The following abbreviations or acronyms are used in the text. References in this report to “we,” “us” and “our” are to ALLETE, Inc., and its subsidiaries, collectively.

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:

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 2018 Form 10-K. Any forward-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.

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 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.

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 recordedrecognized on the Consolidated Balance Sheet.

The majority of our operating leases are for heavy equipment, vehicles and land with fixed monthly payments which we group into two categories: Vehicles and Equipment; and Land and Other. Our largest operating lease is for the dragline at BNI Energy which includes a termination payment at the end of the lease term if we do not exercise our purchase option. The amount of this payment is $3 million and is included in our calculation of the right-of-use assetassets and lease liabilityliabilities recorded. None of our other leases contain residual value guarantees.

TheAdditional information on the components of lease cost and presentation of cash flows were as follows:

Maturities of lease liabilities were as follows:

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 following paragraphs.

In 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 capacity dedication agreement. These agreements wereThe 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‑firedgas-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.

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.

As a result of completing the sale of U.S. Water Services on March 26, 2019, there was no0 goodwill recorded as of March 31,September 30, 2019 ($148.5 million at December 31, 2018).

The balance of intangible assets, net, as of March 31,September 30, 2019, is as follows:

Amortization expense for intangible assets was $1.4$1.5 million for the threenine months ended March 31,September 30, 2019 and 2018.($4.1 million for the nine months ended September 30, 2018). The remaining definite-lived intangible assets will continue to be amortized ratably through 2028.

The Level 3 liability in the preceding table is related to the contingent consideration liability that resulted from the 2015 acquisition of U.S. Water Services. Based on the terms and conditions of the acquisition agreement, a final payout of $3.8 million was made in the first quarter of 2019 for the remaining outstanding shares.

The following tables present the Company’s short-term and long-term debt as of March 31,September 30, 2019, and December 31, 2018:

On 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 $60$100 million in letters of credit.

On March 1, 2019, ALLETE issued and sold the following First Mortgage Bonds (the Bonds):

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 useused 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.

Our PPAs are summarized in Note 11. Commitments, Guarantees and Contingencies to the Consolidated Financial Statements in our 2018 Form 10-K, with additional disclosure provided in the following paragraphs.

In a 2016 order, the MPUC approved the route permit for the GNTL, and in 2016, the U.S. Department of Energy issued a presidential permit to cross the U.S.‑CanadianU.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, with construction expectedand 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 $700 million, of which Minnesota Power’s portion is expected to be between $300 million and $350approximately $325 million; the difference will be recovered from a subsidiary of Manitoba Hydro as non-shareholder contributions to capital. Total project costs of $458.2$581.6 million have been incurred through March 31,September 30, 2019, of which $245.0$310.4 million has been recovered from a subsidiary of Manitoba Hydro.

Manitoba Hydro must obtain regulatory and governmental approvals related to the MMTP, a new transmission line in Canada 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 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, which was recommended for approval on November 15, 2018. ApprovalOn June 14, 2019, Manitoba Hydro announced Canada’s federal government approved the MMTP project and on August 22, 2019, the NEB granted final pre-construction approvals. Construction on the MMTP commenced in the third quarter of the Canadian federal cabinet is also required.2019.

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 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.

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.

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.

The EPA repealed the Clean Power Plan (CPP), following a determination by the EPA that the CPP exceeded the EPA’s statutory authority under the Clean Air Act (CAA). The primary reason for this was that the CPP attempted to regulate electric generating unit’s carbon emissions through measures outside of the affected unit’s direct control. The CPP was first announced as a proposed rule under Section 111(d) of the Clean Air Act for existing power plants entitled “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units”, also referred to as.

With the Clean Power Plan (CPP). The EPA issued the final CPP in 2015, together with a proposed federal implementation plan and a model rule for emissions trading. In 2016, the U.S. Supreme Court issued an order staying the effectiveness of the rule until after the appellate court process is complete. In 2016, the U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments and is currently deliberating. If the CPP is upheld at the completion of the appellate process, allrepeal of the CPP, regulatory deadlines are expected to be reset based on the length of time that the appeals process takes. The EPA is precluded from enforcing the CPP while the U.S. Supreme Court stay is in force.

The proposedAdditionally, the EPA finalized new regulations for the state implementation of the Affordable Clean Energy Rule seeks to reduce carbon intensity at existing steam generation units by prescribing Best System of Emission Reduction (BSER), primarily through Heat Rate Improvement (HRI) technologies. Under the proposal, statesand any future emission guidelines issued under CAA Section 111(d). States will have up to three years to submit State Implementation Plans (SIP), and the EPA has 12 months to review and approve those plans. Since the Affordable Clean Energy Rule allows states considerable flexibility in how to best implement its requirements, Minnesota Power plans to work closely with the MPCA and the Minnesota Department of Commerce, who are currently co-reviewing the rule as the state develops its SIP. If a state does not submit a SIP or submits a SIP that is unacceptable to the EPA, the EPA will develop a Federal Implementation Plan. We currently anticipate that the MPCA will develop a SIP which is subject to EPA approval. While many offor the HRIs proposed by the EPA in the proposed rule have already been installed in Minnesota Power’s largest coal-fired generating units, compliance specifics would be detailed in either Minnesota’s SIP or a FIP.Affordable Clean Energy Rule.