31, 2017
, U.S. Water Services has
$0.8 million
outstanding in standby letters of credit.
BNI Energy.
As of
December 31, 2017
, BNI Energy had surety bonds outstanding of
$49.9 million
and a letter of credit for an additional
$0.6 million
related to the reclamation liability for closing costs associated with its mine and mine facilities. Although its coal supply agreements obligate the customers to provide for the closing costs, additional assurance is required by federal and state regulations. BNI Energy’s total reclamation liability is currently estimated at
$47.5 million
. BNI Energy does not believe it is likely that any of these outstanding surety bonds or the letter of credit will be drawn upon.
ALLETE Properties.
As of
December 31, 2017
, ALLETE Properties had surety bonds outstanding and letters of credit to governmental entities totaling
$8.6 million
primarily related to development and maintenance obligations for various projects. The estimated cost of the remaining development work is
$6.1 million
. ALLETE Properties does not believe it is likely that any of these outstanding surety bonds or letters of credit will be drawn upon.
ALLETE, Inc. 2017 Form 10-K
119
NOTE 11. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Other Matters (Continued)
Community Development District Obligations.
In 2005, the Town Center District issued
$26.4 million
of tax-exempt,
6.0 percent
capital improvement revenue bonds, and in 2006, the Palm Coast Park District issued
$31.8 million
of tax-exempt,
5.7 percent
special assessment bonds. The capital improvement revenue bonds and the special assessment bonds are payable over
31
years (by May 1, 2036 and 2037, respectively) and are secured by special assessments on the benefited land. The bond proceeds were used to pay for the construction of a portion of the major infrastructure improvements in each district and to mitigate traffic and environmental impacts. The assessments were billed to the landowners beginning in 2006 for the Town Center District and 2007 for the Palm Coast Park District. To the extent that ALLETE Properties still owns land at the time of the assessment, it will incur the cost of our portion of these assessments, based upon its ownership of benefited property. As of
December 31, 2017
, we owned
70
percent of the assessable land in the Town Center District (
72
percent as of
December 31, 2016
) and
33
percent of the assessable land in the Palm Coast Park District (
92
percent as of
December 31, 2016
). As of
December 31, 2017
, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are
$1.4 million
for Town Center at Palm Coast and
$2.0 million
for Palm Coast Park. As we sell property at these projects, the obligation to pay special assessments will pass to the new landowners. In accordance with accounting guidance, these bonds are not reflected as debt on our Consolidated Balance Sheet.
Legal Proceedings.
We are involved in litigation arising in the normal course of business. Also in the normal course of business, we are involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, and compliance with regulations, rate base and cost of service issues, among other things. We do not expect the outcome of these matters to have a material effect on our financial position, results of operations or cash flows.
NOTE 12. COMMON STOCK AND EARNINGS PER SHARE
|
|
|
|
|
|
|
Summary of Common Stock
|
Shares
|
|
Equity
|
|
|
Thousands
|
|
Millions
|
|
Balance as of December 31, 2014
|
45,929
|
|
|
$1,107.6
|
|
Employee Stock Purchase Plan
|
18
|
|
0.9
|
|
Invest Direct
|
383
|
|
19.0
|
|
Options and Stock Awards
|
43
|
|
8.6
|
|
Equity Issuance Program
|
1,289
|
|
69.9
|
|
Forward Sale Agreement and Issuance
|
1,413
|
|
65.4
|
|
Balance as of December 31, 2015
|
49,075
|
|
1,271.4
|
|
Employee Stock Purchase Plan
|
16
|
|
0.9
|
|
Invest Direct
|
344
|
|
20.0
|
|
Options and Stock Awards
|
65
|
|
3.7
|
|
Contributions to RSOP
|
60
|
|
3.3
|
|
Equity Issuance Program
|
130
|
|
8.0
|
|
Received for Sale of Land Inventory
|
(130
|
)
|
(8.0
|
)
|
Acquisition of Non-Controlling Interest
|
—
|
|
(4.0
|
)
|
Balance as of December 31, 2016
|
49,560
|
|
1,295.3
|
|
Employee Stock Purchase Plan
|
12
|
|
0.8
|
|
Invest Direct
|
257
|
|
19.0
|
|
Options and Stock Awards
|
22
|
|
3.6
|
|
Contributions to RSOP
|
50
|
|
3.5
|
|
Equity Issuance Program
|
1,000
|
|
65.7
|
|
Contributions to Pension
|
216
|
|
13.5
|
|
Balance as of December 31, 2017
|
51,117
|
|
|
$1,401.4
|
|
ALLETE, Inc. 2017 Form 10-K
120
NOTE 12. COMMON STOCK AND EARNINGS PER SHARE (Continued)
Equity Issuance Program.
We entered into a distribution agreement with Lampert Capital Markets, Inc., in 2008, as amended most recently in
August 2016
, with respect to the issuance and sale of up to an aggregate of
13.6 million
shares of our common stock, without par value, of which
2.9 million
shares remain available for issuance as of
December 31, 2017
. For the year ended
December 31, 2017
,
1.0 million
shares of common stock were issued under this agreement, resulting in net proceeds of
$65.7 million
(
0.1 million
shares for net proceeds of
$8.0 million
in
2016
;
1.3 million
shares for net proceeds of
$69.9 million
in
2015
). The shares issued in 2017 and 2016 were offered and sold pursuant to Registration Statement No. 333-212794, pursuant to which the remaining shares will continue to be offered for sale, from time to time. The shares issued in
2015
were offered and sold pursuant to Registration Statement No. 333-190335.
Earnings Per Share.
We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units, performance share awards granted under our Executive Long-Term Incentive Compensation Plan and common shares under the forward sale agreement (described below).
No
options to purchase shares of common stock were excluded from the computation of diluted earnings per share in
2017
,
2016
and
2015
.
Forward Sale Agreement and Issuance of Common Stock
.
In 2014, ALLETE entered into a confirmation of forward sale agreement (Agreement) with a forward counterparty in connection with a public offering of
2.8 million
shares of ALLETE common stock.
Pursuant to the Agreement, the forward counterparty (or its affiliate) borrowed
2.8 million
shares of ALLETE common stock from third parties and sold them to the underwriters. The forward sale price was
$48.01
per share, subject to adjustment as provided in the Agreement. In 2014, ALLETE physically settled a portion of its obligations under the Agreement by delivering approximately
1.4 million
shares of common stock in exchange for cash proceeds of
$65.0 million
, and in February 2015, ALLETE physically settled the remaining portion of its obligation under the Agreement by delivering approximately
1.4 million
shares of common stock for cash proceeds of
$65.4 million
.
Contributions to Pension.
For the year ended
December 31, 2017
, we contributed approximately
0.2 million
shares of ALLETE common stock to our pension plan, which had an aggregate value of
$13.5 million
when contributed (
none
in
2016
and in
2015
). These shares of ALLETE common stock were contributed in reliance upon an exemption available pursuant to Section 4(a)(2) of the Securities Act of 1933, as amended.
|
|
|
|
|
|
|
|
|
|
Reconciliation of Basic and Diluted
|
|
|
|
Earnings Per Share
|
|
|
Dilutive
|
|
|
|
Year Ended December 31
|
Basic
|
|
Securities
|
|
Diluted
|
|
Millions Except Per Share Amounts
|
|
|
|
2017
|
|
|
|
Net Income Attributable to ALLETE
|
|
$172.2
|
|
|
|
$172.2
|
|
Average Common Shares
|
50.8
|
|
0.2
|
|
51.0
|
|
Earnings Per Share
|
|
$3.39
|
|
|
|
$3.38
|
|
2016
|
|
|
|
Net Income Attributable to ALLETE
|
|
$155.3
|
|
|
|
$155.3
|
|
Average Common Shares
|
49.3
|
|
0.2
|
|
49.5
|
|
Earnings Per Share
|
|
$3.15
|
|
|
|
$3.14
|
|
2015
|
|
|
|
Net Income Attributable to ALLETE
|
|
$141.1
|
|
|
|
$141.1
|
|
Average Common Shares
|
48.3
|
|
0.1
|
|
48.4
|
|
Earnings Per Share
|
|
$2.92
|
|
|
|
$2.92
|
|
ALLETE, Inc. 2017 Form 10-K
121
NOTE 13. INCOME TAX EXPENSE
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
|
Year Ended December 31
|
2017
|
|
2016
|
|
2015
|
|
Millions
|
|
|
|
Current Income Tax Expense
(a)
|
|
|
|
Federal
|
—
|
|
—
|
|
—
|
|
State
|
$0.3
|
$0.4
|
$0.2
|
Total Current Income Tax Expense
|
|
$0.3
|
|
|
$0.4
|
|
|
$0.2
|
|
Deferred Income Tax Expense
|
|
|
|
Federal
|
|
$12.1
|
|
|
$12.0
|
|
|
$19.4
|
|
Federal – Remeasurement of Deferred Income Taxes
(b)
|
(13.0
|
)
|
—
|
|
—
|
|
State
|
15.8
|
|
8.1
|
|
6.5
|
|
Investment Tax Credit Amortization
|
(0.5
|
)
|
(0.7
|
)
|
(0.8
|
)
|
Total Deferred Income Tax Expense
|
|
$14.4
|
|
|
$19.4
|
|
|
$25.1
|
|
Total Income Tax Expense
|
|
$14.7
|
|
|
$19.8
|
|
|
$25.3
|
|
|
|
(a)
|
For the years ended December 31,
2017
,
2016
and
2015
, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012. The federal and state NOLs will be carried forward to offset future taxable income.
|
|
|
(b)
|
Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Taxes from Federal Statutory
|
|
|
|
Rate to Total Income Tax Expense
|
|
|
|
Year Ended December 31
|
2017
|
|
2016
|
|
2015
|
|
Millions
|
|
|
|
Income Before Non-Controlling Interest and Income Taxes
|
|
$186.9
|
|
|
$175.6
|
|
|
$166.8
|
|
Statutory Federal Income Tax Rate
|
35
|
%
|
35
|
%
|
35
|
%
|
Income Taxes Computed at 35 percent Statutory Federal Rate
|
|
$65.4
|
|
|
$61.5
|
|
|
$58.4
|
|
Increase (Decrease) in Tax Due to:
|
|
|
|
State Income Taxes – Net of Federal Income Tax Benefit
|
10.5
|
|
5.6
|
|
4.4
|
|
Regulatory Differences for Utility Plant
|
—
|
|
(0.1
|
)
|
(0.6
|
)
|
Production Tax Credits
|
(45.1
|
)
|
(41.5
|
)
|
(37.0
|
)
|
Change in Fair Value of Contingent Consideration
|
—
|
|
(3.8
|
)
|
—
|
|
Remeasurement of Deferred Income Taxes
(a)
|
(13.0
|
)
|
—
|
|
—
|
|
Other
|
(3.1
|
)
|
(1.9
|
)
|
0.1
|
|
Total Income Tax Expense
|
|
$14.7
|
|
|
$19.8
|
|
|
$25.3
|
|
|
|
(a)
|
Deferred income tax benefit from the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.)
|
The effective tax rate was
7.9 percent
for
2017
(
11.3 percent
for
2016
;
15.2 percent
for
2015
). The
2017
effective tax rate was primarily impacted by production tax credits and the remeasurement of deferred income tax assets and liabilities resulting from the TCJA. (See Note 1. Operations and Significant Accounting Policies.) The
2016
and
2015
effective rates were primarily impacted by production tax credits.
ALLETE, Inc. 2017 Form 10-K
122
NOTE 13. INCOME TAX EXPENSE (Continued)
|
|
|
|
|
|
|
|
Deferred Income Tax Assets and Liabilities
|
|
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Deferred Income Tax Assets
|
|
|
Employee Benefits and Compensation
|
|
$65.9
|
|
|
$104.6
|
|
Property Related
|
104.3
|
|
110.5
|
|
NOL Carryforwards
|
99.1
|
|
185.6
|
|
Tax Credit Carryforwards
|
294.3
|
|
227.4
|
|
Power Sales Agreements
|
35.0
|
|
59.3
|
|
Regulatory Liabilities
|
117.7
|
|
7.3
|
|
Other
|
33.3
|
|
46.9
|
|
Gross Deferred Income Tax Assets
|
749.6
|
|
741.6
|
|
Deferred Income Tax Asset Valuation Allowance
|
(60.0
|
)
|
(43.0
|
)
|
Total Deferred Income Tax Assets
|
|
$689.6
|
|
|
$698.6
|
|
Deferred Income Tax Liabilities
|
|
|
Property Related
|
|
$758.3
|
|
|
$1,039.6
|
|
Regulatory Asset for Benefit Obligations
|
61.4
|
|
91.9
|
|
Unamortized Investment Tax Credits
|
32.8
|
|
33.3
|
|
Partnership Basis Differences
|
34.9
|
|
50.9
|
|
Regulatory Assets
|
32.0
|
|
25.6
|
|
Other
|
0.7
|
|
11.9
|
|
Total Deferred Income Tax Liabilities
|
|
$920.1
|
|
|
$1,253.2
|
|
Net Deferred Income Taxes
(a)
|
|
$230.5
|
|
|
$554.6
|
|
|
|
(a)
|
Recorded as a net long-term Deferred Income Tax liability on the Consolidated Balance Sheet. Additionally, see Note 1. Operations and Significant Accounting Policies – Revision of Prior Balance Sheet.
|
|
|
|
|
|
|
NOL and Tax Credit Carryforwards
|
|
|
As of December 31
|
2017
|
2016
|
|
Millions
|
|
|
Federal NOL Carryforwards
(a)
|
$375.2
|
|
$485.3
|
|
Federal Tax Credit Carryforwards
|
$209.2
|
$163.7
|
State NOL Carryforwards
(a)
|
$289.9
|
$294.4
|
State Tax Credit Carryforwards
(b)
|
$25.6
|
$21.0
|
|
|
(b)
|
Net of a
$59.5 million
valuation allowance as of
December 31, 2017
(
$42.7 million
as of
December 31, 2016
).
|
The federal NOL and tax credit carryforward periods expire between 2030 and 2037. We expect to fully utilize the federal NOL and federal tax credit carryforwards; therefore,
no
federal valuation allowance has been recognized as of
December 31, 2017
. The state NOL and tax credit carryforward periods expire between 2024 and 2045. We have established a valuation allowance against certain state NOL and tax credits that we do not expect to utilize before their expiration. We do not expect a material impact on the Company’s ability to utilize its federal and state NOL and tax credit carryforwards due to the TCJA.
ALLETE, Inc. 2017 Form 10-K
123
NOTE 13. INCOME TAX EXPENSE (Continued)
|
|
|
|
|
|
|
|
|
|
|
Gross Unrecognized Income Tax Benefits
|
2017
|
|
2016
|
|
2015
|
|
Millions
|
|
|
|
Balance at January 1
|
|
$2.0
|
|
|
$2.4
|
|
|
$2.0
|
|
Additions for Tax Positions Related to the Current Year
|
0.1
|
|
0.1
|
|
0.5
|
|
Additions for Tax Positions Related to Prior Years
|
0.1
|
|
0.2
|
|
0.7
|
|
Reductions for Tax Positions Related to Prior Years
|
(0.1
|
)
|
(0.3
|
)
|
(0.7
|
)
|
Lapse of Statute
|
(0.4
|
)
|
(0.4
|
)
|
(0.1
|
)
|
Balance as of December 31
|
|
$1.7
|
|
|
$2.0
|
|
|
$2.4
|
|
Unrecognized tax benefits are the differences between a tax position taken or expected to be taken in a tax return and the benefit recognized and measured pursuant to the “more-likely-than-not” criteria. The unrecognized tax benefit balance includes permanent tax positions which, if recognized would affect the annual effective income tax rate. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The gross unrecognized tax benefits as of
December 31, 2017
, included
$0.8 million
of net unrecognized tax benefits which, if recognized, would affect the annual effective income tax rate.
As of
December 31, 2017
, we had
no
accrued interest (
none
as of
December 31, 2016
, and
2015
) related to unrecognized tax benefits included on the Consolidated Balance Sheet due to our NOL carryforwards. We classify interest related to unrecognized tax benefits as interest expense and tax-related penalties in operating expenses on the Consolidated Statement of Income. Interest expense related to unrecognized tax benefits on the Consolidated Statement of Income was
immaterial
in
2017
(
immaterial
in
2016
, and in
2015
). There were
no
penalties recognized in
2017
,
2016
or
2015
. The unrecognized tax benefit amounts have been presented as reductions to the tax benefits associated with NOL and tax credit carryforwards on the Consolidated Balance Sheet.
No
material changes to unrecognized tax benefits are expected during the next 12 months.
ALLETE and its subsidiaries file a consolidated federal income tax return as well as combined and separate state income tax returns in various jurisdictions. ALLETE has no open federal or state audits, and is no longer subject to federal examination for years before 2013 or state examination for years before 2012.
NOTE 14. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Changes in Accumulated Other Comprehensive Loss.
Comprehensive income (loss) is the change in shareholders’ equity during a period from transactions and events from non-owner sources, including net income. The amounts recorded to accumulated other comprehensive loss include unrealized gains and losses on available-for-sale securities, defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits, and gains and losses on derivatives accounted for as cash flow hedges.
ALLETE, Inc. 2017 Form 10-K
124
NOTE 14. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Continued)
Changes in accumulated other comprehensive loss, net of tax, for the years ended
December 31, 2017
,
2016
and
2015
, were as follows:
|
|
|
|
|
|
|
|
|
|
|
Unrealized Gain (Loss) on
Available-for-sale
Securities
|
Defined Benefit
Pension, Other
Postretirement
Items
(a)
|
Gain
(Loss) on
Cash Flow
Hedge
|
Total
|
Millions
|
|
|
|
|
Balance as of December 31, 2014
|
$(0.3)
|
$(20.7)
|
$(0.1)
|
$(21.1)
|
Other Comprehensive Income (Loss) Before Reclassifications
|
(0.4
|
)
|
(4.3
|
)
|
0.1
|
|
(4.6
|
)
|
Amounts Reclassified From Accumulated Other Comprehensive Loss
|
(0.1
|
)
|
1.3
|
|
—
|
|
1.2
|
|
Net Other Comprehensive Income (Loss)
|
(0.5
|
)
|
(3.0
|
)
|
0.1
|
|
(3.4
|
)
|
Balance as of December 31, 2015
|
(0.8
|
)
|
(23.7
|
)
|
—
|
|
(24.5
|
)
|
Other Comprehensive Income (Loss) Before Reclassifications
|
—
|
|
(4.1
|
)
|
—
|
|
(4.1
|
)
|
Amounts Reclassified From Accumulated Other Comprehensive Loss
|
(0.2
|
)
|
0.6
|
|
—
|
|
0.4
|
|
Net Other Comprehensive Income (Loss)
|
(0.2
|
)
|
(3.5
|
)
|
—
|
|
(3.7
|
)
|
Balance as of December 31, 2016
|
(1.0
|
)
|
(27.2
|
)
|
—
|
|
(28.2
|
)
|
Other Comprehensive Income (Loss) Before Reclassifications
|
1.1
|
|
3.9
|
|
—
|
|
5.0
|
|
Amounts Reclassified From Accumulated Other Comprehensive Loss
|
(0.2
|
)
|
0.8
|
|
—
|
|
0.6
|
|
Net Other Comprehensive Income (Loss)
|
0.9
|
|
4.7
|
|
—
|
|
5.6
|
|
Balance as of December 31, 2017
|
$(0.1)
|
$(22.5)
|
—
|
|
$(22.6)
|
|
|
(a)
|
Defined benefit pension and other postretirement items excluded from our Regulated Operations are recognized in accumulated other comprehensive loss and are subsequently reclassified out of accumulated other comprehensive loss as components of net periodic pension and other postretirement benefit expense. (See Note 15. Pension and Other Postretirement Benefit Plans.)
|
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
We have noncontributory union, non-union and combined retiree defined benefit pension plans covering eligible employees. The combined retiree defined benefit pension plan was created in 2016, to include all union and non-union retirees from the existing plans as of January 1, 2016. The plans provide defined benefits based on years of service and final average pay. We contributed
$1.7 million
in cash to the plans in
2017
(
$6.3 million
in
2016
;
none
in
2015
). We also contributed approximately
0.2 million
shares of ALLETE common stock to the plans in
2017
, which had an aggregate value of
$13.5 million
when contributed (
none
in 2016;
none
in 2015). We also have a defined contribution RSOP covering substantially all employees. The
2017
plan year employer contributions, which are made through the employee stock ownership plan portion of the RSOP, totaled
$11.0 million
(
$9.2 million
for the
2016
plan year;
$9.0 million
for the
2015
plan year). (See Note 12. Common Stock and Earnings Per Share and Note 16. Employee Stock and Incentive Plans.)
The non-union defined benefit pension plan does not allow further crediting of service to the plan and is closed to new participants. The Minnesota Power union defined benefit pension plan is also closed to new participants.
ALLETE, Inc. 2017 Form 10-K
125
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
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 require employees to be at least age 55 with 10 years of participation in the plan. In 2014, our postretirement life plan was amended to close the plan to non-union employees retiring after December 31, 2015.
The postretirement health and life plans are contributory with participant contributions adjusted annually. Postretirement health and life benefits are funded through a combination of Voluntary Employee Benefit Association trusts (VEBAs), established under section 501(c)(9) of the Internal Revenue Code, and irrevocable grantor trusts. In
2017
,
no
contributions were made to the VEBAs (
none
in
2016
;
none
in
2015
) and
no
contributions were made to the grantor trusts (
none
in
2016
;
none
in
2015
).
Management considers various factors when making funding decisions such as regulatory requirements, actuarially determined minimum contribution requirements and contributions required to avoid benefit restrictions for the pension plans. Contributions are based on estimates and assumptions which are subject to change. On
January 8, 2018
, we contributed
$15.0 million
in cash to the defined benefit pension plans. We do
not
expect to make any additional contributions to the defined benefit pension plans in
2018
, and we do
not
expect to make any contributions to the defined benefit postretirement health and life plans in
2018
.
Accounting for defined benefit pension and other postretirement benefit plans requires that employers recognize on a prospective basis the funded status of their defined benefit pension and other postretirement plans on their balance sheet and recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.
The defined benefit pension and postretirement health and life benefit expense (credit) recognized annually by our regulated utilities are expected to be recovered (refunded) through rates filed with our regulatory jurisdictions. As a result, these amounts that are required to otherwise be recognized in accumulated other comprehensive income have been recognized as a long-term regulatory asset (regulatory liability) on the Consolidated Balance Sheet, in accordance with the accounting standards for the effect of certain types of regulation applicable to our Regulated Operations. The defined benefit pension and postretirement health and life benefit expense (credits) associated with our other operations are recognized in accumulated other comprehensive income.
|
|
|
|
|
|
|
|
Pension Obligation and Funded Status
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Accumulated Benefit Obligation
|
|
$745.4
|
|
|
$698.8
|
|
Change in Benefit Obligation
|
|
|
|
|
Obligation, Beginning of Year
|
|
$743.3
|
|
|
$709.8
|
|
Service Cost
|
10.2
|
|
8.1
|
|
Interest Cost
|
32.5
|
|
33.2
|
|
Actuarial Loss
|
44.8
|
|
12.4
|
|
Benefits Paid
|
(51.0
|
)
|
(44.5
|
)
|
Participant Contributions
|
13.4
|
|
24.3
|
|
Obligation, End of Year
|
|
$793.2
|
|
|
$743.3
|
|
Change in Plan Assets
|
|
|
|
|
Fair Value, Beginning of Year
|
|
$557.5
|
|
|
$521.3
|
|
Actual Return on Plan Assets
|
91.6
|
|
48.8
|
|
Employer Contribution
(a)
|
30.1
|
|
31.9
|
|
Benefits Paid
|
(51.0
|
)
|
(44.5
|
)
|
Fair Value, End of Year
|
|
$628.2
|
|
|
$557.5
|
|
Funded Status, End of Year
|
$(165.0)
|
$(185.8)
|
|
|
|
Net Pension Amounts Recognized in Consolidated Balance Sheet Consist of:
|
|
|
|
|
Current Liabilities
|
$(1.4)
|
$(1.4)
|
Non-Current Liabilities
|
$(163.6)
|
$(184.4)
|
|
|
(a)
|
Includes Participant Contributions noted above.
|
ALLETE, Inc. 2017 Form 10-K
126
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
The pension costs that are reported as a component within the Consolidated Balance Sheet, reflected in long-term regulatory assets or liabilities and accumulated other comprehensive income, consist of a net loss of
$236.2 million
as of
December 31, 2017
(net loss of
$250.4 million
as of
December 31, 2016
).
|
|
|
|
|
|
Reconciliation of Net Pension Amounts Recognized in Consolidated Balance Sheet
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Net Loss
|
$(236.2)
|
$(250.4)
|
Accumulated Contributions in Excess of Net Periodic Benefit Cost (Prepaid Pension Asset)
|
71.2
|
|
64.6
|
|
Total Net Pension Amounts Recognized in Consolidated Balance Sheet
|
$(165.0)
|
$(185.8)
|
|
|
|
|
|
|
|
|
|
|
|
Components of Net Periodic Pension Cost
|
Year Ended December 31
|
2017
|
|
2016
|
|
2015
|
|
Millions
|
|
|
|
Service Cost
|
|
$10.2
|
|
|
$8.1
|
|
|
$10.1
|
|
Interest Cost
|
32.5
|
|
33.2
|
|
29.9
|
|
Expected Return on Plan Assets
|
(42.4
|
)
|
(43.6
|
)
|
(40.7
|
)
|
Amortization of Loss
|
9.9
|
|
9.5
|
|
17.9
|
|
Amortization of Prior Service Cost
|
—
|
|
—
|
|
0.2
|
|
Net Pension Cost
|
|
$10.2
|
|
|
$7.2
|
|
|
$17.4
|
|
|
|
|
|
|
|
|
Other Changes in Pension Plan Assets and Benefit Obligations Recognized in
Other Comprehensive Income and Regulatory Assets or Liabilities
|
Year Ended December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Net (Gain) Loss
|
$(4.3)
|
|
$7.2
|
|
Amortization of Loss
|
(9.9
|
)
|
(9.5
|
)
|
Total Recognized in Other Comprehensive Income and Regulatory Assets or Liabilities
|
$(14.2)
|
$(2.3)
|
|
|
|
|
|
|
|
|
Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Projected Benefit Obligation
|
|
$793.2
|
|
|
$743.3
|
|
Accumulated Benefit Obligation
|
|
$745.4
|
|
|
$698.8
|
|
Fair Value of Plan Assets
|
|
$628.2
|
|
|
$557.5
|
|
ALLETE, Inc. 2017 Form 10-K
127
NOTE 15. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
|
|
|
|
|
|
|
|
Postretirement Health and Life Obligation and Funded Status
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Change in Benefit Obligation
|
|
|
Obligation, Beginning of Year
|
|
$173.4
|
|
|
$160.2
|
|
Service Cost
|
4.4
|
|
3.9
|
|
Interest Cost
|
7.7
|
|
7.4
|
|
Actuarial Loss
|
15.5
|
|
11.9
|
|
Benefits Paid
|
(12.2
|
)
|
(13.1
|
)
|
Participant Contributions
|
3.1
|
|
3.1
|
|
Plan Amendments
|
(1.8
|
)
|
—
|
|
Obligation, End of Year
|
|
$190.1
|
|
|
$173.4
|
|
Change in Plan Assets
|
|
|
Fair Value, Beginning of Year
|
|
$154.3
|
|
|
$153.4
|
|
Actual Return on Plan Assets
|
24.5
|
|
9.6
|
|
Employer Contribution
|
1.3
|
|
1.3
|
|
Participant Contributions
|
3.1
|
|
3.1
|
|
Benefits Paid
|
(12.2
|
)
|
(13.1
|
)
|
Fair Value, End of Year
|
|
$171.0
|
|
|
$154.3
|
|
Funded Status, End of Year
|
$(19.1)
|
$(19.1)
|
|
|
|
Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet Consist of:
|
|
|
Non-Current Assets
|
$3.0
|
$1.4
|
Current Liabilities
|
$(1.1)
|
$(1.1)
|
Non-Current Liabilities
|
$(21.0)
|
$(19.4)
|
According to the accounting standards for retirement benefits, only assets in the VEBAs are treated as plan assets in the preceding table for the purpose of determining funded status. In addition to the postretirement health and life assets reported in the previous table, we had
$19.2 million
in irrevocable grantor trusts included in Other Investments on the Consolidated Balance Sheet as of
December 31, 2017
(
$17.6 million
as of
December 31, 2016
).
The postretirement health and life costs that are reported as a component within the Consolidated Balance Sheet, reflected in regulatory long-term assets or liabilities and accumulated other comprehensive income, consist of the following:
|
|
|
|
|
|
Unrecognized Postretirement Health and Life Costs
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Net Loss
|
$21.1
|
$19.8
|
Prior Service Credit
|
(4.6
|
)
|
(4.7
|
)
|
Total Unrecognized Postretirement Health and Life Cost
|
$16.5
|
$15.1
|
|
|
|
|
|
|
Reconciliation of Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
|
As of December 31
|
2017
|
|
2016
|
|
Millions
|
|
|
Net Loss
(a)
|
$(21.1)
|
$(19.8)
|
Prior Service Credit
|
4.6
|
|
4.7
|
|
Accumulated Net Periodic Benefit Cost in Excess of Contributions
(a)
|
(2.6
|
)
|
(4.0
|
)
|
Total Net Postretirement Health and Life Amounts Recognized in Consolidated Balance Sheet
|
$(19.1)
|
$(19.1)
|