Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our financial condition and results of operations together with our financial statements and the related notes appearing under Item 8 of this Form 10-K.
OVERVIEW
Otter Tail Corporation (OTC) and its subsidiaries form a diverse group of businesses with operations classified into three segments: Electric, Manufacturing and Plastics. Our Electric business is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve our customers in western Minnesota, eastern North Dakota and northeastern South Dakota. Our Manufacturing segment provides metal fabrication for custom machine parts and metal components and manufactures extruded and thermoformed plastic products. Our Plastics segment manufactures PVC pipe for use in, among other applications, municipal and rural water, wastewater and water reclamation projects.
Our strategy includes investing in rate base growth opportunities in our Electric segment and capitalizing on organic growth opportunities in our Manufacturing and Plastics segments. Investments in our Electric segment are expected to produce increased earnings and cash flow potential and lower our overall risk, create a more predictable earnings stream, improve our credit quality and preserve our ability to fund our dividend. Our Electric segment is complemented by our Manufacturing and Plastics segment businesses, which we expect to contribute to earnings growth by capitalizing on market expansion opportunities and increasing utilization of existing capacities and planned investments to create additional capacity and increased efficiencies. Collectively, our mix of businesses is expected to contribute to the achievement of our targeted annual growth in earnings per share of five to seven percent over the next several years, using 2020 as the base for measurement.
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In 2021, all of our businesses were able to effectively manage through the challenges resulting from the COVID-19 pandemic and other marketplace challenges, including supply chain disruptions and rapidly escalating costs for certain raw material components used in our manufacturing processes. We continue to remain focused on maintaining the health and safety of our employees, customers and communities and ensuring continued electrical reliability and continuous delivery of our products to our customers.
2021 FINANCIAL RESULTS
Our Electric segment produced earnings growth of 8.5% in 2021, driven by returns on our recent rate base investments. Our Merricourt wind farm and Astoria Station natural gas plant, which collectively constitute a $420 million investment, were completed and placed in service in the fourth quarter of 2020 and the first quarter of 2021, respectively. Recovery of these investments and associated operating costs through either rate riders or interim rates provided under our Minnesota rate case led to increasing operating revenues and net income.
Our Manufacturing segment produced earnings growth in 2021 of 55.6%, as strong end market demand across most of the markets we serve led to increased sales volumes. Higher production volumes to meet customer demand led to improved leveraging of fixed manufacturing costs which, along with increased prices, led to improved gross profit levels. Our Manufacturing segment was impacted in 2021 by steel supply constraints and a significant increase in steel prices, as further discussed below.
Our Plastics segment produced earnings of $97.8 million in 2021, compared to $27.6 million in 2020. The unprecedented level of earnings in 2021 resulted from extraordinary industry supply and demand dynamics. As further described below, supply shortages of resin, the primary raw material used in the manufacturing of PVC pipe, coupled with robust end market demand for PVC pipe led to a rapid escalation in PVC pipe prices and gross margins. Our ability to manage through these supply disruptions and to deliver products to our customers allowed us to capitalize on these unique industry conditions.
Collectively in 2021, our businesses generated net income of $176.8 million, or $4.23 per diluted share, an increase of 84.4% from $95.9 million, or $2.34 per diluted share, in 2020. In 2021, we paid an annual dividend of $1.56 per share, or $64.9 million, completing our 83rd consecutive year of dividend payments to our shareholders.
Our earnings mix in 2021 was 41% from our Electric segment and 59% from the combination of our Manufacturing and Plastics segments net of unallocated corporate costs. Electric segment earnings as a percentage of our total earnings were less than our long-term estimate of 70% due to the unique market conditions that occurred in our Plastics segment. We expect our earnings mix to return back to our expected 70% from our Electric segment and 30% from our Manufacturing and Plastics segments over the long term as the conditions within the Plastics' industry subside.
RESOURCE MATERIAL AVAILABILITY AND PRICING
Supply shortages and the cost of steel and resin, two key material inputs to our Manufacturing and Plastics segments, respectively, significantly impacted our operating results in 2021.
Steel supply shortages arose in 2021 following steel mill capacity reductions in 2020 in response to lower demand due to COVID-19. Production and availability of steel began to improve late in 2021 after steel mill facilities increased production capacities in response to strong market demand for steel products. The combination of supply shortages and strong end user demand led to significantly increased steel prices. The increase in steel prices led to increased sale prices for our products at BTD, our metal fabrication business within our Manufacturing segment, as we passed along material cost increases to our customers. Limited steel availability also heightened the complexity in managing our business, including effective management of our production and shipping schedules. Steel costs began to recede late in 2021, but we anticipate steel prices will remain elevated relative to historic norms through at least the first half of 2022.
PVC resin is the primary material input of the PVC pipe manufactured by our Plastics segment businesses. Resin supply disruptions initially arose as a result of production plant shutdowns due to abnormally low temperatures and ice storms in the Gulf Coast region of the United States in the first quarter of 2021 and were exacerbated by hurricane activity in the third quarter of the year. These supply disruptions, along with robust domestic and global demand for PVC resin led to significantly increased resin prices.
Limited PVC resin resulted in reduced manufacturing of PVC pipe and low pipe inventories across the industry. The combination of constrained PVC resin supply and the resulting low PVC pipe inventories along with significantly increased PVC resin costs and robust demand for PVC pipe led to rapidly increasing sale prices for PVC pipe, with the increase in sale prices outpacing the increase in PVC resin costs, leading to expanding gross profit margins and a significant increase in earnings in our Plastics segment. We anticipate these market dynamics will continue through the first quarter of 2022 but begin to subside thereafter.
The marketplace dynamics impacting both our Manufacturing and Plastics segments are fluid and subject to change which may impact our operating results prospectively.
COVID-19
We continue to monitor the progression of COVID-19 and its impact on our business. As this pandemic continues, we are following the directives and advice of government leaders and medical professionals and have adopted practices to help curtail the spread of the virus and mitigate its impact on our employees, customers, vendors and other business partners, and communities in which we live and work.
While the impact of COVID-19 and the resulting macroeconomic conditions did not materially impact our operating results in 2021, uncertainty remains regarding the magnitude and duration of the pandemic and the resulting potential future financial effects. Increased infection rates and any future responses to mitigate the spread of the virus, including any potential vaccination mandates that would apply to our employees, could impact our business and our financial results in future periods.
OSHA has issued an ETS requiring all employers with at least 100 employees to ensure their employees are fully vaccinated or require weekly testing for unvaccinated employees, and President Biden has issued an executive order, which requires employees of certain federal contractors
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and covered subcontractors to be vaccinated, with no weekly testing option, unless they have an approved disability or religious exemption. OSHA has withdrawn its ETS, however, they have emphasized that the ETS will continue to serve as its proposal for a permanent standard. Currently, the mandate set forth by the President's executive order has been halted as several states are challenging its legality and the matter remains in litigation. If these mandates are upheld in federal court and become effective, we expect one, or both, of these new regulations will apply to at least some, and possibly all, of our businesses which could require us to mandate COVID-19 vaccination of our workforce or have our unvaccinated employees undergo required weekly COVID-19 testing, or some combination thereof, which could be difficult and costly. Further, additional vaccine and testing mandates may be announced in jurisdictions in which we operate our business, and there could be potential actions by certain states that are in conflict with the federal mandates, the impacts of which remain uncertain. Requirements to mandate COVID-19 vaccination of our workforce or requirements of our unvaccinated employees to be tested could result in labor disruptions, employee attrition and difficulty securing future labor needs.
We continue to monitor developments involving our workforce, customers, construction contractors, suppliers and vendors and the financial effects on our business. However, due to the unprecedented and evolving nature of this pandemic, we cannot predict the full extent of the impact COVID-19 will have on our operating results, financial condition and liquidity.
FINANCIAL AND OTHER METRICS
Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.
Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
Otter Tail Power Company (OTP) generally bases its forecasted kilowatt-hour (kwh) sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast and on period-to-period results.
Utility Rate Base is the value of property on which a public utility is permitted to earn a specified rate of return in accordance with rules set by a regulatory agency. In general, rate base consists of the value of property used by the utility in providing service. Rate base can also include: cash, working capital, materials and supplies, deductions for accumulated provisions for depreciation, contributions in aid of construction, customer advances for construction, accumulated deferred income taxes, and accumulated deferred investment tax credits, dependent on the method that is used in the calculation, which can vary from jurisdiction to jurisdiction. We present actual and forecasted levels of utility rate base to provide an indication of expected investments on which we expect to earn future returns.
RESULTS OF OPERATIONS
For a comparison of fiscal year 2020 to 2019, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our report on Form 10-K for the fiscal year ended December 31, 2020, filed with the SEC on February 19, 2021 and incorporated by reference into this report on Form 10-K.
Provided below is a summary and discussion of our operating results on a consolidated basis followed by a discussion of the operating results of each of our segments, Electric, Manufacturing and Plastics. Intersegment transactions were not material in 2021 or 2020 and amounted to less than $0.1 million of operating revenues and operating expenses for each year. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated statements of income.
CONSOLIDATED RESULTS
The following table summarizes our consolidated results of operations for the years ended December 31, 2021 and 2020:
(in thousands) 2021 2020 $ change % change
Operating Revenues $ 1,196,844 $ 890,107 $ 306,737 34.5 %
Operating Expenses 947,136 742,221 204,915 27.6
Operating Income 249,708 147,886 101,822 68.9
Interest Charges 37,771 34,447 3,324 9.6
Nonservice Cost Components of Postretirement Benefits 2,016 3,437 (1,421) (41.3)
Other Income 2,900 6,055 (3,155) (52.1)
Income Before Income Taxes 212,821 116,057 96,764 83.4
Income Tax Expense 36,052 20,206 15,846 78.4
Net Income $ 176,769 $ 95,851 $ 80,918 84.4 %
Operating Revenues increased $306.7 million on a consolidated basis in 2021. Each operating segment contributed to the growth in operating revenues. Electric segment operating revenue increased 7.7% primarily due to increased retail, transmission and wholesale revenues. Manufacturing segment operating revenues increased 40.8% mainly as a result of higher material input costs, primarily steel, which are passed
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through to customers, and increased volumes due to strong end market demand. Plastics segment operating revenues increased 85.3% primarily due to unique supply and demand dynamics resulting from resin supply constraints coupled with robust demand for PVC pipe leading to rapid and significant increases in sale prices of PVC pipe. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses increased $204.9 million in 2021. Electric segment operating expenses increased 10.1% primarily due to increased production fuel and purchased power costs along with incremental operating costs and depreciation expense rising from our recent rate base investments. Operating expenses in our Manufacturing segment increased 40.2%, driven by increased cost of products sold, which resulted from higher material input costs and increased sales volumes, and increased other operating expenses. Operating expenses in our Plastics segment increased 47.8% primarily due to higher costs of products sold from higher resin inputs costs. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Charges increased $3.3 million in 2021 due to a $40.0 million long-term debt issuance in August 2020, a higher level of short-term debt borrowings outstanding in 2021 and a lower level of capitalized interest due to the completion and placement in service of Astoria Station in the first quarter of 2021. The increase in our short- and long-term debt borrowings were largely used to finance the rate base investments in our Electric segment.
Nonservice Cost Components of Postretirement Benefits decreased $1.4 million in 2021 mostly due to a decrease in nonservice costs of our postretirement healthcare plan reflecting the effect of plan amendments adopted in 2020 and 2019.
Other Income decreased $3.2 million in 2021 due to a reduction of allowance for equity funds used during construction (AFUDC) on Electric segment investments, mainly for the Minnesota share of Astoria Station. Astoria Station was placed into service, and the recognition of AFUDC discontinued, in the first quarter of 2021.
Income Tax Expense increased $15.8 million in 2021 primarily due to an increase in income before income taxes, but partially offset by an increase in production tax credits generated from our Merricourt wind farm, which was placed in service in the fourth quarter of 2020. Our effective tax rate was 16.9% in 2021 and 17.4% in 2020. See Note 12 to our consolidated financial statements included in the report on Form 10-K for additional information regarding factors impacting our effective tax rate.
ELECTRIC SEGMENT RESULTS
The following table summarizes the operating results of our Electric segment for the years ended December 31, 2021 and 2020:
(in thousands) 2021 2020 $ change % change
Retail Sales Revenue $ 405,484 $ 389,522 $ 15,962 4.1 %
Transmission Services Revenues 48,835 44,001 4,834 11.0
Wholesale Revenues 17,936 4,857 13,079 269.3
Other Electric Revenues 8,066 7,750 316 4.1
Total Operating Revenue 480,321 446,130 34,191 7.7
Production Fuel 59,327 46,296 13,031 28.1
Purchased Power 65,409 61,698 3,711 6.0
Operating and Maintenance Expenses 159,669 150,848 8,821 5.8
Depreciation and Amortization 71,343 63,171 8,172 12.9
Property Taxes 17,609 17,034 575 3.4
Operating Income $ 106,964 $ 107,083 $ (119) (0.1) %
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales 4,789,879 4,776,687 13,192 0.3 %
Wholesale kwh Sales 420,044 236,528 183,516 77.6
Heating Degree Days 5,794 6,174 (380) (6.2)
Cooling Degree Days 704 534 170 31.8
Our Electric segment operating results are impacted by fluctuations in weather conditions and the resulting demand for electricity for heating and cooling. The following table presents heating and cooling degree days as a percent of normal for the years ended December 31, 2021 and 2020:
2021 2020
Heating Degree Days 91.3 % 97.2 %
Cooling Degree Days 151.7 % 116.3 %
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions for the years ended December 31, 2021 and 2020, and between years:
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2021 vs
Normal
2021 vs
2020
2020 vs
Normal
Effect on Diluted Earnings Per Share $ 0.01 $ 0.01 $ —
Retail Revenues increased $16.0 million primarily due to the following:
• An $8.1 million increase in fuel recovery revenues primarily resulting from increased production fuel and purchase power costs, both of which were impacted by increasing natural gas prices throughout most of 2021. Partially offsetting this increase are credits provided to retail customers from increased margins recognized on wholesale sales.
• A $6.6 million increase in rider revenues in our North Dakota and South Dakota jurisdictions primarily to recover our investments in and costs to operate Merricourt and Astoria Station.
• A $5.0 million increase in new retail revenues from an interim rate increase in Minnesota, net of estimated refunds.
These increases in retail revenue were partially offset by the impact of reduced demand, exclusive of the impact of weather, from residential customers, and net of the effect of a change in customer usage mix. In addition, retail revenue in 2020 benefited from the recognition of $2.6 million of Minnesota transmission rider revenue resulting from a favorable judicial decision regarding the state jurisdictional treatment of federally approved transmission projects.
Transmission Services Revenues increased $4.8 million primarily due to increased recovery of higher transmission costs and increased transmission investment along with increased generator interconnection revenues.
Wholesale Revenues increased $13.1 million as a result of a 77.6% increase in wholesale sales volumes and a 107.9% increase in wholesale prices driven by increased fuel costs and market demand for wholesale energy, which serves to drive up spot market prices for electricity.
Production Fuel costs increased $13.0 million as a result of a 16.9% increase in kwhs generated from our fuel-burning plants, largely driven by output from Astoria Station after energy generation commenced in April of 2021.
Purchased Power costs increased $3.7 million due to a 27.9% increase in the cost per kwh purchased in 2021. This increase was partially offset by a 17.1% decrease in the volume of purchased power in 2021 as our recent generation additions provide additional generation resources to serve customer demand and market conditions led to operating our facilities at higher capacity factors in lieu of purchasing power at higher market prices.
Operating and Maintenance Expense increased $8.8 million mainly due to:
• A $5.2 million increase in operating and maintenance costs for Merricourt and Astoria Station as these facilities were placed in service in the fourth quarter of 2020 and the first quarter of 2021, respectively.
• A $4.0 million increase in Big Stone plant maintenance costs arising from our planned facility outage, which began in the third quarter and was completed in the fourth quarter of 2021.
• Other additional costs including a $2.2 million increase in transmission tariff expenses and increases in information technology services, insurance costs and increased vegetative maintenance costs.
These expense increases were partially offset by, among other items, a $3.0 million reduction in bad debt expense as customer collections have improved from 2020, which were negatively impacted by the economic effects of COVID-19, along with lower operating costs following the closure of Hoot Lake Plant in May 2021.
Depreciation and Amortization expense increased $8.2 million primarily due to Merricourt and Astoria Station being placed in service in the fourth quarter of 2020 and the first quarter of 2021, respectively.
MANUFACTURING SEGMENT RESULTS
The following table summarizes operating results of our Manufacturing segment for the years ended December 31, 2021 and 2020:
(in thousands) 2021 2020 $ change % change
Operating Revenues $ 336,294 $ 238,769 $ 97,525 40.8 %
Cost of Products Sold 259,581 180,432 79,149 43.9
Other Operating Expenses 37,163 27,301 9,862 36.1
Depreciation and Amortization 15,436 14,933 503 3.4
Operating Income $ 24,114 $ 16,103 $ 8,011 49.7 %
Operating Revenues increased $97.5 million primarily due to the following:
• At BTD, operating revenues increased $91.3 million. Parts revenue increased $78.4 million, primarily due to a 31.2% increase in material costs, which are passed through to customers, as steel prices increased significantly from the previous year. Steel prices increased during the year as steel mill production did not match customer demand as mill capacity recovered from shutdowns in 2020 resulting from the COVID-19 pandemic. Sales volumes increased 6.8% in 2021 from increased and robust end market demand across most markets served. Demand in 2020 was impacted by COVID-19 after certain customers implemented temporary plant shutdowns in response to the pandemic. A $7.3 million increase in scrap revenues, with $5.9 million due to higher scrap metal prices and $1.4 million attributable to higher volumes, also contributed to the increase in operating revenues.
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• At T.O. Plastics, revenues increased $6.2 million, primarily due to a 12.5% increase in sales volumes as well as 5.6% increase in sale prices. Increases in horticultural product sales volumes due to strong customer demand during the year were partially offset by decreases in sales to other end market customers. Sales volumes in 2020 were impacted by the COVID-19 pandemic, as certain end markets experienced reduced demand.
Cost of Products Sold increased $79.1 million due to the following:
• Cost of products sold at BTD increased $76.6 million as a result of both increased material costs and higher sales volumes. Increased gross profit margins resulting from a higher leveraging of fixed costs due to increased sales volumes were partially offset by lower productivity and increased labor and freight costs. The lower level of productivity during the year was primarily the result of increased staffing levels to meet higher business volumes and the time required for new employees to achieve peak productivity.
• Cost of products sold at T.O. Plastics increased $3.2 million primarily due to increased sales volumes. Gross profit margins increased as a result of a higher leveraging of fixed costs due to increased sales volumes and better pricing spreads.
Other Operating Expenses increased $9.9 million due to increased staffing levels and associated recruitment costs, travel costs, incentive based compensation and other costs resulting from higher business volumes.
PLASTICS SEGMENT RESULTS
The following table summarizes operating results for our Plastics segment for the years ended December 31, 2021 and 2020:
(in thousands) 2021 2020 $ change % change
Operating Revenues $ 380,229 $ 205,249 $ 174,980 85.3 %
Cost of Products Sold 228,789 148,835 79,954 53.7
Other Operating Expenses 14,326 14,987 (661) (4.4)
Depreciation and Amortization 4,354 3,604 750 20.8
Operating Income $ 132,760 $ 37,823 $ 94,937 251.0 %
Operating Revenues increased $175.0 million primarily due to unique supply and demand dynamics during the year. The average price per pound of PVC pipe sold in 2021 increased 82.1% compared to 2020, which exceeded the 65.5% increase in the cost of PVC resin and other input materials. The increase in sale prices was largely due to the combination of PVC resin supply constraints, which limited PVC pipe manufacturing output and led to extremely low inventory levels, and strong demand for PVC pipe products. Resin supply was negatively impacted during the year by production disruptions caused by extreme weather events in the Gulf Coast region of the U.S. in the first and third quarters of the year. Pounds of pipe sold in 2021 increased 1.7% compared to the previous year.
Cost of Products Sold increased $80.0 million primarily due to the increase in the cost per pound of PVC pipe sold largely due to higher material input costs.
Other Operating Expenses decreased $0.7 million. In 2020, our Plastics businesses made a $2.0 million contribution commitment to OTC’s charitable foundation, and no such contribution commitment was made in 2021. The decrease in foundation contributions was partially offset by an increase in variable costs associated with the increased financial results in 2021.
CORPORATE COSTS
The following table summarizes Corporate results of operations for the years ended December 31, 2021 and 2020:
(in thousands) 2021 2020 $ change % change
Other Operating Expenses $ 13,905 $ 12,794 $ 1,111 8.7 %
Depreciation and Amortization 225 329 (104) (31.6)
Operating Loss $ 14,130 $ 13,123 $ 1,007 7.7 %
Other Operating Expenses increased $1.1 million primarily due to increased labor and benefit costs as well as a $3.0 million contribution commitment to OTC’s charitable foundation in 2021, compared to a $2.5 million commitment in the previous year.
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REGULATORY RATE MATTERS
The following provides a summary of our current general rates and a summary of recent rate case filings and rate rider filings that have or are expected to have a material impact on our operating results, financial position or cash flows.
GENERAL RATES
The following includes a summary of electric base rates as determined in OTP's most recent general rate case in each state:
Revenue Allowed
Implementation Requirement Return on Return Equity
Jurisdiction Date (in millions) Rate Base on Equity Ratio
Minnesota 06/01/19 $ 198.6 7.51 % 9.41 % 52.50 %
North Dakota 02/01/19 153.1 7.64 9.77 52.50
South Dakota (1)
08/01/19 35.5 7.09 8.75 52.92
(1) Includes an earnings sharing mechanism to share with South Dakota customers any weather-normalized earnings above the authorized ROE of 8.75%. The mechanism requires annual customer refunds of 50% of any weather-normalized revenue creating earnings in excess of the authorized ROE up to a maximum of 9.50% and 100% refunds revenue creating earnings above 9.50%.
Minnesota Rate Case: On November 2, 2020, OTP filed a request with the MPUC for an increase in revenue recoverable through base rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of approximately $14.5 million, or 6.77%, based on an allowed rate of return on rate base of 7.59% and an allowed rate of return on equity of 10.20% on an equity ratio of 52.5% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of cost recovery, with some costs moving from riders into base rates and fuel, purchased power, and conservation program costs moving out of base rates and into riders. The filing also included a revenue decoupling mechanism proposal. Such mechanisms are designed to separate a utility's revenue from changes in energy sales. The decoupling mechanism uses a tracker balance through which authorized customer margins are subject to a true-up mechanism to maintain or cap a given level of revenues.
On December 3, 2020, the MPUC approved an interim annual rate increase of $6.9 million, or 3.2%, effective January 1, 2021. This approval was provided after an alternative recovery proposal was submitted by OTP, which, among other changes, requested the extension of depreciable lives of certain wind-related assets and deferred certain cost recovery decisions to the final rate determination. In the aggregate, this alternative recovery proposal reduced operating costs and delayed recovery of certain other costs by approximately $7.0 million to lessen the interim rate impact on customers.
In a filing submitted to the MPUC on April 30, 2021, OTP lowered its requested net annual revenue increase from its initial request of $14.5 million to $8.2 million, primarily due to a reduction in operating costs from amounts included in its November 2020 filing. The cost reductions include, among other items, lower depreciation expense on our wind generation assets due to the extension of depreciable lives from 25 to 35 years and a reduction in postretirement benefit costs.
On February 1, 2022, the MPUC issued its written order. The key provisions of the order include a revenue requirement of $209.0 million based on a return on rate base of 7.18%, including an allowed return on equity of 9.48% on an equity ratio of 52.5%. The order also authorizes recovery, over a five-year period, of our remaining Hoot Lake Plant net asset and approves the requested decoupling mechanism for most residential and commercial customer rate groups, with a cap of 4% of annual base revenues. Following the submission of certain compliance filings and a comment period on such filings, we expect final rates will be implemented in mid-2022.
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RATE RIDERS
The following table includes a summary of pending and recently concluded rate rider proceedings:
Recovery Filing Amount Effective
Mechanism Jurisdiction Status Date (in millions) Date Notes
RRR - 2019 MN Approved 06/21/19 $ 12.5 01/01/20 Includes return on Merricourt construction costs.
TCR - 2018 MN Approved 05/07/20 10.3 01/21/20 See below for additional details.
CIP - 2021 MN Approved 04/01/21 9.4 12/01/21 Includes recovery of energy conservation improvement costs as well as a demand side management financial incentive.
CIP - 2020 MN Approved 05/01/20 8.2 10/01/20 Includes recovery of energy conservation improvement costs as well as a demand side management financial incentive.
TCR - 2021 MN Requested 11/23/21 7.2 07/01/22 Includes recovery of two new transmission projects.
RRR - 2021 MN Requested 12/06/21 2.7 07/01/22 Includes return on Hoot Lake Solar construction costs and costs associated with the acquisition of the Ashtabula III wind farm.
EUIC - 2021 MN Requested 06/07/21 1.3 01/01/22 Includes recovery of new infrastructure costs, including advanced metering, outage management and demand response systems.
RRR - 2021 ND Approved 03/07/21 11.8 04/01/21 Includes recovery of Merricourt investment and operating costs.
GCR - 2020 ND Approved 06/10/20 6.2 07/01/20 Includes return on Astoria Station construction costs.
TCR - 2021 ND Approved 09/15/21 6.1 01/01/22 Includes recovery of three new transmission projects/programs.
RRR - 2020 ND Approved 03/18/20 5.8 04/01/20 Includes return on Merricourt construction costs.
TCR - 2020 ND Approved 08/31/20 5.7 01/21/20 Includes recovery of seven new transmission assets.
TCR - 2020 ND Approved 11/18/20 5.6 01/01/21 Includes recovery of eight new transmission projects.
GCR - 2021 ND Approved 03/01/21 5.2 07/01/21 Includes recovery of Astoria Station, net of anticipated savings associated with the retirement of Hoot Lake Plant.
TCR - 2020 SD Approved 01/29/20 2.3 03/02/20 Annual update to transmission cost recovery rider.
TCR - 2021 SD Requested 10/29/21 2.2 03/01/22 Annual update to transmission cost recovery rider.
TCR - 2021 SD Approved 02/19/21 2.2 03/01/21 Includes recovery of two new transmission projects.
PIR - 2020 SD Approved 05/31/20 1.6 09/01/20 Includes return on Merricourt and Astoria Station construction costs.
Minnesota TCR: On May 1, 2017, the MPUC ordered OTP to include in the TCR rider retail rate base the Minnesota jurisdictional share of OTP's investments in certain transmission assets and all revenues received from other utilities under MISO's tariffed rates as a credit in its TCR revenue requirement calculations. The order had the effect of diverting interstate wholesale revenues that have been approved by the FERC to offset the FERC-approved expenses, effectively reducing OTP's recovery of FERC-approved expense levels.
On August 18, 2017, OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC transmission projects in the TCR rider. On June 11, 2018, the Minnesota Court of Appeals reversed the MPUC's order. On July 11, 2018, the MPUC filed a petition for review of the decision to the Minnesota Supreme Court, which granted review of the appellate court decision. The Minnesota Supreme Court issued its opinion on April 22, 2020, concluding the MPUC lacked authority to amend an existing TCR rider approved under Minnesota state law to include the costs and revenues associated with these transmission projects and affirming the decision of the Minnesota Court of Appeals.
On October 22, 2020, the MPUC approved OTP's request for a Minnesota TCR rider update with the exclusion of these transmission projects. In addition, the MPUC approved the inclusion of three new projects previously requested in the Minnesota TCR rider eligibility petition. Updated rates went into effect in January 2021. With this decision, one-half of the projected TCR rider tracker balance at December 2020 of $13.4 million will be included in the 2021 TCR rider annual revenue requirement, with the remainder included in the next annual update. The annual updates provide for recovery of approximately $2.6 million in MISO revenue credits to Minnesota customers through the TCR rider prior to September 30, 2020. As a result, OTP recognized additional rider revenue of $2.6 million during the third quarter of 2020.
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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 capital expenditures related to expansion of existing businesses and development of new projects. Our liquidity, including our operating cash flows and access to capital markets, can be impacted by macroeconomic factors outside of our control, such as those which may be caused by COVID-19. In addition, our liquidity could be impacted by non-compliance with covenants under our various debt instruments. As of December 31, 2021, 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, 2021 and 2020:
2021 2020
(in thousands) Line Limit Amount Outstanding Letters
of Credit Amount Available Amount Available
Otter Tail Corporation Credit Agreement $ 170,000 $ 22,637 $ — $ 147,363 $ 104,834
OTP Credit Agreement 170,000 68,526 13,159 88,315 140,068
Total $ 340,000 $ 91,163 $ 13,159 $ 235,678 $ 244,902
We have an internal risk tolerance metric to maintain a minimum of $50 million of liquidity under the OTC Credit Agreement. Should additional liquidity be needed, this 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.
CASH FLOWS
The following is a discussion of our cash flows for the years ended December 31, 2021 and 2020:
(in thousands) 2021 2020
Net Cash Provided by Operating Activities $ 231,243 $ 211,921
Net Cash Provided by Operating Activities increased $19.3 million primarily due to a $80.9 million increase in net income, but partially offset by an increase in working capital. Our working capital increase was primarily the result of a $61.0 million increase in accounts receivable and a $54.3 million increase in inventories, which exceeded the increase in accounts payable and accrued and other liabilities. The increase in accounts receivable was primarily due to increased sales prices in our Manufacturing and Plastics segments, as well as increased sales volumes in our Plastics segment in the fourth quarter of 2021 compared to the fourth quarter of 2020. The increase in inventories was largely the result of increased material costs within our Manufacturing and Plastics segments. The increase in material costs of our Plastics segment more than offset the significant decrease in pounds of pipe inventory, which decreased as a result of lower manufacturing output due to resin supply constraints and strong demand for PVC pipe. The increase in accounts payable was largely due to the increased material costs in our Manufacturing and Plastics segments and increased inventory levels primarily in our Manufacturing segment.
(in thousands) 2021 2020
Net Cash Used in Investing Activities $ 171,510 $ 375,652
Net Cash Used in Investment Activities decreased $204.1 million primarily related to our Astoria Station natural gas plant and Merricourt wind farm being under construction during 2020, with the capital spend being substantially complete for both projects by year-end 2020.
(in thousands) 2021 2020
Net Cash (Used in) Provided by Financing Activities $ (59,359) $ 143,695
Net Cash (Used in) Provided by Financing Activities decreased $203.1 million primarily related to a decrease in construction financing needs within our Electric segment, as capital spending was substantially complete for both Astoria Station and Merricourt by year-end 2020. In 2021 our financing activities included the issuance of $140.0 million in long-term debt at OTP, which was used to repay long-term debt that matured in December 2021, and $10.2 million of net short-term borrowings on our lines of credit, which were primarily used to fund construction expenditures and support operating activities. In 2021, we paid $64.9 million in dividends to common shareholders. In 2020, $75.0 million of long-term debt was issued at OTP, we had $75.0 million of net short-term borrowings on our lines of credit, and we also raised $52.4 million from the issuance of common stock to fund capital expenditures at OTP. In 2020, we paid $60.3 million in dividends to common shareholders.
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CAPITAL REQUIREMENTS
CAPITAL EXPENDITURES
We have a capital expenditure program for expanding, upgrading and improving our facilities and operating equipment. Typical uses of cash for capital expenditures are investments in electric generation facilities and environmental upgrades, transmission and distribution lines, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. The capital expenditure program 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, 2021 and 2020 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five year period 2022 through 2026:
(in millions) 2020 2021 2022 2023 2024 2025 2026 Total
Electric Segment:
Renewables and Natural Gas Generation $ 30 $ 80 $ 92 $ 92 $ 160 a $ 454
Technology and Infrastructure 26 30 18 — — 74
Distribution Plant Replacements 37 35 35 35 33 175
Transmission (includes replacements) 26 28 24 20 27 125
Other 30 29 32 36 23 a 150
Total Electric Segment $ 357 $ 140 $ 149 $ 202 $ 201 $ 183 $ 243 $ 978
Manufacturing and Plastics Segments 15 32 33 46 31 21 22 153
Total Capital Expenditures $ 372 $ 172 $ 182 $ 248 $ 232 $ 204 $ 265 $ 1,131
Total Electric Utility Average Rate Base $ 1,385 $ 1,575 $ 1,630 $ 1,750 $ 1,860 $ 1,980 $ 2,100
Rate Base Growth 3.5 % 7.4 % 6.3 % 6.5 % 6.1 %
CONTRACTUAL OBLIGATIONS
The following table summarizes our contractual obligations at December 31, 2021 and the effect these obligations are expected to have on our liquidity and cash flow in future periods.
(in millions) Total Less than
1 Year 1-3
Years 3-5
Years More than
5 Years
Debt Obligations $ 858 $ 121 $ — $ 80 $ 657
Interest on Debt Obligations 570 33 63 63 411
Coal Contracts 548 23 48 49 428
Capacity and Energy Requirements 177 20 24 24 109
Postretirement Benefit Obligations 116 5 12 12 87
Other Purchase Obligations (including land easements) 58 2 18 4 34
Operating Lease Obligations 21 5 9 5 2
Total Contractual Cash Obligations $ 2,348 $ 209 $ 174 $ 237 $ 1,728
Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company under the lignite sales agreement 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, but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make a contribution to that plan.
Off-Balance Sheet Arrangements
As of December 31, 2021, we have outstanding letters of credit totaling $15.9 million, a portion of which reduces our borrowing capacity under our lines of credit. No outstanding letters of credit are reflected in outstanding short-term debt on our consolidated balance sheets.
We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.
COMMON STOCK DIVIDENDS
We paid dividends to our shareholders totaling $64.9 million, or $1.56 per share, in 2021. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures 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 our subsidiaries. See Note 14 to our consolidated
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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 4, 2022, our Board of Directors increased the quarterly dividend from $0.39 to $0.4125 per common share.
CAPITAL RESOURCES
Financial flexibility is provided by operating cash flows, unused 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 2022 through 2025 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. No shares were issued pursuant to the registration statement in 2021.
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 and/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. In 2021, we issued 115,180 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, 2021, 1,384,820 shares remain available for purchase or issuance under the Plan.
SHORT-TERM DEBT
OTC and OTP are each party to a credit agreement (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provides for unsecured revolving lines of credit. The agreements generally bear interest at the London Interbank Offered Rate (LIBOR) 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, 2021 and 2020 was 1.42% and 1.61%.
The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2021:
(in thousands, except interest rates) OTC Credit Agreement OTP Credit Agreement
Borrowing Limit $ 170,000 $ 170,000
Borrowing Limit if Accordion Exercised 1
290,000 250,000
Amount Restricted Due to Outstanding Letters of Credit at Year-End — 13,159
Amount Outstanding at Year-End 22,637 68,526
Average Amount Outstanding During Year 49,600 52,218
Maximum Amount Outstanding During the Year 79,718 110,582
Interest Rate at Year-End 1.6 % 1.4 %
Maturity Date September 30, 2026 September 30, 2026
1 Each facility includes an accordion featuring allowing the borrower to increase the borrowing limit if certain terms and conditions are met.
LONG-TERM DEBT
At December 31, 2021, we had $767.0 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 2022 to 2051. One OTP debt instrument with a principal balance of $30.0 million matures in August 2022. Pursuant to a Note Purchase Agreement executed in June 2021, OTP intends to issue its Series 2022A notes in May 2022, for aggregate proceeds of $90.0 million, subject to the satisfaction of certain customary conditions to closing, and use a portion of the proceeds to repay the $30.0 million which is maturing in August 2022.
Financial Covenants
Certain of our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2021, 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, 2021, our Interest-Bearing Debt to Total Capitalization was 0.46 to 1.00, our Interest and Dividend Coverage Ratio was 6.82 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
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December 31, 2021, OTP's Interest-Bearing Debt to Total Capitalization was 0.48 to 1.00, its Interest and Dividend Coverage Ratio was 3.24 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, 2021 are summarized below:
Otter Tail Corporation Otter Tail Power Company
Moody's Fitch S&P Moody's Fitch S&P
Corporate Credit/Long-Term Issuer Default Rating Baa2 BBB- BBB A3 BBB BBB+
Senior Unsecured Debt n/a BBB- n/a n/a BBB+ BBB+
Outlook Stable Stable Negative Stable Stable Stable
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
Preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. While we believe the estimates 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 sheet and recognize in the consolidated statement of income as an expense or income item in the period in which this accounting treatment is no longer applicable.
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. Also, a reduction 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 below assumed rates of return or an increase in the anticipated life expectancy of plan participants could result in significant increases 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
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plan assets based on asset category studies using historical market returns and volatility rates with forward looking estimates based on existing and forecasted future market conditions.
At December 31, 2021, we set the discount rate used to measure our pension plan obligations at 3.03% and at 3.01% to measure postretirement healthcare obligations, a 25 and 26 basis point increase, respectively, from the estimates used at December 31, 2020. Our estimates used to determine benefit cost for 2021 included a discount rate of 2.78% for pension benefits and 2.75% for postretirement healthcare costs, a 69 and 68 basis point decrease, respectively, from 2020 estimates. In addition, we estimated our assumed rate of return on pension assets to be 6.51% for 2021, a 37 basis point decrease from our 2020 estimate.
The following table summarizes the impact on 2021 pension and postretirement costs for a 0.25 increase or decrease, holding all other variables constant, on certain key assumptions:
(in thousands) +0.25 -0.25
Pension Plan:
Discount Rate $ (1,249) $ 1,317
Rate of Increase in Future Compensation 880 (833)
Long-Term Return on Plan Assets (859) 859
Other Postretirement Benefits:
Discount Rate (327) 345
For 2022, we expect pension benefit cost for our pension plan to be $3.0 million compared to $7.7 million in 2021, as the amortization of actuarial losses is reduced in 2022 following actuarial gains recognized as of December 31, 2021. The estimated discount rate used to determine annual benefit cost accruals increased from 2.78% in 2021 to 3.03% in 2022. The assumed rate of return on pension plan assets is 6.30% for 2022 compared with 6.51% for 2021.
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 EBITDA, comparable price earnings ratios 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 2021 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 inherently include a 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.
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