NOTE 3. ACQUISITIONS (Continued)
2017 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 2018, is reflected in the following table. 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 4. 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.
NOTE 4. GOODWILL AND INTANGIBLE ASSETS
The aggregate carrying amount of goodwill was
$148.5 million
as of
June 30, 2018
, and
$148.3 million
as of
December 31, 2017
.
Balances of intangible assets, net, excluding goodwill as of
June 30, 2018
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2017
|
|
|
Additions
|
|
Amortization
|
|
June 30,
2018
|
|
Millions
|
|
|
|
|
|
|
|
Intangible Assets
|
|
|
|
|
|
|
|
Definite-Lived Intangible Assets
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$54.7
|
|
|
|
$0.2
|
|
|
$(2.1)
|
|
|
$52.8
|
|
Developed Technology and Other
(a)
|
6.3
|
|
|
2.2
|
|
|
(0.6)
|
|
7.9
|
|
Total Definite-Lived Intangible Assets
|
61.0
|
|
|
2.4
|
|
|
(2.7)
|
|
60.7
|
|
Indefinite-Lived Intangible Assets
|
|
|
|
|
|
|
|
Trademarks and Trade Names
|
16.6
|
|
|
—
|
|
|
n/a
|
|
16.6
|
|
Total Intangible Assets
|
|
$77.6
|
|
|
|
$2.4
|
|
|
$(2.7)
|
|
|
$77.3
|
|
|
|
(a)
|
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
6
years). The weighted average remaining useful life of all definite-lived intangible assets as of
June 30, 2018
, is approximately
18
years.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
20
NOTE 4. GOODWILL AND INTANGIBLE ASSETS (Continued)
Amortization expense for intangible assets was
$1.3 million
and
$2.7 million
for the
quarter and six months ended June 30, 2018
, respectively (
$1.4 million
and
$2.8 million
for the
quarter and six months ended June 30, 2017
, respectively). Accumulated amortization was
$17.5 million
as of
June 30, 2018
(
$14.8 million
as of
December 31, 2017
). The estimated amortization expense for definite-lived intangible assets for the remainder of
2018
is
$2.8 million
. Estimated annual amortization expense for definite‑lived intangible assets is
$5.2 million
in
2019
,
$5.0 million
in
2020
,
$4.9 million
in
2021
,
$4.6 million
in
2022
and
$38.2 million
thereafter
.
NOTE 5. 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). Descriptions of the three levels of the fair value hierarchy are discussed in Note 9. Fair Value to the Consolidated Financial Statements in our
2017
Form 10-K.
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
June 30, 2018
, and
December 31, 2017
. 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 June 30, 2018
|
Recurring Fair Value Measures
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
Millions
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
Investments
(a)
|
|
|
|
|
|
|
|
Available-for-sale – Equity Securities
|
|
$12.8
|
|
|
—
|
|
|
—
|
|
|
|
$12.8
|
|
Available-for-sale – Corporate and Governmental Debt Securities
|
—
|
|
|
|
$8.6
|
|
|
—
|
|
|
8.6
|
|
Cash Equivalents
|
1.5
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
Total Fair Value of Assets
|
|
$14.3
|
|
|
|
$8.6
|
|
|
—
|
|
|
|
$22.9
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Deferred Compensation
(b)
|
—
|
|
|
|
$20.5
|
|
|
—
|
|
|
|
$20.5
|
|
U.S. Water Services Contingent Consideration
(c)
|
—
|
|
|
—
|
|
|
|
$5.6
|
|
|
5.6
|
|
Total Fair Value of Liabilities
|
—
|
|
|
|
$20.5
|
|
|
|
$5.6
|
|
|
|
$26.1
|
|
Total Net Fair Value of Assets (Liabilities)
|
|
$14.3
|
|
|
$(11.9)
|
|
$(5.6)
|
|
$(3.2)
|
|
|
(a)
|
Included in Other Investments on the Consolidated Balance Sheet.
|
|
|
(b)
|
Included in Other Non-Current Liabilities on the Consolidated Balance Sheet.
|
|
|
(c)
|
Included in Other Current Liabilities on the Consolidated Balance Sheet.
|
ALLETE, Inc. Second Quarter 2018 Form 10-Q
21
NOTE 5. FAIR VALUE (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
The Level 3 liability in the preceding tables is the result of the 2015 acquisition of U.S. Water Services. Changes in the U.S. Water Services Contingent Consideration can result from modifications to the shareholder agreement, changes in discount rates, timing of milestones that trigger payment, or the timing and amount of earnings estimates. 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
June 30, 2018
. Management analyzes the fair value of the contingent liability on a quarterly basis and makes adjustments as appropriate.
|
|
|
|
|
Recurring Fair Value Measures
|
|
Activity in Level 3
|
|
Millions
|
|
Balance as of December 31, 2017
|
|
$5.4
|
|
Accretion
|
0.2
|
|
Balance as of June 30, 2018
|
|
$5.6
|
|
For the
six months ended June 30, 2018
, and the year ended
December 31, 2017
, 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
|
|
|
|
June 30, 2018
|
$1,528.8
|
|
$1,572.8
|
December 31, 2017
|
$1,513.3
|
|
$1,627.6
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis.
Non-financial assets such as equity method investments, goodwill, intangible assets, land inventory, 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. For the
quarter and six months ended June 30, 2018
, and the
year ended December 31, 2017
, there were
no
triggering events or indicators of impairment for these non-financial assets.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
22
NOTE 6. REGULATORY MATTERS
Regulatory matters are summarized in Note 4. Regulatory Matters to our Consolidated Financial Statements in our
2017
Form 10‑K, with additional disclosure provided in the following paragraphs.
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
$28.0 million
and
$52.1 million
for the quarter and
six months ended June 30, 2018
, respectively (
$24.4 million
and
$48.6 million
for the quarter and
six months ended June 30, 2017
, respectively).
2016 Minnesota General Rate Case.
In November 2016, Minnesota Power filed a retail rate increase request with the MPUC which sought 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 in January 2017.
In February 2017, Minnesota Power filed an additional request to further reduce its requested interim rate increase. In an April 2017 order, 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 in May 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. In an order dated March 12, 2018, the MPUC affirmed determinations made at a hearing on January 18, 2018, 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 are fully offset by the recognition of a corresponding reserve. Minnesota Power has recorded a reserve for an interim rate refund of
$49.2 million
as of
June 30, 2018
(
$32.3 million
as of December 31, 2017). The MPUC also disallowed Minnesota Power’s regulatory asset for deferred fuel adjustment clause costs due to the anticipated adoption of a forward-looking fuel adjustment clause methodology resulting in a
$19.5 million
pre-tax charge to Fuel, Purchased Power and Gas – Utility in the fourth quarter of 2017.
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
in the fourth quarter of 2017.
On April 2, 2018, Minnesota Power filed a petition with the MPUC requesting reconsideration of certain decisions in the MPUC’s order dated March 12, 2018, collectively representing approximately
$20 million
to
$25 million
in additional revenue on an annualized basis. Minnesota Power’s petition included requesting reconsideration of the allowed return on common equity, recovery of the prepaid pension asset in rate base, certain disallowed expenses, and certain transmission revenue adjustments. In an order dated May 29, 2018, the MPUC denied Minnesota Power’s petition for reconsideration and accepted a Minnesota Department of Commerce request for reconsideration reducing the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 while utilizing the benefits of the lower federal income tax rate enacted as part of the TCJA to mitigate the impact on customer rates.
Energy-Intensive Trade-Exposed Customer Rates.
An EITE customer ratemaking law was enacted in 2015, which established a Minnesota energy policy 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 April 2017 order; 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 in October 2017 that modified the April 2017 order. During 2017, Minnesota Power provided discounts of
$8.6 million
that were recorded as a regulatory asset.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
23
NOTE 6. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
In September 2017, Minnesota Power informed its EITE customers that it had suspended the EITE discount due to a concern that it was not revenue and cash flow neutral to Minnesota Power based on an MPUC decision at a hearing in September 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, discounts provided to EITE customers will offset interim rate refund reserves for non-EITE customers. Minnesota Power provided
$3.8 million
and
$8.1 million
of discounts to EITE customers during the quarter and
six months ended June 30, 2018
, respectively (
$3.6 million
and
$5.9 million
for the quarter and
six months ended June 30, 2017
, respectively).
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.
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 August 31, 2021, and through June 30, 2019, respectively. Under the agreement with SWL&P, no termination notice has been given. The other municipal customer provided termination notice for its contract in 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 varying dates ranging from 2024 through 2029 with a majority 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 for certain transmission investments and expenditures. In a 2016 order, the MPUC approved Minnesota Power’s updated customer billing rates allowing 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 for investments and expenditures related to Bison. The cost recovery rider allows Minnesota Power to charge retail customers on a current basis for the costs of 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 a November 2017 order. On June 5, 2018, Minnesota Power made a renewable resources factor filing. Upon approval of the filing, Minnesota Power will be authorized to include updated billing rates on customer bills.
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.
Environmental Improvement Rider
. Minnesota Power has an approved environmental improvement rider 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 provisionally approved by the MPUC in an order dated June 20, 2018, subject to further review by the MPUC.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
24
NOTE 6. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
Fuel Adjustment Clause Reform
. In a December 2017 order, the MPUC adopted a three-year program to implement certain procedural reforms to the Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. The order will change the method of accounting for all Minnesota electric utilities to a monthly budgeted, forward-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 program is expected to begin in 2019.
Tax Cuts and Jobs Act of 2017
. In December 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 March 2, 2018, Minnesota Power submitted an initial filing to the MPUC regarding the impacts of the TCJA on Minnesota Power. As part of Minnesota Power’s rate case, in an order dated May 29, 2018, the MPUC directed Minnesota Power to utilize the benefits of lower federal income tax rates enacted as part of the TCJA to offset a reduction in the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035 that would have otherwise resulted in an increase in customer rates. The treatment of the impact of the TCJA on Minnesota Power’s deferred income tax assets and liabilities is still subject to this regulatory proceeding.
On January 10, 2018, the PSCW opened a docket to review the effects of the TCJA and directed Wisconsin utilities to defer its impacts until further direction was provided by the PSCW. On February 9, 2018, SWL&P filed comments with the PSCW regarding the impacts of the TCJA on SWL&P. In this filing, SWL&P proposed deferring the benefits of the TCJA and incorporating any deferred refunds or credits into its next general rate case.
In an order dated May 24, 2018, the PSCW directed SWL&P to refund the benefits of the lower federal income tax rates enacted as part of the TCJA on customer bills beginning in July 2018. Any changes in deferred income taxes will be adjusted as part of SWL&P’s rate filing. (See
2018 Wisconsin General Rate Case.
)
We have recorded the impact of the remeasurement of deferred income tax assets and liabilities in 2017 resulting from the TCJA for Minnesota Power and SWL&P as regulatory assets and liabilities as the benefits are deferred pending the outcome of regulatory proceedings. Most of the benefits 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 expected to be passed back based upon the outcome of regulatory proceedings. 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 since August 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 2017 were based on a 2012 PSCW retail rate order that provided for a
10.9 percent
return on equity. On an annualized basis, SWL&P expects to collect additional revenue of
$2.5 million
under the 2017 PSCW retail rate order.
2018 Wisconsin General Rate Case.
On May 25, 2018, SWL&P filed a rate increase request with the PSCW requesting an average increase of
2.7 percent
for retail customers (
2.0 percent
increase in electric rates;
2.3 percent
increase in natural gas rates; and
8.3
percent increase in water rates). The filing seeks an overall return on equity of
10.5 percent
and a
55.41 percent
equity ratio. On an annualized basis, this filing is expected to result in additional revenue of approximately
$2.4 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 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 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 2016, Minnesota Power announced Boswell Units 1 and 2 will be retired, which is expected to occur in the fourth quarter of 2018.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
25
NOTE 6. REGULATORY MATTERS (Continued)
Integrated Resource Plan (Continued)
In July 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 are subject to MPUC approval of the construction of NTEC, 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 a September 2017 order, 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 a contested case process. On July 2, 2018, an administrative law judge issued a recommendation that the MPUC deny approval of the NTEC agreements; the recommendation is not binding on the MPUC. On July 23, 2018, Minnesota Power filed exceptions to the administrative law judge’s recommendation. The MPUC is expected to hold a hearing in the fourth quarter of 2018 on NTEC. On June 18, 2018, Minnesota Power filed a separate petition for approval of the PPA for the output of a
10
MW solar energy facility located in central Minnesota.
The MPUC has not taken any action regarding the wind energy PPA which will be refiled separately from the natural gas energy PPA.
Great Northern Transmission Line
.
Minnesota Power is constructing the GNTL, an approximately
220
-mile
500
-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro. 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 a 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 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. To date, most of the right-of-way has been cleared while foundation installation and transmission tower construction have commenced. The 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 non-shareholder contributions to capital. Total project costs of
$248.8 million
have been incurred through
June 30, 2018
, of which
$129.2 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 known as the Manitoba-Minnesota Transmission Project (MMTP) that will connect with the GNTL. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which remains pending. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP. The NEB determined that Manitoba Hydro’s application was complete in December 2017, and held public hearings in June 2018. The NEB is required to make a decision on the MMTP by March 2019, but is not precluded from making a decision prior to that date. Approval of the Canadian federal cabinet is also required.
The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in‑service requirements in PPAs with Minnesota Power, Manitoba Hydro has indicated that it would need to start construction of the MMTP in December 2018. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. Any significant delays in the MMTP construction schedule may result in Minnesota Power adjusting the GNTL construction schedule and impact the timing of capital expenditures and associated cost recovery under our transmission cost recovery rider.
Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be in service by early 2021.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
26
NOTE 6. REGULATORY MATTERS (Continued)
Conservation Improvement Program.
Minnesota requires electric utilities to spend a minimum of
1.5 percent
of gross operating revenues, excluding revenue received from exempt customers, from service provided in the state on energy CIPs each year. On April 2, 2018, Minnesota Power submitted its 2017 CIP consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of
$3.3 million
based upon MPUC procedures. In 2017, the CIP financial incentive of
$5.5 million
was recognized in the second quarter upon approval by the MPUC of Minnesota Power’s 2016 CIP consolidated filing in a June 2017 order. Approval of Minnesota Power’s 2017 CIP consolidated filing and related financial incentive is expected in the third quarter of 2018. CIP financial incentives are recognized in the period in which the MPUC approves the filing.
MISO Return on Equity Complaints.
MISO transmission owners, including ALLETE and ATC, have an authorized return on equity of
10.32 percent
, or
10.82
percent including an incentive adder for participation in a regional transmission organization.
In 2016, a federal administrative law judge ruled on a complaint proposing a 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.
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 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 a February 2017 order, 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 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. Second Quarter 2018 Form 10-Q
27
NOTE 6. REGULATORY MATTERS (Continued)
|
|
|
|
|
|
|
|
|
Regulatory Assets and Liabilities
|
June 30,
2018
|
|
|
December 31,
2017
|
|
Millions
|
|
|
|
Non-Current Regulatory Assets
|
|
|
|
Defined Benefit Pension and Other Postretirement Benefit Plans
|
|
$216.7
|
|
|
|
$220.3
|
|
Income Taxes
|
109.3
|
|
|
112.8
|
|
Asset Retirement Obligations
|
31.0
|
|
|
29.6
|
|
Manufactured Gas Plant
|
8.0
|
|
|
8.1
|
|
PPACA Income Tax Deferral
|
5.0
|
|
|
5.0
|
|
Conservation Improvement Program
|
—
|
|
|
3.3
|
|
Other
|
4.5
|
|
|
5.6
|
|
Total Non-Current Regulatory Assets
|
|
$374.5
|
|
|
|
$384.7
|
|
|
|
|
|
Current Regulatory Liabilities
(a)
|
|
|
|
Provision for Interim Rate Refund
(b)
|
|
$32.5
|
|
|
—
|
|
Provision for Tax Reform Refund
(c)
|
6.7
|
|
|
—
|
|
Total Current Regulatory Liabilities
|
39.2
|
|
|
—
|
|
Non-Current Regulatory Liabilities
|
|
|
|
Income Taxes
|
401.4
|
|
|
|
$411.2
|
|
Wholesale and Retail Contra AFUDC
|
60.2
|
|
|
57.9
|
|
Plant Removal Obligations
|
23.0
|
|
|
20.3
|
|
Cost Recovery Riders
|
16.8
|
|
|
2.2
|
|
North Dakota Investment Tax Credits
|
14.4
|
|
|
14.1
|
|
Provision for Interim Rate Refund
(b)
|
—
|
|
|
23.7
|
|
Other
|
0.2
|
|
|
2.6
|
|
Total Non-Current Regulatory Liabilities
|
516.0
|
|
|
532.0
|
|
Total Regulatory Liabilities
|
|
$555.2
|
|
|
|
$532.0
|
|
|
|
(a)
|
Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet.
|
|
|
(b)
|
This amount is expected to be refunded to Minnesota Power’s regulated retail customers in the first quarter of 2019 and includes
$16.7 million
of discounts provided to EITE customers that will be offset against interim rate refunds as of
June 30, 2018
(
$8.6 million
as of December 31, 2017). (See 2016 Minnesota General Rate Case and Energy-Intensive Trade‑Exposed Customer Rates.)
|
|
|
(c)
|
We have recorded the impact of income tax changes for Minnesota Power and SWL&P resulting from the TCJA in 2018 as regulatory liabilities and a reduction in revenue as the benefits are deferred pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Tax Cuts and Jobs Act of 2017.)
|
NOTE 7. 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 June 30, 2018
, our equity investment in ATC was
$123.6 million
(
$118.7 million
at
December 31, 2017
). In the
first six months of 2018
, we invested
$3.9 million
in ATC, and on
July 31, 2018
, we invested an additional
$1.2 million
. We expect to make additional investments of
$1.3 million
in
2018
.
|
|
|
|
|
ALLETE’s Investment in ATC
|
|
Millions
|
|
Equity Investment Balance as of December 31, 2017
|
|
$118.7
|
|
Cash Investments
|
3.9
|
|
Equity in ATC Earnings
|
9.0
|
|
Distributed ATC Earnings
|
(8.6
|
)
|
Amortization of the Remeasurement of Deferred Income Taxes
(a)
|
0.6
|
|
Equity Investment Balance as of June 30, 2018
|
|
$123.6
|
|
(a) Amortization related to the impact of the remeasurement of deferred income tax assets and liabilities resulting from the TCJA.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
28
NOTE 7. INVESTMENT IN ATC (Continued)
ATC’s authorized return on equity is
10.32 percent
, or
10.82 percent
including an incentive adder for participation in a regional transmission organization.
In 2016, a federal administrative law judge ruled on a complaint proposing a 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.
NOTE 8. SHORT-TERM AND LONG-TERM DEBT
The following tables present the Company’s short-term and long-term debt as of
June 30, 2018
, and
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
Principal
|
|
|
Unamortized Debt Issuance Costs
|
|
Total
|
|
Millions
|
|
|
|
|
|
Short-Term Debt
|
|
$57.1
|
|
|
$(0.4)
|
|
|
$56.7
|
|
Long-Term Debt
|
1,471.7
|
|
|
(9.5)
|
|
1,462.2
|
|
Total Debt
|
|
$1,528.8
|
|
|
$(9.9)
|
|
|
$1,518.9
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
Principal
|
|
|
Unamortized Debt Issuance Costs
|
|
Total
|
|
Millions
|
|
|
|
|
|
Short-Term Debt
|
|
$64.6
|
|
|
$(0.5)
|
|
|
$64.1
|
|
Long-Term Debt
|
1,448.7
|
|
|
(9.5)
|
|
1,439.2
|
|
Total Debt
|
|
$1,513.3
|
|
|
$(10.0)
|
|
|
$1,503.3
|
|
On April 16, 2018, ALLETE issued and sold
$60.0 million
of its First Mortgage Bonds (the Bonds) that bear interest at
4.07
percent. The Bonds will mature in April 2048 and pay interest 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. ALLETE intends to use the proceeds from the sale of the Bonds to fund utility capital investment 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.
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
June 30, 2018
, 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
June 30, 2018
, ALLETE was in compliance with its financial covenants.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
29
NOTE 9. INCOME TAX EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Millions
|
|
|
|
|
|
|
|
|
Current Income Tax Expense (Benefit)
(a)
|
|
|
|
|
|
|
|
|
Federal
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
State
|
|
$(0.3)
|
|
|
$0.1
|
|
|
|
$0.4
|
|
|
$0.2
|
Total Current Income Tax Expense (Benefit)
|
|
$(0.3)
|
|
|
$0.1
|
|
|
|
$0.4
|
|
|
$0.2
|
Deferred Income Tax Expense (Benefit)
|
|
|
|
|
|
|
|
|
Federal
(b)
|
|
$(7.4)
|
|
|
$3.8
|
|
|
$(14.2)
|
|
|
$11.1
|
|
State
|
|
2.4
|
|
|
3.6
|
|
|
5.0
|
|
|
9.5
|
|
Investment Tax Credit Amortization
|
|
(0.1
|
)
|
|
(0.2
|
)
|
|
(0.3
|
)
|
|
(0.4
|
)
|
Total Deferred Income Tax Expense (Benefit)
|
|
$(5.1)
|
|
|
$7.2
|
|
|
$(9.5)
|
|
|
$20.2
|
|
Total Income Tax Expense (Benefit)
|
|
$(5.4)
|
|
|
$7.3
|
|
|
$(9.1)
|
|
|
$20.4
|
|
|
|
(a)
|
For the quarter and
six months ended June 30, 2018, and 2017
, the federal and state current tax expense was minimal due to NOLs which resulted from the bonus depreciation provisions of the Protecting Americans from Tax Hikes Act of 2015, the Tax Increase Prevention Act of 2014 and the American Taxpayer Relief Act of 2012.
|
|
|
(b)
|
For the quarter and
six months ended June 30, 2018
, the federal tax benefit is primarily due to the reduction of the federal statutory tax rate from
35 percent
to
21 percent
enacted as part of the TCJA, and production tax credits.
|
The Company's tax provision for interim periods is determined using an estimate of its annual effective tax rate, adjusted for discrete items arising in that quarter. In each quarter, the Company updates its estimate of the annual effective tax rate, and if the estimated annual effective tax rate changes, the Company would make a cumulative adjustment in that quarter.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
Six Months Ended
|
Reconciliation of Taxes from Federal Statutory
|
June 30,
|
June 30,
|
Rate to Total Income Tax Expense
|
2018
|
|
2017
|
2018
|
|
2017
|
Millions
|
|
|
|
|
|
|
Income Before Non-Controlling Interest and Income Taxes
|
|
$25.9
|
|
|
|
$44.2
|
|
|
$73.2
|
|
|
|
$106.3
|
|
Statutory Federal Income Tax Rate
|
21
|
%
|
|
35
|
%
|
21
|
%
|
|
35
|
%
|
Income Taxes Computed at Statutory Federal Rate
|
|
$5.4
|
|
|
|
$15.5
|
|
|
$15.4
|
|
|
|
$37.2
|
|
Increase (Decrease) in Income Tax Due to:
|
|
|
|
|
|
|
State Income Taxes – Net of Federal Income Tax Benefit
|
1.6
|
|
|
2.4
|
|
4.2
|
|
|
6.3
|
|
Production Tax Credits
|
(11.2
|
)
|
|
(10.0
|
)
|
(25.6
|
)
|
|
(23.0
|
)
|
Other
|
(1.2
|
)
|
|
(0.6
|
)
|
(3.1
|
)
|
|
(0.1
|
)
|
Total Income Tax Expense (Benefit)
|
$(5.4)
|
|
|
$7.3
|
|
$(9.1)
|
|
|
$20.4
|
|
For the
six months ended June 30, 2018
, the effective tax rate was a benefit of
12.4 percent
(expense of
19.2 percent
for the
six months ended June 30, 2017
).
Uncertain Tax Positions.
As of
June 30, 2018
, we had gross unrecognized tax benefits of
$1.7 million
(
$1.7 million
as of
December 31, 2017
). Of the total gross unrecognized tax benefits,
$0.8 million
represents the amount of unrecognized tax benefits included on the Consolidated Balance Sheet that, if recognized, would favorably impact the effective income tax rate. 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.
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 2014, or state examination for years before 2013.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
30
NOTE 10. RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE 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 debt securities and defined benefit pension and other postretirement items, consisting of deferred actuarial gains or losses and prior service costs or credits.
For the
quarter and six months ended June 30, 2018
, and
2017
, reclassifications out of accumulated other comprehensive loss for the Company were not material. Changes in accumulated other comprehensive loss for the
six months ended June 30, 2018
, are presented on the Consolidated Statement of Shareholders’ Equity.
NOTE 11. EARNINGS PER SHARE AND COMMON STOCK
We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. The difference between basic and diluted earnings per share, if any, arises from outstanding stock options, non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan. For the quarter and
six months ended June 30, 2018, and 2017
,
no
options to purchase shares of ALLETE common stock were excluded from the computation of diluted earnings per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
2017
|
|
|
Reconciliation of Basic and Diluted
|
|
|
Dilutive
|
|
|
|
|
|
Dilutive
|
|
|
Earnings Per Share
|
Basic
|
|
Securities
|
|
Diluted
|
|
Basic
|
|
Securities
|
|
Diluted
|
Millions Except Per Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
Quarter ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$31.3
|
|
|
|
|
|
$31.3
|
|
|
|
$36.9
|
|
|
|
|
|
$36.9
|
|
Average Common Shares
|
51.3
|
|
|
0.2
|
|
|
51.5
|
|
|
50.9
|
|
|
0.2
|
|
|
51.1
|
|
Earnings Per Share
|
|
$0.61
|
|
|
|
|
|
$0.61
|
|
|
|
$0.73
|
|
|
|
|
|
$0.72
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$82.3
|
|
|
|
|
|
$82.3
|
|
|
|
$85.9
|
|
|
|
|
|
$85.9
|
|
Average Common Shares
|
51.2
|
|
|
0.2
|
|
|
51.4
|
|
|
50.5
|
|
|
0.2
|
|
|
50.7
|
|
Earnings Per Share
|
|
$1.61
|
|
|
|
|
|
$1.60
|
|
|
|
$1.70
|
|
|
|
|
|
$1.69
|
|
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
|
|
Other
Postretirement
|
Components of Net Periodic Benefit Cost
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Millions
|
|
|
|
|
|
|
|
Quarter Ended June 30,
|
|
|
|
|
|
|
|
Service Cost
|
|
$2.8
|
|
|
|
$2.6
|
|
|
|
$1.3
|
|
|
|
$1.1
|
|
Non-Service Cost Components
(a)
|
|
|
|
|
|
|
|
Interest Cost
|
7.4
|
|
|
8.2
|
|
|
1.8
|
|
|
1.9
|
|
Expected Return on Plan Assets
|
(11.1
|
)
|
|
(10.6
|
)
|
|
(2.8
|
)
|
|
(2.7
|
)
|
Amortization of Prior Service Credits
|
—
|
|
|
—
|
|
|
(0.5
|
)
|
|
(0.5
|
)
|
Amortization of Net Loss
|
3.0
|
|
|
2.4
|
|
|
0.2
|
|
|
0.1
|
|
Net Periodic Benefit Cost (Income)
|
|
$2.1
|
|
|
|
$2.6
|
|
|
—
|
|
|
$(0.1)
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
Service Cost
|
|
$5.5
|
|
|
|
$5.1
|
|
|
|
$2.5
|
|
|
|
$2.2
|
|
Non-Service Cost Components
(a)
|
|
|
|
|
|
|
|
Interest Cost
|
14.8
|
|
|
16.3
|
|
|
3.6
|
|
|
3.8
|
|
Expected Return on Plan Assets
|
(22.1
|
)
|
|
(21.2
|
)
|
|
(5.5
|
)
|
|
(5.3
|
)
|
Amortization of Prior Service Credits
|
—
|
|
|
—
|
|
|
(0.9
|
)
|
|
(1.0
|
)
|
Amortization of Net Loss
|
6.0
|
|
|
4.9
|
|
|
0.4
|
|
|
0.2
|
|
Net Periodic Benefit Cost (Income)
|
|
$4.2
|
|
|
|
$5.1
|
|
|
|
$0.1
|
|
|
$(0.1)
|
|
|
(a)
|
These components of net periodic benefit cost are included in the line item “Other” under Other Income (Expense) on the Consolidated Statement of Income.
|
ALLETE, Inc. Second Quarter 2018 Form 10-Q
31
NOTE 12. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS (Continued)
Employer Contributions.
For the
six months ended June 30, 2018
, we contributed
$15.0 million
in cash to the defined benefit pension plans (
$1.7 million
in cash and
$13.5 million
in ALLETE common stock for the
six months ended June 30, 2017
); we do
not
expect to make additional contributions to our defined benefit pension plans in
2018
. For the
six months ended June 30, 2018, and 2017
, we made
no
contributions to our other postretirement benefit plans; we do
not
expect to make any contributions to our other postretirement benefit plans in
2018
.
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES
Power Purchase Agreements.
Our long-term PPAs have been evaluated under the accounting guidance for variable interest entities. We have determined that either we have no variable interest in the PPAs or, where we do have variable interests, we are not the primary beneficiary; therefore, consolidation is not required. These conclusions are based on the fact that we do not have both control over activities that are most significant to the entity and an obligation to absorb losses or receive benefits from the entity’s performance. Our financial exposure relating to these PPAs is limited to our capacity and energy payments.
Our PPAs are summarized in Note 11. Commitments, Guarantees and Contingencies to our Consolidated Financial Statements in our
2017
Form 10-K, with additional disclosure provided in the following paragraphs.
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. (See
Minnkota Power PSA
.) Square Butte’s costs consist primarily of debt service, operating and maintenance, depreciation and fuel expenses.
As of June 30, 2018
, Square Butte had total debt outstanding of
$311.4 million
. 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 the
six months ended June 30, 2018
, was
$37.7 million
(
$40.7 million
for the
six months ended June 30, 2017
). 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
$4.6 million
(
$4.7 million
for the same period in
2017
). Minnesota Power’s payments to Square Butte are approved as a purchased power expense for ratemaking purposes by both the MPUC and the FERC.
Minnkota Power PSA.
Minnesota Power has a PSA with Minnkota Power, which commenced in 2014. Under the PSA, 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
2018
and in
2017
.
Oconto Electric Cooperative PSA.
On March 6, 2018, Minnesota Power entered into a PSA with Oconto Electric Cooperative. The contract begins in January 2019 and is effective through May 2026. Under the PSA, Minnesota Power expects to provide approximately
25
MW of energy and capacity at fixed prices.
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 estimated minimum payments under these supply and transportation agreements is
$16.7 million
for the remainder of
2018
,
$1.7 million
in
2019
, and none thereafter. 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 by 2024. The aggregate amount of minimum lease payments for all operating leases is
$7.1 million
for the remainder of
2018
,
$12.8 million
in
2019
,
$9.5 million
in
2020
,
$7.3 million
in
2021
,
$6.1 million
in
2022
and
$30.0 million
thereafter.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
32
NOTE 13. 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 is constructing the GNTL, an approximately
220
‑mile
500
-kV transmission line between Manitoba and Minnesota’s Iron Range that was proposed by Minnesota Power and Manitoba Hydro in order to strengthen the electric grid, enhance regional reliability and promote a greater exchange of sustainable energy.
In 2015, a certificate of need was approved by the MPUC. Based on this approval, Minnesota Power’s portion of the investments and expenditures for the project are eligible for cost recovery under its existing transmission cost recovery rider and are anticipated to be included in future transmission cost recovery filings. (See Note 6. 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 a 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 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. To date, most of the right-of-way has been cleared while foundation installation and transmission tower construction have commenced. The 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 non-shareholder contributions to capital. Total project costs of
$248.8 million
have been incurred through
June 30, 2018
, of which
$129.2 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 known as the Manitoba-Minnesota Transmission Project (MMTP) that will connect with the GNTL. In 2015, Manitoba Hydro submitted the final preferred route and EIS for the MMTP to the Manitoba Conservation and Water Stewardship for siting and environmental approval, which remains pending. In 2016, Manitoba Hydro filed an application with the Canadian National Energy Board (NEB) requesting authorization to construct and operate the MMTP. The NEB determined that Manitoba Hydro’s application was complete in December 2017, and held public hearings in June 2018. The NEB is required to make a decision on the MMTP by March 2019, but is not precluded from making a decision prior to that date. Approval of the Canadian federal cabinet is also required.
The MMTP is subject to legal and regulatory challenges which Minnesota Power is actively monitoring. Manitoba Hydro has informed Minnesota Power that it continues to work towards completing the MMTP on schedule. In order to meet the transmission in‑service requirements in PPAs with Minnesota Power, Manitoba Hydro has indicated that it would need to start construction of the MMTP in December 2018. We are unable to predict the outcome of the Canadian regulatory review process, including the timing thereof or whether any onerous conditions may be imposed, or the timing of the completion of the MMTP, including the impact of any delays that may result in construction schedule adjustments. Any significant delays in the MMTP construction schedule may result in Minnesota Power adjusting the GNTL construction schedule and impact the timing of capital expenditures and associated cost recovery under our transmission cost recovery rider.
Construction of Manitoba Hydro’s Keeyask hydroelectric generation facility, which will provide the power to be sold under PPAs with Minnesota Power and transmitted on the MMTP and the GNTL, commenced in 2014 and is anticipated to be 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 been promulgated by both the EPA and state authorities over the past several years. Minnesota Power’s facilities are subject to additional requirements under many of these regulations. Minnesota Power is reshaping its generation portfolio, over time, to reduce its reliance on coal, has installed cost-effective emission control technology, and advocates for sound science and policy during rulemaking implementation.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
33
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
We consider our businesses to be in substantial compliance with currently applicable environmental regulations and believe all necessary permits have been obtained. We anticipate that with many state and federal environmental regulations and requirements finalized, or to be finalized in the near future, potential expenditures for future environmental matters may be material and 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.
New Source Review (NSR).
In 2014, Minnesota Power reached a settlement with the EPA and entered into a Consent Decree regarding certain Notices of Violation received in 2008 and 2011 that asserted violations of the NSR requirements of the Clean Air Act, which was approved by the U.S. District Court for the District of Minnesota. 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 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 but does require facilities have sufficient allowances to cover their emissions on an annual basis. These allowances are allocated to facilities from each state’s annual budget, and can be bought and sold. Based on our review of the 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.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
34
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
National Ambient Air Quality Standards (NAAQS).
The EPA is required to review the NAAQS every five years. If the EPA determines that a state’s air quality is not in compliance with the NAAQS, the state is required to adopt plans describing how it will reduce emissions to attain the NAAQS. Four NAAQS have either recently been revised or are currently proposed for revision, as described below.
|
|
•
|
Ozone NAAQS.
All areas of Minnesota currently meet the new standard based on the most recent available ambient monitoring data; however, some areas in the metropolitan Twin Cities and southwest 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 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
. In July 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.
|
|
|
•
|
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 required facilities have federally-enforceable permit limits at which the one-hour SO
2
NAAQS compliance was modeled by January 2017. Taconite Harbor was issued an amended air permit in 2016, containing the new modeling limits at that facility. The MPCA did not meet the January 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 June 8, 2018, the EPA formally proposed in the Federal Register to retain 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.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
35
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
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 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 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In 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.
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 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. In October 2017, the EPA issued a notice of proposed rulemaking, proposing to repeal the CPP. In December 2017, an Advanced Notice of Proposed Rulemaking for a CPP replacement rule was published in the Federal Register.
Minnesota Power is currently evaluating the CPP rescission and recent proposal 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 6. 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 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 apply to the following facilities: Boswell, Taconite Harbor, Laskin, Rapids Energy Center, Hibbard Renewable Energy Center and portions of the DC transmission line that runs from Center, North Dakota, to Duluth, Minnesota. 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.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
36
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
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. In September 2017, the EPA announced a two-year postponement of the ELG compliance date of November 1, 2018, to November 1, 2020, while the agency reconsiders the bottom ash transport water and FGD wastewater provisions.
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 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 re-use. Minnesota Power would seek recovery of additional costs through a rate proceeding.
Solid and Hazardous Waste.
The Resource Conservation and Recovery Act of 1976 regulates the management and disposal of solid and hazardous wastes. We are required to notify the EPA of hazardous waste activity and, consequently, routinely submit reports to the EPA.
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, 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 15 years and be between approximately
$65 million
and
$100 million
. The EPA has indicated to Minnesota Power that the Taconite Harbor landfill, which has been idled and has a temporary landfill cover in place, 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. 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.
Minnesota Power continues to work on minimizing costs through evaluation of beneficial re-use and recycling of CCR and CCR‑related waters. In September 2017, the EPA announced its intention to formally reconsider the CCR rule under Subtitle D of the RCRA and on March 15, 2018, published the first phase of the proposed rule revisions in the Federal Register. On July 17, 2018, the EPA finalized revisions to elements of the CCR rule, including extending certain deadlines by two years, the establishment of alternative groundwater protection standards for certain constituents and the potential for risk‑based management options at facilities based on site characteristics.
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
June 30, 2018
, we have recorded a liability of approximately
$7 million
for remediation costs at this site (approximately
$8 million
as of December 31, 2017), and an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expect to incur these costs over the next four years.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
37
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
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
June 30, 2018
, ALLETE Clean Energy has
$16.2 million
outstanding in standby letters of credit.
U.S. Water Services.
As of
June 30, 2018
, U.S. Water Services has
no
outstanding standby letters of credit.
BNI Energy.
As of
June 30, 2018
, 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
June 30, 2018
, 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.
Community Development District Obligations.
As of
June 30, 2018
, we owned
70 percent
of the assessable land in the Town Center District (
70 percent
as of
December 31, 2017
) and
27 percent
of the assessable land in the Palm Coast Park District (
33
percent as of
December 31, 2017
). As of
June 30, 2018
, ownership levels, our annual assessments related to capital improvement and special assessment bonds for the ALLETE Properties projects within these districts are approximately
$1.4 million
for Town Center at Palm Coast and
$0.6 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.
U.S. Water Services is involved in on-going patent defense litigation it brought against a company for infringement of
two
patents held by U.S. Water Services. As of June 30, 2018, U.S. Water Services has recognized approximately
$2 million
of patent defense costs as an intangible asset. Management expects that U.S. Water Services will prevail, but in the event of an unfavorable outcome, the patent defense costs would be recognized as an expense in the period of resolution.
NOTE 14. BUSINESS SEGMENTS
We present three reportable segments: Regulated Operations, ALLETE Clean Energy and U.S. Water Services. We measure performance of our operations through budgeting and monitoring of contributions to consolidated net income by each business segment.
Regulated Operations includes
three
operating segments which consist of our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC. ALLETE Clean Energy is our business focused on developing, acquiring and operating clean and renewable energy projects. U.S. Water Services is our integrated water management company. The ALLETE Clean Energy and U.S. Water Services reportable segments comprise our Energy Infrastructure and Related Services businesses. We also present Corporate and Other which includes
two
operating segments, BNI Energy, our coal mining operations in North Dakota, and ALLETE Properties, our legacy Florida real estate investment, along with other business development and corporate expenditures, unallocated interest expense, a small amount of non-rate base generation, approximately
4,000
acres of land in Minnesota, and earnings on cash and investments.
ALLETE, Inc. Second Quarter 2018 Form 10-Q
38
NOTE 14. BUSINESS SEGMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Six Months Ended
|
|
June 30,
|
|
June 30,
|
|
2018
|
2017
|
|
2018
|
2017
|
Millions
|
|
|
|
|
|
Operating Revenue
(a)
|
|
|
|
|
|
Regulated Operations
|
|
|
|
|
|
Residential
|
|
$30.7
|
|
|
$27.6
|
|
|
|
$71.4
|
|
|
$67.1
|
|
Commercial
|
36.2
|
|
33.7
|
|
|
72.8
|
|
71.9
|
|
Municipal
|
13.7
|
|
12.3
|
|
|
27.7
|
|
30.5
|
|
Industrial
|
115.3
|
|
121.6
|
|
|
230.2
|
|
243.3
|
|
Other Power Suppliers
|
42.7
|
|
41.7
|
|
|
86.4
|
|
82.9
|
|
CIP Financial Incentive
(b)
|
—
|
|
5.5
|
|
|
—
|
|
5.5
|
|
Other
|
19.2
|
|
22.5
|
|
|
39.5
|
|
45.3
|
|
Total Regulated Operations
|
257.8
|
|
264.9
|
|
|
528.0
|
|
546.5
|
|
|
|
|
|
|
|
Energy Infrastructure and Related Services
|
|
|
|
|
|
|
|
|
|
|
|
ALLETE Clean Energy
|
|
|
|
|
|
Long-term PSA
|
12.4
|
|
13.7
|
|
|
31.0
|
|
31.5
|
|
Other
|
5.9
|
|
5.9
|
|
|
11.9
|
|
11.8
|
|
Total ALLETE Clean Energy
|
18.3
|
|
19.6
|
|
|
42.9
|
|
43.3
|
|
|
|
|
|
|
|
U.S. Water Services
|
|
|
|
|
|
Point-in-Time
|
25.7
|
|
23.9
|
|
|
48.0
|
|
45.7
|
|
Contract
|
9.5
|
|
8.8
|
|
|
19.0
|
|
17.7
|
|
Capital Project
|
6.3
|
|
5.7
|
|
|
12.7
|
|
7.1
|
|
Total U.S. Water Services
|
41.5
|
|
38.4
|
|
|
79.7
|
|
70.5
|
|
|
|
|
|
|
|
Corporate and Other
|
|
|
|
|
|
|
|
Long-term Contract
|
22.7
|
|
23.2
|
|
|
42.7
|
|
45.3
|
|
Other
|
3.8
|
|
7.2
|
|
|
9.0
|
|
13.3
|
|
Total Corporate and Other
|
26.5
|
|
30.4
|
|
|
51.7
|
|
58.6
|
|
Total Operating Revenue
|
|
$344.1
|
|
|
$353.3
|
|
|
|
$702.3
|
|
|
$718.9
|
|
Net Income (Loss)
|
|
|
|
|
|
Regulated Operations
|
|
$26.0
|
|
|
$32.4
|
|
|
|
$69.9
|
|
|
$75.9
|
|
|
|
|
|
|
|
Energy Infrastructure and Related Services
|
|
|
|
|
|
ALLETE Clean Energy
|
6.8
|
|
3.8
|
|
|
14.9
|
|
10.5
|
|
U.S. Water Services
|
0.2
|
|
0.6
|
|
|
(1.2
|
)
|
0.3
|
|
|
|
|
|
|
|
Corporate and Other
|
(1.7
|
)
|
0.1
|
|
|
(1.3
|
)
|
(0.8
|
)
|
Total Net Income
|
|
$31.3
|
|
|
$36.9
|
|
|
|
$82.3
|
|
|
$85.9
|
|
|
|
(a)
|
With the adoption of new revenue recognition guidance, the Company has enhanced the presentation of business segment Operating Revenue. (See Note 1. Operations and Significant Accounting Policies.)
|
|
|
(b)
|
See Note 6. Regulatory Matters.
|
ALLETE, Inc. Second Quarter 2018 Form 10-Q
39
NOTE 14. BUSINESS SEGMENTS (Continued)
|
|
|
|
|
|
|
|
|
June 30,
2018
|
|
December 31,
2017
|
|
Millions
|
|
|
Assets
|
|
|
Regulated Operations
|
|
$3,898.2
|
|
|
$3,886.6
|
|
|
|
|
Energy Infrastructure and Related Services
|
|
|
ALLETE Clean Energy
|
620.2
|
|
600.5
|
|
U.S. Water Services
|
291.8
|
|
292.4
|
|
|
|
|
Corporate and Other
|
304.5
|
|
300.5
|
|
Total Assets
|
|
$5,114.7
|
|
|
$5,080.0
|
|