Otter Tail Corp

REGULATORY MATTERS

The following provides a summary of OTP's current and recent rate case filings, rate rider filings, and other regulatory filings that have or are expected to have a material impact on our operating results, financial position, or cash flows.

RATE CASES

The following includes a summary of electric rate cases as determined in OTP's most recent general rate case in each state:

North Dakota Rate Case: On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of return on equity of 10.6% on an equity ratio of 53.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost and investment recovery, with recovery moving from riders into base rates. The filing also includes a proposal to implement a sales adjustment mechanism to address potential significant load additions or losses. The filing included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023, and interim rates went into effect on January 1, 2024. These interim rate revenues, when collected, are subject to potential refund until the finalization of the rate case.

RATE RIDERS

The following table includes a summary of substantial pending and recently concluded rate rider proceedings:

RESOURCE PLANNING

On March 31, 2023, OTP submitted a supplemental resource plan filing to the MPUC, the NDPSC, and the South Dakota Public Utilities Commission (SDPUC). The supplemental filing updated OTP’s original 2022 Integrated Resource Plan (2022 IRP), which was filed on September 1, 2021. In the supplemental filing, OTP outlined its updated plan for meeting all customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates in light of several changes that had occurred since the original filing, including significant winter and spring reserve planning margins adopted by MISO, tax credits made available for renewable energy projects under the Inflation Reduction Act, the enactment of the Clean Energy Bill in Minnesota, and volatility experienced in energy and capacity markets.

On December 15, 2023, OTP submitted a second supplemental resource plan filing to the MPUC outlining an updated plan specifically for meeting Minnesota customers’ anticipated capacity and energy needs while maintaining system reliability and low electric service rates. Based on feedback received on the preferred plan outlined in the March 31, 2023 supplemental filing and the inability to reach a consensus on certain aspects of the plan, the second supplemental filing includes a proposal to bifurcate OTP's resource planning by jurisdiction.

Under bifurcated resource planning, it is anticipated that OTP would develop two separate resource plans, one plan developed for Minnesota and a second developed for North Dakota and South Dakota. Each plan would be developed incorporating the assumption that all existing generation resources, except Hoot Lake Solar, would continue to be allocated to all jurisdictions using established jurisdictional allocators. Hoot Lake Solar is currently directly allocated to only Minnesota. As new generation resources are needed for each plan, those generation resources would be allocated to the jurisdiction that is needing the resource. To the extent a common generation resource is needed for both plans, that resource would be allocated using established jurisdictional allocators. This method of resource planning would diverge from OTP’s historical practice of planning on an integrated basis for all jurisdictions served.

With the proposal of bifurcated resource planning, the supplemental filing outlines OTP’s preferred plan for Minnesota only. The preferred plan in this supplemental filing includes:

•repowering four of our existing wind facilities in 2025;

•the addition of approximately 200 megawatts of solar generation in 2025;

•the addition of approximately 100 megawatts of wind generation in 2026;

•the addition of on-site liquefied natural gas fuel storage at our Astoria Station natural gas plant in 2027;

•the designation of Coyote Station, a jointly owned coal-fired generation plant, as an Available Maximum Emergency (AME) Resource beginning in 2029 and annually thereafter;

•a withdrawal from our 35 percent ownership interest in Coyote Station in the event we are required to make a major, non-routine capital investment in the plant; and

•the addition of approximately 50 megawatts of wind generation in 2032.

The preferred plan requests the MPUC issue an order requiring the Minnesota’s jurisdictionally allocated share of the generation from Coyote Station be designated as an AME Resource beginning March 1, 2029, subject to additional analysis to be performed by OTP. AME Resources are resources called on only in the event of a maximum generation event, such as in the cases of extreme heat, cold, or other extreme events. Designating Coyote Station as an AME Resource would allow us to retain Coyote Station’s capacity, thereby providing an important reliability benefit. This also helps ensure we remain compliant with market monitoring regulations and our contractual obligations to the co-owners of Coyote Station while advancing our compliance with Minnesota's carbon-free standard. The supplemental filing requests Minnesota customer rates continue to include the recovery of an allocated share of OTP’s costs associated with owning the plant, and a return on those costs, as well as the fixed costs of operating the plant. The variable cost of operating the plant, which consists primarily of variable fuel costs, would not be attributed to Minnesota customers, except when the plant is called upon to serve Minnesota customers in emergency situations.

The supplemental IRP filing made December 15, 2023 outlines our proposed resource plan for Minnesota. We anticipate filing future resource plans on a bifurcated basis in North Dakota and South Dakota.

LIQUIDITY

LIQUIDITY OVERVIEW

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets, and borrowing ability, because of investment-grade credit ratings, when taken together, provide us ample liquidity to conduct business operations and fund our capital expenditure program. Our liquidity, including our operating cash flows and access to capital markets, could be impacted by macroeconomic factors outside of our control. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of December 31, 2023, we were in compliance with all debt covenants (see the Financial Covenant section under Capital Resources below).

The following table presents the status of our lines of credit as of December 31, 2023 and 2022:

OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. Should additional liquidity be needed, the OTC Credit Agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $250 million, subject to certain terms and conditions.

As of December 31, 2023, we had $249.4 million of available liquidity under our credit facilities and $230.4 million of available cash and cash equivalents, resulting in total available liquidity of $479.8 million, compared to total available liquidity of $441.2 million as of December 31, 2022.

CASH FLOWS

The following is a discussion of our cash flows for the years ended December 31, 2023 and 2022:

Net Cash Provided by Operating Activities increased $15.2 million primarily due to an increase in net income, the absence of any pension contribution in 2023 due to the plan's funded status, and the timing of customer collections of forecasted fuel costs, partially offset by increased working capital. Working capital increased primarily due to an increase in receivables in our Plastics segment, due to increased sales volumes in the fourth quarter of the current year, and a decrease in payables due to the timing of capital investment spending in our Electric segment and inventory purchases in our Plastics segment compared to last year.

Unique market dynamics experienced by our Plastics segment businesses in 2023 and 2022 resulted in a significant increase in our overall cash from operations compared to prior periods, and we do not expect cash from operations at these levels to continue in future years.

Net Cash Used in Investment Activities increased $114.2 million primarily due to a higher amount of Electric segment capital investment compared to last year, including the purchase of the Ashtabula III wind farm, investments in our Hoot Lake Solar facility and several wind repowering projects, transmission and distribution asset investments, and investments in new technology. Capital expenditures in our Manufacturing and Plastics segments increased $23.1 million as a result of investments in additional equipment and facility expansion projects at our Plastics segment facility in Arizona and our Manufacturing segment facility in Georgia.

Net Cash Used in Financing Activities decreased $92.9 million primarily due to increased short-term borrowings on our OTP credit facility, which were primarily used to fund capital expenditures in our Electric segment, including the acquisition of the Ashtabula III wind farm. Our financing activities in 2023 included net short-term borrowings of $73.2 million compared to net short-term repayments of $83.0 million in 2022. There was no change in our long-term debt in 2023. In 2022, OTP issued $60.0 million of long-term debt, net of retirements, which was primarily used to fund the repayment of short-term credit facility borrowings and fund capital expenditures. In 2023, we made dividend payments of $73.1 million compared to $68.8 million in 2022.

CAPITAL REQUIREMENTS

CAPITAL EXPENDITURES

Our capital expenditure plan includes investments in electric generation facilities, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. Our capital expenditure plan is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory changes, business expansion opportunities, the costs of labor, materials and equipment and our financial condition.

The following provides a summary of capital expenditures for the years ended December 31, 2023 and 2022 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2024 through 2028:

CONTRACTUAL OBLIGATIONS

The following table summarizes our contractual obligations at December 31, 2023 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.

Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company (CCMC) under the Lignite Sales Agreement (LSA) that ends in 2040. Postretirement benefit obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan (ESSRP), but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make any contributions to that plan.

COMMON STOCK DIVIDENDS

We paid dividends to our shareholders totaling $73.1 million, or $1.75 per share, in 2023. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, level of earnings and cash flows from operations, our capital expenditure plan and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC subsidiaries to OTC. These intercompany distributions serve as the primary source of funding for dividends paid to our shareholders. See Note 14 to our consolidated financial statements included in this report on Form 10-K for additional information. The decision to declare a dividend is reviewed quarterly by our Board of Directors. On February 5, 2024, our Board of Directors increased the quarterly dividend from $0.4375 to $0.4675 per common share.

CAPITAL RESOURCES

Financial flexibility is provided by operating cash flows, borrowing capacity under our lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing. Debt financing will be required in the five-year period from 2024 through 2028 to refinance maturing debt and to finance our capital investments within our Electric segment. Our financing plans are subject to change and are impacted by our planned level of capital investments, a decision to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes.

REGISTRATION STATEMENTS

On May 3, 2021, we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement expires in May 2024, at which time we anticipate filing a new shelf registration statement. No shares were issued pursuant to the registration statement in 2023.

On May 3, 2021, we filed a second registration statement with the SEC for the issuance of up to 1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends or making optional cash investments. Shares purchased under the plan may be new issue common shares or common shares purchased on the open market. The registration statement expires in May 2024, at which time we plan to file a new registration statement. In 2023, we issued 105,663 shares under the plan. All shares issued under the plan to date have been open market purchases and there have been no new issue shares, resulting in no proceeds received by the Company. As of December 31, 2023, 1,145,330 shares remained available for purchase or issuance under the plan.

SHORT-TERM DEBT

The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit. The agreements generally bear interest at the Secured Overnight Financing Rate (SOFR) plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the issuer. The weighted-average interest rate on all outstanding borrowings as of December 31, 2023 and 2022 was 6.70% and 5.61%.

The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2023:

LONG-TERM DEBT

At December 31, 2023, we had $827.0 million of principal outstanding under long-term debt arrangements. Note 9 to our consolidated financial statements included in this report on Form 10-K includes information regarding these instruments. The agreements generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2026 to 2052.

Financial Covenants

Certain of our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2023, we were in compliance with these financial covenants as further described below:

OTC, under its financial covenants, may not permit its ratio of Interest-Bearing Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Indebtedness to exceed 10% of our Total Capitalization. As of December 31, 2023, our Interest-Bearing Debt to Total Capitalization was 0.39 to 1.00, our Interest and Dividend Coverage Ratio was 10.85 to 1.00 and we had no Priority Indebtedness outstanding.

OTP, under its financial covenants, may not permit its ratio of Debt to Total Capitalization to exceed 0.60 to 1.00, may not permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, and may not permit its Priority Debt to exceed 20% of its Total Capitalization. As of December 31, 2023, OTP's Interest-Bearing Debt to Total Capitalization was 0.46 to 1.00, its Interest and Dividend Coverage Ratio was 3.54 to 1.00 and it had no Priority Indebtedness outstanding.

None of our debt agreements include any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

Credit Ratings

The credit ratings of OTC and OTP as of December 31, 2023 are summarized below:

CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and the Company’s discussion and analysis of its financial condition and operating results requires management to make assumptions, estimates and judgments that affect the reported amounts. While we believe the estimates, assumptions, and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of our Board of Directors. The following critical accounting policies affect the most significant judgments and estimates used in the preparation of our consolidated financial statements.

REGULATORY ACCOUNTING

Our utility business is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. Accordingly, our utility business must adhere to the accounting requirements of regulated operations, which requires the recognition of regulatory assets and regulatory liabilities for amounts that otherwise would impact the statement of income or comprehensive income when it is probable that such amounts will be collected from customers or credited to customers through the rate-making process. This guidance also provides recognition criteria for adjustments to rates outside of a general rate case proceeding which are provided to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. Regulatory assets generally represent costs that have been incurred but have been deferred because future recovery from customers, as established through the rate-making process, is probable. Regulatory liabilities generally represent amounts to be refunded to customers or amounts currently collected from customers for future costs.

We assess the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Our probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which we operate and the impact these incurred costs may have on our customers. Changes in our assessments regarding the likelihood of recovery or settlement of our regulatory assets and liabilities may have a material impact on our operating results and financial position. Further, if we determine that all or a portion of our utility business no longer meets the criteria for continued application of regulatory accounting, or our regulators disallow recovery of a previously incurred cost or eliminate a regulatory liability, we would be required to remove the associated regulatory assets and liabilities from our consolidated balance sheets and recognize those amounts in the consolidated statement of income as an expense or income item, or in the consolidated statement of comprehensive income as a loss or gain item, in the period in which this accounting treatment is no longer applicable.

As of December 31, 2023 and 2022, we had regulatory assets of $111.8 million and $119.7 million and regulatory liabilities of $302.0 million and $261.8 million. If future recovery of amounts recorded as regulatory assets was no longer probable we would be required to recognize an expense or loss in the period in which recovery was deemed to no longer be probable.

PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS

Pension and postretirement benefit liabilities and expenses are determined by actuaries using assumptions about the discount rate, expected return on plan assets, rate of compensation increase and healthcare cost-trend rates. See Note 10 to our consolidated financial statements included in this report on Form 10-K for additional information on our pension and postretirement benefit plans and related assumptions.

These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 30 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Likewise, compensation decreases and healthcare cost decreases or an increase in the discount rate applied from one year to the next can significantly decrease our benefit expenses in the year of the change. Also, a change in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well above or below assumed rates of return or a change in the anticipated life expectancy of plan participants could result in significant increases or decreases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.

We estimate the discount rate through the use of a hypothetical bond portfolio method, which incorporates yields on a collection of high credit quality bonds that produce cash flows similar to our anticipated future benefit payments.

We estimate the assumed long-term rate of return on plan assets based on asset category studies using historical market returns achieved by our asset portfolio allocation over long-term periods, as well as long-term projected return levels.

Pension plan assets are invested in a portfolio according to our return, liquidity and diversification objectives to provide a source of funding for plan obligations and manage contributions to the plan. The principal process for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.

At December 31, 2023, we set the discount rate used to measure our pension plan obligations at 5.57% and at 5.53% to measure postretirement healthcare obligations, a six and one basis point increase, respectively, from the estimates used at December 31, 2022. Our estimates used to determine benefit cost for 2023 included a discount rate of 5.51% for pension benefits and 5.52% for postretirement healthcare costs, a 248 and 251 basis point increase, respectively, from 2022 estimates. The 5.52% discount rate for postretirement healthcare costs was adjusted to 6.06% effective September 30, 2023, in connection with a remeasurement of our plan liability due to an amendment to the plan. The adjustment to 6.06% was a 305 basis point increase from the 2022 estimate. In addition, we estimated our assumed rate of return on pension assets to be 7.00% for 2023, a 70 basis point increase from our 2022 estimate.

The following table summarizes the impact on 2023 pension and postretirement costs for a 25 basis point increase or decrease, holding all other variables constant, on certain key assumptions:

For 2024, we expect pension and other postretirement benefit income to be $8.5 million compared to $9.5 million of income in 2023, due to the impacts of updated actuarial assumptions. See additional information at footnote 10 of the consolidated financial statements.

Subsequent increases or decreases in actual rates of return on plan assets over assumed rates, increases or decreases in the discount rate, increases in future compensation levels, and increases in retiree healthcare cost inflation rates could significantly change projected costs.

We believe the estimates made for our pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are subject to change.

GOODWILL IMPAIRMENT

Goodwill is required to be evaluated annually for impairment and more frequently as events or circumstances require. Goodwill is tested for impairment at the reporting unit level. We have identified two reporting units which carry a material amount of goodwill.

The goodwill impairment test is a single-step quantitative assessment which compares the estimated fair value of the reporting unit to its carrying value. An impairment charge is recognized if the carrying amount exceeds the estimated fair value in an amount that is equal to the excess but limited to the amount of recorded goodwill of the reporting unit. An optional qualitative impairment assessment may be performed prior to and may eliminate the need to perform the quantitative assessment.

Estimating the fair value of a reporting unit under the quantitative impairment method requires significant judgments and estimates. We estimate the fair value of our reporting units primarily using an income approach, which includes a discounted cash flow methodology to arrive at a fair value estimate by determining the present value of projected future cash flows over a specified period plus a terminal value to reflect cash flows beyond the projection period. The discount rate applied to the estimated future cash flows reflects our estimate of the weighted-average cost of capital of comparable entities. To supplement our income approach, we reference various market indications of fair value, where available, and include fair value estimates using multiples derived from comparable enterprise values to earnings before interest, taxes, depreciation, and amortization (EBITDA), and, if available, comparable sales transactions for comparative peer companies.

Our discounted cash flow methodology incorporates significant estimates, which include assumptions of future operating results and cash flows, which are impacted by economic and industry conditions, the amount and timing of estimated capital expenditures, an estimated terminal growth rate and the selection of an appropriate weighted-average cost of capital, among others.

Our goodwill impairment testing performed in the fourth quarter of 2023 indicated no impairment was present for either reporting unit and the estimated fair value of each reporting unit substantially exceeded the respective carrying value. As part of our testing, we perform various sensitivity analyses to understand if our conclusions are sensitive to changes in certain assumptions. A 1% decrease in projected operating revenues, a one hundred basis point decrease in projected gross profit margins and a twenty five basis point increase in the discount rate would not lead to a goodwill impairment charge for either reporting unit.

We believe the estimates and assumptions used in our impairment assessments are reasonable and based on the best information available. However, these estimates and assumptions include an inherent degree of uncertainty. Significant adverse changes in our expectations for any of these estimates could result in an impairment charge in a future period which may materially impact our operating results and financial position.