Pacific Ethanol Columbia, LLC v. Morrow County Assessor

IN THE OREGON TAX COURT MAGISTRATE DIVISION Property Tax

PACIFIC ETHANOL COLUMBIA, LLC, ) ) Plaintiff, ) TC-MD 200380N ) v. ) ) MORROW COUNTY ASSESSOR ) and DEPARTMENT OF REVENUE, ) State of Oregon, ) ) Defendants. ) DECISION

Plaintiff appealed the assessment of property identified as Accounts 10607, 10673, and 11301 (subject property) for the 2020-21 tax year. A trial was held on July 27 and 28, 2022, in the courtroom of the Oregon Tax Court. Lauren B. Bernton, an Oregon attorney, appeared on behalf of Plaintiff. Robert Olander (Olander), Plaintiff’s Vice President of Corporate Control; Patrick Millar (Millar), Senior Manager in Business Valuation for Gordon Brothers; and Martin Michael (Michael), who performs forecasting and risk management for Plaintiff, each testified on behalf of Plaintiff.

Sam Zeigler, Senior Assistant Attorney General, appeared on behalf of Defendant Department of Revenue (the Department). William “Bill” Peters (Peters), Market Analyst for the Clean Fuels Program at Oregon Department of Environmental Quality, and Darlene Johnson (Johnson), Appraiser Analyst 4 for the Department, each testified on behalf of the Department.

I. PRELIMINARY RULING ON EXHIBITS

Plaintiff’s Exhibits 1, 3 to 5, 7, 9, 12, 21, 26, 30, 34, 42 to 43, 46 to 47, and 52, and the Department’s Exhibits A and D were admitted or provisionally admitted under seal. Defendant objected to any exhibits pertaining to events that occurred after the January 1, 2020, assessment DECISION TC-MD 200380N 1 date. Specifically, Defendant objected to part or all of Plaintiff’s Exhibits 3 to 5, 7, 9, 12, 21, 30, 34, 43, and 47. Those exhibits include documents from 2020: board meeting minutes, lender updates, investment bank presentations, a subsidy agreement, Plaintiff’s profit and loss detail, and a spreadsheet detailing shutdowns of the subject. Plaintiff responded that at least some of those exhibits reflect events and discussions on or around the assessment date. For instance, Pacific Ethanol 1 and Plaintiff’s poor financial results were known; idling the subject and other Western plants was a possibility; and Pacific Ethanol had retained an investment bank to market the Western plants for sale.

The Oregon Supreme Court has “rejected the ‘assumption’ that ‘evidence of events subsequent to the assessment date is irrelevant to determining property’s real market value.” Oakmont, LLC v. Dept. of Rev., 359 Or 779, 793-94, 377 P3d 523 (2016) (explaining the ruling in Sabin v. Dept. of Rev., 270 Or 422, 528 P2d 69 (1974)). In Sabin, the Court reversed and remanded the Tax Court’s determination that consideration of a sale nearly two years after the assessment date was “impermissible hindsight.” 270 Or at 426. The court explained that the key inquiry compares the similarity of conditions at the time of the transaction with the time of assessment. Id. at 426-27; see also Truitt Bros., Inc. v. Dept. of Rev., 302 Or 603, 732 P2d 497 (1987) (considering sale 15 months after assessment date). In other words, the question is

“whether the condition of the property and the market conditions between the assessment date and the date of the transaction were sufficiently stable that the court can reasonably infer that a willing buyer on the assessment date would have reached a conclusion of value similar to that of the party to the later transaction.”

Level 3 Communications, LLC v. Dept. of Rev., TC 5236, WL 2230557 at *8 (Or Tax R Div 2018) (citations omitted). 2 In Level 3, the court declined to consider a transaction 22 and 46

1 Pacific Ethanol, Inc. was the parent of Plaintiff. (See Ptf’s Ex 1 at 4, 16; Def’s Ex A at 7, 38.) 2 With respect to later-discovered facts about the subject, the question is whether the facts are the type that

DECISION TC-MD 200380N 2 months after the two assessment dates at issue based, in part, on evidence that the telecommunications industry was experiencing “intense change,” including expert witness testimony that “the only constant in the communications industry is change.” Id. at *9. 3

Plaintiff’s Exhibit 3, the January 23, 2020, board meeting minutes, are admitted as reflective of information known as of January 1, 2020, about market conditions and potential plans to idle or sell the subject. Indeed, Johnson quoted from that exhibit in her report and, presumably, found the information pertinent to a January 1, 2020, valuation. (See Def’s Ex A at 70.) The court declines to admit the remaining exhibits reflecting market conditions, events, and decisions after January 1, 2020.

The ethanol industry is characterized by volatility due to swings in corn and crude oil prices. Even a few months can make a difference to the industry outlook. 4 As Millar noted, the COVID-19 pandemic that emerged in early 2020 was just such an event: “In early 2020, the outlook for the ethanol industry appeared to be improving * * *. As market conditions began to look slightly more promising, however, the ethanol industry was rocked by the effects of the COVID-19 pandemic and the ensuing oil price war between Saudi Arabia and Russia.” (Ptf’s Ex 1 at 15. 5) In February 2020, Pacific Ethanol decided to cold idle the subject along with the other

an “informed buyer and seller reasonably could have discovered [them] on the assessment date.” Oakmont, 359 Or at 794. For instance, construction defects that existed on the assessment date and were discoverable through “a reasonable inspection” may be considered even if they were not, in fact, discovered until later. Id. 3 The court also considered the extent to which the character of the property changed through mergers and acquisitions, as well as growth through the integration of new property. 4 Michael testified that corn and ethanol prices can vary dramatically on a daily basis, making long-term predictions or forecasts difficult. Johnson testified that she used the DCF due to volatility associated with the subject. 5 Millar noted several events contributing to an improving forecast for the ethanol industry: restrictions on a 15 percent ethanol blend were lifted in late May 2019; a 10th Circuit opinion reversed small refiner exemptions in January 2020; and the US signed phase one of a trade with deal with China in January 2020. (Ptf’s Ex 1 at 15.)

DECISION TC-MD 200380N 3 Western plants and, in fact, idled the subject from March 31, 2020, to April 10, 2020. (Id. at 24; Ptf’s Ex 5.) Due to an unforeseen subsidy agreement that materialized with a business partner, the subject resumed operations in April 2020. (See Ptf’s Ex 1 at 24.) Those events highlight the month-to-month instability of the ethanol industry’s market conditions and the subject property’s own uncertain fortune. The changing conditions and intervening events of early 2020 invariably informed the creators of the challenged exhibits, preventing the court from parsing and excluding impermissible hindsight from the exhibits.

II. STATEMENT OF FACTS

The subject property is an ethanol production plant located on leased land in Boardman, Oregon. (Ptf’s Ex 1 at 4; Def’s Ex A at 6.) As of January 1, 2020, it was owned by Plaintiff Pacific Ethanol Columbia, LLC, a subsidiary of Pacific Ethanol, Inc. (Ptf’s Ex 1 at 4, 16; Def’s Ex A at 7, 38. 6) The subject is known as “the Columbia Plant” due to its location along the Columbia River. (See id.) For the 2020-21 tax year, Defendant assessed the subject property at a total real market value of $26,818,490. (Def’s Ex A at 8.) Plaintiff requests a real market value of $14,400,400 based on Millar’s appraisal. (Ptf’s Ex 1 at 40.) Defendant concluded a real market value of $27,500,000 based on Johnson’s appraisal. (Def’s Ex A at 9.)

The parties appear to agree on most facts pertaining to the subject’s description and essential aspects of the ethanol industry, such as the impact of corn prices. They differ on the economic outlook for the Columbia plant as of January 1, 2020; specifically, whether idling the plant was imminent and whether sales of idled plants are useful comparators for the subject. The parties also differ on several aspects of the discounted cash flow (DCF) analysis, such as likely future prices for the subject’s ethanol and carbon credits, as well as certain cost calculations.

6 As of January 12, 2021, Pacific Ethanol changed its name to Alto Ingredients. (Ptf’s Ex 1 at 16.)

DECISION TC-MD 200380N 4 The Statement of Facts presents background information on the ethanol industry, economic conditions, Oregon’s Clean Fuels program, Pacific Ethanol’s business, and the subject property. Valuation evidence under the approaches to value is presented and discussed in the Analysis. A. Ethanol Industry Generally, Economic Conditions as of January 1, 2020

Ethanol demand is largely determined by government regulation. (Ptf’s Ex 1 at 8.) The renewable fuel standard (RFS), established in 2005, set a requirement for blending ethanol into transportation fuels. (Id.) Program goals included reducing dependency on foreign oil and using more climate-friendly transportation fuel. (Id.) The RFS was intended to increase annually and did so up to a point. (See id. at 8.) The RFS required 14.5 billion gallons of ethanol in 2016, and 15 billion gallons each for the years 2017 through 2020. (Id. at 8-9.) However, the presidential administration in 2019 retroactively granted 85 small refiner exemptions (SREs) from mandated ethanol blending requirements for the 2016 to 2018 years, effectively reducing the mandate to 13.8 billion gallons. (Id. at 14.) Olander testified that ethanol consumption is also constrained by the “blend wall” – a 10 percent ethanol blend – and only a limited number of vehicles are approved for a 15 percent blend. 7 (See id. at 11-12.) Infrastructure to support a 15 percent blend – such as tanks and pumps – is limited, and the federal government has declined to mandate it broadly. (See id. at 12; Def’s Ex A at 25.)

Olander testified that the establishment of the RFS in 2005 set off a “boom” or “gold rush” era for the ethanol industry as companies rushed to build ethanol plants in response to the government-created demand. The industry grew from 81 plants in 2005 to 189 plants in 2010. (Ptf’s Ex 1 at 10.) Since 2010, demand has leveled off and the number of plants has fluctuated

7 The “blend wall” only became an issue in 2013 when the government-mandated volume of 13.8 billion gallons exceeded the blend wall of 13.45 billion gallons, or 10 percent of gasoline consumption. (Ptf’s Ex 1 at 12.)

DECISION TC-MD 200380N 5 from 204 in 2011 to a high of 214 in 2016, then down to 205 in 2020. (Id.) As of January 2020, US ethanol production capacity was 17.1 billion gallons per year. (Id.) In 2019, the US ethanol industry produced 15.8 billion gallons, or 93.6 percent of capacity. (Id.)

Domestic consumption of ethanol ranged from 13.9 to 14.5 billion gallons per year between 2015 and 2019. (Ptf’s Ex 1 at 12.) Exports of additional supply increased during that period to a high of 1.7 billion gallons in 2018 and fell slightly to 1.5 billion gallons in 2019. (Id.) The top three export destinations were Brazil, Canada, and India, totaling 68 percent of all exports. (Id. at 13.) In 2016, China was the third largest export market for the US, but the “trade war” that began thereafter “all but closed off” the Chinese market by 2019. (Id. at 14.) Exports to Brazil also declined from 2018 to 2019 for a variety of reasons. (Id.)

Ethanol is produced from corn through a fermentation process that yields marketable coproducts in addition to ethanol, such as wet distillers grains (WDG), syrup, corn oil, and liquid carbon dioxide. (See Def’s Ex A at 7.) Thus, ethanol margins depend largely on the price of corn. (Id. at 34.) For instance, 2009 and 2013 were bad years for the ethanol industry due to droughts that decreased the supply of corn and increased the price. 8 (Ptf’s Ex 1 at 14; Def’s Ex A at 68.) Corn prices were relatively low and stable from 2015 through 2019. (Ptf’s Ex 1 at 13-14.) Michael testified that a national corn price is set at commodity exchanges – called the CBOT price – and the price to individual buyers is adjusted to account for geographic variation, such as freight cost to ship the corn. 9 Most US ethanol plants are in the corn-growing regions of the Midwest due to the abundance of cheap corn. (Id. at 11 (map).)

8 The drought in 2012 reduced corn production to 10.8 billion bushels, whereas 2013 was “a banner year” with corn production of 13.8 billion bushels, the highest since 2009. (Ptf’s Ex 1 at 14.) 9 As an example, Michael testified that a buyer in Illinois might pay $0.50 whereas a buyer in Washington or Oregon would have to pay $2.00 to account for freight and other costs.

DECISION TC-MD 200380N 6

Michael testified that ethanol pricing follows a similar concept as corn pricing: the commodity exchange establishes a reference point, which is then adjusted based on a variety of factors, including freight and customer negotiations. The Columbia plant uses the OPIS 10 PNW price as the reference point to start negotiations with customers. Ethanol prices were around $2.00 per gallon in January 2010 and rose to a high of just over $3.00 in January 2014. (See Ptf’s Ex 1 at 13.) Ethanol prices “declined markedly in the early part of 2015 in response to falling oil and gasoline prices.” (Id. at 14.) The average monthly prices in 2015 and 2016 were $1.61 and $1.55, respectively. (Id.) Prices stayed below $1.50 through 2018 and 2019. (Id. at 13.)

Michael testified that the relationship between corn and ethanol prices is modeled by the “crush margin”: (ethanol price) – (corn price/2.8). 11 (See also Ptf’s Ex 1 at 13; Ptf’s Ex 26; Def’s Ex A at 35.) The crush margin was “negative for much of 2018 and 2019.” (Ptf’s Ex 1 at 13.) Johnson testified that negative crush margins in those years did not necessarily mean producers lost money because they received income from co-products. (See Def’s Ex A at 34-35.) A dry mill plant like the subject yields, on average, $2 per bushel of corn from co-products. (Id. at 18.) Johnson testified that the best years for the ethanol industry were 2011 through 2014, excluding 2013. (Id. at 66-68. 12) Revenues and profits declined after 2014. (See id.) Johnson described 2019 as a middling year for the industry: export revenue was good, but demand was

10 Oil Price Information Service. (Def’s Ex A at 30.) 11 Michael testified that 2.8 is the yield rate from a bushel of corn. Millar gave the yield rate as 2.9 gallons of ethanol and Johnson listed it as 3 gallons. (Ptf’s Ex 1 at 7; Def’s Ex A at 18.) Johnson wrote that the ethanol industry has successfully increased production efficiencies over time. (See Def’s Ex A at 19.) 12 Johnson referred to a chart detailing world economic indicators for the ethanol industry from 2005 through 2019, including a metric of gross revenue called “industry value added” (IVA), or gross produce less costs. (Def’s Ex at 68.)

DECISION TC-MD 200380N 7 down. (See id. at 36, 68.) She acknowledged that “market participants” characterized 2019 “as experiencing overcapacity, flat or reduced demand, with low margins and marginal plants that have been idled or closed.” (Id. at 35.) Michael testified that the ethanol industry saw a downturn from 2016 through 2019, and an oversupply of ethanol going into 2020. 13 B. Clean Fuels Program, Carbon Credits

Johnson testified that state greenhouse gas emission reduction policies drive demand for ethanol, with programs in 24 states and the District of Columbia. (Def’s Ex A at 25.) California was one of the first states to create financial incentives to reduce carbon intensity, and Oregon modeled its Clean Fuels Program after California’s program. (Id. at 26.)

The Oregon Clean Fuels Credit Program, implemented beginning in 2016, increased the price of Oregon ethanol due to marketable credits associated with ethanol production. (Def’s Ex A at 26, 33 (showing $0.11 premium for Oregon ethanol over Washington).) Peters testified that the Clean Fuels program assigns carbon intensity (CI) scores to different fuels (e.g., ethanol, diesel, gas, natural gas, hydroelectric) to allow an apples-to-apples comparison. 14 The program also established a CI standard score that decreases over time, thus requiring all fuel types to reduce their carbon intensity. Regulated entities – those that import or produce regulated fuel 15 – are required to report CI scores, resulting in credits or deficits when compared to the standard score. The credits are regulatory instruments that are traded within the program. Regulated

13 But compare with Def’s Ex A at 37 (“[the US Energy Information Administration] expects that by 2020 excess ethanol supplies will be consumed and normal weather and harvest conditions will help production levels increase slightly * * * similar to 2018 levels.”) 14 Peters gave an example of factors impacting the CI score of ethanol: carbon produced from farming corn, transporting corn to the plant, emissions from the plant, and transporting ethanol to market. An ethanol plant might reduce its CI score by making technical upgrades to increase efficiency or switching to a cleaner electricity source. 15 Generally, these are transportation fuels: gas, diesel, ethanol, biodiesel, renewable diesel, or other blends.

DECISION TC-MD 200380N 8 parties with deficits must purchase offsetting credits by the end of the year. Credit transfer prices must be reported to DEQ, 16 which in turn publishes the prices. (See Ex B at 322-23.) OPIS publishes a daily price based on reported credit prices. 17

Plaintiff is a regulated entity and a net generator of carbon credits, but the parties’ witnesses disagreed about the likely value of the carbon credits over time. Olander testified that Plaintiff maximizes the value it can get for carbon credits, but the value diminishes over time as the CI standard becomes stricter. Peters agreed that, because the CI standard reduces (to allow less carbon, and therefore becomes stricter) over time, the value of credits to an ethanol plant will also decline over time if the plant does nothing to improve its CI score. Johnson testified that she expected the value of credits to increase due to the CI standard becoming stricter. She noted that the price paid for Oregon carbon credits has increased drastically since the program’s inception in 2017. (See Def’s Ex A at 32.) C. Pacific Ethanol’s Business

As of January 1, 2020, Pacific Ethanol was the sixth largest ethanol producer in the US with a 605-million-gallon capacity per year and four percent market share. (Ptf’s Ex 1 at 16; Def’s Ex A at 38.) At the end of 2019, it operated four plants in the Western US (California, Oregon, and Idaho) built between 2006 and 2008, as well as five plants in the Midwest (Illinois and Nebraska 18) that it acquired in 2015 and 2017. (Ptf’s Ex 1 at 16.) Kinergy Marketing (Kinergy), a subsidiary of Pacific Ethanol, marketed ethanol and co-products for all of Pacific

16 Department of Environmental Quality. 17 Olander testified that the first carbon credit prices were posted by OPIS on April 1, 2017.

Pacific Ethanol owned two plants in Aurora, Nebraska, the smaller of which (45 mgy) was idled at the 18

end of 2018 “due to negative margin conditions in the ethanol industry at the time.” (Ptf’s Ex 1 at 16-17.) Pacific Ethanol put both Aurora plants up for sale in 2019 and sold them in 2020. (Id. at 18.)

DECISION TC-MD 200380N 9 Ethanol’s plants, as well as some third-party plants. (See id. at 19; Def’s Ex D. 19) Olander testified that Kinergy served as a broker: it took temporary title to ethanol and borrowed against its own line of credit to provide cash flow to the plants. It could take between two days and two weeks to receive customer payment. Kinergy did not charge interest to the plants; that was part of its standard marketing fee.

Pacific Ethanol was a publicly traded company and its stock price declined from nearly $10 at the beginning of 2017 to a low of $0.39 in the fourth quarter 2019, closing at $0.65 on December 31, 2019. (Ptf’s Ex 1 at 16, 20.) The company reported net operating losses in four out of five years from 2015 through 2019. (Id. at 21.) Its total gallons sold reached a high of 952 million in 2017 before declining to 819.4 million in 2019. (Id. at 22.) Over that same period, its average sales price per gallon declined from $1.68 in 2015 to $1.57 in 2018, then increased to $1.61 in 2019. (Id.) Its debt to asset ratio grew from 40.9 percent in 2016 to 62.9 percent in 2019. (Id. at 22-23.) Millar described the picture in 2019 as follows:

“Due to its heightened leverage and consistent operating losses, Pacific Ethanol’s lenders * * * started pressuring the Company during 2019 to sell assets. As the year wore on and losses continued to mount, the Company stopped servicing its debt. By the fourth quarter of the year, it became readily apparent that the Company would run out of cash if it continued to operate its negative cash flow plants. Given its precarious liquidity situation, Pacific Ethanol retained [an investment bank] to help the Company explore liquidity enhancing options. In December 2019, the Company reached an agreement with its [lenders] to extend its capital structure and distribute cash proceeds from future asset sales to reduce debt and supplement liquidity.”

(Id. at 24.) ///

19 Olander testified that line 315 reflects a unique one-time item credit transfer following a change in Plaintiff’s carbon intensity score. (Ex D.) Kinergy transferred $244,000 to the subject property and Plaintiff reflected that amount in its revenues and operating losses. Other lines on the document do not relate to the subject.

DECISION TC-MD 200380N 10 D. Subject Property

The subject property was built in 2006 and 2007 and came online in 2007. (Ptf’s Ex 1 at 25.) Its “nameplate capacity” is 40 million gallons per year (mgy), which is small for the industry. 20 (Id.) The average capacity for an ethanol plant in the US is 86.5 mgy, and only 13 percent of plants have a capacity of 40 mgy or less. 21 (Id.) Johnson testified that most US ethanol plants fall in the range of 42 to 73 mgy. (Def’s Ex A at 22.) Plant capacity sizes of 73 to 105 mgy and 105 to 137 mgy are the next most common size ranges. (See id.) Millar noted that smaller plants like the subject do not enjoy the same economies of scale as larger plants: the subject has the same fixed costs as larger plants, but they are spread over fewer units of production. (See Ptf’s Ex 1 at 25.) Johnson testified smaller plants can get more favorable corn prices. (Def’s Ex A at 21.) But the subject has limited corn storage capacity, so it cannot take full advantage of favorable corn prices. (Ptf’s Ex 1 at 26.) Olander testified that the subject typically produces less than its nameplate capacity. (See also id. at 28 (subject sold 40.9 mgy in 2016, 37.5 mgy in 2017, 35.2 mgy in 2018, and 35.8 mgy in 2019).)

The subject is a dry mill facility, which is typical for the industry: nearly 90 percent of US plants are dry mill. (Def’s Ex A at 16.) It includes a main processing building, a fermentation building, a distillation building and tower, a wet cake storage building, a maintenance building, cooling towers, and a boiler building. (Id. at 7, 16-17, 40, 44-54.) Some improvements were made in 2015, including a corn oil extraction system and a carbon dioxide capture system. (Id. at 7.) The subject has corn storage capacity of 970,000 bushels and ethanol

20 The subject has “permitted capacity” of 43 mgy. (Def’s Ex A at 7.) Olander explained that nameplate capacity is what the plant was designed for under ideal circumstances. By contrast, permitted capacity is an environmental permit to produce up to a certain volume. 21 Olander testified that smaller ethanol plants are often specialized biodiesel or research and development facilities seeking input alternatives to corn. (See also Ptf’s Ex 1 at 25.)

DECISION TC-MD 200380N 11 storage capacity of 1.6 million gallons. (Ptf’s Ex 1 at 26.) In addition to river access, the subject has rail access to receive corn shipments. (See Def’s Ex A at 38.) Millar identified several projects 22 that would make the subject profitable and competitive but concluded the total cost of those projects – $46.5 million – was prohibitive based on the subject’s small size. (Ptf’s Ex 1 at 26-27.)

Olander testified that Plaintiff’s founder and CEO had a vision for “destination model” ethanol plants on the West Coast. (See also Ptf’s Ex 1 at 26.) His vision was to ship corn from the Midwest and source ethanol locally, assuming that shipping corn across the country could be cheaper than shipping ethanol. The CEO’s vision did not come to fruition over the subsequent years. Shipping corn has been as or more expensive than shipping ethanol: one bushel of corn weighs 56 pounds, a greater volume than the resulting ethanol. Whereas Midwest plants source corn locally and sell some ethanol locally, West Coast plants ship 100 percent of their corn and pay more freight on average. Olander testified that the subject is a “taker” on corn prices. It typically idles a few times each year due to logistical challenges with corn shipments. Johnson testified that the subject’s location provides some competitive advantages. (Def’s Ex A at 58-59.) It can sell ethanol locally, which lowers its CI score, and it can take advantage of rail congestion that can occur with delivery of ethanol because it’s closer to markets. (See id.)

Olander testified that plants on the West Coast must also compete with ethanol shipments via barge. (See also Ptf’s Ex 1 at 27 (describing competition from Brazil in 2019).) For a time, the subject enjoyed a “barge advantage” due to its location on the Columbia River: it could ship ethanol directly to the Portland market via barge. (See id. (the subject’s barge advantage was

22 Specifically, a cogeneration plant; a heat recovery system; a mechanical vapor recovery system; and a high-protein separation system. (Ptf’s Ex 1 at 26.)

DECISION TC-MD 200380N 12 $0.0425 per gallon more than the OPIS price in the third quarter of 2018).) The barge advantage ended in 2019 when an ethanol unloading and storage facility opened in Pasco, Washington, serving the Columbia and Snake rivers, and allowing barge shipments of ethanol from the Midwest, especially the Dakotas. (See id. (the subject sold ethanol at $0.11 per gallon less than the OPIS price in 2019).) Olander testified that Plaintiff’s Chief Commercial Officer described the subject’s loss of its barge advantage as a “company killer.”

Olander testified that, from 2017 through 2019, the subject plant lost $11.5 million. (See Ptf’s Ex 1 at 28-29; Ex 43.) Plaintiff had net losses in 2015, 2017, 2018, and 2019. (See id.) Olander testified that Pacific Ethanol’s board of directors began discussing idling the subject, along with its other Western plants, during the fourth quarter of 2019. (See also Ptf’s Ex 3 (January 23, 2020, meeting minutes).) Idling is part of the industry, but smaller plants like the subject are more prone to idling due to their high costs. The subject must be idled every four to six weeks for 24 to 48 hours for maintenance. In addition, the subject has been idled to install new technologies; when margins have deteriorated such that it loses money to operate; when the subject has run out of storage capacity for ethanol; and due to other market conditions. Olander testified that the decision to “cold idle” a plant is a big decision, not a knee-jerk reaction.

III. ANALYSIS

The issue presented is the subject property’s 2020-21 real market value. “Real market value” is “the amount in cash that could reasonably be expected to be paid by an informed buyer to an informed seller, each acting without compulsion in an arm’s-length transaction occurring as of the assessment date for the tax year.” ORS 308.205(1). 23 The assessment date for the 2020-21 tax year was January 1, 2020. ORS 308.007; ORS 308.210. Real market value “shall be

23 The court’s references to the Oregon Revised Statutes (ORS) are to 2019.

DECISION TC-MD 200380N 13 determined by methods and procedures in accordance with rules adopted by the Department of Revenue * * *.” ORS 308.205(2). Three approaches to value must be considered but may not be applicable in every case: the cost approach; the sales comparison approach; and the income approach. OAR 150-308-0260(3)(a). 24 Whether an approach is applicable is a question of fact. Pacific Power & Light Co. v. Dept. of Rev., 286 Or 529, 533, 596 P2d 912 (1979). With “an operating plant,” the highest and best use of which is continued operation, “the real market value will be considered to be a ‘going concern.’ The going concern concept recognizes that the value of an assembled and operational group of assets usually exceed the value of an identical group of assets that are separate or not operational.” OAR 150-308-0260(2). 25

Plaintiff bears the burden of proof by a preponderance of the evidence, which means “the greater weight of evidence, the more convincing evidence.” ORS 305.427; Feves v. Dept. of Revenue, 4 OTR 302, 312 (1971). “[T]he court has jurisdiction to determine the real market value or correct valuation on the basis of the evidence before the court, without regard to the values pleaded by the parties.” ORS 305.412. A. Sales Comparison Approach

“In utilizing the sales comparison approach only actual market transactions of property comparable to the subject, or adjusted to be comparable, will be used. All transactions utilized in the sales comparison approach must be verified to ensure they reflect arms-length transactions.”

24 Millar testified that he did not use the cost approach because ethanol plants typically cost more than they are worth and are subject to significant economic obsolescence. Johnson used the cost approach, concluding a value of $31,980,000. (Def’s Ex A at 61-69, 90.) She testified that she did not place much weight on the cost approach due to the age of the subject and the difficulty measuring economic obsolescence. 25 Johnson concluded that the subject property’s highest and best use was continuation of its current use “as a going concern operating plant * * *.” (Def’s Ex A at 15.) Millar did not present a different conclusion.

“Going concern” in the context of this rule may be thought of as “assemblage value” rather than a broader concept that incorporates intangible values such as goodwill. See Boise Cascade Corp. v. Dept. of Rev., 12 OTR 263, 267-68 (1991).

DECISION TC-MD 200380N 14 OAR 150-308.0260(3)(c). The appraiser must make market-based adjustments for non-typical conditions such as bankruptcy or liquidation. Id. The appraiser must select similar properties for comparison and adjust “for differences in location, product, production capacity, and all other factors that may affect value.” OAR 150-308.0260(3)(c)(A). The appraiser must also adjust for differences in “physical condition, functional deficiencies, operating efficiency, and economic obsolescence.” OAR 150-308.0260(3)(c)(B).

1. Subject property sales history

Olander testified that Plaintiff filed for bankruptcy in 2009 when corn prices were high and Plaintiff could not service its debt. (See also Def’s Ex A at 38 (Pacific Ethanol forced four subsidiary plants to file for bankruptcy).) When Plaintiff and the other plants emerged from bankruptcy in 2010, the bank-owner hired Pacific Ethanol to run the plants for a fixed fee. Pacific Ethanol purchased its plants back in arm’s-length sales between 2011 and 2015. It paid a total price of $65 million, or $0.32 per gallon average, indicating a reacquisition price of $12.9 million for the subject plant. (See Ptf’s Ex 53 at 4 (chart).)

In November 2019, Pacific Ethanol hired an investment banking firm to assist with marketing its plants. A January 16, 2020, email from Pacific Ethanol’s Vice President of Commodities and Corporate Development to its management team explained: “To be clear, this does not mean that we will sell some assets rather it will allow us the opportunity to sell assets as may be necessary to meet scheduled debt repayment.” (Ptf’s Ex 1 at 24.) Olander testified that, by the end of 2019, Pacific Ethanol had run out of borrowing capacity and lacked cash resources to sustain continued operating losses from plants. The obvious response, according to Olander, was to idle those plants costing the most to operate, including the subject. Pacific Ethanol’s board meeting minutes from January 23, 2020, reference the bank’s presentation on the “viability DECISION TC-MD 200380N 15 of the business in the deteriorating environment” noting that “ethanol prices would need to move (and stay) 20% higher than the current market price in order for the Company to be viable and able to sustain a reasonable amount of leverage.” (Ptf’s Ex 3 at 4.) Johnson noted that the minutes refer to “four different scenarios for resolution of liquidity constraints,” only one of which involved idling the subject. (Def’s Ex A at 70.)

2. Millar’s sales comparison approach (“guideline transaction method”)

Millar observed that “plant owners tend to sell plants when crush margins are low and industry economics are unfavorable and retain plants when crush margins are high or improving. As evidence of this, profit margins slumped in 2012 spurring a flurry of idled and distressed asset sales in 2013.” (Ptf’s Ex 1 at 34.) Since 2013, only a few plants have sold each year, which Millar described as “sluggish.” (See id.) Millar testified that he recognized idling was a “distinct possibility” for the subject as of January 1, 2020, because it was distressed and losing money. (See id. at 34.) A market participant would consider idling the subject given its small size, location, and loss of barge advantage. Millar focused on sales of idled plants because the subject was “economically obsolete and largely unmarketable as of December 31, 2019.” (Id.)

Millar reviewed transactions dating back to 2013 and focused on eight sales of idled plants (sales 1, 2, 3, 4, 5, 10, 15, and 22). (Ptf’s Ex 1 at 34-35.) Five of Millar’s sales occurred in 2013; one occurred in 2014; one in 2015; and one in 2017. (Id.) Sales 1 and 4 both occurred in 2013 and involved the same plant. (Id.) Millar testified that he discounted those sales because they were essentially for scrap. Sale 3 was a 50 mgy plant in Nebraska that sold for $0.30 per gallon in 2013; sale 5 was a 52 mgy plant in Wisconsin that sold for $0.32 per gallon in 2013; and sale 15 was a 60 mgy plant in Virginia that sold for $0.30 per gallon in 2015. 26 (Id. at 35.)

26 Price per gallon of nameplate capacity is the unit of comparison for the industry. (Ptf’s Ex 1 at 34.)

DECISION TC-MD 200380N 16 Millar considered each of those sales as comparable to the subject based on their size. The buyer in sale 15 planned to invest $6 to $7 million “to improve the plant’s profitability.” (Id.) Johnson gave the sale price as $0.32 per gallon for Millar’s sale 15. (Def’s Ex A at 71 (sale 4).)

Millar’s sale 10 was a 110 mgy plant in Indiana that sold for $0.31 per gallon in 2014 and sale 22 was a 100 mgy plant in Indiana that sold for $0.16 per gallon in 2017. (Ptf’s Ex 1 at 35.) Both were significantly larger than the subject. Sale 22 was the same plant that sold for scrap twice in 2013. (See id.) The sale 22 buyer was “a Swiss-based commodities trading company with no other ethanol plants in the United States.” (Id.) Johnson described sale 22 as “forced” because the seller was “facing potential default.” (Def’s Ex A at 71, 73 (sale 13).) She wrote that the plant, originally opened in 1984 and closed in 2012 when the owner filed for bankruptcy, was retrofitted and reopened in 2015. (Id.) It was operating at the time of sale with a 65 mgy capacity and sold for $0.24 per gallon. (Id.) Johnson noted that the buyer planned “planned to spend up to $30 million to improve efficiency and reliability and to expand production capacity by 50% to approximately 100 million gallons per year.” (Id.)

Millar found that “idled plants that will continue to be used for ethanol production” sell for around $0.30 per gallon. (Ptf’s Ex 1 at 36.) Based on the many negative impacts on the subject as of 2019, he concluded a likely price of $0.35 per gallon for the subject, indicating a value of $14 million. (Id.)

3. Johnson’s sales comparison approach

Johnson considered all sales of ethanol plants but did not use idled plant sales because she did not think they were comparable to the subject. (See Def’s Ex A at 70-71.) She equated idled plants with ones that are no longer a going concern. Although cold idling the subject along with Pacific Ethanol’s other Western plants was a possibility as of January 1, 2020, she did not DECISION TC-MD 200380N 17 think it was imminent. (Id. at 70.) Johnson also excluded from consideration sales before 2015, sales that were unknown as of January 1, 2020, and sales with missing information. Ultimately, Johnson relied on ten sales that occurred between 2015 and 2020 and gave most weight to four of those sales (7, 8, 14, and 17). (See id. at 75 (other six sales were 2, 3, 5, 12, 13, and 18). 27)

Sale 7 was a 2016 bankruptcy sale of a 90 mgy plant in Nebraska for $1.28 per gallon. (Def’s Ex A at 71.) Although the seller was in bankruptcy, the plant was of a similar age as the subject. (Id. at 72-73.) Sale 8 was another 2016 bankruptcy sale by the same seller of a 55 mgy 28 plant in Nebraska, an 88 mgy plant in Illinois, and an 88 mgy plant in Indiana for an adjusted price of $1.02 per gallon. (Id. at 71.) Johnson found those plants to be similar in age and size to the subject. (Id. at 73.) Sale 14 was a 2018 sale of a 120 mgy plant in Indiana, a 124 mgy plant in Iowa, and a 60 mgy plant in Michigan for an adjusted price of $0.99 per gallon. (Id. at 71.) Johnson noted that the Michigan plant was similar in size to the subject. (Id. at 74.)

Johnson’s sale 17 was the December 2019 sale of two plants in South Dakota for an adjusted price of $0.58 per gallon. (Def’s Ex A at 71.) One plant was 33 mgy and the other was 49 mgy. (Id.) She found them to be “very good comparable sales for the size and vintage” of the subject, noting the 49 mgy plant “began operations in 2008 and included a train loop track.” (Id. at 74.) The 33 mgy plant “began operations in 1998 but was retro-fitted in 2006.” (Id.) Johnson testified that she reviewed the SEC filings of both the buyer and seller. She found similar market pressures on the seller as on Plaintiff; bankruptcy was on the table, so the sale captured some of the same economic obsolescence. Millar reported this sale price as $0.55 per gallon. (Ptf’s Ex 1

27 Sales 3, 12, and 18 each involve Pacific Ethanol and are discussed below. Sale 13 is the 2017 sale of a plant in Indiana discussed above (Millar’s sales). 28 Defendant variously listed the capacity of sale 8’s Nebraska plant at 55 and 50 mgy, respectively. (Id. at 71 and 73.)

DECISION TC-MD 200380N 18 at 35 (sale 25).) He testified that the buyer owned a few plants in South Dakota, so “synergistic premiums” made the sale appealing.

Johnson testified that she did not find many sales of smaller plants, but the four sales she selected were a bit smaller and more representative of the subject. All her comparable sales were located closer to corn, but further from the “low carbon markets.” 29 The plants were mostly of a similar age as the subject, 2007 to 2008. Johnson made qualitative adjustments for conditions of sale, proximity to corn feedstock, proximity to low carbon markets, capacity size, land, and year built. (See id. at 76-78.) She did not make any adjustments for storage capacity, though each of her sales included more than the subject. Johnson gave the most weight sale 17 and concluded a value of $0.63 mgy for the subject, indicating a value of $25,200,000. (Id. at 78.)

4. Additional sales involving Pacific Ethanol

Each appraiser discussed three sales involving Pacific Ethanol, although neither placed much if any weight on the sales. First, Pacific Ethanol acquired four plants in Nebraska and Illinois in 2015. (Ptf’s Ex 1 at 35; Def’s Ex A at 71.) The Nebraska plants are the two in Aurora discussed below, which Pacific Ethanol sold in 2020. The Illinois plants are 60 and 100 mgy capacity. (Id.) Millar reported the sale price as $0.99 per gallon, whereas Johnson reported $1.21 per gallon. (Id.) Johnson described the transaction as a merger. (Def’s Ex A at 71-72.)

Second, Pacific Ethanol purchased an 84 mgy plant in Illinois for $0.73 per gallon in 2017. (See Ptf’s Ex 1 at 34-35.) Millar noted that Pacific Ethanol owned two other plants nearby. (Id.) Johnson reported the plant size as 90 mgy and the sale price as $0.85 per gallon. (Def’s Ex A at 71 (sale 12).) She wrote that the plant “was acquired through a merger” paid partially in cash and partially in “non-amortizing secured promissory notes.” (Id. at 73.)

29 Specifically, California and Oregon. (See Def’s Ex A at 77.)

DECISION TC-MD 200380N 19 Johnson did not ultimately rely on the sale because “it was difficult to isolate the exact sales price less working capital and inventory due to the merger * * *.” (Id.)

Third, Pacific Ethanol sold its majority interest in two plants in Aurora, Nebraska to the minority investor in April 2020. (See Ptf’s Ex 1 at 18, 35.) Millar reported that Pacific Ethanol signed a letter of intent in September 2019 to sell its 75 percent interest for $57.3 million, including working capital of $34.1 million. (Id. at 18.) He calculated the price for 100 percent interest, less working capital, was $46.2 million or just under $0.30 per gallon. (Id.) Olander testified that the two plants were located on the same campus; the 110 mgy plant was operating, but the 45 mgy was idled due to economic conditions. (See id.) The buyer owned a 26 percent minority interest and came forward with the best price. Pacific Ethanol also agreed to cover some deferred maintenance and made upgrades at cost of $2.5 million. The property included a unique feature: a separate grain-handling elevator that was appraised at $16.5 million in 2016. Olander testified that, after those adjustments, the indicated price was $0.36 per gallon. Johnson reported the sale as $0.49 per gallon. (Def’s Ex A at 71 (sale 18).) She gave it no weight due to “an excessive working capital adjustment” that did not make sense in light of the total sales price and the fact that one of the two plants was idled. (Id. at 74.)

5. Analysis and conclusion of indicated value

“[A] recent, voluntary, arm’s length transaction between a buyer and seller, both of whom are knowledgeable and willing, * * * while certainly not conclusive, is very persuasive of the market value.” Kem v. Dept. of Rev., 267 Or 111, 114, 514 P2d 1335 (1973). Neither appraiser relied on Pacific Ethanol’s repurchase of its plants following bankruptcy and the court sees no reason to do so given the date of those sales and the preceding bankruptcy. At most, the price of $0.32 per gallon serves as a reference point for the low end of the value range. DECISION TC-MD 200380N 20

Turning to the comparable sales, the court notes that the appraisers presented some conflicting information concerning plant capacity and sale prices. Some of those differences may be due to differing adjustments for working capital. 30 Others appear to be due to different factual understandings: for instance, whether the plant in Indiana (Millar’s sales 1, 4, and 22) was 100 mgy at the time of sale, or rather, would be improved by the 2017 buyer to become that capacity from 65 mgy (Johnson’s sale 13). Ultimately, the court is unable to reconcile those differences.

Millar focused exclusively on sales of idled plants for his valuation. Although Plaintiff’s financial outlook was not good at the end of 2019 and idling was clearly on the table, the subject was not in fact idled as of January 1, 2020. Both appraisers appeared to agree that the distinction between idled and operating plants was important to valuation, and Millar’s sales evidence supports that conclusion. Thus, the court is not persuaded by Millar that only sales of idled plants should be considered as comparable to the subject. The court also declines to adopt Johnson’s view that sales of idled plants are, necessarily, equivalent to auction, liquidation, or scrap sales. (See Def’s Ex A at 70-71 (citing OAR 150-308-0260(3)(f) (“sales for the disposal of properties through auction, liquidation, or scrap sales are indicators of market value only when on the assessment date such disposal of the subject property is imminent or has actually taken place”).) Although some idled plant sales appear to fit that category (for example, Millar’s sales 1 and 4), other sales are to buyers who plan to resume operations following sale (for example, Millar’s sales 5 and 15). Thus, the court will consider sales of idled plants, but finds they are at the low end of the value range. ///

30 Each appraiser testified that working capital should be subtracted from the sales price.

DECISION TC-MD 200380N 21

Perhaps related to his decision to focus only on idled plants, Millar also relied primarily on older sales from 2013. That was one of the worst years for the ethanol industry due to a severe drought that reduced the supply of corn and dramatically increased corn prices. The industry faced challenges in 2018 and 2019: negative crush margins driven by low ethanol prices, reduced domestic demand, and oversupply. However, the evidence presented does not indicate that 2019 was as bad as 2013. See Sabin, 270 Or at 426-27, and Level 3, WL 2230557 at *8 (requiring a comparison of conditions at time of transaction with time of the assessment). Indeed, Millar noted the significant sales activity in 2013 was driven by poor profit margins in 2012 and resulting distressed sales. Ultimately, the court concludes that Millar’s value of $0.35 per gallon is understated because he limited his analysis to sales of idled plants, primarily from 2013.

Johnson focused exclusively on sales of operating plants, albeit two of which were sold in bankruptcy. She also selected plants of a similar age as the subject with sales dates closer in proximity to the January 1, 2020, valuation date, making them somewhat more persuasive. However, the court is not persuaded by several of Johnson’s qualitative adjustments. Most significantly, Johnson treated a comparable sale’s proximity to the Midwest corn belt as offset by the subject’s proximity to low carbon markets. (Def’s Ex A at 77-78 (“It is assumed that the locational disadvantage of having to ship corn feed stock via rail is balanced by having the ability to sell ethanol with a lower carbon intensity score which is supported by the statements in Pacific Ethanol’s 2019 10-K report”).) That assumption is contradicted by Olander’s testimony concerning the shortcomings of the “destination model” plant in practice as well as the behavior of market participants, paying more for plants in the Midwest. Of Johnson’s four comparable sales, the highest prices were commanded by the plants in Illinois, Indiana, and Nebraska even DECISION TC-MD 200380N 22 though they were bankruptcy sales. That indicates that proximity to corn has a significant impact on price, more so than proximity to low carbon markets. The court concludes that Johnson’s value of $0.63 per gallon is overstated.

The court finds that the two most relevant sales are the 2019 sale in South Dakota and the 2020 sale in Aurora, Nebraska. Both sales are close to the January 1, 2020, assessment date and, therefore, capture some of the market pressures in the ethanol industry. The South Dakota sale involved two plants of a similar size and age to the subject. The location was superior in terms of proximity to corn but was not one of the top three corn producing states. (See Ptf’s Ex 1 at 11; Def’s Ex A at 77.) The sale price of $0.55 to $0.58 per gallon is a good, albeit somewhat high, indicator for the subject. The Aurora sale involved two plants owned by Pacific Ethanol: one of a similar size as the subject that was idled at the time of sale, and a second, larger plant that was operating. The sale likely reflects similar financial pressures as those impacting the subject. The location in Nebraska is superior, but the fact that one plant was idled was inferior. It is difficult to discern the sale price for the plants given the unusually large amount of working capital reported and other assets sold, but it was no more than $0.49 per gallon. Considering those sales, the court finds a value of $0.49 per gallon, or $19.6 million, is indicated. B. Income Approach -- Discounted Cash Flow

The income approach is based on the idea that “a potential investor will be willing to pay a price for an asset that reflects the present value of the future benefits (i.e., income) that the investor can obtain from the asset.” Union Pacific R. Co. v. Dept. of Rev., 315 Or 11, 20, 843 P2d 864 (1992). It “measures the present value of the anticipated future stream of income attributable to the company’s operating property, by discounting the company’s anticipated cash flows to present value using a capitalization rate that reflects the company’s costs of DECISION TC-MD 200380N 23 investment.” Delta Air Lines, Inc. v. Dept. of Rev., 328 Or 596, 603, 984 P2d 836 (1999).

Both appraisers used the DCF method to value the subject, forecasting debt-free cash flow for the five-year period of 2020 to 2025. (Ptf’s Ex 1 at 38, 46; Def’s Ex A at 88.) Defendant’s rule generally approves of using the DCF to value industrial property:

“When using the income approach, the income from the operation of the property may be utilized for industrial properties and other properties that are not typically leased or rented. When the income from the property’s operation is used, the unit of property must be valued as a going concern. In utilizing the income approach for the valuation of industrial properties, the discounted cash flow technique is one of the appropriate methods to derive a value estimate.”

OAR 150-308.0260(3)(h). The two key parts of the income approach are forecasting the income stream and discounting that income stream. Union Pacific, 315 Or at 20.

“The income approach requires a correct determination of the net income or net cash flow.” Southern Pacific Transp. Co. v. Dept. of Rev., 11 OTR 138, 142 (1989). The “essence” of the approach “lies in the assumptions made by the appraisers.” Id. at 149. Determination of net cash flows involves consideration of “historical experience and future prospects.” Union Pacific, 315 Or at 22. With respect to the railroad property at issue in Union Pacific, the court found that “many growth-defeating factors” supported the taxpayer’s projection of no industry growth; for instance, the railroad industry was “mature * * * with little possibility of expansion in terms of miles of road” or ton-miles. Id. at 26. The court further found that the department erred by relying, in part, on taxpayer’s “internal strategic plans” because they were not “sufficiently reliable” to be used in the DCF. Id. at 27. The plans had an “historic record of unjustified optimism” in light of evidence about the state of the railroad industry. Id.

1. Millar’s DCF analysis

Millar testified that he relied on Plaintiff’s 2020 budget and five-year forecast to create his model, documents a reasonable investor would consider. (See Ptf’s Ex 1 at 30.) He noted DECISION TC-MD 200380N 24 that the 2020 budget reflects “current market conditions and [Plaintiff’s] expectations[,]” whereas the five-year forecast is more optimistic. (Id.) Michael, who prepared the budget and forecast, testified that the forecast is used to motivate employees and was more optimistic than the 2019 historical data indicated. (See Ptf’s Ex 42.) Millar’s model assumed Plaintiff’s ethanol sales would increase from 35.8 mgy in 2020 to 39.2 mgy in 2021 “and then stabilize at or near that level.” (Ptf’s Ex 1 at 38.) He assumed Plaintiff would “be able to sell ethanol at $1.54 per gallon in 2020 and $1.66 per gallon thereafter.” (Id.) Millar added coproducts revenue of $16.1 million in 2020 and $19 million in each year thereafter, resulting in total revenues of $71.4 million in 2020 and $84 to $84.2 million in each year thereafter. 31 (Id. at 46.) Millar testified that he projected negative operating income in 2020, but positive income in the subsequent years, which was better than Plaintiff’s prior five-year performance. He found the DCF indicated a value of $14,893,223. (Id.)

Johnston testified that she found Plaintiff’s revenue projections did not align with historical data. (See Def’s Ex A at 81.) In 2019, Plaintiff reported its ethanol price as $1.75 per gallon, co-products revenue of $20.2 million, and total revenue of $83 million, each more than its 2020 budget used by Millar. (See Ptf’s Ex 1 at 46.) Johnson noted that Plaintiff projected an ethanol spot price of $1.49 for the first quarter of 2020, $1.54 for the second quarter, $1.59 for the third quarter, and $1.64 for the fourth quarter, but the average OPIS spot price for the fourth quarter of 2019 was $1.66 and the average spot price for 2019 was $1.60. (Def’s Ex A at 81-82.) She could not determine if Millar incorporated the full value of the carbon credits into his valuation. (See id. at 84. ) ///

31 Figures are all rounded.

DECISION TC-MD 200380N 25

Michael testified that it is challenging to forecast ethanol prices because production is seasonal and demand is cyclical. Plants tend to produce more ethanol during the colder months, but consumers use more ethanol during warmer months when there is more travel volume. Although OPIS prices were higher in 2019, trending toward $1.70 per gallon in the fourth quarter, he deducted about $0.15 because first quarter prices are usually $0.15 less than the fourth quarter prices. (See Ptf’s Ex 16.) Michael thought 2020 would be a weaker year due to poor export prices. OPIS prices do not include freight or basis because those are negotiated with the customer. Kinergy performed a “true up” process at the end of each month subtracting freight and basis from the provisional market price for ethanol, including carbon credits, to yield “net back,” which is the effective sale price to Plaintiff. Michael’s coproducts assumptions were determined in reference to corn costs: Plaintiff can recover 25 to 30 percent of corn costs through coproduct sales.

2. Johnson’s DCF analysis

For each year, Johnson assumed an ethanol price of $1.60 per gallon, to which she added a clean fuel premium (CFP) of $0.24 per gallon and subtracted transportation costs of $0.09 per gallon for a netback of $1.75 per gallon. (Def’s Ex A at 88.) The price of $1.60 per gallon was the average price for Oregon ethanol in 2019; the average price in 2018 was $1.55 and the average price in 2017 was $1.64. (Id. at 82-83.) Johnson’s CFP of $0.24 per gallon was based on the premium Plaintiff received in December 2019 from its CI score of 51.48 compared to the CI standard of 69.89, and a price of $161.41 per carbon credit. (Id. at 84-84.) She projected that Plaintiff would produce 39 to 39.3 mgy each year. (Id. at 87-88.) Johnson received Plaintiff’s netback calculation, including basis and freight, but did not receive supporting documentation so she did not deduct basis and separately calculated freight. (Id. at 85.) She based her freight costs on Plaintiff’s 2019 average cost. (Id.) Johnson added co-products revenue of $19.5 million each DECISION TC-MD 200380N 26 year based on Plaintiff’s 2019 sales for total revenues of $87.8 to $88.2 million annually. (Id. at 87-88.) After making her own revenue calculations, Johnson testified that she adopted Millar’s other assumptions, finding them to be supported by market data and Plaintiff’s operating history. (See id.) She found the DCF indicated a value of $34,018,516. (Id. at 88.)

Millar testified that reversion value should reflect the assumptions used in the model, so Johnson erred by adopting Millar’s reversion value because each of their DCF analyses relied on different assumptions. Michael testified that Johnson’s analysis was “all over the place” insofar as she sometimes used yearly prices, sometimes used quarterly prices, and used an incorrect freight cost calculation. In particular, he took issue with her failure to subtract basis – resulting in an overstatement of approximately $4 million per year – and her reliance on Plaintiff’s fourth quarter 2019 CFP of $0.24 per gallon, close to an historic high. (See also Def’s Ex A at 60, 84-85.) Plaintiff’s average CFP in 2019 was $0.22 per gallon. (See id. at 84.) Michael testified that, if Johnson’s model were revised to deduct basis and use a CFP of $0.19 per gallon, it would indicate a value of $18,345,242. He found it appropriate to use a more conservative CFP because the program was relatively new.

3. Analysis and conclusion of indicated value under DCF

Millar’s DCF analysis is based on Plaintiff’s budget and forecast. Undoubtedly, Michael considered historical performance to create the budget and forecast, but other factors played a role because those documents serve a variety of purposes, such as motivating employees. As the court noted in Union Pacific, internal strategic plans may not be sufficiently reliable for the DCF. Thus, the court focuses on recent historical data as the most useful evidence of Plaintiff’s likely future revenue, absent clear evidence suggesting otherwise. Looking at Millar’s DCF in that light, several of his 2020 projections are understated compared to Plaintiff’s 2019 actual performance. Specifically, ethanol prices and coproducts revenue. Michael expected 2020 to be DECISION TC-MD 200380N 27 a weaker year due to poor export prices. However, exports had already declined from 2018 to 2019 and it is unclear what additional factors seemed likely to cause further decline in 2020.

Johnson’s DCF is overly optimistic in some respects. For instance, she forecast a large increase in Plaintiff’s production to 39 mgy in 2020, whereas Plaintiff produced 35.2 mgy in 2018, and 35.8 mgy in 2019. She selected a CFP of $0.24 per gallon, nearly the historic high for a new program with limited price data, rather than a more conservative figure such as the 2019 average CFP of $0.22 per gallon. Perhaps most importantly, Johnson did not deduct basis. The court does not fault her because Plaintiff failed to timely supply her with sufficient supporting data. However, the court agrees with Plaintiff that Johnson’s conclusion is overstated as a result.

Michael testified that Johnson’s DCF, if revised to deduct basis and reflect a lower CFP of $0.19 per gallon would indicate a value of $18,345,242 for the subject. His CFP of $0.19 per gallon is low compared to the 2019 average of $0.22 per gallon and upward trend since the inception of the Clean Fuels Program. Nevertheless, Michael’s proposed revision to Johnson’s DCF provides a reasonable, albeit low, value indication. C. Value Reconciliation

Millar gave equal weight to both approaches to value, concluding a reconciled value of $14,400,400. (Ptf’s Ex 1 at 40.) Johnson gave most weight to the sales comparison approach and some weight to the income approach, concluding a reconciled value of $27,500,000. (Def’s Ex A at 89-90.) She testified that she used the DCF due to the subject’s volatility, but the method is not typically used for assessment and taxation because small input changes can result in “vastly different” values. (See also id. at 79-80. 32) Millar testified that he considered the DCF

32 Johnson quoted an article entitled Fundamentals of Industrial Valuation,” which stated that, in the context of litigation, the DCF should “be considered only lightly as a secondary or tertiary approach, insofar as it corroborates other methods.” (Def’s Ex A at 80, 94.)

DECISION TC-MD 200380N 28 to be good at capturing the volatility in the subject’s income stream. Michael testified that the DCF is not speculative, it’s the industry standard. Investment banks use it to value companies. It provides a more accurate long-term model because it builds in business cycles.

The court agrees that both the sales comparison and income approaches are appropriate and useful methods to value the subject property. 33 The court places more weight on the sales comparison approach because transactions that occurred close to the January 1, 2020, assessment date capture many of the market forces impacting the subject on that date. The court places less weight on the income approach due to the issues noted with respect to each appraiser’s projected income. In reconciliation, the court finds an indicated value of $19.3 million.

III. CONCLUSION

Upon careful consideration, the court finds that the subject property’s 2020-21 real market value was $19.3 million. Now, therefore,

IT IS THE DECISION OF THIS COURT that the 2020-21 real market value of property identified as Accounts 10607, 10673, and 11301 was $19.3 million.

Dated this _____ day of April 2023.

ALLISON R. BOOMER PRESIDING MAGISTRATE

If you want to appeal this Decision, file a complaint in the Regular Division of the Oregon Tax Court, by mailing to: 1163 State Street, Salem, OR 97301-2563; or by hand delivery to: Fourth Floor, 1241 State Street, Salem, OR.

Your complaint must be submitted within 60 days after the date of this Decision or this Decision cannot be changed. TCR-MD 19 B.

33 The court gives no weight to cost approach for reasons stated by appraisers: the age of subject and difficulty measuring economic obsolescence.

DECISION TC-MD 200380N 29

This document was signed by Presiding Magistrate Allison R. Boomer and entered on April 20, 2023.

DECISION TC-MD 200380N 30