Statements in this report that are not statements of historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there can be no assurance that the expected results will be achieved. Any statements that express, or involve discussions as to, future expectations, risks, beliefs, plans, objectives, assumptions, events, uncertainties, financial performance, or growth strategies (often, but not always, through the use of words or phrases such as “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” “projects,” “likely,” “will continue,” “could,” “may,” “potential,” “target,” “outlook” or words of similar meaning) are not statements of historical facts and may be forward-looking.
In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause our actual results to differ materially from those indicated in forward-looking statements made by or on behalf of ALLETE in this Form 10-Q, in presentations, on our website, in response to questions or otherwise. These statements are qualified in their entirety by reference to, and are accompanied by, the following important factors, in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements that could cause our actual results to differ materially from those indicated in the forward-looking statements:
the outcome of legal and administrative proceedings (whether civil or criminal) and settlements;
changes in operating expenses and capital expenditures and our ability to raise revenues from our customers in regulated rates or salescontract price increases at our Energy Infrastructure and Related Services and other businesses;
federal and state regulatory and legislative actions that impact regulated utility economics, including our allowed rates of return, capital structure, ability to secure financing, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities and utility infrastructure, recovery of purchased power, capital investments and other expenses, including present or prospective environmental matters;
effects of competition, including competition for retail and wholesale customers;
the impacts on our Regulated Operations segment of climate change and future regulation to restrict the emissions of GHG;
effects of increased deployment of distributed low-carbon electricity generation resources;
the impacts of laws and regulations related to renewable and distributed generation;
pricing, availability and transportation of fuel and other commodities and the ability to recover the costs of such commodities;
our current and potential industrial and municipal customers’ ability to execute announced expansion plans;
real estate market conditions where our legacy Florida real estate investment is located may not improve;
the success of efforts to realize value from, invest in, and develop new opportunities in, our Energy Infrastructure and Related Services businesses; and
factors affecting our Energy Infrastructure and Related Services businesses, including fluctuations in the volume of customer orders, unanticipated cost increases, changes in legislation and regulations impacting the industries in which the customers served operate, the effects of weather, creditworthiness of customers, ability to obtain materials required to perform services, and changing market conditions.
Additional disclosures regarding factors that could cause our results or performance to differ from those anticipated by this report are discussed in Part I, Item 1A. Risk Factors of ALLETE’s 20172018 Form 10-K, and in Part II, Item 1A. Risk Factors in this Form 10‑Q.10-K. Any forward‑lookingforward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the businesses of ALLETE or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. Readers are urged to carefully review and consider the various disclosures made by ALLETE in this Form 10-Q and in other reports filed with the SEC that attempt to identify the risks and uncertainties that may affect ALLETE’s business.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
The accompanying notes are an integral part of these statements.
ALLETE
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
Unaudited
|
| | | | | | | | | | | | | |
| | Quarter Ended | | Six Months Ended |
| | June 30, | | June 30, |
| | 2019 | 2018 | | 2019 | 2018 |
| Millions Except Per Share Amounts | | | | | |
| Common Stock | | | | | |
| Balance, Beginning of Period |
| $1,431.1 |
|
| $1,407.4 |
| |
| $1,428.5 |
|
| $1,401.4 |
|
| Common Stock Issued | 2.2 |
| 8.0 |
| | 4.8 |
| 14.0 |
|
| Balance, End of Period | 1,433.3 |
| 1,415.4 |
| | 1,433.3 |
| 1,415.4 |
|
| | | | | | |
| Accumulated Other Comprehensive Loss | | | | | |
| Balance, Beginning of Period | (27.2 | ) | (27.9 | ) | | (27.3 | ) | (28.2 | ) |
| Other Comprehensive Income - Net of Income Taxes | | | | | |
| Unrealized Gain (Loss) on Debt Securities | 0.1 |
| — |
| | 0.2 |
| (0.1 | ) |
| Defined Benefit Pension and Other Postretirement Plans | 0.2 |
| 0.3 |
| | 0.2 |
| 0.7 |
|
| Balance, End of Period | (26.9 | ) | (27.6 | ) | | (26.9 | ) | (27.6 | ) |
| | | | | | |
| Retained Earnings | | | | | |
| Balance, Beginning of Period | 794.8 |
| 717.8 |
| | 754.6 |
| 695.5 |
|
| Net Income | 34.2 |
| 31.3 |
| | 104.7 |
| 82.3 |
|
| Common Stock Dividends | (30.4 | ) | (28.7 | ) | | (60.7 | ) | (57.4 | ) |
| Balance, End of Period | 798.6 |
| 720.4 |
| | 798.6 |
| 720.4 |
|
| | | | | | |
| Total Shareholders’ Equity |
| $2,205.0 |
|
| $2,108.2 |
| |
| $2,205.0 |
|
| $2,108.2 |
|
| | | | | | |
| Dividends Per Share of Common Stock |
| $0.5875 |
|
| $0.56 |
| |
| $1.175 |
|
| $1.12 |
|
|
| | | | | | | | | | | |
| | Total Shareholders’ Equity | Retained Earnings | Accumulated Other Comprehensive Loss | Common Stock |
| Millions | | | | |
| Balance as of December 31, 2017 |
| $2,068.2 |
|
| $689.4 |
| $(22.6) |
| $1,401.4 |
|
Adjustments to Opening Balance – Net of Income Taxes (a) | 0.5 |
| 6.1 |
| (5.6 | ) | — |
|
| Balance as of January 1, 2018 | 2,068.7 |
| 695.5 |
| (28.2 | ) | 1,401.4 |
|
| Comprehensive Income | | | | |
| Net Income | 82.3 |
| 82.3 |
| — |
| — |
|
| Other Comprehensive Income – Net of Income Taxes | | | | |
| Unrealized Loss on Debt Securities | (0.1 | ) | — |
| (0.1 | ) | — |
|
| Defined Benefit Pension and Other Postretirement Plans | 0.7 |
| — |
| 0.7 |
| — |
|
| Total Comprehensive Income | 82.9 |
| | | |
| Common Stock Issued | 14.0 |
| — |
| — |
| 14.0 |
|
| Dividends Declared | (57.4 | ) | (57.4 | ) | — |
| — |
|
| Balance as of June 30, 2018 |
| $2,108.2 |
|
| $720.4 |
| $(27.6) |
| $1,415.4 |
|
| |
(a) | Reflects the impacts associated with the adoption of accounting standards concerning Financial Instruments, Revenue from Contracts with Customers and the Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. (See Note 1. Operations and Significant Accounting Policies.) |
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – UNAUDITED
The accompanying unaudited Consolidated Financial Statements have been prepared in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X, and do not include all of the information and notes required by GAAP for complete financial statements. Similarly, the December 31, 20172018, Consolidated Balance Sheet was derived from audited financial statements, but does not include all disclosures required by GAAP. In management’s opinion, these unaudited financial statements include all adjustments necessary for a fair statement of financial results. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Operating results for the six months ended June 30, 2018,2019, are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 20182019. For further information, refer to the Consolidated Financial Statements and notes included in our 20172018 Form 10-K.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
Cash, Cash Equivalents and Restricted Cash. We consider all investments purchased with original maturities of three months or less to be cash equivalents. RestrictedAs of June 30, 2019, restricted cash amounts included in Prepayments and Other on the Consolidated Balance Sheet include collateral deposits required under an ALLETE Clean Energy loan agreement andagreement. In prior periods presented, the amounts also include U.S. Water Service’sServices' standby letters of credit. The restricted cash amounts included in Other Non-Current Assets represent collateral deposits required under an ALLETE Clean Energy loan agreement and PSAs, andPSAs. In prior periods presented, the amounts also include deposits from a SWL&P customer in aid of future capital expenditures. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheet that aggregate to the amountamounts presented in the Consolidated Statement of Cash Flows. During the first quarter of 2018, the Company updated the presentation of its Consolidated Statement of Cash Flows to include restricted cash 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. (See Recently Adopted Pronouncements -Statement of Cash Flows: Restricted Cash.)
|
| | | | | | | | | | | | | | | |
| Cash, Cash Equivalents and Restricted Cash | June 30,
2019 |
| | December 31,
2018 |
| | June 30,
2018 |
| | December 31,
2017 |
|
| Millions | | | | | | | |
| Cash and Cash Equivalents |
| $203.1 |
| |
| $69.1 |
| |
| $121.9 |
| |
| $98.9 |
|
| Restricted Cash included in Prepayments and Other | 0.9 |
| | 1.3 |
| | 2.3 |
| | 2.6 |
|
| Restricted Cash included in Other Non-Current Assets | 2.6 |
| | 8.6 |
| | 8.6 |
| | 8.6 |
|
| Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows |
| $206.6 |
| |
| $79.0 |
| |
| $132.8 |
| |
| $110.1 |
|
|
| | | | | | | | | | | | | | | |
| Cash, Cash Equivalents and Restricted Cash | June 30,
2018 |
| | December 31,
2017 |
| | June 30,
2017 |
| | December 31,
2016 |
|
| Millions | | | | | | | |
| Cash and Cash Equivalents |
| $121.9 |
| |
| $98.9 |
| |
| $84.2 |
| |
| $27.5 |
|
| Restricted Cash included in Prepayments and Other | 2.3 |
| | 2.6 |
| | 3.7 |
| | 2.2 |
|
| Restricted Cash included in Other Non-Current Assets | 8.6 |
| | 8.6 |
| | 8.6 |
| | 8.6 |
|
| Cash, Cash Equivalents and Restricted Cash on the Consolidated Statement of Cash Flows |
| $132.8 |
| |
| $110.1 |
| |
| $96.5 |
| |
| $38.3 |
|
Inventories – Net. Inventories are stated at the lower of cost or net realizable value. Inventories in our Regulated Operations segment are carried at an average cost or first-in, first-out basis. Inventories in our U.S. Water Services and ALLETE Clean Energy segments,segment and Corporate and Other businesses are carried at an average cost, first-in, first-out or specific identification basis.
|
| | | | | | | |
| Inventories – Net | June 30,
2019 |
| | December 31,
2018 |
|
| Millions | | | |
Fuel (a) |
| $33.4 |
| |
| $26.0 |
|
| Materials and Supplies | 44.8 |
| | 44.2 |
|
Raw Materials (b) | — |
| | 2.8 |
|
Work in Progress (b) | — |
| | 6.1 |
|
Finished Goods (b) | — |
| | 8.4 |
|
Reserve for Obsolescence (b) | — |
| | (0.8 | ) |
| Total Inventories – Net |
| $78.2 |
| |
| $86.7 |
|
|
| | | | | | | |
| Inventories – Net | June 30,
2018 |
| | December 31,
2017 |
|
| Millions | | | |
Fuel (a) |
| $31.4 |
| |
| $34.8 |
|
| Materials and Supplies | 44.3 |
| | 46.5 |
|
Construction of Wind Energy Facility (b) | 54.1 |
| | — |
|
| Raw Materials | 3.0 |
| | 2.8 |
|
| Work in Progress | 4.4 |
| | 4.2 |
|
| Finished Goods | 9.1 |
| | 8.3 |
|
| Reserve for Obsolescence | (0.9 | ) | | (0.7 | ) |
| Total Inventories – Net |
| $145.4 |
| |
| $95.9 |
|
| |
| (a) | Fuel consists primarily of coal inventory at Minnesota Power. |
| |
| (b) | On February 28, 2018, Montana-Dakota Utilities exercised its option to purchaseMarch 26, 2019, ALLETE completed the Thunder Spirit II wind energy facility upon completion, resultingsale of U.S. Water Services which resulted in a reclassificationthe removal of the project costsrelated inventory items from Property, Plant and Equipment – Net to Inventories – Net as ALLETE Clean Energy will not own the facility upon completion.Consolidated Balance Sheet. |
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
|
| | | | | | | |
| Other Non-Current Assets | June 30,
2019 |
| | December 31,
2018 |
|
| Millions | | | |
Contract Assets (a) |
| $29.2 |
| |
| $30.7 |
|
Finance Receivable (b) | — |
| | 10.4 |
|
Operating Lease Right-of-use Assets (c) | 31.2 |
| | — |
|
| ALLETE Properties | 22.6 |
| | 24.4 |
|
| Other | 80.8 |
| | 86.9 |
|
| Total Other Non-Current Assets |
| $163.8 |
| |
| $152.4 |
|
|
| | | | | | | |
| Other Non-Current Assets | June 30,
2018 |
| | December 31,
2017 |
|
| Millions | | | |
Contract Assets (a) |
| $30.9 |
| |
| $31.6 |
|
| Finance Receivable | 10.9 |
| | 11.0 |
|
| Other | 63.2 |
| | 65.1 |
|
| Total Other Non-Current Assets |
| $105.0 |
| |
| $107.7 |
|
| |
| (a) | Contract Assets includeconsist of payments made to customers as an incentive to execute or extend service agreements. The contract payments are being amortized over the term of the respective agreements as a reduction to revenue. |
| |
| (b) | Finance Receivable related to the 2016 sale of Ormond Crossings and Lake Swamp, which was collected in the second quarter of 2019. |
|
| | | | | | | |
| Other Current Liabilities | June 30,
2019 |
| | December 31,
2018 |
|
| Millions | | | |
Provision for Interim Rate Refund (a) | — |
| |
| $40.0 |
|
| PSAs |
| $12.4 |
| | 12.6 |
|
Contract Liabilities (b) | — |
| | 7.6 |
|
Provision for Tax Reform Refund (c) | 0.4 |
| | 10.7 |
|
Contingent Consideration (d) | — |
| | 3.8 |
|
Operating Lease Liabilities (e) | 7.2 |
| | — |
|
| Other | 39.5 |
| | 53.8 |
|
| Total Other Current Liabilities |
| $59.5 |
| |
| $128.5 |
|
|
| | | | | | | |
| Other Current Liabilities | June 30,
2018 |
| | December 31,
2017 |
|
| Millions | | | |
Provision for Interim Rate Refund (a) |
| $32.5 |
| | — |
|
Contract Liabilities (b) | 24.3 |
| |
| $8.7 |
|
| PSAs | 18.4 |
| | 24.5 |
|
Provision for Tax Reform Refund (c) | 6.7 |
| | — |
|
Contingent Consideration (d) | 5.6 |
| | — |
|
| Other | 41.0 |
| | 50.0 |
|
| Total Other Current Liabilities |
| $128.5 |
| |
| $83.2 |
|
| |
| (a) | Provision for Interim Rate Refund is expected to bewas refunded to Minnesota Power’s regulated retail customers in the firstsecond 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 Note 6. Regulatory Matters.)2019. |
| |
| (b) | Contract Liabilities includeconsist of deposits received as a result of entering into contracts with our customers prior to completing our performance obligations. |
| |
| (c) | Provision for Tax Reform Refund is deferred as a regulatory liability pendingrelated to the outcomeincome tax benefits of regulatory proceedings with the MPUCTCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and PSCW. (See Note 6. Regulatory Matters.)will be refunded to SWL&P customers in 2019 and 2020. |
| |
| (d) | Contingent Consideration relatesrelated to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 5. Fair Value.)acquisition was paid in the first quarter of 2019. |
|
| | | | | | | |
| Other Non-Current Liabilities | June 30,
2019 |
| | December 31,
2018 |
|
| Millions | | | |
| Asset Retirement Obligation |
| $142.7 |
| |
| $138.6 |
|
| PSAs | 70.7 |
| | 76.9 |
|
Operating Lease Liabilities (a) | 24.0 |
| | — |
|
| Other | 45.4 |
| | 47.1 |
|
| Total Other Non-Current Liabilities |
| $282.8 |
| |
| $262.6 |
|
|
| | | | | | | |
| Other Non-Current Liabilities | June 30,
2018 |
| | December 31,
2017 |
|
| Millions | | | |
| Asset Retirement Obligation |
| $143.2 |
| |
| $122.7 |
|
| PSAs | 83.1 |
| | 89.5 |
|
Contingent Consideration (a) | — |
| | 5.4 |
|
| Other | 48.1 |
| | 49.5 |
|
| Total Other Non-Current Liabilities |
| $274.4 |
| |
| $267.1 |
|
| |
| (a) | Contingent Consideration relates to the estimated fair value of the earnings-based payment resulting from the U.S. Water Services acquisition. (See Note 5. Fair Value.)See Leases. |
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Supplemental Statement of Cash Flows Information.
|
| | | | | | | |
| Six Months Ended June 30, | 2019 |
| | 2018 |
|
| Millions | | | |
| Cash Paid for Interest – Net of Amounts Capitalized |
| $33.8 |
| |
| $33.0 |
|
| Noncash Investing and Financing Activities | |
| | |
|
| Increase (Decrease) in Accounts Payable for Capital Additions to Property, Plant and Equipment | $21.1 | | $(39.4) |
Reclassification of Property, Plant and Equipment to Inventory (a) | — |
| |
| $46.3 |
|
Recognition of Right-of-use Assets and Lease Liabilities (b) | $31.2 | | — |
|
| Capitalized Asset Retirement Costs |
| $1.4 |
| |
| $20.8 |
|
| AFUDC–Equity |
| $1.3 |
| |
| $0.5 |
|
|
| | | | | | | |
| Six Months Ended June 30, | 2018 |
| | 2017 |
|
| Millions | | | |
| Cash Paid for Interest – Net of Amounts Capitalized |
| $33.0 |
| |
| $32.5 |
|
| Noncash Investing and Financing Activities | |
| | |
|
| Decrease in Accounts Payable for Capital Additions to Property, Plant and Equipment | $(39.4) | | $(0.4) |
Reclassification of Property, Plant and Equipment to Inventory (a) |
| $46.3 |
| | — |
|
| Capitalized Asset Retirement Costs |
| $20.8 |
| |
| $19.7 |
|
| AFUDC–Equity |
| $0.5 |
| |
| $0.4 |
|
| ALLETE Common Stock Contributed to the Pension Plans | — |
| |
| $13.5 |
|
| |
| (a) | OnIn February 28, 2018, Montana-Dakota Utilities exercised its option to purchase the Thunder Spirit II wind energy facility upon completion, resulting in a reclassification of the project costs from Property, Plant and Equipment – Net to Inventories – Net as ALLETE Clean Energy will not ownfor project costs incurred in the facility upon completion.prior year. |
Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the date of the financial statements issuance.
Revenue.
Contracts with Customers – Utility includes sales from our regulated operations for generation, transmission and distribution of electric service, and distribution of water and gas services to our customers. Also included is an immaterial amount of regulated steam generation that is used by customers in the production of paper and pulp.
Contracts with Customers – Non-utility includes sales of goods and services to customers from ALLETE Clean Energy, U.S. Water Services and our Corporate and Other businesses.
Other – Non-utility is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices for PSAs that were assumed during the acquisition of various wind energy facilities.
Revenue Recognition
Revenue is recognized upon transfer of control of promised goods or services to our customers in an amount that reflects the consideration we expect to receive in exchange for those products or services. Revenue is recognized net of allowance for returns and any taxes collected from customers, which are subsequently remitted to the appropriate governmental authorities. We account for shipping and handling activities that occur after the customer obtains control of goods as a cost rather than an additional performance obligation thereby recognizing revenue at time of shipment and accruing shipping and handling costs when control transfers to our customers. We have a right to consideration from our customers in an amount that corresponds directly with the value to the customer for our performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.
Nature of Revenue Streams
Utility
Residential and Commercial includes sales for electric, gas or water service to customers, who have implied contracts with the utility, under rates governed by the MPUC, PSCW or FERC. Customers are billed on a monthly cycle basis and revenue is recognized for electric, gas or water service delivered during the billing period. Revenue is accrued for service provided but not yet billed at period end. Performance obligations with these customers are satisfied at time of delivery to customer meters and simultaneously consumed.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue (Continued)
Municipal includes sales to 16 non-affiliated municipal customers in Minnesota under long-term wholesale electric contracts. All wholesale electric contracts include a termination clause requiring a three-year notice to terminate. These contracts have termination dates ranging from 2019 through at least 2032, with a majority of contracts effective through at least 2024. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon municipal substation or meter.
Industrial includes sales recognized from contracts with customers in the taconite mining, iron concentrate, paper, pulp and secondary wood products, pipeline and other industries. Industrial sales accounted for approximately 49 percent of total regulated utility kWh sales for the six months ended June 30, 2018. Within industrial revenue, Minnesota Power has 9 Large Power Customer contracts, each serving requirements of 10 MW or more of customer load. These contracts automatically renew past the contract term unless a four-year advanced written notice is given. Large Power Customer contracts have earliest termination dates ranging from 2022 through 2026. We satisfy our performance obligations for these customers at the time energy is delivered to an agreed upon customer substation. Revenue is accrued for energy provided but not yet billed at period end. Based on current contracts with industrial customers, we expect to recognize minimum revenue for the fixed contract components of approximately $70 million per annum through 2019, $50 million in 2020 and 2021, $30 million in 2022 and $30 million for aggregate years thereafter, which reflects the termination notice period in these contracts. When determining minimum revenue, we assume that customer contracts will continue under the contract renewal provision; however, if long-term contracts are renegotiated and subsequently approved by the MPUC or there are changes within our industrial customer class, these amounts may be impacted. Contracts with customers that contain variable pricing or quantity components are excluded from the expected minimum revenue amounts.
Other Power Suppliers includes the sale of energy under long-term PSAs with two customers as well as MISO market and liquidation sales. Expiration dates of these PSAs range from 2020 through 2026. Performance obligations with these customers are satisfied at the time energy is delivered to an agreed upon delivery point defined in the contract (generally the MISO pricing node). Based on current contracts with two customers, we expect to recognize minimum revenue for fixed contract components of approximately $10 million per annum through 2019. Other power supplier contracts that extend beyond 2020 contain variable pricing components that prevent us from estimating future minimum revenue, and therefore are not included.
Other Revenue includes all remaining individually immaterial revenue streams for Minnesota Power and SWL&P, and is comprised of steam sales to paper and pulp mills, wheeling revenue and other sources. Revenue for steam sales to customers is recognized at the time steam is delivered and simultaneously consumed. Revenue is recognized at the time each performance obligation is satisfied.
Alternative Programs includes revenue that is driven by factors outside of our regulated entities’ control or as a result of the achievement of certain objectives, such as CIP financial incentives. This revenue is accounted for in accordance with the accounting standards for alternative revenue programs which allow for the recognition of revenue under an alternative revenue program if the program is established by an order from the utility’s regulatory commission, the order allows for automatic adjustment of future rates, the amount of revenue recognized is objectively determinable and probable of recovery, and the revenue will be collected within 24 months following the end of the annual period in which it is recognized. CIP financial incentives are recognized in the period in which the MPUC approves the filing, which is typically mid-year.
Non-utility
ALLETE Clean Energy
Long-term PSA revenue includes all sales recognized under long-term contracts for production, curtailment, capacity and associated renewable energy credits from ALLETE Clean Energy wind energy facilities. Expiration dates of these PSAs range from 2018 through 2032. Performance obligations for these contracts are satisfied at the time energy is delivered to an agreed upon point, or production is curtailed at the request of the customer, at specified prices. Revenue from the sale of renewable energy credits is recognized at the same time the related energy is delivered to the customer when sold to the same party.
Other is the non-cash adjustments to revenue recognized by ALLETE Clean Energy for the amortization of differences between contract prices and estimated market prices on assumed PSAs. As part of wind energy facility acquisitions, ALLETE Clean Energy assumed various PSAs that were above or below estimated market prices at the time of acquisition; the resulting differences between contract prices and estimated market prices are amortized to revenue over the remaining PSA term.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue (Continued)
U.S. Water Services
Point-in-time revenue is recognized for purchases by customers for chemicals, consumable equipment (e.g. filters, pumps and valves) or related maintenance and repair services as the customer’s usage and needs change over time. These goods and services are purchased on an as-needed basis by the customers and therefore revenue can be variable. Products are shipped to the customer in accordance with the terms of the purchase order, and performance obligations are satisfied at the time of shipment of goods or when services are rendered to the customer.
Contract includes monthly revenue from contracts with customers to provide chemicals, consumable equipment and services to meet customer needs during the contract period. As agreed with the customer, a fixed amount is invoiced based on the goods and services to be provided under the contract. The duration of these contracts generally range in length from three months to five years and automatically renew. A 30-day notice is required to terminate such contracts without penalty after contract execution. Performance obligations are satisfied during the period as goods and service are delivered in accordance with the terms of the contract.
Capital Project includes the sale of equipment and other components assembled to create a water treatment system for the customer. These projects are provided under contracts at an agreed upon price to meet a customer's specifications and typically take less than one year to complete. In general, progress payments are received throughout the project period and are recorded as contract liabilities until performance obligations are satisfied at the time the equipment and other components are delivered to the customer’s site.
Corporate and Other
Long-term Contract encompasses the sale and delivery of coal to customer generation facilities. Revenue is recognized on a monthly basis at the cost of production plus a specified profit per ton of coal delivered to the customer. Coal sales are secured under long-term coal supply agreements extending through 2037. Performance obligations are satisfied during the period as coal is delivered to customer generation facilities.
Other primarily includes revenue from BNI Energy unrelated to coal, the sale of real estate from ALLETE Properties, and non‑rate base steam generation that is sold for use during production of paper and pulp. Performance obligations are satisfied when control transfers to the customer.
Payment Terms
Payment terms and conditions vary across our businesses. Aside from taconite-producing Large Power Customers, payment terms generally require payment to be made within 15 to 30 days from the end of the period that the service has been rendered or goods provided. In the case of its taconite-producing Large Power Customers, as permitted by the MPUC, Minnesota Power requires weekly payments for electric usage based on monthly energy usage estimates. These customers receive estimated bills based on Minnesota Power’s estimate of the customers’ energy usage, forecasted energy prices and fuel adjustment clause estimates. Minnesota Power’s taconite-producing Large Power Customers have generally predictable energy usage on a weekly basis and any differences that occur are trued-up the following month. Due to the timing difference of revenue recognition from the timing of invoicing and payment, the customer receives credit for the time value of money; however, we have determined that our contracts do not include a significant financing component as the period between when we transfer the service to the customer and when they pay for such service is minimal.
Assets Recognized From the Costs to Obtain a Contract with a Customer
We recognize as an asset the incremental costs of obtaining a contract with a customer if we expect the benefit of those costs to be longer than one year. We expense incremental costs when the asset that would have resulted from capitalizing these costs would have been amortized in one year or less. As of June 30, 2018, we have $30.9 million of assets recognized for costs incurred to obtain contracts with our customers ($31.6 million as of December 31, 2017). Management determined the amount of costs to be recognized as assets based on actual costs incurred and paid to obtain and fulfill these contracts to provide goods and services to our customers. Assets recognized to obtain contracts are amortized on a straight-line basis over the contract term as a non-cash reduction to revenue. For the six months ended June 30, 2018, and 2017, we recognized $1.3 million of non-cash amortization.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements.
Recently Adopted Pronouncements
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.Disclosure Update and Simplification. In FebruaryNovember 2018, the FASB issued an update allowingSEC adopted amendments to certain disclosure requirements. The amendments adopted include requirements that interim financial statements should include comparative statements for the same period in the prior financial year, except that the requirement for comparative balance sheet information may be satisfied by presenting the year-end balance sheet. It further includes a one-time reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting fromrequirement analyzing the enactmentchanges in each caption of shareholders’ equity either separately in a note or on the face of the TCJA. With the enactment of the new federal tax rates in 2017, entitiesfinancial statement. These amendments were required to adjust deferred tax assets and liabilities to reflect the lower federal rate with the effect of this reduction impacting income from continuing operations in the period of enactment, even in instances where the related income tax effects of items were originally recognized in other comprehensive income. As such, companies were left with stranded tax effects in accumulated other comprehensive income that did not reflect the appropriate tax rate. This guidance is effective for ALLETE in the first quarter of 2019 with early adoption permitted. The Company elected to early adopt this guidance in the first quarter of 2018 which resulted in a reduction of $5.7 million to Accumulated Other Comprehensive Loss and a corresponding increase to Retained Earnings for the reclassification of the stranded income tax effects.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In March 2017, the FASB issued an accounting standard update to improve2019. We have included the presentation of net periodic pension and postretirement benefit costs. Under the guidance, an entity is required to 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 on a prospective basis. The other components of net periodic expense must be presented separately from the line item that includes the service cost and must be excluded from the operating income subtotal. The Company adopted the guidance in the first quarter of 2018 and retrospectively adjusted the presentation of the service cost component and the other components of net periodic costs in the Consolidatedour Statement of Income. The retrospective adjustments for the quarter and six months ended June 30, 2017, were as follows: Operating and Maintenance increased $1.0 million and $2.1 million, respectively, Cost of Sales – Non-utility remained unchanged and decreased $0.1 million, respectively, resulting in an increase of $1.0 million and $2.0 million, respectivelyShareholders’ Equity to Other Income (Expense) – Other. There was no impact to net income as a result of adoption.meet these requirements.
Financial Instruments.Leases. In 2016, the FASB issued an accounting standard update which requires entities to measure equity 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 update was adopted by the Company in the first quarter of 2018 which resulted in a cumulative-effect transition adjustment reducing Retained Earnings by $0.1 million, including the tax effect, for the previously unrealized loss on available-for-sale equity securities in Accumulated Other Comprehensive Loss as of December 31, 2017.
Classification of Certain Cash Receipts and Cash Payments. In 2016, the FASB issued an accounting standard update which addressed 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. The amendments of this update were adopted by the Company in the first quarter of 2018. There was no impact to the Consolidated Statement of Cash Flows as a result of adoption.
Statement of Cash Flows: Restricted Cash. In 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 guidance update was adopted by the Company in the first quarter of 2018 and was applied retrospectively to the periods presented in the Consolidated Statement of Cash Flows which resulted in a net increase in cash from financing activities of $1.5 million for the six months ended June 30, 2017. Additional disclosure, including a reconciliation of the beginning-of-period and end-of-period cash on hand to the statement of cash flows, is included in this note. (See Cash, Cash Equivalents and Restricted Cash.)
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
New Accounting Pronouncements (Continued)
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 to in exchange for those goods or services. The guidance 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 regarding customer contracts, significant judgments and changes in those judgments, and the assets recognized from the costs to obtain or fulfill a contract are required. The Company adopted this accounting guidance in the first quarter of 2018 and elected to apply the modified retrospective method of adoption to all contracts as of the date of initial application. The financial impact to the consolidated financial statements as a result of adoption of the new standard is immaterial. Based on the nature of the contracts with our customers and our related performance obligations which transfer control, a $0.5 million after-tax cumulative‑effect transition adjustment was made to increase the opening balance of Retained Earnings. We have included additional disclosures in the notes to the consolidated financial statements including additional information on the Company’s revenue streams and related performance obligations required to be satisfied in order to recognize revenue. (See Revenue Recognition.)
Practical Expedients
The following practical expedients were used by the Company as part of the adoption of the new revenue recognition guidance:
We have a right to consideration from our customers in an amount that corresponds directly with the value to such customer for performance completed to date; therefore, we may recognize revenue in the amount to which we have a right to invoice.
We do not adjust the promised amount of consideration for the effects of a significant financing component as at contract inception we expect that the period between when we transfer a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
Where applicable, we adopted this guidance using the portfolio approach in which contracts that have similar characteristics were reviewed as a portfolio. The effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying the guidance to each individual contract.
We recognize the incremental costs of obtaining a contract as an expense when incurred if the amortization period of the asset that would otherwise have been recognized is one year or less.
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.
Leases. In 2016, the FASB issued an accounting standard update which revisesrevised the existing guidance for leases. Under the revised guidance, lessees will beare required to recognize a “right-of-use” assetright-of-use assets and a lease liabilityliabilities on the Consolidated Balance Sheet for all leases with a termterms greater than 12 months. The new standard also requires additional quantitativequalitative and qualitativequantitative 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 areis not expected to significantly change as a result of the new guidance. We expect to make approximately $80 million in minimum lease payments due in future years (undiscounted). The revisedCompany adopted this guidance is effective for the Company beginning in the first quarter of 2019 with earlyusing the optional transition method and the package of practical expedients, which allowed for the adoption permitted. We are currently evaluating the impact of the revisedstandard as of January 1, 2019, without restating previously disclosed information. Management elected the optional transition method of adoption due to the overall immateriality of the balance sheet gross up in the period of adoption. The package of practical expedients allowed management to not reassess the lease guidanceclassification for leases, including those that had expired during the periods presented or that still existed at the time of adoption. We have included additional disclosures in the notes to the consolidated financial statements. (See Leases.)
Leases. We determine if a contract is, or contains, a lease at inception and recognize a right-of-use asset and lease liability for all leases with a term greater than 12 months. Our right-of-use assets and lease liabilities for operating leases are included in Other Non-Current Assets, Other Current Liabilities and Other Non-Current Liabilities, respectively, in our Consolidated Balance Sheet. We currently do not have any finance leases.
Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease right-of-use assets and lease liabilities are recognized at the commencement date based on the estimated present value of lease payments over the lease term. As our leases do not provide an explicit rate, we determine the present value of future lease payments based on our Consolidated Financial Statements.estimated incremental borrowing rate using information available at the lease commencement date. The operating lease right-of-use asset includes lease payments to be made during the lease term and any lease incentives, as applicable.
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Leases (Continued)
Income Taxes. Under SEC Staff Accounting Bulletin 118 (SAB 118),
Our leases may include options to extend or buy out the lease at certain points throughout the term, and if it is reasonably certain that we will exercise that option at lease commencement, we include those rental payments in our calculation of the right-of-use asset and lease liability. Lease and rent expense is recognized on a straight-line basis over the lease term. Leases with a term of 12 months or less are not recognized on the Consolidated Balance Sheet.
The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which was issued in December 2017, companies are allowed up to one year to complete the required analyseswe group into two categories: Vehicles and accountingEquipment; and Land and Other. Our largest operating lease is for the TCJA. SAB 118 requires companies to disclosedragline at BNI Energy which tax positions are considered complete, which tax positions are considered provisional and which tax provisions reflect prior law. At December 31, 2017, we were reasonably able to estimateincludes a termination payment at the effectsend of the TCJA,lease term if we do not exercise our purchase option. The amount of this payment is $3 million and therefore recorded provisional amounts associated with the changes under the TCJA. The provisional amounts incorporate assumptions made based upon the Company’s interpretationis included in our calculation of the TCJA,right-of-use asset and may changelease liability recorded. None of our other leases contain residual value guarantees.
Additional information on the components of lease cost and presentation of cash flows were as follows:
|
| | | | | | | |
| | Quarter Ended | | Six Months Ended |
| | June 30, | | June 30, |
| | 2019 | | 2019 |
| Millions | | | |
| Operating Lease Cost |
| $2.8 |
| |
| $5.7 |
|
| | | | |
| Other Information: | | | |
| Operating Cash Flows From Operating Leases |
| $2.8 |
| |
| $5.7 |
|
Additional information related to leases was as follows: |
| | | |
| June 30, |
|
| 2019 |
|
| Millions | |
| Balance Sheet Information Related to Leases: | |
| Other Non-Current Assets |
| $31.2 |
|
| Total Operating Lease Right-of-use Assets |
| $31.2 |
|
| |
| Other Current Liabilities |
| $7.2 |
|
| Other Non-Current Liabilities | 24.0 |
|
| Total Operating Lease Liabilities |
| $31.2 |
|
| |
| Weighted Average Remaining Lease Term (Years): | |
| Operating Leases - Vehicles and Equipment | 4 |
|
| Operating Leases - Land and Other | 29 |
|
| |
| Weighted Average Discount Rate: | |
| Operating Leases - Vehicles and Equipment | 3.2 | % |
| Operating Leases - Land and Other | 4.5 | % |
NOTE 1. OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES (Continued)
Leases (Continued)
Maturities of lease liabilities were as follows:
|
| | | |
| | June 30, 2019 |
|
| Millions | |
| 2019 |
| $4.2 |
|
| 2020 | 7.9 |
|
| 2021 | 6.1 |
|
| 2022 | 4.9 |
|
| 2023 | 3.1 |
|
| Thereafter | 9.4 |
|
| Total Lease Payments Due | 35.6 |
|
| Less: Imputed Interest | 4.4 |
|
| Total Lease Obligations | 31.2 |
|
| Less: Current Lease Obligations | 7.2 |
|
| Long-term Lease Obligations |
| $24.0 |
|
Sale of U.S. Water Services. On February 8, 2019, the Company receives additional clarificationentered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million. On March 26, 2019, ALLETE completed the sale and implementation guidance. We have not made any adjustmentsreceived approximately $265 million in cash at closing, net of transaction costs and cash retained. The Company recognized a gain on the sale of U.S. Water Services of $11.1 million after-tax in 2019.
ALLETE Clean Energy Asset Acquisition. On May 3, 2019, ALLETE Clean Energy acquired the Diamond Spring wind project in Oklahoma from Apex Clean Energy. ALLETE Clean Energy will build, own and operate the approximately 300 MW wind energy facility. The Diamond Spring wind project is fully contracted to our accountingsell wind power to Walmart Inc., Smithfield Foods, Inc. and Starbucks Corporation under long-term power sales agreements. Construction is expected to begin in late 2019 and be completed in the second half of 2020.
Subsequent Events. The Company performed an evaluation of subsequent events for potential recognition and disclosure through the date althoughof the accounting is still considered provisional while we complete our analysis. Any adjustments recorded to the provisional amounts in 2018 will be included in income from operations as an adjustment to income tax expense.financial statements issuance.
NOTE 2. INVESTMENTSREGULATORY MATTERS
Investments. As of June 30,Regulatory matters are summarized in Note 4. Regulatory Matters to the Consolidated Financial Statements in our 2018 Form 10‑K, with additional disclosure provided in 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 equivalentsfollowing paragraphs.
Electric Rates. Entities within these plans and other assets consisting primarily of land in Minnesota.
|
| | | | | | | |
| Other Investments | June 30,
2018 |
| | December 31,
2017 |
|
| Millions | | | |
| ALLETE Properties |
| $25.9 |
| |
| $26.4 |
|
Available-for-sale Securities (a) | 21.4 |
| | 19.1 |
|
| Cash Equivalents | 1.5 |
| | 3.8 |
|
| Other | 3.7 |
| | 3.8 |
|
| Total Other Investments |
| $52.5 |
| |
| $53.1 |
|
| |
(a) | As of June 30, 2018, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $1.1 million, in one year to less than three years was $3.9 million, in three years to less than five years was $2.5 million and in five or more years was $1.1 million. |
Available-for-Sale Securities.We accountour Regulated Operations segment file for our available-for-sale securities portfolio in accordanceperiodic rate revisions with the guidanceMPUC, PSCW or FERC. As authorized by the MPUC, Minnesota Power also recognizes revenue under cost recovery riders for certaintransmission, renewable, and environmental 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 for the quarter and six months ended June 30, 2018, and 2017.
NOTE 3. ACQUISITIONS
The following acquisition is 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 acquisitionsexpenditures. Revenue from cost recovery riders was not significant, either individually or in the aggregate, to the results of the Company$17.4 million for the six months ended June 30, 2019 ($52.1 million for six months ended June 30, 2018). With the implementation of final rates in Minnesota Power’s general rate case, certain revenue previously recognized under cost recovery riders was incorporated into base rates. (See 2016 Minnesota General Rate Case.)
2016 Minnesota General Rate Case. The MPUC issued an order dated March 12, 2018, in Minnesota Power’s general rate case approving a return on common equity of 9.25 percent and 2017.a 53.81 percent equity ratio. Final rates went into effect on December 1, 2018, which is expected to result in additional revenue of approximately $13 million on an annualized basis. Interim rates were collected from January 1, 2017, through November 30, 2018, which were fully offset by the recognition of a corresponding reserve. Minnesota Power recorded a reserve for an interim rate refund, net of discounts provided to EITE customers, of $40.0 million as of December 31, 2018, which was refunded in the second quarter of 2019.
Tonka Water.
NOTE 2. REGULATORY MATTERS (Continued)
Electric Rates (Continued)
2018 Wisconsin General Rate Case. In September 2017, U.S. Water Services acquired 100an order dated December 20, 2018, the PSCW approved a rate increase for SWL&P including a return on equity of 10.4 percent and a 55.0 percent equity ratio. Final rates went into effect January 1, 2019, which is expected to result in additional revenue of Tonka Water. Total considerationapproximately $1.3 million on an annualized basis.
Transmission Cost Recovery Rider. Minnesota Power has an approved cost recovery rider in place 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 transaction was $19.2 million, includingcosts of constructing certain transmission facilities plus a working capital adjustment. Consideration of $19.0 million was paid in cashreturn on the acquisition datecapital invested. On July 9, 2019, Minnesota Power filed a petition seeking MPUC approval to update the customer billing factor to include investments made for the GNTL.
Fuel Adjustment Clause Reform. In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power. With this order, the method of accounting for all Minnesota electric utilities changed to a working capitalmonthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On May 1, 2019, Minnesota Power filed its fuel adjustment forecast for 2020 with the MPUC.
Integrated Resource Plan.In a 2016 order, the MPUC approved Minnesota Power’s 2015 IRP with modifications. The order accepted Minnesota Power’s plans for the economic idling of $0.2 million was paidTaconite Harbor Units 1 and 2 and the ceasing of coal-fired operations at Taconite Harbor in 2020, 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 requests for proposal for additional wind, solar and demand response resource additions. Minnesota Power retired Boswell Units 1 and 2 in the fourth quarter of 2017. Tonka Water2018. Minnesota Power’s next IRP filing is due October 1, 2020.
In 2017, Minnesota Power submitted a supplierresource package to the MPUC requesting approval of municipalPPAs for the output of a 250 MW wind energy facility and industrial water treatment systemsa 10 MW solar energy facility as well as approval of a 250 MW natural gas capacity dedication agreement. The natural gas capacity dedication agreement was 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 an order dated January 24, 2019, the MPUC approved Minnesota Power’s request for approval of the NTEC natural gas capacity dedication agreement. Separately, the MPUC required a baseload retirement evaluation in Minnesota Power’s next IRP filing analyzing its existing fleet, including potential early retirement scenarios of Boswell Units 3 and 4, as well as a securitization plan. On January 8, 2019, an application for a certificate of public convenience and necessity for NTEC was submitted to the PSCW. A decision on the application is expected in 2020.
Conservation Improvement Program. On April 1, 2019, Minnesota Power submitted its 2018 consolidated filing, which detailed Minnesota Power’s CIP program results and requested a CIP financial incentive of $2.8 million based upon MPUC procedures, which was approved by the MPUC in an order dated July 19, 2019. In 2018, the CIP financial incentive of $3.0 million was recognized in the third quarter upon approval by the MPUC of Minnesota Power’s 2017 CIP consolidated filing. CIP financial incentives are recognized in the period in which the MPUC approves the filing.
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. With the exception of the regulatory asset for Boswell Units 1 and 2 net plant and equipment, no other regulatory assets are currently earning a return. The recovery, refund or credit to rates for these regulatory assets and liabilities will expand U.S. Water Services’ geographic and customer markets.occur over the periods either specified by the applicable regulatory authority or over the corresponding period related to the asset or liability.
NOTE 2. REGULATORY MATTERS (Continued)
|
| | | | | | | |
| Regulatory Assets and Liabilities | June 30,
2019 |
| | December 31,
2018 |
|
| Millions | | | |
| Non-Current Regulatory Assets | | | |
| Defined Benefit Pension and Other Postretirement Benefit Plans |
| $216.5 |
| |
| $218.5 |
|
| Income Taxes | 102.2 |
| | 105.5 |
|
| Asset Retirement Obligations | 32.3 |
| | 32.6 |
|
| Boswell 1 and 2 Net Plant and Equipment | 13.5 |
| | 16.3 |
|
| Cost Recovery Riders | 10.0 |
| | — |
|
Manufactured Gas Plant | 8.1 |
| | 8.0 |
|
| PPACA Income Tax Deferral | 4.9 |
| | 5.0 |
|
| Other | 3.7 |
| | 3.6 |
|
| Total Non-Current Regulatory Assets |
| $391.2 |
| |
| $389.5 |
|
| | | | |
Current Regulatory Liabilities (a) | | | |
Provision for Interim Rate Refund (b) | — |
| |
| $40.0 |
|
| Transmission Formula Rates Refund |
| $3.1 |
| | 4.4 |
|
Provision for Tax Reform Refund (c) | 0.4 |
| | 10.7 |
|
| Total Current Regulatory Liabilities | 3.5 |
| | 55.1 |
|
| Non-Current Regulatory Liabilities | | | |
| Income Taxes | 386.2 |
| | 396.4 |
|
| Wholesale and Retail Contra AFUDC | 70.6 |
| | 64.4 |
|
| Plant Removal Obligations | 29.3 |
| | 25.1 |
|
| North Dakota Investment Tax Credits | 12.3 |
| | 14.7 |
|
| Conservation Improvement Program | 7.0 |
| | 1.5 |
|
| Transmission Formula Rates Refund | 0.8 |
| | 1.6 |
|
Cost Recovery Riders | — |
| | 6.9 |
|
| Other | 2.6 |
| | 1.5 |
|
| Total Non-Current Regulatory Liabilities | 508.8 |
| | 512.1 |
|
| Total Regulatory Liabilities |
| $512.3 |
| |
| $567.2 |
|
| |
| (a) | Current regulatory liabilities are presented within Other Current Liabilities on the Consolidated Balance Sheet. |
| |
| (b) | This amount was refunded to Minnesota Power’s regulated retail customers in the second quarter of 2019. |
| |
| (c) | Provision for Tax Reform Refund related to the income tax benefits of the TCJA in 2018 was refunded to Minnesota Power customers in the first quarter of 2019 and will be refunded to SWL&P customers in 2019 and 2020. |
NOTE 3. ACQUISITIONS (Continued)EQUITY INVESTMENTS
2017 Activity (Continued)
The acquisition was accountedInvestment 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 as a business combination andour investment in ATC under the purchase price was allocated basedequity method of accounting. In thesix months ended June 30, 2019, we invested $2.7 million in ATC, and on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition. The purchase price accounting, which was finalizedJuly 31, 2019, we invested an additional $1.9 million. We expect to make approximately $4 million in 2018, is reflectedadditional investments in the following table. Fair value measurements were valued primarily using the discounted cash flow method and replacement cost basis.2019.
|
| | | |
| ALLETE’s Investment in ATC | |
| Millions | |
Assets AcquiredEquity Investment Balance as of December 31, 2018 |
| $128.1 |
|
Accounts ReceivableCash Investments |
2.7 | $5.1 |
|
Other Current AssetsEquity in ATC Earnings | 5.110.4 |
|
Trade Names (a)
Distributed ATC Earnings | 0.9(8.2 |
) |
Goodwill (a)(b)
Amortization of the Remeasurement of Deferred Income Taxes | 16.90.6 |
|
Other Non-Current AssetsEquity Investment Balance as of June 30, 2019 | 0.2 |
|
Total Assets Acquired |
| $28.2133.6 |
|
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
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.
NOTE 3. EQUITY INVESTMENTS (Continued)
Investment in ATC (Continued)
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 Consolidated Balance Sheet. (See Note 4. Goodwilladministrative law judge’s recommendation is pending.
Investment in Nobles 2. Our wholly-owned subsidiary, ALLETE South Wind, owns 49 percent of Nobles 2, the entity that will own 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. |
operate a 250 MW wind energy facility in southwestern Minnesota pursuant to a 20-year PPA with Minnesota Power. We account for our investment in Nobles 2 under the equity method of accounting. As of June 30, 2019, our equity investment in Nobles 2 was $26.6 million ($33.0 million at December 31, 2018). In the first quarter of 2019, Nobles 2 returned capital of $8.3 million based on its cash needs. We expect to make approximately $33 million in additional investments in 2019.
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 amountAs a result of completing the sale of U.S. Water Services on March 26, 2019, there was no goodwill was $148.5 millionrecorded as of June 30, 2018, and $148.32019 ($148.5 million as ofat December 31, 2017.2018).
BalancesThe balance of intangible assets, net, excluding goodwill as of June 30, 2018, are2019, is as follows:
|
| | | | | | | | | | | |
| | December 31,
2018 |
| | Amortization | | Other (b) | | June 30,
2019 |
|
| Millions | | | | | | | |
| Intangible Assets | | | | | | | |
| Definite-Lived Intangible Assets | | | | | | | |
| Customer Relationships |
| $50.7 |
| | $(1.1) | | $(49.6) | | — |
|
Developed Technology and Other (a) | 7.5 |
| | (0.3) | | (6.1) | |
| $1.1 |
|
| Total Definite-Lived Intangible Assets | 58.2 |
| | (1.4) | | (55.7) | | 1.1 |
|
| Indefinite-Lived Intangible Assets | | | | | | | |
| Trademarks and Trade Names | 16.6 |
| | n/a | | (16.6) | | — |
|
| Total Intangible Assets |
| $74.8 |
| | $(1.4) | | $(72.3) | |
| $1.1 |
|
|
| | | | | | | | | | | | | |
| | 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. |
| |
| (b) | On March 26, 2019, ALLETE completed the sale of U.S. Water Services which resulted in the removal of the related intangible assets from the Consolidated Balance Sheet. |
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.
NOTE 4. GOODWILL AND INTANGIBLE ASSETS (Continued)
Amortization expense for intangible assets was $1.3 million and $2.7$1.4 million for the quarter and six months ended June 30, 2018, respectively2019 ($1.4 million and $2.82.7 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)2018). The estimated amortization expense forremaining 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.will continue to be amortized ratably through 2028.
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 20172018 Form 10-K.
NOTE 5. 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 June 30, 20182019, and December 31, 20172018. 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 | Fair Value as of June 30, 2019 |
| Recurring Fair Value Measures | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
| Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
|
| Millions | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | |
Investments (a) | | | | | | | | | | | | | | |
| Available-for-sale – Equity Securities |
| $12.8 |
| | — |
| | — |
| |
| $12.8 |
|
| $10.9 |
| | — |
| | — |
| |
| $10.9 |
|
Available-for-sale – Corporate and Governmental Debt Securities | — |
| |
| $8.6 |
| | — |
| | 8.6 |
| — |
| |
| $9.5 |
| | — |
| | 9.5 |
|
| Cash Equivalents | 1.5 |
| | — |
| | — |
| | 1.5 |
| 1.1 |
| | — |
| | — |
| | 1.1 |
|
| Total Fair Value of Assets |
| $14.3 |
| |
| $8.6 |
| | — |
| |
| $22.9 |
|
| $12.0 |
| |
| $9.5 |
| | — |
| |
| $21.5 |
|
| | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | |
Deferred Compensation (b) | — |
| |
| $20.5 |
| | — |
| |
| $20.5 |
| |
U.S. Water Services Contingent Consideration (c) | — |
| | — |
| |
| $5.6 |
| | 5.6 |
| |
Deferred Compensation (c) | | — |
| |
| $21.7 |
| | — |
| |
| $21.7 |
|
| Total Fair Value of Liabilities | — |
| |
| $20.5 |
| |
| $5.6 |
| |
| $26.1 |
| — |
| |
| $21.7 |
| | — |
| |
| $21.7 |
|
| Total Net Fair Value of Assets (Liabilities) |
| $14.3 |
| | $(11.9) | | $(5.6) | | $(3.2) |
| $12.0 |
| | $(12.2) | | — |
| | $(0.2) |
| | | | | | | | | |
| | | | | | | | | |
| | | Fair Value as of December 31, 2018 |
| Recurring Fair Value Measures | | Level 1 |
| | Level 2 |
| | Level 3 |
| | Total |
|
| Millions | | | | | | | | |
| Assets | | | | | | | | |
Investments (a) | | | | | | | | |
| Available-for-sale – Equity Securities | |
| $12.2 |
| | — |
| | — |
| |
| $12.2 |
|
| Available-for-sale – Corporate and Governmental Debt Securities | | — |
| |
| $8.0 |
| | — |
| | 8.0 |
|
| Cash Equivalents | | 1.0 |
| | — |
| | — |
| | 1.0 |
|
| Total Fair Value of Assets | |
| $13.2 |
| |
| $8.0 |
| | — |
| |
| $21.2 |
|
| | | | | | | | | |
| Liabilities | | | | | | | | |
Deferred Compensation (c) | | — |
| |
| $19.8 |
| | — |
| |
| $19.8 |
|
U.S. Water Services Contingent Consideration (d) | | — |
| | — |
| |
| $3.8 |
| | 3.8 |
|
| Total Fair Value of Liabilities | | — |
| |
| $19.8 |
| |
| $3.8 |
| |
| $23.6 |
|
| Total Net Fair Value of Assets (Liabilities) | |
| $13.2 |
| | $(11.8) | | $(3.8) | | $(2.4) |
| |
| (a) | Included in Other InvestmentsNon-Current Assets on the Consolidated Balance Sheet. |
| |
| (b) | As of June 30, 2019, the aggregate amount of available-for-sale corporate and governmental debt securities maturing in one year or less was $3.1 million, in one year to less than three years was $3.9 million, in three years to less than five years was $1.6 million and in five or more years was $0.9 million. |
| |
| (c) | Included in Other Non-Current Liabilities on the Consolidated Balance Sheet. |
| |
(c)(d) | Included in Other Current Liabilities on the Consolidated Balance Sheet. |
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 tablestable is related to the result ofcontingent consideration liability that resulted from the 2015 acquisition of U.S. Water Services. ChangesBased on the terms and conditions of the acquisition agreement, a final payout of $3.8 million was made in the U.S. Water Services Contingent Consideration can result from modifications tofirst quarter of 2019 for 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.remaining outstanding shares.
|
| | | |
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 |
NOTE 5. FAIR VALUE (Continued)
|
| | | |
| Financial Instruments | Carrying Amount | | Fair Value |
| Millions | | | |
| Long-Term Debt, Including Long-Term Debt Due Within One Year | | | |
| June 30, 2019 | $1,543.0 | | $1,684.3 |
| December 31, 2018 | $1,495.2 | | $1,534.6 |
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, 2018,2019, and the year ended December 31, 2017,2018, there were no triggering events or indicators of impairment for these non-financial assets.
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.
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.
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. (See2018 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.
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.
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.
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.
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 8.6. SHORT-TERM AND LONG-TERM DEBT
The following tables present the Company’s short-term and long-term debt as of June 30, 2018,2019, and December 31, 2017:2018:
|
| | | | | | | | | |
| June 30, 2019 | Principal |
| | Unamortized Debt Issuance Costs | | Total |
|
| Millions | | | | | |
| Short-Term Debt |
| $28.1 |
| | $(0.4) | |
| $27.7 |
|
| Long-Term Debt | 1,514.9 |
| | (9.0) | | 1,505.9 |
|
| Total Debt |
| $1,543.0 |
| | $(9.4) | |
| $1,533.6 |
|
|
| | | | | | | | | |
| 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, 2018 | Principal |
| | Unamortized Debt Issuance Costs | | Total |
|
| Millions | | | | | |
| Short-Term Debt |
| $57.9 |
| | $(0.4) | |
| $57.5 |
|
| Long-Term Debt | 1,437.3 |
| | (8.8) | | 1,428.5 |
|
| Total Debt |
| $1,495.2 |
| | $(9.2) | |
| $1,486.0 |
|
|
| | | | | | | | | |
| 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,January 10, 2019, ALLETE entered into an amended and restated $400 million credit agreement, as amended (Credit Agreement). The Credit Agreement is unsecured, has a variable interest rate and will expire in January 2024. At ALLETE’s request and subject to certain conditions, the Credit Agreement may be increased by up to $150 million and ALLETE may make two requests to extend the maturity date, each for a one-year extension. Advances may be used by ALLETE for general corporate purposes, to provide liquidity in support of ALLETE’s commercial paper program and to issue up to $100 million in letters of credit.
We had $56.3 million outstanding in standby letters of credit and no outstanding draws under our lines of credit as of June 30, 2019 ($18.4 million in standby letters of credit and no outstanding draws as of December 31, 2018).
On March 1, 2019, ALLETE issued and sold $60.0 million of itsthe following 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. :
|
| | |
| Maturity Date | Principal Amount | Interest Rate |
| March 1, 2029 | $70 Million | 4.08% |
| March 1, 2049 | $30 Million | 4.47% |
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.
NOTE 6. 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 June 30, 20182019, 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, 20182019, ALLETE was in compliance with its financial covenants.
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.
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. |
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 13.7. 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 ourthe Consolidated Financial Statements in our 20172018 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, 20182019, Square Butte had total debt outstanding of $311.4$301.9 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, 2018,2019, was $37.7$41.1 million ($40.737.7 million for the six months ended June 30, 2017)2018). 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$4.2 million ($4.74.6 million for the same period in 2017)2018). 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 20182019 and in 2017.2018.
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 20182019 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.2021. 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.
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.
NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Transmission (Continued)
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‑constructionConstruction activities commenced in the first quarter of 2017, and with construction expectedon schedule, Minnesota Power expects the GNTL to be completed in 2020. To date, most of the right-of-way has been cleared while foundation installationcomplete and transmission tower construction have commenced.in-service by mid-2020. The total project cost in the U.S., including substation work, is estimated to be between $560 million and $710approximately $750 million, of which Minnesota Power’s portion is expected to be between $300 million and $350approximately $345 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $248.8$510.8 million have been incurred through June 30, 2018,2019, of which $129.2$272.7 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.was received on April 4, 2019. 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 thatMMTP, which was recommended for approval on November 15, 2018. On June 14, 2019, Manitoba Hydro’s application was complete in December 2017, and held public hearings in June 2018. The NEB is required to make a decision onHydro announced Canada’s federal government approved the MMTP by March 2019, but is not precluded from making a decision priorproject, subject to that date. Approval of the Canadian federal cabinet is also required.certain compliance conditions.
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.by September 2019. 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 inIn the event the MMTP construction schedule may result inis delayed and not in-service by June 1, 2020, Minnesota Power adjusting the GNTLhas construction schedule and impact the timing of capital expendituresrelated agreements in place with Manitoba Hydro and associated cost recovery under our transmission cost recovery rider.a Manitoba Hydro subsidiary that will protect Minnesota Power and its customers.
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.
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 NOX 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.
NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
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 NOx and SO2 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.
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 portionNone of the state are close to exceeding the standard. As a result, voluntary efforts to reduce ground-level ozone continue in the state. No additionalcompliance costs for complianceproposed or current NAAQS revisions are anticipated at this time.
expected to be material.
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• | 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 PM2.5 standards in certain states, including Minnesota, by not enforcing states’ submittals of required infrastructure implementation plans for the 2012 PM2.5 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.
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• | NO2 NAAQS. Ambient monitoring data indicates that Minnesota is likely in compliance with the one-hour NAAQS standard for NO2. In July 2017, the EPA proposed retaining the current one-hour and annual NO2 NAAQS. Additional compliance costs for the one-hour NO2 NAAQS are not expected at this time.
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• | SO2 NAAQS. In 2015, the EPA finalized the SO2 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 SO2 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 SO2 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 SO2 one-hour NAAQS. Compliance costs for the one-hour SO2 NAAQS are not expected to be material.
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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;supply for both our operations and the operations of others;
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.facilities;
Managing vegetation on right-of-way corridors to reduce potential wildfire or storm damage risks; and
Practicing sound forestry management in our service territories to create landscapes more resilient to disruption from climate-related changes, including planting and managing long-lived conifer species.
EPA Regulation of GHG Emissions. In 2010,On June 19, 2019, the EPA issuedfinalized several separate rulemakings regarding regulating carbon emissions from electric utility generating units.
The EPA repealed 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 facilitiesClean Power Plan (CPP), following a determination by the EPA that undergo major modifications and other facilities characterized as major sourcesthe CPP exceeded the EPA’s statutory authority under the Clean Air Act’s Title V program. For our existing facilities,Act (CAA). The primary reason for this was that the rule does not require amending our existing Title V operating permitsCPP attempted 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.
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
In 2014, the U.S. Supreme Court invalidated the aspectregulate electric generating unit’s carbon emissions through measures outside 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.affected unit’s direct control. 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,CPP was first announced 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.
With the repeal of the CPP, the Affordable Clean Energy Rule was finalized. The rule establishes emissions guidelines for states to use when developing plans to limit carbon dioxide at coal-fired power plants. The rule identifies heat rate improvements made at individual units as the Cleanbest system of emission reduction. Affected facilities for Minnesota Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation planinclude Boswell Units 3 and a model rule for emissions trading. In 2016, the U.S. Supreme Court issued an order staying the effectiveness4. Based on our initial review of the rule, until aftermany of the appellate court process is complete. In 2016,candidate heat rate improvements are already installed on Boswell Units 3 and 4.
Additionally, the U.S. Court of AppealsEPA finalized new regulations for the District of Columbia heard oral arguments and is currently deliberating. If the CPP is upheld at the completionstate implementation of the appellate process, all ofAffordable Clean Energy Rule and any future emission guidelines issued under CAA Section 111(d). States will have three years to submit State Implementation Plans (SIP), and the CPP regulatory deadlines are expectedEPA has 12 months to be reset based onreview and approve those plans. Since the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay isAffordable Clean Energy Rule allows states considerable flexibility in force; however,how to best implement its requirements, Minnesota Power plans to work closely with the MPCA has been holdingand the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If 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, andstate does not submit a SIP or submits a SIP that is closely monitoring the appeals process.
If upheld, the CPP would establish uniform CO2 emission performance rates for existing fossil fuel-fired and natural gas-fired combined cycle generating units, setting state-specific goals for CO2 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 Circuitunacceptable to hold CPP-related litigation in suspension while the EPA, is reviewing the rule. In October 2017, the EPA issuedwill develop 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.Implementation Plan.
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 hashad already initiated several measures consistent with those called for under the CPP.now repealed CPP and finalized Affordable Clean Energy Rule. Minnesota Power iscontinues 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 6.2. Regulatory Matters.)
We are unable to predict the GHG emission compliance costs we might incur;incur as a result of the Affordable Clean Energy Rule and the resulting SIP; however, the costs could be material. Minnesota Power would seek recovery of additional costs through a rate proceeding.
NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
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.
NOTE 13. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
Steam Electric Power Generating Effluent Limitations Guidelines. In 2015, the EPA issued revised federal effluent limitlimitation 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. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded back to the EPA portions of the ELG that allowed for continued discharge of legacy wastewater and leachate.
The final ELG rule’sELG'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 to surface waters, but may do so in the future. Under the existing ELG rule, bottom ash transport water discharge to surface waters 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. The EPA’s additional reconsideration of legacy wastewater discharge requirements have the potential to reduce time lines for dewatering Boswell’s existing bottom ash pond. The timing of a draft rule addressing legacy wastewater and leachate is currently unknown.
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$120 million. The EPA has indicated to Minnesota Power that the landfill at 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 cannotare not expected to be estimated at this time.material. 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 onin March 15, 2018, published the first phase of the proposed rule revisions in the Federal Register. OnIn 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. In August 2018, a U.S. District Court for the District of Columbia decision vacated specific provisions of the CCR rule. The court decision changes the status of three existing impoundments at Boswell that must now be considered unlined. Compliance costs at Boswell due to the court decision are unknown at this time. Minnesota Power would seek recovery of additional costs through a rate proceeding.
NOTE 7. COMMITMENTS, GUARANTEES AND CONTINGENCIES (Continued)
Environmental Matters (Continued)
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.Wisconsin. 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, 2018,2019, we have recorded a liability of approximately $7 million for remediation costs at this site (approximately $8$7 million as of December 31, 2017)2018), and an associated regulatory asset as we expect recovery of these remediation costs to be allowed by the PSCW. We expectRemediation costs are expected to incur these costs over the next four years.be incurred through 2023.
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 20182019 and 2032. As of June 30, 2018,2019, ALLETE Clean Energy has $16.2$58.4 million outstanding in standby letters of credit.
U.S. Water Services. BNI Energy.As of June 30, 2018, U.S. Water Services has no outstanding standby letters of credit.
BNI Energy. As of June 30, 2018,2019, BNI Energy had surety bonds outstanding of $49.9 million and a letter of credit for an additional $0.6$66.5 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$65.8 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, 2018,2019, 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, 20182019, we owned 7066 percent of the assessable land in the Town Center District (70(68 percent as of December 31, 2017)2018) and 2712 percent of the assessable land in the Palm Coast Park District (33(19 percent as of December 31, 20172018). As of June 30, 20182019, 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.
NOTE 8. 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 non-vested restricted stock units and performance share awards granted under our Executive Long-Term Incentive Compensation Plan.
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| | | | 2019 | | | | | | 2018 | | |
| 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 |
| $34.2 |
| | | |
| $34.2 |
| |
| $31.3 |
| | | |
| $31.3 |
|
| Average Common Shares | 51.6 |
| | 0.1 |
| | 51.7 |
| | 51.3 |
| | 0.2 |
| | 51.5 |
|
| Earnings Per Share |
| $0.66 |
| | | |
| $0.66 |
| |
| $0.61 |
| | | |
| $0.61 |
|
| Six Months Ended June 30, | |
| | | | |
| | | | | | |
| Net Income |
| $104.7 |
| | | |
| $104.7 |
| |
| $82.3 |
| | | |
| $82.3 |
|
| Average Common Shares | 51.6 |
| | 0.1 |
| | 51.7 |
| | 51.2 |
| | 0.2 |
| | 51.4 |
|
| Earnings Per Share |
| $2.03 |
| | | |
| $2.02 |
| |
| $1.61 |
| | | |
| $1.60 |
|
NOTE 9. INCOME TAX EXPENSE
|
| | | | | | | | | | | | | | |
| | | Quarter Ended | | Six Months Ended |
| | | June 30, | | June 30, |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Millions | | | | | | | | |
Current Income Tax Expense (Benefit) (a) | | | | | | | | |
| Federal | | — |
| | — |
| | — |
| | — |
|
| State | | $(0.1) | | $(0.3) | |
| $0.2 |
| |
| $0.4 |
|
| Total Current Income Tax Expense (Benefit) | | $(0.1) | | $(0.3) | |
| $0.2 |
| |
| $0.4 |
|
| Deferred Income Tax Expense (Benefit) | | | | | | | | |
Federal (b) | | $(7.1) | | $(7.4) | | $(16.8) | | $(14.2) |
State (c) | | 2.5 |
| | 2.4 |
| | 15.0 |
| | 5.0 |
|
| Investment Tax Credit Amortization | | (0.1 | ) | | (0.1 | ) | | (0.3 | ) | | (0.3 | ) |
| Total Deferred Income Tax Benefit | | $(4.7) | | $(5.1) | | $(2.1) | | $(9.5) |
| Total Income Tax Benefit | | $(4.8) | | $(5.4) | | $(1.9) | | $(9.1) |
| |
| (a) | For each of the six months ended June 30, 2019, and 2018, 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. Federal and state NOLs are being carried forward to offset current and future taxable income. |
| |
| (b) | For each of the six months ended June 30, 2019, and 2018, the federal income tax benefit is primarily due to production tax credits. |
| |
| (c) | For the six months ended June 30, 2019, the state income tax expense is primarily due to the sale of U.S. Water Services. |
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.
NOTE 9. INCOME TAX EXPENSE (Continued)
|
| | | | | | | | | | | | | | |
| | Quarter Ended | Six Months Ended |
| Reconciliation of Taxes from Federal Statutory | June 30, | June 30, |
| Rate to Total Income Tax Expense | 2019 | | 2018 | 2019 | | 2018 |
| Millions | | | | | | |
| Income Before Income Taxes |
| $29.4 |
| |
| $25.9 |
|
| $102.8 |
| |
| $73.2 |
|
| Statutory Federal Income Tax Rate | 21 | % | | 21 | % | 21 | % | | 21 | % |
| Income Taxes Computed at Statutory Federal Rate |
| $6.2 |
| |
| $5.4 |
|
| $21.6 |
| |
| $15.4 |
|
| Increase (Decrease) in Income Tax Due to: | | | | | | |
| State Income Taxes – Net of Federal Income Tax Benefit | 1.9 |
| | 1.6 |
| 12.0 |
| | 4.2 |
|
| Production Tax Credits | (9.8 | ) | | (11.2 | ) | (26.1 | ) | | (25.6 | ) |
| Regulatory Differences – Excess Deferred Tax | (1.6 | ) | | (2.2 | ) | (4.8 | ) | | (4.4 | ) |
| U.S. Water Services Sale of Stock Basis Difference | (0.7 | ) | | — |
| 1.7 |
| | — |
|
| Share-Based Compensation | — |
| | — |
| (0.9 | ) | | (0.5 | ) |
| Other | (0.8 | ) | | 1.0 |
| (5.4 | ) | | 1.8 |
|
| Total Income Tax Benefit | $(4.8) | | $(5.4) | $(1.9) | | $(9.1) |
For the six months ended June 30, 2019, the effective tax rate was a benefit of 1.8 percent (benefit of 12.4 percent for the six months ended June 30, 2018). The effective tax rate for 2019 was a lower benefit primarily due to a higher tax rate on the gain on the sale of 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.and higher pre-tax income.
Uncertain Tax Positions. As of June 30, 2019, we had gross unrecognized tax benefits of $1.3 million ($1.6 million as of December 31, 2018). Of the total gross unrecognized tax benefits, $0.6 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 2015, or state examination for years before 2014.
NOTE 10. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
|
| | | | | | | | | | | | | | | |
| | Pension | | Other Postretirement |
| Components of Net Periodic Benefit Cost | 2019 | | 2018 | | 2019 | | 2018 |
| Millions | | | | | | | |
| Quarter Ended June 30, | | | | | | | |
| Service Cost |
| $2.4 |
| |
| $2.8 |
| |
| $1.0 |
| |
| $1.3 |
|
Non-Service Cost Components (a) | | | | | | | |
| Interest Cost | 8.0 |
| | 7.4 |
| | 1.9 |
| | 1.8 |
|
| Expected Return on Plan Assets | (11.1 | ) | | (11.1 | ) | | (2.7 | ) | | (2.8 | ) |
| Amortization of Prior Service Credits | (0.1 | ) | | — |
| | (0.4 | ) | | (0.5 | ) |
| Amortization of Net Loss | 1.9 |
| | 3.0 |
| | 0.1 |
| | 0.2 |
|
| Net Periodic Benefit Cost |
| $1.1 |
| |
| $2.1 |
| | $(0.1) | | — |
|
| | | | | | | | |
| Six Months Ended June 30, | | | | | | | |
| Service Cost |
| $4.7 |
| |
| $5.5 |
| |
| $2.0 |
| |
| $2.5 |
|
Non-Service Cost Components (a) | | | | | | | |
| Interest Cost | 16.0 |
| | 14.8 |
| | 3.8 |
| | 3.6 |
|
| Expected Return on Plan Assets | (22.1 | ) | | (22.1 | ) | | (5.3 | ) | | (5.5 | ) |
| Amortization of Prior Service Credits | (0.1 | ) | | — |
| | (0.8 | ) | | (0.9 | ) |
| Amortization of Net Loss | 3.7 |
| | 6.0 |
| | 0.2 |
| | 0.4 |
|
| Net Periodic Benefit Cost |
| $2.2 |
| |
| $4.2 |
| | $(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. |
Employer Contributions. For the six months ended June 30, 2019, we contributed $10.4 million in cash to the defined benefit pension plans ($15.0 million for the six months ended June 30, 2018); we do not expect to make additional contributions to our defined benefit pension plans in 2019. For the six months ended June 30, 2019, and 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, butwe made no contributions to our other postretirement benefit plans; we do not expect to make any contributions to our other postretirement benefit plans in the event of an unfavorable outcome, the patent defense costs would be recognized as an expense in the period of resolution.2019.
NOTE 14.11. 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 iswas our integrated water management company.company, which reflects operating results until the closing date of its sale on March 26, 2019. 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 our investment in Nobles 2, 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.
NOTE 14.11. BUSINESS SEGMENTS (Continued)
|
| | | | | | | | | | | | | |
| | Quarter Ended | | Six Months Ended |
| | June 30, | | June 30, |
| | 2019 | 2018 | | 2019 | 2018 |
| Millions | | | | | |
| Operating Revenue | | | | | |
| Regulated Operations | | | | | |
| Residential |
| $29.2 |
|
| $30.7 |
| |
| $74.4 |
|
| $71.4 |
|
| Commercial | 34.9 |
| 36.2 |
| | 73.8 |
| 72.8 |
|
| Municipal | 12.2 |
| 13.7 |
| | 27.6 |
| 27.7 |
|
| Industrial | 120.3 |
| 115.3 |
| | 241.9 |
| 230.2 |
|
| Other Power Suppliers | 35.2 |
| 42.7 |
| | 74.6 |
| 86.4 |
|
| Other | 18.0 |
| 19.2 |
| | 39.7 |
| 39.5 |
|
| Total Regulated Operations | 249.8 |
| 257.8 |
| | 532.0 |
| 528.0 |
|
| | | | | | |
| Energy Infrastructure and Related Services | | | | | |
| | | | | | |
| ALLETE Clean Energy | | | | | |
| Long-term PSA | 12.5 |
| 12.4 |
| | 27.1 |
| 31.0 |
|
| Other | 2.9 |
| 5.9 |
| | 5.8 |
| 11.9 |
|
| Total ALLETE Clean Energy | 15.4 |
| 18.3 |
| | 32.9 |
| 42.9 |
|
| | | | | | |
U.S. Water Services (a) | | | | | |
| Point-in-Time | — |
| 25.7 |
| | 19.0 |
| 48.0 |
|
| Contract | — |
| 9.5 |
| | 9.2 |
| 19.0 |
|
| Capital Project | — |
| 6.3 |
| | 5.2 |
| 12.7 |
|
| Total U.S. Water Services | — |
| 41.5 |
| | 33.4 |
| 79.7 |
|
| | | | | | |
| Corporate and Other |
|
|
|
| | | |
| Long-term Contract | 21.2 |
| 22.7 |
| | 41.4 |
| 42.7 |
|
| Other | 4.0 |
| 3.8 |
| | 7.9 |
| 9.0 |
|
| Total Corporate and Other | 25.2 |
| 26.5 |
| | 49.3 |
| 51.7 |
|
| Total Operating Revenue |
| $290.4 |
|
| $344.1 |
| |
| $647.6 |
|
| $702.3 |
|
| Net Income (Loss) | | | | | |
| Regulated Operations |
| $30.3 |
|
| $26.0 |
| |
| $81.8 |
|
| $69.9 |
|
| | | | | | |
| Energy Infrastructure and Related Services | | | | | |
| ALLETE Clean Energy | 1.9 |
| 6.8 |
| | 7.7 |
| 14.9 |
|
U.S. Water Services (a) | — |
| 0.2 |
| | (1.1 | ) | (1.2 | ) |
| | | | | | |
Corporate and Other (a) | 2.0 |
| (1.7 | ) | | 16.3 |
| (1.3 | ) |
| Total Net Income |
| $34.2 |
|
| $31.3 |
| |
| $104.7 |
|
| $82.3 |
|
|
| | | | | | | | | | | | | |
| | 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) | WithOn March 26, 2019, ALLETE completed the adoptionsale of new revenue recognition guidance,U.S. Water Services. The Company recognized a gain on the Company has enhanced the presentationsale of business segment Operating Revenue.$11.1 million after-tax reflected in Corporate and Other in 2019. (See Note 1. Operations and Significant Accounting Policies.) |
|
| | | | | | |
| | June 30,
2019 |
| December 31,
2018 |
|
| Millions | | |
| Assets | | |
| Regulated Operations |
| $4,004.4 |
|
| $3,952.5 |
|
| | | |
| Energy Infrastructure and Related Services | | |
| ALLETE Clean Energy | 755.0 |
| 606.6 |
|
U.S. Water Services (a) | — |
| 295.8 |
|
| | | |
| Corporate and Other | 417.1 |
| 310.1 |
|
| Total Assets |
| $5,176.5 |
|
| $5,165.0 |
|
| |
(b)(a) | SeeOn March 26, 2019, ALLETE completed the sale of U.S. Water Services. (See Note 6. Regulatory Matters.1. Operations and Significant Accounting Policies.) |
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 |
|
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
The following discussion should be read in conjunction with our Consolidated Financial Statements and notes to those statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations from the 2017our 2018 Form 10-K, and the other financial information appearing elsewhere in this report. In addition to historical information, the following discussion and other parts of this Form 10-Q contain forward-looking information that involves risks and uncertainties. Readers are cautioned that forward-looking statements should be read in conjunction with our disclosures in this Form 10-Q and our 20172018 Form 10-K under the headings: “Forward-Looking Statements” located on page 6 and “Risk Factors” located in Part I, Item 1A, beginning on page 2523 of our 20172018 Form 10-K. The risks and uncertainties described in this Form 10-Q and our 20172018 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations could suffer if the risks are realized.
Regulated Operations includes our regulated utilities, Minnesota Power and SWL&P, as well as our investment in ATC, a Wisconsin-based regulated utility that owns and maintains electric transmission assets in portions of Wisconsin, Michigan, Minnesota and Illinois. Minnesota Power provides regulated utility electric service in northeastern Minnesota to approximately 145,000 retail customers. Minnesota Power also has 16 non-affiliated municipal customers in Minnesota. SWL&P is a Wisconsin utility and a wholesale customer of Minnesota Power. SWL&P provides regulated utility electric, natural gas and water service in northwestern Wisconsin to approximately 15,000 electric customers, 13,000 natural gas customers and 10,000 water customers. Our regulated utility operations include retail and wholesale activities under the jurisdiction of state and federal regulatory authorities. (See Note 6.2. Regulatory Matters.)
ALLETE Clean Energy focuses on developing, acquiring, and operating clean and renewable energy projects. ALLETE Clean Energy currently owns and operates, in four states, approximately 535555 MW of nameplate capacity wind energy generation that is contracted under PSAs of various durations. ALLETE Clean Energy also engages in the development of wind energy facilities to operate under long-term PSAs or for sale to others upon completion.
U.S. Water Services providesprovided integrated water management for industry by combining chemical, equipment, engineering and service for customized solutions to reduce water and energy usage, and improve efficiency. On February 8, 2019, the Company entered into a stock purchase agreement providing for the sale of U.S. Water Services to a subsidiary of Kurita Water Industries Ltd. for a cash purchase price of $270 million. On March 26, 2019, ALLETE completed the sale and received approximately $265 million in cash at closing, net of transaction costs and cash retained.
Corporate and Otheris comprised of BNI Energy, our coal mining operations in North Dakota, ALLETE Properties, our legacy Florida real estate investment, our investment in Nobles 2, 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 is incorporated under the laws of Minnesota. Our corporate headquarters are in Duluth, Minnesota. Statistical information is presented as of June 30, 20182019, unless otherwise indicated. All subsidiaries are wholly-owned unless otherwise specifically indicated. References in this report to “we,” “us” and “our” are to ALLETE and its subsidiaries, collectively.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (Continued)
Financial Overview
The following net income discussion summarizes a comparison of the six months ended June 30, 2018,2019, to the six months ended June 30, 2017.2018.
Net income for the six months ended June 30, 2018,2019, was $82.3$104.7 million, or $1.60$2.02 per diluted share, compared to $85.9$82.3 million, or $1.69$1.60 per diluted share, for the same period in 2017.2018. Net income in 2019 included the gain on sale of U.S. Water Services of $11.1 million after-tax, or $0.21 per share. Earnings per share dilution was $0.02 due to additional shares of common stock outstanding as of June 30, 2018.2019.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (Continued)
Regulated Operations net income was $69.9$81.8 million for the six months ended June 30, 2018,2019, compared to $75.9$69.9 million for the same period in 2017.2018. Net income at Minnesota Power was lowerhigher than 20172018 primarily due to reserves for an interim rate refund, lower transmissionoperating and maintenance and property tax expenses, increased cost recovery rider revenue, the timing of financial incentives under the Minnesota conservation improvement programfuel adjustment clause recoveries and higher property taxes.revenue from wholesale customers under FERC formula-based rates. These decreasesincreases were partially offset by lower kWh sales. Net income at Superior Water, Light and Power was higher than 2018 primarily due to higher rates and lower operating and maintenance expense, higher sales to residential customers due to more favorable weather conditions, and higher sales to industrial customers due to the start-up of Keetac in March 2017. Net income at SWL&P was higher than 2017 due to the implementation of updated rates in August 2017 and more favorable weather conditions in 2018.expenses. Our after-tax equity earnings in ATC for the six months ended June 30,were higher than 2018 were consistent with 2017.primarily due to additional investments.
ALLETE Clean Energy net income was $14.9$7.7 million for the six months ended June 30, 2018,2019, compared to $10.5$14.9 million for the same period in 2017.2018. Net income in 2018 included $4.5$2.6 million after‑of production tax credits that resulted from the retrospective qualification of additional wind turbine generators in 2016 and 2017. Net income in 2019 included lower revenue resulting from lower wind resources and availability due to weather as well as lower non-cash amortization related to the expiration of power sales agreements, and higher depreciation expense. These decreases were partially offset by $2.0 million of additional production tax credits generated in 2019 compared to production tax credits generated in 2018 as ALLETE Clean Energy continues to execute its refurbishment strategy and a lower federal income tax rate due to the TCJA. Of the $4.5 million after-tax in additional production tax credits, $2.6 million resulted from the retrospective qualification of additional WTGs in 2016 and 2017. These increases were partially offset by higher operating and maintenance expenses, and lower revenue resulting from lower wind resources.strategy.
U.S. Water Services net loss was $1.2$1.1 million for the six months ended June 30, 2018,2019, compared to a net incomeloss of $0.3$1.2 million for the same period in 2017. The net loss2018. ALLETE completed the sale of U.S. Water Services in 2018 includes higher operating expenses, partially offset by increased revenue primarily resulting from the September 2017 acquisitionfirst quarter of Tonka Water. The first six months of 2018 were also impacted by the timing of capital project sales and unfavorable weather conditions reducing chemical sales. The net loss in 2018 also included $0.5 million of after-tax expense recognized as cost of sales related to purchase accounting for sales backlog.2019.
Corporate and Other net lossincome was $1.3$16.3 million for the six months ended June 30, 2018,2019, compared to a net loss of $0.8$1.3 million for the same period in 2017. Results2018. Net income in 2018 decreased primarily due to2019 included the gain on sale of U.S. Water Services of $11.1 million after-tax. Net income in 2019 also included additional income tax expensebenefit recorded in 20182019 as GAAP requires the recognition of quarterly income tax expense at the estimated annual effective tax rate, partially offset by lower operating and maintenance expenses at ALLETE Properties.rate.
COMPARISON OF THE QUARTERS ENDED JUNE 30, 20182019 AND 20172018
(See Note 14.11. Business Segments for financial results by segment.)
Regulated Operations
| | | Quarter Ended June 30, | 2018 |
| 2017 |
| 2019 |
| 2018 |
|
| Millions | | |
| Operating Revenue – Utility |
| $257.8 |
|
| $264.9 |
|
| $249.8 |
|
| $257.8 |
|
| Fuel, Purchased Power and Gas – Utility | 96.5 |
| 93.1 |
| 87.9 |
| 96.5 |
|
| Transmission Services – Utility | 16.8 |
| 17.6 |
| 19.2 |
| 16.8 |
|
| Operating and Maintenance | 54.9 |
| 57.3 |
| 54.2 |
| 54.9 |
|
| Depreciation and Amortization | 44.5 |
| 39.0 |
| 40.2 |
| 44.5 |
|
| Taxes Other than Income Taxes | 13.0 |
| 12.7 |
| 12.5 |
| 13.0 |
|
| Operating Income | 32.1 |
| 45.2 |
| 35.8 |
| 32.1 |
|
| Interest Expense | (15.1 | ) | (14.5 | ) | (14.4 | ) | (15.1 | ) |
| Equity Earnings in ATC | 4.3 |
| 5.3 |
| |
| Equity Earnings | | 4.8 |
| 4.3 |
|
| Other Income | 1.0 |
| 1.2 |
| 2.8 |
| 1.0 |
|
| Income Before Income Taxes | 22.3 |
| 37.2 |
| 29.0 |
| 22.3 |
|
| Income Tax Expense (Benefit) | (3.7 | ) | 4.8 |
| |
| Income Tax Benefit | | (1.3 | ) | (3.7 | ) |
| Net Income | $26.0 |
| $32.4 |
|
| $30.3 |
|
| $26.0 |
|
Operating Revenue – Utility decreased $7.1$8.0 million, or 3 percent, from 2017 reflecting interim retail rate2018 as a result of lower revenue from kWh sales and the timing of the provision for tax reform refund reserves, lower financial incentives underin 2018 related to income tax changes resulting from the Minnesota conservation improvement program and lower transmission revenue,TCJA, partially offset by higher revenue from kWh sales,fuel adjustment clause recoveries, increased cost recovery rider revenue conservation improvement program recoveries and fuel clause adjustment recoveries.higher FERC formula-based rates.
Interim rates, net of reserves, decreased $7.8 million from 2017 as interim rate refund reserves were recognized during
COMPARISON OF THE QUARTERS ENDED JUNE 30, 2019 AND 2018 due to the regulatory outcome of the MPUC’s decisions in Minnesota Power’s 2016 general rate case. (See Note 6. Regulatory Matters.)(Continued)
Regulated Operations (Continued)
Financial incentives under the Minnesota conservation improvement program were lower $5.5 million from 2017 due to the timing of MPUC approval. The conservation improvement program financial incentive was recognized in the second quarter of 2017 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 is expected in the third quarter of 2018.
Transmission revenue decreased $4.4 million primarily due to lower MISO-related revenue. (See Operating Expenses - Transmission Services – Utility.)
Revenue from kWh sales increased $4.4decreased $15.0 million from 20172018 reflecting lower sales residential, commercial and municipal customers as well as lower sales to other power suppliers. Sales to residential and commercial customers decreased from 2018 primarily due to higher salesmilder weather in 2019 compared to Residential, Commercial and Municipal customersthe same period in 2018. Sales to Residential, Commercial and Municipal customers increased from 2017 primarily due to more favorable weather conditions in 2018. Sales to Industrialmunicipal customers decreased 1.9 percent primarily due to lower sales to paper, pulp and secondary wood product customersin 2019 as a result of the closure of the smaller of UPM Blandin’s two paper machinesadditional customer self-generation in the fourth quarter of 2017.2019. Sales to Other Power Suppliers were comparable to 2017, while revenue increasedother power suppliers decreased in 2019 primarily due to higher pricing.fewer market sales and sales under PSAs as a result of less generation available for sale, partially offset by the commencement of Minnesota Power’s PSA with Oconto Electric Cooperative in January 2019. Sales to Other Power Suppliersother power suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreementsPSAs of various durations.
COMPARISON OF THE QUARTERS ENDED JUNE 30, 2018 AND 2017 (Continued)
Regulated Operations (Continued)
| | | Kilowatt-hours Sold | | | | | Quantity | | % | | | | | Quantity | | % |
| Quarter Ended June 30, | 2018 |
| | 2017 |
| | Variance | | Variance | 2019 |
| | 2018 |
| | Variance | | Variance |
| Millions | | | | | | | | | | | | | | |
| Regulated Utility | | | | | | | | | | | | | | |
| Retail and Municipal | | | | | | | | | | | | | | |
| Residential | 243 |
| | 229 |
| | 14 |
| | 6.1 | % | 232 |
| | 243 |
| | (11 | ) | | (4.5 | )% |
| Commercial | 339 |
| | 328 |
| | 11 |
| | 3.4 | % | 317 |
| | 339 |
| | (22 | ) | | (6.5 | )% |
| Industrial | 1,781 |
| | 1,816 |
| | (35 | ) | | (1.9 | )% | 1,773 |
| | 1,781 |
| | (8 | ) | | (0.4 | )% |
| Municipal | 188 |
| | 181 |
| | 7 |
| | 3.9 | % | 170 |
| | 188 |
| | (18 | ) | | (9.6 | )% |
| Total Retail and Municipal | 2,551 |
| | 2,554 |
| | (3 | ) | | (0.1 | )% | 2,492 |
| | 2,551 |
| | (59 | ) | | (2.3 | )% |
| Other Power Suppliers | 1,005 |
| | 1,004 |
| | 1 |
| | 0.1 | % | 714 |
| | 1,005 |
| | (291 | ) | | (29.0 | )% |
| Total Regulated Utility Kilowatt-hours Sold | 3,556 |
| | 3,558 |
| | (2 | ) | | (0.1 | )% | 3,206 |
| | 3,556 |
| | (350 | ) | | (9.8 | )% |
Revenue from electric sales to taconite and iron concentrate customers accounted for 2227 percent of consolidated operating revenue in 20182019 (22 percent in 2017)2018). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 56 percent of consolidated operating revenue in 20182019 (5 percent in 2017)2018). Revenue from electric sales to pipelines and other industrial customers accounted for 68 percent of consolidated operating revenue in 2018 (72019 (6 percent in 2017)2018).
Revenue was $3.4 million lower than 2018 reflecting the timing of Minnesota Power’s provision for tax reform refund in 2018. In the first quarter of 2018, Minnesota Power reserved for income tax benefits resulting from the reduction of the federal income tax rate enacted as part of the TCJA. In the second quarter of 2018, Minnesota Power reversed the reserve as the MPUC allowed Minnesota Power to retain these income tax benefits to mostly offset an increase in depreciation expense resulting from the reconsideration of its decision in Minnesota Power’s general rate case to reduce the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035. (See Operating Expenses - Depreciation and Amortization.)
Fuel adjustment clause revenue increased $5.9 million due to period over period timing of recoveries for fuel and purchased power costs attributable to retail and municipal customers.
Cost recovery rider revenue increased $3.6contributed an incremental $4.2 million over current base rates compared to 2018 (see Note 2. Regulatory Matters) primarily due to higher expenditures related to the construction of the GNTL.GNTL and lower transmission margins related to our portion of CapX2020 transmission lines. Transmission margins for CapX2020 transmission lines recognized below those assumed in Minnesota Power base rates result in increased cost recovery rider revenue to offset the impact of the lower margins.
Conservation improvement program recoveriesRevenue from wholesale customers under FERC formula-based rates increased $1.9$1.8 million from 20172018 primarily due to an increase in related expenditures. (See higher rates.
Operating Expenses - Operating and Maintenance.)
Fuel adjustment clause recoveries increased $1.6 million due to higher fuel and purchased power costs attributable to retail and municipal customers.
Operating Expenses increased $6.0 decreased $11.7 million, or 35 percent, from 2017.2018.
Fuel, Purchased Power and Gas – Utility expense increased $3.4decreased $8.6 million, or 49 percent, from 20172018 primarily due to higher purchased power prices, partially offset by lower fuel costs.kWh sales. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.
Transmission Services – Utility expense decreased $0.8increased $2.4 million, or 514 percent, from 20172018 primarily due to lowerhigher MISO‑related expense. (See Operating Revenue – Utility.)
COMPARISON OF THE QUARTERS ENDED JUNE 30, 2019 AND 2018 (Continued)
Regulated Operations (Continued)
Operating and Maintenance expensedecreased $2.4$0.7 million, or 41 percent, from 20172018 primarily due to lower salary and benefit expenses, and lower bad debt expense, partially offset by a $1.9 million increase in conservation improvement programhigher expenses in 2018. Conservation improvement program expenses are recovered from certain retail customers. (See Operating Revenue – Utility.)for planned maintenance outages at our generation facilities.
Depreciation and Amortization expense increased $5.5decreased $4.3 million, or 1410 percent, from 20172018 primarily due to the timing of modifications of the depreciable lives for Boswell as part of Minnesota Power’s general rate case. As part of its order dated March 12, 2018, affirming determinations made at a hearing on January 18,decision in Minnesota Power’s general rate case in 2018, the MPUC extended the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2050, and shortened the depreciable lives of Boswell Unit 1 and Unit 2 to 2022, resulting in a net decrease to depreciation expense in the first quarter of 2018. Subsequently,In the second quarter of 2018, as part of the reconsideration of its decision in an order dated May 29, 2018,Minnesota Power’s general rate case, the MPUC modified its March 12, 2018 order, reducingreduced the depreciable lives of Boswell Unit 3, Unit 4 and common facilities to 2035, resulting in an increase tohigher depreciation expense beginning in the second quarter of 2018. (See Note 6. Regulatory Matters.)
Equity Earnings in ATC decreased $1.0 million, or 19 percent, from2017 primarily due to the federal income tax rate change due to the TCJA, partially offset by additional investments in ATC. (See Note 7. Investment in ATC.)
COMPARISON OF THE QUARTERS ENDED JUNE 30, 2018 AND 2017 (Continued)
Regulated Operations (Continued)
Income Tax Expense decreased $8.5 million from 2017 primarily due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, and lower pre-tax income. (See Note 6. Regulatory Matters.)
We expect our annual effective tax rate in 2018 to be lower than 2017 due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, and lower pre-tax income.
ALLETE Clean Energy
|
| | | | | | |
| Quarter Ended June 30, | 2018 |
| 2017 |
|
| Millions | | |
| Operating Revenue |
| $18.3 |
|
| $19.6 |
|
| Net Income |
| $6.8 |
|
| $3.8 |
|
Operating Revenue.)
Interest Expense decreased $1.3 million, or 7 percent, from 2017 primarily due to lower kWh sales at most of ALLETE Clean Energy’s wind energy facilities resulting from lower wind resources.
|
| | | | | | | | | | |
| | Quarter Ended June 30, |
| | 2018 | 2017 |
| Production and Operating Revenue | kWh | Revenue | kWh | Revenue |
| Millions | | | | |
| Wind Energy Facilities | | | | |
| Lake Benton | 49.0 |
|
| $2.8 |
| 58.4 |
|
| $3.1 |
|
| Storm Lake II | 31.7 |
| 2.3 |
| 35.0 |
| 2.3 |
|
| Condon | 24.0 |
| 1.9 |
| 20.6 |
| 1.7 |
|
| Storm Lake I | 41.3 |
| 2.9 |
| 49.4 |
| 3.0 |
|
| Chanarambie/Viking | 59.4 |
| 3.3 |
| 64.6 |
| 3.5 |
|
| Armenia Mountain | 55.5 |
| 5.1 |
| 62.5 |
| 6.0 |
|
| Total Production and Operating Revenue | 260.9 |
| $18.3 | 290.5 |
|
| $19.6 |
|
Net Income increased $3.0 million, or 79 percent, from 2017. Net income in 2018 included $3.9 million after-tax of additional production tax credits generated as ALLETE Clean Energy continues to execute its refurbishment strategy and a lower federal income tax rate due to the TCJA. Of the $3.9 million after-tax in additional production tax credits, $2.6 million resulted from the retrospective qualification of additional WTGs in 2016 and 2017 and $0.6 million resulted from the qualification of additional WTGs in the first quarter of 2018. These increases were partially offset by higher operating and maintenance expenses, and lower revenue resulting from lower wind resources.
U.S. Water Services
|
| | | | | | |
| Quarter Ended June 30, | 2018 |
| 2017 |
|
| Millions | | |
| Operating Revenue |
| $41.5 |
|
| $38.4 |
|
| Net Income |
| $0.2 |
|
| $0.6 |
|
Operating Revenue increased $3.1 million, or 8 percent, from 2017 primarily due to the acquisition of Tonka Water in September 2017. Revenue from chemical sales and related services was $35.2 million in 2018 compared to $32.7 million in 2017. Revenue from capital projects was $6.3 million for 2018 compared to $5.7 million in 2017; capital project sales can significantly fluctuate from period to period.
Net Income decreased $0.4 million from 2017. Net income in 2018 included higher operating expenses, partially offset by increased revenue primarily resulting from the September 2017 acquisition of Tonka Water. The second quarter of 2018 was also negatively impacted by the timing of capital project sales. Net income in 2018 also included $0.2 million of after-tax expense recognized as cost of sales related to purchase accounting for sales backlog.
COMPARISON OF THE QUARTERS ENDED JUNE 30, 2018 AND 2017 (Continued)
Corporate and Other
Operating Revenue decreased $3.9 million, or 13 percent, from 2017 primarily due to lower land sales at ALLETE Properties and lower revenue at BNI Energy, which operates under cost-plus fixed fee contracts, as a result of lower expenses in 2018 compared to 2017.
Net Loss was $1.7 million in 2018 compared to net income of $0.1 million in 2017. Results in 2018 decreased primarily due to additional income tax expense recorded in 2018 as GAAP requires the recognition of quarterly income tax expense at the estimated annual effective tax rate. The estimated annual effective tax rate can differ from what a quarterly effective tax rate would otherwise be on a stand-alone basis, and this may cause quarter to quarter differences in the timing of income taxes. Results in 2018 also included lower revenue at ALLETE Properties. The net loss at ALLETE Properties was $0.7 million in 2018 compared to a net loss of $0.4 million in 2017. Net income at BNI Energy was $1.8 million in 2018 compared to net income of $2.0 million in 2017.
Income Taxes – Consolidated
For the quarter ended June 30, 2018, the effective tax rate was a benefit of 20.8 percent (expense of 16.5 percent for the quarter ended June 30, 2017). The decrease from 2017 was primarily due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA and lower pre-tax income. (See Regulated Operations - Income Tax Expense.)
We expect our annual effective tax rate in 2018 to be lower than 2017 due to a reduction of the federal income tax rate as part of the TCJA, and lower pre-tax income. The effective rate deviated from the combined statutory rate of approximately 28 percent primarily due to production tax credits. (See Note 9. Income Tax Expense.) The estimated annual effective tax rate can differ from what a quarterly effective tax rate would otherwise be on a stand-alone basis, and this may cause quarter to quarter differences in the timing of income taxes.
COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017
(See Note 14. Business Segments for financial results by segment.)
Regulated Operations
|
| | | | | | |
| Six Months Ended June 30, | 2018 |
| 2017 |
|
| Millions | | |
| Operating Revenue – Utility |
| $528.0 |
|
| $546.5 |
|
| Fuel, Purchased Power and Gas – Utility | 197.4 |
| 189.7 |
|
| Transmission Services – Utility | 35.2 |
| 34.2 |
|
| Operating and Maintenance | 110.4 |
| 113.4 |
|
| Depreciation and Amortization | 78.8 |
| 78.7 |
|
| Taxes Other than Income Taxes | 28.1 |
| 25.9 |
|
| Operating Income | 78.1 |
| 104.6 |
|
| Interest Expense | (30.0 | ) | (28.5 | ) |
| Equity Earnings in ATC | 9.0 |
| 11.4 |
|
| Other Income | 2.6 |
| 2.5 |
|
| Income Before Income Taxes | 59.7 |
| 90.0 |
|
| Income Tax Expense (Benefit) | (10.2 | ) | 14.1 |
|
| Net Income |
| $69.9 |
|
| $75.9 |
|
Operating Revenue – Utility decreased $18.5 million, or 3 percent, from 2017 reflecting interim retail rate refund reserves, lower transmission revenue, provision for tax reform refund related to income tax changes resulting from the TCJA, lower financial incentives under the Minnesota conservation improvement program and lower FERC formula‑based rates, partially offset by higher revenue from kWh sales, conservation improvement program recoveries and cost recovery rider revenue.
COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017 (Continued)
Regulated Operations (Continued)
Interim rates, net of reserves, decreased $16.6 million from 2017 as interim rate refund reserves were recognized during 2018 due to the regulatory outcome of the MPUC’s decisions in Minnesota Power’s 2016 general rate case. (See Note 6. Regulatory Matters.)
Transmission revenue decreased $7.0 million primarily due to lower MISO-related revenue. (See Operating Expenses - Transmission Services – Utility.)
Provision for tax reform refund of $6.7 million related to income tax changes resulting from the TCJA was recognized during 2018. We have recorded the impact of these income tax changes for Minnesota Power and SWL&P as regulatory liabilities pending the outcome of regulatory proceedings with the MPUC and PSCW. (See Note 6. Regulatory Matters.)
Financial incentives under the Minnesota conservation improvement program were lower by $5.5 million from 2017 due to the timing of MPUC approval. The conservation improvement program financial incentive was recognized in the second quarter of 2017 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.
Revenue from wholesale customers under FERC formula-based rates decreased $1.6 million from 2017 primarily due to lower rates.
Revenue from kWh sales increased $10.1 million from 2017 primarily due to higher sales to Residential, Commercial, Industrial and Municipal customers in 2018. Sales to Industrial customers increased 1.3 percent primarily due to increased taconite production. USS Corporation restarted production at its Keetac plant in March 2017. Sales to Residential, Commercial and Municipal customers increased in 2018 primarily due to more favorable weather conditions in 2018 compared to 2017. Sales to Other Power Suppliers decreased 1.8 percent from 2017 as a result of increased sales to Industrial customers, which was more than offset by higher pricing on PSAs with these customers. Sales to Other Power Suppliers are sold at market-based prices into the MISO market on a daily basis or through bilateral agreements of various durations.
|
| | | | | | | | | | | |
| Kilowatt-hours Sold | | | | | Quantity | | % |
| Six Months Ended June 30, | 2018 |
| | 2017 |
| | Variance | | Variance |
| Millions | | | | | | | |
| Regulated Utility | | | | | | | |
| Retail and Municipal | | | | | | | |
| Residential | 585 |
| | 552 |
| | 33 |
| | 6.0 | % |
| Commercial | 706 |
| | 697 |
| | 9 |
| | 1.3 | % |
| Industrial | 3,624 |
| | 3,578 |
| | 46 |
| | 1.3 | % |
| Municipal | 407 |
| | 396 |
| | 11 |
| | 2.8 | % |
| Total Retail and Municipal | 5,322 |
| | 5,223 |
| | 99 |
| | 1.9 | % |
| Other Power Suppliers | 2,008 |
| | 2,045 |
| | (37 | ) | | (1.8 | )% |
| Total Regulated Utility Kilowatt-hours Sold | 7,330 |
| | 7,268 |
| | 62 |
| | 0.9 | % |
Revenue from electric sales to taconite and iron concentrate customers accounted for 21 percent of consolidated operating revenue in 2018 (22 percent in 2017). Revenue from electric sales to paper, pulp and secondary wood product customers accounted for 5 percent of consolidated operating revenue in 2018 (5 percent in 2017). Revenue from electric sales to pipelines and other industrial customers accounted for 7 percent of consolidated operating revenue in 2018 (7 percent in 2017).
Conservation improvement program recoveries increased $4.2 million from 2017 primarily due to an increase in related expenditures. (See Operating Expenses - Operating and Maintenance.)
Cost recovery rider revenue increased $2.6 million primarily due to higher expenditures related to the construction of the GNTL.
COMPARISON OF THE SIX MONTHS ENDED JUNE 30, 2018 AND 2017 (Continued)
Regulated Operations (Continued)
Operating Expenses increased $8.0 million or 2 percent from 2017.
Fuel, Purchased Power and Gas – Utility expense increased $7.7 million, or 4 percent, from 2017 primarily due to increased kWh sales and higher purchased power prices, partially offset by lower fuel costs. Fuel and purchased power expense related to our retail and municipal customers is recovered through the fuel adjustment clause.
Transmission Services – Utility expense increased $1.0 million, or 3 percent, from 2017 primarily due to higher MISO‑related expense. (See Operating Revenue – Utility.)
Operating and Maintenance expensedecreased $3.0 million, or 3 percent, from 2017 primarily due to lower salary and benefit expenses, and lower materials purchased for generation facilities, partially offset by a $4.2 million increase in conservation improvement program expenses in 2018. Conservation improvement program expenses are recovered from certain retail customers. (See Operating Revenue – Utility.)
Taxes Other than Income Taxes increased $2.2 million, or 8 percent, from 2017 primarily due to higher property tax expenses resulting from higher taxable plant.
Interest Expense increased $1.5 million, or 5 percent, from 20172018 primarily due to higherlower average long-term debt balances and lower interest rates. We record interest expense for Regulated Operations primarily based on rate base and authorized capital structure, and allocate the balance to Corporate and Other.
Equity Earnings in ATC decreased $2.4increased $0.5 million, or 2112 percent, from20172018 primarily due to the federal income tax rate change due to the TCJA, partially offset by additional investments in ATC. (See Note 7. Investment in ATC.)
Other Income increased $1.8 million from2018 reflecting various individually immaterial items.
Income Tax ExpenseBenefit decreased $24.3$2.4 million from 20172018 primarily due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, and lowerhigher pre-tax income. (See Note 6. Regulatory Matters.)
We expect our annual effective tax rate in 20182019 to be a lower income tax benefit than 2017in 2018 primarily due to the reduction of the federal income tax rate from 35 percent to 21 percent enacted as part of the TCJA, and lowerhigher pre-tax income.
ALLETE Clean Energy
| | | Six Months Ended June 30, | 2018 |
| 2017 |
| |
| Quarter Ended June 30, | | 2019 |
| 2018 |
|
| Millions | | |
| Operating Revenue |
| $42.9 |
|
| $43.3 |
|
| $15.4 |
|
| $18.3 |
|
| Net Income |
| $14.9 |
|
| $10.5 |
|
| $1.9 |
|
| $6.8 |
|