Aemetis, Inc

Welcome to the AMETIS fourth quarter and year 2021 earnings review conference call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Todd Waltz, Executive Vice President and Chief Financial Officer of AMETIS, Inc. Mr. Waltz, you may begin.

Thank you, Kate. Welcome to the AMETIS fourth quarter and year 2021 earnings review conference call. Joining us for the call today is Eric McAfee, founder, chairman, and CEO of AMETIS, and Andy Foster, president of AMETIS Advanced Fuels and AMETIS Biogas. We suggest visiting our website at ametis.com to review today's earnings press release, the AMETIS corporate and investor presentations, filing with the Security and Exchange Commission, recent press releases, and previous earnings conference calls. The presentation for today's call is available for review and download on the investor section of the ametis.com website. Before we begin our discussion today, I'd like to read the following disclaimer statements. During today's call, we'll be making forward-looking statements, including, without limitation, statements with respect to our future stock performance plans, opportunities, and expectations with respect to financing activities and the execution of our business plan. These statements must be considered in conjunction with the disclosures and cautionary warnings that appear in our SEC filings. Investors are cautioned that all forward-looking statements made on this call involve risk and uncertainty, and that future events may differ materially from the statements made. For additional information, please refer to the company's Security and Exchange Commission filings, which are posted on our website and available from the company without charge. Our discussion on the call will include a review of non-GAAP measures as a supplement to financial results based on GAAP. A reconciliation of the non-GAAP measures to the most directly comparable GAAP measures is included in our earnings release for the quarter ended on December 31, 2021, which is available on our website. Adjusted EBITDA is defined as net income or loss plus, to the extent deducted in calculating such net income, interest expense, gains on extinguishment, income tax expense, intangible and other amortization expense, accretion and other expense of Series A preferred units, depreciation expense, and share-based compensation expense. Now I'd like to review the financial results for the fourth quarter and year end of 2021. Revenues were $64.4 million for the fourth quarter of 2021 compared to $37.3 million for the fourth quarter of 2020. The selling price of ethanol increased from $1.60 per gallon during the fourth quarter of 2020 to $3.36 per gallon during the fourth quarter of 2021. The delivered corn price rose from an average of $5.61 per bushel during the fourth quarter of 2020 to $7.23 per bushel during the fourth quarter of 2021. Our California ethanol and dairy natural gas segments accounted for all of the reported consolidated gross profits in both periods. Gross profit for the three months ended December 31, 2021 was $12.7 million compared to a gross loss of $3.4 million during the same period in 2020. The gross profit increase was attributable to stronger ethanol and wet distillers grains pricing during the fourth quarter of 2021 compared to the fourth quarter of 2020. Selling general administrative expense increased to $7.5 million during the fourth quarter of 2021 compared to $4.3 million during the fourth quarter of 2020, principally due to a $2.5 million non-cash share-based compensation charge. Operating profit was $5.2 million for the fourth quarter of 2021 compared to an operating loss of $7.7 million during the fourth quarter of 2020. Net loss was $881,000 for the fourth quarter of 2021 compared to a net loss of $14.6 million for the fourth quarter of 2020. Turning to the financial results for the year ended December 31, 2021. Revenues were $212 million for the 12-month end of December 31, 2021, compared to $166 million for the same period in 2020, which is a 28% revenue increase for 2021 compared to 2020. The increase in revenue was primarily attributable to increase in the sales price for ethanol in California from $1.84 per gallon during 2020 to $2.72 per gallon as demand for ethanol increased as recovery from COVID-19 disruptions continued. Gross profit for the 12 months ended December 31, 2021 was $7.9 million compared to $11 million of gross profit during the same period in 2020, primarily due to the stronger margin associated with high grade alcohol sales coupled with lower corn prices during the December 31, 2020 in our California ethanol segment and lower gross profit margin contribution from our India biodiesel segment during 2021. Selling general and administrative expenses increased to $23.7 million during the 12 month ended December 30, 2021 compared to $16.9 million during the same period in 2020 driven principally from a charge for stock-based compensation, property insurance and professional services. Operating loss increased to $15.8 million for the 12 months ended December 31, 2021, compared to an operating loss of $6.1 million for the same period in 2020. Interest expense was $24.1 million during the year ended December 31, 2021, excluding accretion and other expensive Series A preferred units in our Ametis Biogas LLC subsidiary, compared to interest expense of $26.4 million during the year ended December 31, 2020. Additionally, our Ametis Biogas LLC subsidiary recognized $7.7 million of accretion in connection with preference payments on its preferred stock, during the year ended December 31, 2021, compared to $4.7 million during the same period in 2020. Net loss was $47.1 million for the 12 months ended December 31, 2021, compared to a net loss of $36.7 million during the same period in 2020. Cash at the end of the fourth quarter of 2021 increased to $7.8 million compared to $592,000 at the end of 2020. Investments in our low-carbon initiatives increased property plant equipment by $30.5 million, while debt repayment of $55.5 million were made during 2021. These activities and others were funded with proceeds from equity offerings of $103.6 million. This completes our review of the fourth quarter and year end of 2021. Now, I'd like to introduce the founder, chairman, and chief executive officer of AMETIS, Eric McAfee.

Let's update. Eric. Thank you, Todd. AMETIS is focused on producing below zero carbon intensity products, including the production of negative carbon intensity renewable natural gas and renewable fuels. Our projects maximize the value of carbon credits under the California Low Carbon Fuel Standard, the federal renewable fuel standard, IRS 45Q carbon sequestration tax credits, and Blender's tax credits, while reducing operating costs by using waste materials as feedstock. In early 2021, we announced a five-year plan to grow to more than $1 billion of revenues and $325 million of annual EBITDA cash flow by year 2025. Last month, we updated the five-year plan projecting revenues to grow to $1.5 billion and annual EBITDA to increase to $460 million by year 2026. We are on track with last year's five-year plan. In the past year and this year, we have paid $79 million to reduce the higher interest rate bridge loans from Third Eye Capital, with only about $90 million of high interest rate loans remaining outstanding to Third Eye. We are also on track with financing growth, using long-term 20-year low interest rate project financing from the United States Department of Agriculture, including a $50 million funding for our biogas subsidiary that is expected to close in the next couple of months. Importantly, our 2021 fourth quarter cash flow and our 2021 annual revenues were on track with the five-year plan. The positive regulatory trends for renewable fuels have continued to improve. driven by initiatives to decarbonize transportation, the need to reduce the cost of fuels as petroleum prices increase, and a renewed interest in energy security. California, and much of the rest of the country, currently enforces a 90% petroleum gasoline mandate, which is commonly known as a 10% ethanol blending limit. With record high gasoline prices in California, the fact that AMETIS sells ethanol for more than $2 per gallon less than gasoline creates a direct cost to California consumers by the California Air Resource Board's slow progress toward adoption of E15. E15 allows a 15% blend of ethanol into gasoline, directly decreasing fuel costs to California drivers and expanding the use of renewable fuels in the state. We're hopeful that this year, especially with consumers getting squeezed by high prices of the pump, CARB will move forward with the 15% ethanol blending requirement in California. During the fourth quarter and year of 2021, Emetis achieved important milestones toward revenue growth and sustained profitability in each of our four lines of business. Now, Andy Foster, the president of the Emetis Biogas and Emetis Advanced Fuels businesses, will review highlights of our renewable natural gas and ethanol business. Andy?

Thanks, Eric. The Ametis dairy renewable natural gas business has been producing biogas since September of 2020, and we received a negative 426 carbon intensity pathway from CARB in 2021 for our first two dairy digesters. RNG is a negative carbon intensity renewable fuel that exemplifies the circular bioeconomy that Ametis is creating by using waste products and byproducts of our production facilities as feedstocks to produce sustainable, below zero carbon intensity transportation fuels. Let me take a moment to update you on some key milestones achieved as we build out our network of dairy digesters and the supporting infrastructure that will deliver RNG to the California market. In addition to the two dairy digesters and four miles of gas pipeline currently in operation since September of 2020, We have completed the construction and are currently commissioning the main biogas cleanup facility and utility pipeline interconnection unit. We are also currently permitting, procuring equipment, and or constructing an additional 15 dairy digesters and 32 miles of biogas pipeline. We now have executed participation or lease agreements with 24 dairies to install digesters. We are in advanced discussions with more than a dozen additional dairies. As the pipeline and digesters are built, we are receiving additional inquiries from other dairies in the local area who would like to participate in the AMETIS biogas project. AMETIS was granted an encroachment permit to use the public right-of-way in local roads, county roads, for the construction of the 21-mile Stanislaus County segment of our pressurized biogas pipeline and the 11-mile Merced County segment of the pipeline. About 16 miles of the 36 miles 36 mile biogas pipeline, nearly 50% has been completed with expected completion of the entire biogas pipeline construction before the end of 2022. Five additional digester projects are now under construction with the expected completion of these five digesters in the summer of 2022. The portion of the pipeline to transport biogas from these five dairies to the central biogas upgrading facility has already been completed. A USDA guaranteed loan under the Renewable Energy for America program, known as REAP, is nearing completion of a $50 million financing for dairy digesters, on-site H2S cleanup and pressurization, and pipeline construction at about a 6% interest rate to be repaid over 20 years. An additional $50 million of USDA REAP financing is in process for closing in Q4 of 2022, with another $50 million expected to close in 2023. The USDA guaranteed credit facilities enable the construction of the biogas project without equity dilution to AMETIS parent company shareholders. During 2021, we added several key people to our biogas team, including an experienced senior dairy digester operations manager who recently managed 10 dairy biogas digesters in California's Central Valley, and a construction supervisor with extensive civil engineering and construction project management experience. Our pipeline construction manager is a 30-year industry veteran who supervised the installation of our phase one pipeline while working for our lead contractor. We've also added an operations and maintenance operator who has extensive experience working at our ethanol plant for the past 10 years. To date, AMETIS has been awarded $23 million of grants related to the biogas project from the California Department of Food and Agriculture, CDFA, the California Energy Commission, Pacific Gas and Electric, and other government agencies for the dairy biogas project and the production of renewable natural gas. The RNG initiative has many natural synergies with our Keys ethanol plant, which uses agricultural feed, feedstock that absorbs CO2 from the atmosphere during plant growth, from which our production facility produces ethanol and high-value animal feed. The Ametis ethanol plant produces about 65 million gallons per year of renewable ethanol, but also produces about two million pounds per day of wet distillers grains that supply about eighty local dairies to feed more than a hundred thousand cows. These cows consume the renewable feed produced by AMETIS and create waste, which in turn produces the methane we capture for the production of RNG. Trucks involved in our ethanol, animal feed, sustainable aviation fuel, renewable diesel, and carbon sequestration businesses can be fueled by our RNG at compressed natural gas fueling stations at locations throughout the state of California or at the RNG fueling site that we are building at the Keys plant. Additionally, the Keys ethanol plant produces approximately 1.4 million pounds per month of renewable distillers oil, corn oil, or DCO, which has been traditionally sold as animal feed. With the explosive growth of renewable diesel, biodiesel, and sustainable aviation fuel, DCO has become a far more valuable commodity as a feedstock input to renewable fuels. In fact, the value of our DCO has more than tripled since we first started producing it in 2012, allowing us to sell this coproduct to other biofuel producers and eventually utilize it in the production of AMETIS, SAF, and renewable diesel at our own riverbank plant, further complementing the circular bioeconomy that Eric often refers to when describing our business model. Let's discuss progress at our California ethanol plant. As Todd mentioned earlier, we saw a 28% year-over-year increase in revenues from ethanol sales in 2021 compared to 2020. As the COVID pandemic restrictions were relaxed in the second half of 2021, demand for ethanol increased and ethanol margins also increased. At the same time, high corn prices and a tight corn supply have combined with ongoing railroad logistical issues to increase the cost of corn to about $9 per bushel delivered to Keys, nearing all-time highs. Strong demand and favorable pricing for both wet distillers grains and distillers corn oil remain bright spots in the overall product mix, and we expect this trend to continue. Let me take a moment to provide a few updates on the Keys ethanol plant projects that are expected to increase cash flow by approximately $23 million per year when the projects are fully completed. The Keys ethanol plant is operating at full capacity, taking advantage of strong ethanol, distillers corn oil, and distillers grain pricing. Wet distillers grains are completely sold out with more than 2.2 million pounds per day, or the equivalent of 45 truckloads being delivered to dairies across our region. Distillers corn oil deliveries are more than 1 million pounds per month at record prices, driven by the use of non-edible corn oil in biodiesel and renewable diesel production. CO2 production at the Keys plant is approximately 400 metric tons per day, which is being upgraded, compressed, and delivered to local food and beverage processors by Messer, generating about $3.4 million per year of tax credits at a $30 per metric ton under current law. The Mitsubishi Zebrex dehydration unit, which separates water from ethanol, has been fully installed, the test run has been completed, and the system met or exceeded key system design milestones. The goal of significantly reducing steam consumption in the plant has been demonstrated in stable operations with the reduction from 20,000 pounds of steam per hour to less than 5,000 pounds of steam per hour. Since steam is currently mostly produced from carbon-intensive, expensive petroleum-based natural gas, this 75% reduction in steam use for the ethanol dehydration reduces our operating costs and increases our revenues through lower carbon-intensity ethanol. Additional commissioning work is currently underway, and we expect to have the Zebrax system fully operational during the second quarter of this year. The solar microgrid with battery backup is progressing with the signed EPC contract with SunPower for the installation of a $12 million solar microgrid. This project is supported by an $8 million grant from the California Energy Commission. The solar unit is designed to generate approximately 1.9 megawatts of zero carbon intensity electric power at a low cost for operation at the ethanol plant. The mechanical vapor recompression system, otherwise known as MVR, to further reduce petroleum natural gas and steam use is moving forward with detailed engineering almost completed. This project is expected to significantly reduce the use of petroleum natural gas, and combined with the ZBREC system, we expect to eliminate approximately 85% of our natural gas use when the MVR system becomes operational in 2023. Currently, natural gas costs for the Keys plant are more than $10 million per year, so we expect to save more than a $8 million per year of natural gas cost, while also reducing the ethanol's carbon intensity, therefore increasing the value of the ethanol produced by the Keys plant. Our California ethanol plant is being upgraded to primarily operate using high-efficiency electric motors and pumps powered by low or zero carbon intensity renewable power sources, including our solar array and local renewable electricity. In summary, operational performance and project milestones for the AMETIS biogas and AMETIS plant, ethanol plant businesses are on track with our five-year plan.

Eric? Thank you, Andy. Let's discuss our carbon zero renewable jet and diesel fuel project with carbon sequestration in Riverbank, California. We are pleased that the Amedis Carbon Zero Biorefinery under development in Riverbank, California near Modesto continues to achieve major milestones. In December 2021, after three years in negotiations with the City of Riverbank and the U.S. Army, Amedis signed the acquisition of the 125-acre Riverbank Industrial Complex. This site is a former U.S. Army ammunition production facility. with 710,000 square feet of existing buildings laid out as eight production lines, 120 rail cars and a rail line on the site, a 20 megawatt electricity substation, and 100% zero carbon intensity renewable power with a direct power line connection to a hydroelectric dam. The terms of the agreement provide for a payment of about $145,000 per year to the City of Riverbank along with ongoing investments in building our sustainable aviation fuel and renewable diesel plant at the site. But Emetis receives all of the lease revenue from more than 30 existing tenants at the facility. We expect to transfer ownership to about 50 acres of the Riverbank site to Emetis during 2023 for a total of $2.6 million. Actually, correction, during 2022 for a total of $2.6 million, including the jet diesel plant site and the carbon sequestration project site. The remaining 75-acre parcel will be under the low-cost lease for about 15 years, and then will be purchased by Metis for $8.8 million. In the past two quarters, we have announced $2.5 billion of sales contracts with Delta Airlines, American Airlines, and Japan Airlines for blended sustainable aviation fuel for flight operations at San Francisco Airport. Additional memorandums of understanding have been signed with other airlines for more than $1 billion of sales contracts. These additional agreements are expected to be announced during the next quarter. Under the sales agreements, the NEAT SAF will be trucked from the Riverbank production plant to a tank farm in the San Francisco Bay Area for blending with jet fuel. The blended SAF will be delivered via pipeline to San Francisco Airport for use by airlines. In addition to major U.S. and international airlines, we have received a high level of interest from leading private jet FBOs due to meeting corporate jet owner interest in sustainable aviation fuel. In addition to the $2.5 billion of blended sustainable aviation fuel sales contracts, we signed a $3.2 billion renewable diesel sales agreement to deliver 45 million gallons per year under a 10-year sales contract with a major travel stop chain for its Northern California locations. The construction of the renewable jet and diesel plant is moving forward steadily. We are currently in the engineering phase to support the closing of the debt financing, which is planned for late this year. We announced that the $2 billion global EPC contractor CTCI has begun engineering work to support completion of the permits and the EPC agreement. CTCI is currently constructing a 225 million gallon renewable diesel plant in Bakersfield, California, with planned completion of that plant in mid-2022. And CTCI is ideally suited to construct the Amedis plant on time and on budget. Let's review our new subsidiary, Amedis Carbon Capture. In October 2020, the Ametis plant in California was identified in this study issued by the Stanford University Center for Carbon Capture as one of three ethanol plant CO2 sources in California that have the highest potential return on investment from building a carbon capture and sequestration facility compared to the oil refineries, cement plants, and natural gas power plants that comprise the 61 largest CO2 emission sources in California. Our ethanol plant currently captures about 150,000 metric tons per year of CO2 and compresses the CO2 in the Messer liquefaction plant into transportable liquid carbon dioxide, from which we already generate IRS 45Q tax credits worth $30 per metric ton from CO2 reuse. Current operations generate about $3.4 million per year of tax credits. We selected Baker Hughes as the drilling vendor for the CCS project, a $20 billion market value company operating in more than 120 countries. Baker Hughes was originally founded in the west side of the Central Valley of California about 100 years ago. And the company is very familiar with the formations in the former inland ocean that formed the Central Valley. The carbon sequestration study prepared by Baker Hughes determined that the Ametis Keys plant and the Riverbank plant site are located above a 7,000 foot deep strata known as a cap rock and an 8,000 foot deep strata known as a basement rock. Between the two layers is a saline formation that was cited by Stanford as ideal for carbon dioxide sequestration. Over a long period of time, the injected CO2 reacts with saline to form a mineral that is permanently sequestered underground as it does not return to the atmosphere. We expanded the team managing the Amedis Carbon Capture subsidiary by adding Megan Hopkins as Manager of Regulatory Compliance to lead the EPA Class 6 CO2 injection well permitting process, as well as to manage other permitting and regulatory opportunities related to the Riverbank site and our jet diesel plant development process. In addition to the Central California permitting experience for industrial and commercial projects, Megan worked at Chevron for 10 years and recently managed Chevron's global waste remediation. In phase one of the Amedis carbon capture project, we plan to inject up to 400,000 metric tons per year of CO2 emissions from our biogas, ethanol, and jet diesel plants into two sequestration wells which we plan to drill near our two biofuels plant sites in California. We are expecting to construct two CO2 injection wells that each have a minimum of 1 million metric tons per year of injection capacity, with additional CO2 supplied by oil refineries and other sources to sequester a total of 2 million metric tons per year of CO2. The initial phase of construction includes drilling two characterization wells to provide empirical data for the EPA Class VI permit. The injection wells will then be drilled at the same site after receiving EPA and other permits. We are currently in the engineering and permitting process for the two characterization wells, with an expectation that we will drill the first characterization well at the Riverbank site in the second quarter of this year. Let's review our biodiesel business in India. India is now recovering from a significant COVID pandemic impact. Last month, a two rupee per liter tax was adopted in India for any petroleum diesel that is not blended with biodiesel. The new tax becomes effective in October 2022 and has already led to significant discussions with major oil refineries in India regarding supply of more than 1.25 billion gallons of biodiesel that will need to be blended into about 25 billion gallons of diesel, which is consumed in India each year, in order to avoid payment of the new tax. We continue to work on an approval to export biodiesel, opening the export market, which has previously been prohibited under the India National Biofuels Policy. The price of biodiesel in California has been significantly higher than India prior to the new India government tax. Our riverbank facility is well positioned to manage product reheating and transloading for local truck delivery of biodiesel in California. Since our India subsidiary has no debt and is fully constructed and commissioned, we are well positioned for a rapid revenue increase as we expand biodiesel exports. We do expect large oil refinery and government purchases of renewable biodiesel to meet climate change and air quality goals in India as the current COVID crisis facing India continues to subside. Let's finish with a brief review of an important innovation, which is in the commercialization process, from the Amedis Technology Development Group. Millions of acres of wildfires each year and other adverse impacts of climate change continue to create significant losses of property and life, causing alternative uses of waste wood to become a focus of government policy and funding. Headed by Dr. Gautam Dhumiri as our Vice President of Technology Development, Working with our laboratory staff in Minnesota and at the Keys Ethanol Plant in California, the Amedis Technology Development Team worked with the federally funded Joint Bioenergy Institute in Berkeley, California, for more than three years in the development of a patented process to extract sugars from low-cost waste orchard and forest wood feedstocks. We now hold exclusive licenses to two issued patents that protect this sugar extraction technology for use with waste biomass and with wood from non-commercial forests. By extracting negative carbon intensity C6 and C5 sugars from waste wood, we plan to reduce the amount of cornstarch used in our ethanol production process by using negative carbon intensity sugars from waste wood to produce cellulosic ethanol. Every 10% of our feedstock for ethanol production that is obtained from waste wood sugars instead of cornstarch is expected to generate about $30 million per year of increased EBITDA cash flow from the Keys ethanol plant. The increased EBITDA is created by the value of D3 cellulosic ethanol RINs compared to D6 corn ethanol RINs and the expected significantly lower cost of waste wood feedstock compared to cornstarch. The remaining lignin and non-converted sugars are designed to be the feedstock for our gasifier unit at the Riverbank Jet Diesel Plant to produce carbon-negative cellulosic hydrogen for the hydro-treatment of vegetable and other oils to produce sustainable aviation and diesel fuels. A $3 million California Energy Commission grant was awarded to J. Bay and Amedis, which partially funded the years of collaborative work and lab testing that led to the granted patents. AMETIS was awarded a $250,000 U.S. Forest Service grant to further develop the sugar extraction technology to extract sugars from locally sourced orchard and forest waste wood. We expect commercial operations to pre-extract cellulosic sugars from waste wood when the Riverbank Renewable Jet and Diesel Plant becomes operational. In summary, AMETIS is expanding a diversified portfolio of negative carbon intensity projects, dairy renewable natural gas, renewable aviation and diesel fuel, low carbon ethanol using cellulosic sugars from waste wood, and CO2 sequestration. All these projects are synergistic and create a circular bioeconomy within AMETIS in which we use byproducts and waste products from our facilities and local areas as feedstock to produce low and negative carbon intensity renewable fuels. Our company's values include a long-term commitment to building value for shareholders, the empowerment and respect for our employees and business partners, and making significant and positive contributions to the communities we serve. Now, let's take a few questions from our call participants. Kate?

Thank you. Ladies and gentlemen, the floor is now open for questions. If you have any questions or comments, please press star 1 on your phone at this time. If you wish to leave the queue, you may press star 2. We do ask that if you are listening via speakerphone to please pick up your handset for optimum sound quality. Please hold a moment while we poll for questions. And our first question today is coming from Manav Gupta at Credit Suisse. Your line is live. You may begin.

So, Eric, a year ago, the pushback we primarily got on Ematus was if the story is so good, Why aren't other people associating with it? Now, a year ahead, you see Delta, American, some Japanese airlines, all collaborating with you. So I think that overhang on the stock is kind of gone, in my opinion. There are some people who still push a negative thesis on Ematus, and there are two reasons they say they're still negative on this company. One, they say there are so many projects coming on, that LCFS price will go to $80 and stay there in perpetuity and CARB would not do anything to help out. And B, they say there's a probability that RNG might get kicked out by CARB. Now, you talk to higher officials at CARB versus some of these other people. So help us understand how CARB is thinking about LCFS prices and the probability of RNG not being part of the LCFS program.

You are correct. There is wide concern about the response CARB has had to a roughly 38% decrease in the price of LCFS credits. We deal directly with the staff at CARB, and we can confirm that they have a very strong commitment to the low-carbon fuel standard and actually have expressed confusion about why institutional investors have not seen a strong commitment to reducing carbon emissions in California. As you know, January 2024 is the next scheduled adoption of LCFS credit demand criteria. But in the meantime, we have completed a study by Argus. It was a part of a federal financing process we go through. And that study brought a very interesting point to light. And that is the roughly 8 billion gallons of renewable diesel that's been announced largely will not be at the same carbon intensity of current renewable diesel because of a lack of used cooking oil and other low carbon intensity feedstocks that currently drive the low CI scores. So if the CI score is much higher than the number of LCFS credits generates, it's much lower. And so the Argus report concluded that the market is basically, unfortunately, expecting too much of future renewable diesel production and that the amount of LCFS credits generated could be 50 to 75 percent less than what the market is expecting and described the LCFS market as being structurally in a deficit in other words under any circumstance it's reasonable it will be running at a maximum level which is 200 plus the cost of living index and We ran our projection and our five-year plan at the lowest number that the Argus projection had, which is $155 per LCFS credit. But their own most probable outcome actually got to $242 by the year 2026. So our five-year plan model is 242 minus 150. It's $90 less. than what the actual expected outcome is by the experts in the field. And what they're looking at is that we're not too far from a year from now when CARB will certainly be telling the market where they think they'll end up in 2024, and they're expecting the market's going to be somewhat surprised at CARB's commitment to decarbonization. Though CARB's not surprised. They're telling us constantly that's what they intend to do. Institutional investors are reacting to the immediate response gap in information that's occurring during 2020, 2022, I'm sorry. Regarding RNG, staff members of CARB at senior levels have just recently in the last two weeks written public social media postings in strong support of dairy renewable natural gas because of the positive benefits on local disadvantaged communities, creating jobs, But more importantly, I would almost say, than jobs, though it would be hard to say more importantly than jobs, is improved environment. Our digesters significantly reduce odor emissions and, of course, capture methane, which have been harmful for local disadvantaged communities. And so we've seen top staff at CARB strongly support RNG as a result of that. So, as you know, the board in January denied a petition to exclude dairy RNG from the LCFS, and we do see that the CARB staff understands the significant environmental health and decarbonization benefits of dairy RNG.

Eric, I just have one quick follow-up. Some of your peers who are also in RNG and even in CNG are very excited about this Cummins 15-liter engine. Can you talk a little bit about it and if you think that could be a game changer? And I'll leave it there. Thank you so much, Eric.

Thank you so much, Manav, and thank you for the opportunity to be with you at the Vail Energy Conference last week in Colorado. The Cummins 15-liter engine is a game changer because this is a long-haul engine heavy cargo truck engine that's widely adopted throughout the trucking industry. And Cummins bringing an RNG, or I should say a natural gas version of that engine to market, does substantially increase the demand for dairy RNG, which is the world's lowest carbon intensity fuel, and is a very large contributor to two things. Number one, decarbonizing the diesel fuel for long-haul trucking, but also, frankly, lowering the cost. R&G is a great opportunity for operators to reduce their fuel costs in light of $120 or so crude oil prices.

Thank you for taking my question.

Thank you, though.

Thank you. Our next question today is coming from Amit Dayal at HC Wainwright. Your line is live. You may begin.

Thank you. Good afternoon, everyone. Eric, just to begin with, in terms of RNG deployments and revenue expectations against those deployments, could you give us any update on how we should think about contributions from the dairy digesters that are coming online for you guys?

Bill Meyer- On our five-year plan, it's on our website on the home page. We lay out the number of digesters per year. We define two different rows. One of the rows is capacity. The other one is actually the number of MMVTUs being delivered, which is what drives revenue. And the reason why there's a gap there is we complete construction, then we have an approval process of the pathway with the state of California CARB group. And so we felt it was important that investors had insight that even though we have capacity in place, it's completed, we can't start actual revenue generation until that those approvals have occurred. So there's a slight delay there, and we disclosed that in our five-year plan. We are in our sixth year scheduled now to go to 66 dairy digesters, and currently we're on track. And frankly, I think we'll see some nice acceleration during the middle of the year due to the weather and other things. Winter tends to be a little slower in construction, but we should have a great spring and summer And so I expect us to see that we're continuing to just be on track with our five-year plan.

Okay. And with respect to your, you know, CapEx needs for this year, just from the presentation, it looks like you have all the funding you need to, you know, make all these investments. Could you give us any color on sort of what your needs going into 2023 are going to be and whether some of those needs are already in place for you guys?

What we've structured the company to do is to use the parent company, which has significant value of its existing assets, as the source of the equity for our subsidiaries. So the $100 million of financing that we announced here in the last week or so is broken into a $50 million carbon reduction bucket. And that is funding the activities of the subsidiary and the mentioned the Zebrex unit and solar units and other things we're doing, mechanical vapor compression, but also our carbon sequestration subsidiary, our jet and diesel subsidiary. The initial project development of each one of those subsidiaries is actually paid for by the credit facility of the parent company. Separately from that, we have a $50 million credit facility. It has availability calculations in it, but it's working capital, so it can be used for any sort of things that we need to do in the course of development, of course. So that $100 million credit facility is set up to fully fund all of the development activities of our subsidiaries, which provide the equity capital such that when we get to project financing, and we really are pretty much down to only a couple of them. It's jet and diesel. We already have $32 million of total investment there. We'll put in another roughly $8 million this year. So about $40 million in the common equity of our jet and diesel project. We'll do a project financing, which will fully fund that project. And then in about a year and a half or so, we'll have our EPA Class VI licenses And we'll be doing some smaller financings, which are project financings. But the development work is all being funded from our $100 million credit line. So we're really funded for 18 months on our carbon sequestration business. So the Keys plant largely has all the money it needs between the $16.7 million of grants that we've been awarded and the credit lines. We're pretty much wrapping up all those projects except for one here in the next 12 months. And so, basically, we're just fully funded for all these miscellaneous items, and then we just do one project financing on jet fuel, and then in a year and a half or so, do one project financing on carbon sequestration, and we're done. And none of these require any equity investment by the parent company. We were able to use our credit facilities to fund these projects.

Okay. Thank you for that, Andy. Just one last question. Could you clarify, you know, at what utilization levels the plant in India is operating at right now, and where do you expect that to be maybe by the end of the year or early 2023?

Our India plant is ramping up out of the winter, typically about two months in the wintertime, biodiesel plants in India. don't operate because it's a little bit cold. But as I mentioned, this new government tax is a big driver for the scale-up in India, and the existing three oil marketing companies, again, are an opportunity in India. We do have high feedstock costs, but this 2 rupee per liter, there's 3.7854 liters per gallon. So it's a very, very significant government tax per gallon to that is driving the rapid adoption of biodiesel blending in India. And that's occurring over the next two quarters. October 2022 is when that tax comes into play. So we're dealing specifically with the private refiners in India because their desire to avoid this government tax is extremely high, even though it applies to all the refiners in India. So we expect to scale up over the next two quarters. And if we can get an export approval to export to California, we'll be getting that process as fast as possible. So we have two very, very exciting expansion opportunities in India. One to California and one domestically in India that all appeared really in the last couple of months. So we're looking to see that ramp up occur this year.

Okay. Thank you, Eric. That's all I have. Thank you.

Sure.

Thank you. Our next question today is coming from Nate Pendleton at Stiefel. Your line is live. You may begin.

Good morning, all, and thanks for taking my questions. For my first question, regarding the potential use of tallow from India in your riverbank plant, could you at a high level speak to the difference in cost and CI potential compared to using vegetable oil?

The tallow in India that we acquire is a crude product, so it actually is not a biofuel feedstock at the point at which we acquire it. We announced recently that we're building a crude refining program. So what comes out of that plant is now a biofuels feedstock. So we take what is essentially a non-viable product and turn it into a feedstock product. And we can use that in India at our biodiesel plant. We are already one of the largest users of tallow in the biodiesel business in India. And, of course, because of our need in California, we can also export tallow, which is allowed in India, to the United States and specifically to our California plant. So the core of our operational activity in India is taking this really literally waste product and converting it into a low or no odor clean feedstock that can be used for renewable fuels production. So, in terms of cost differential, there is a meaningful cost differential. It's more than 20% today and potentially even more than 30% today less expensive to buy that crude product than it is to buy a refined vegetable oil or animal oil feedstock.

Great, thanks. And for my second question, regarding your CCS business, could you provide an update on how conversations are progressing regarding third-party CO2 volumes? Also, could you comment on the logistics involved to move those potential third-party volumes? Thank you.

We have spoken to every California, San Francisco Bay Area oil refiner. We are actively in negotiations on actual terms with two of those refiners that would comprise, frankly, all of the 2 million metric tons per year if we included flue gas. There's two major sources. One is the steam methane reformer that produces hydrogen. It's a very concentrated source of CO2. And if we just go with SMR, we could probably include a third oil refinery. But we are having very solid discussions with several of the oil refiners. And they're located roughly 100 miles from our facility. So our approach is... As a producer of dairy renewable natural gas, we're seeking to have trucks that can be very, very low emission. Of course, negative carbon intensity RNG as a fuel instead of diesel. And so driving roughly 100 miles to pick up CO2 at oil refineries is actually probably the lowest carbon transportation tool available. in terms of vehicular transport. And so we see ourselves being uniquely positioned to provide the roughly 100 trucks per well. We're doing two wells, and that's only about five trucks an hour. You just kind of do the math, 100 trucks divided by 20 hours. And so we're well positioned to have a low-cost, low-carbon emission system You know, five trucks an hour is not much. One truck every 10 minutes is just not a big deal. So we're seeing that as a value out of our situation because the alternative, of course, is building a CO2 pipeline. It's high pressure. It's very difficult to see how that could get permitted and constructed in California without significant litigation. Or barging, which is enormously problematic because CO2 evaporates. Or railing, which is even worse. You lose about 10% of your CO2 every day. It sits in a rail car. So in a $500 million business, two days in a rail car can easily reduce revenues by $100 million and reduce earnings by $100 million. So we think we're very well positioned to add value to that business. And I think our oil refiner... partners I guess would be a big term to use, see it the same way. We have a unique value proposition there.

Thanks for your time and congrats on a strong quarter.

Thank you so much.

Thank you. Our next question today is coming from Matthew Blair at Tudor Pickering Holt. Your line is live. You may begin.

Hey, good afternoon Eric and Todd. Congrats on the quarter. I think your progress on the dairy RNG side has been pretty impressive. I think you mentioned that you signed agreements with an additional 24 or 25 dairies. Could you talk about the factors that are helping you win these contracts and what we're hearing is a pretty competitive market? And then could you also talk about your market opportunity outside of the 80 dairies that you currently supply the wet distillers grains to? any contracts with dairies outside of that existing network? Andy, you want to take this?

Sure. Thanks for the question. I think you're correct that it is a competitive marketplace. You know, we've been in this business since early 2018, and at that time there were, you know, really in addition to Amedis, a couple other significant developers, CalBio and Moss Energy Works, and a lot more have come to the party since that time. I think one of the things that has helped us tremendously in terms of securing the dairy participation agreements releases or the ongoing discussions that we have with multiple parties is the fact that we are located in the neighborhood, if you will. We have a long operating history at the Keys plant. We've been operating the ethanol plant since 2011. We, you know, we come to the party with some local knowledge and obviously those that are currently customers of our distillers grains know who we are. So I think, you know, starting with that foundation and building upon it, one of the other things I think that has helped us, and this is, you know, one of the real, when Eric, you know, when we talked about getting into this business, it was, let's get busy and let's execute quick. Let's move to demonstrate how serious we are in the marketplace. Some of the other developers had some fits and starts with how they've delivered in the marketplace. We said we were going to build two dairies in a year, commission them, get them operating, get a CI score, and we did it. We stayed right on track. We got four miles of pipeline built. We did all of that literally in the space of a year. And I think from a credibility perspective, that's helped us a lot with the dairymen. If you spend any time around farmers, and dairymen in particular, they've had lots of people come through and try to sell them on interesting schemes and various things, and they are a highly cynical group of people because most of those things never come to pass. When you deliver, as you say you're going to deliver, that goes a long way. And then I think additionally, when people see evidence of our construction, when they see a 30-mile pipeline being built, it all of a sudden becomes more than just a PowerPoint presentation. They realize that this is happening. And so... that's when we start getting incoming phone calls from folks saying, hey, why haven't you talked to me yet? And there's a strategic plan there. There are some folks that are maybe smaller dairies on our pipeline route that we're not getting to first because we're trying to secure the anchor tenants, if you will. But we go back to them and we will include them for participation. The last part of your question, there are areas outside of our geographic, you know, our footprint that we are exploring because they're, you know, There are some dairies that are in more remote parts of California that don't necessarily make sense for pipelines or things like that. So we're looking and talking to some of those folks to add more to the mix because there's different ways to get there, either through using that gas for electricity or using that gas for transporting it or even setting up a remote hub. to clean up the gas and do an interconnection at that site. So, you know, we're trying to focus primarily this, you know, in the next year or so on our geographic, our neighborhood, and get that really put to bed. But at the same time, Robbie Macias, who's our VP of biogas, and I are spending a lot of time in the car talking to prospective dairymen.

I should mention on the contracts with RNG customers, we're actually the number one contractor. initial RNG customer, we have trucks that carry distillers grain and ethanol and a variety of other things that can be supplied from the RNG station that we're putting up at our facility. And so, in addition to Amedis being the customer, we have other customers in the marketplace, which we expect to announce here in the next month or two. So you'll see some other names start to pop up. But we're our own customer, sort of like what we did when we initially launched biogas and we used it in our ethanol plant.

Great. Thanks for all the color. I also want to follow up on your dairy RNG volumes and the guidance for 2022. So, you know, thanks for providing the quarterly number. It looks like it was 13.4 million. MMBTU in the fourth quarter and so if I annualize that I get to around 53 million and then your 2022 guidance is around I think it's 49.9 million even though you're adding eight digesters so I'm not sure if I'm missing something here but could you just walk us through that bridge on the Q4 run rate versus the 2022 guidance for your RNG volumes?

To simplify matters, we have a slide in the February 28th presentation, which I actually gave at Credit Suisse Energy Conference in Vail, Colorado, last week. And that slide breaks down production capacity per year and also breaks down actual delivered production for the year. And so if those are the numbers you're referring to, the delivered production number has that delay of the California Resources Board pathway approval built into that production number. So that's where you see a bit of a gap is that we initially next month, we're putting gas into the pipeline and we would be generating revenue in D3 RENs and everything next month if that were available. But unfortunately, we have this regulatory delay as we're getting our approvals in place. So it's on slide eight of the company presentation at the bottom of the homepage of Amedis.com. The title is Amedis Expansion Plans. And we have RNG digester capacity And then the revenue line is the RNG production. So that production number is what drives actual revenue. But you'll notice that our capacity is significantly larger at 272,000 MMBTs per year exiting this year, whereas our actual production is only 49. So you go into 2023 with a very large actual production happening. We're putting it into underground storage. For conservatively speaking, it could be as much as nine months. We're not projecting that. We're projecting it to be in the two-quarter kind of situation. But we put production starting next month into the ground, store it, and then when we have the pathway, we pull it out of the ground and are able to generate D3 federal RINs and also LCFS credits when it comes out of storage.

And Eric, the numbers on slide eight of that presentation, are they, so it shows, you know, 10 dairy digesters for 2022. Is that an annual average for the year? Or are these like kind of year-end exit run rates?

Those are year-end exit numbers. And there's a little bit of, there's a couple of digesters that'll be under construction or completed construction and being filled. So take it as a, it really is a 12 number at the end of the year, but 10 was a conservative number we put in there. We'll be filling digesters and doing other things. There's a gap in the capacity as you fill the digester. It takes a month and a half or so to fill it up. So you'll see on this slide, though, that our conservative number of 10 drives the production capacity number. So all those numbers correlate, but I would expect we'd probably exceed that by one or two. Great, thank you so much. Yeah, thank you, Matthew.

Thank you. Our next question today is coming from Jordan Levy at Truist. Your line is live. You may begin.

Afternoon, all, and thanks for all the details. Just one for me. Going back to the CCS business, you give us a lot of good detail there. Maybe just a little more on that side of things. I'm just curious to get your thoughts after You said that first characterization well is coming up. After that's drilled, maybe just kind of a general path to getting that first injection well drilled and so forth and so on, and then maybe even taking a step back on that side of things. Is there an even larger potential you see for that business beyond these two wells, which obviously have huge potential for you all?

Certainly. Thank you, Jordan. Let's talk about money, first of all. Each characterization well and related permitting is about $6 million. We're doing one under our Riverbank site, and we're doing one near our ethanol plant site. They're about 15 miles away. So it's the same people, same crews, same everybody, just doing it twice. The Riverbank site's Q2 of this year, we're expecting that the Keys plant site, because of permitting delays, will be closer to Q4 this year. Rupert Bank's already zoned correctly, et cetera. So we're literally within a month or two of rolling the drilling rig out there. That combination of six plus six is about $12 million. Add another $3 million for just ongoing consultants and lawyers and everything else over about an 18-month cycle, and that puts us at the end of 2023, end of next year, with approved class six projects. licenses potentially for both sites. There was a site up in South Dakota approved in nine months in 2021. So projecting 18 months, I think, is certainly a reasonable projection. So by the end of 2023, we'll have about $15 million plus some real estate acquisitions, about $18 million of total investment. All this comes off of our carbon capture credit line of $50 million that's already there And if we need a working capital, we have another $50 million available with that. At that point in time, we then complete a project financing. Renewable Energy for America program certainly is a very attractive opportunity for us. Tax-free municipal bonds, private activity bonds in California are attractive for us. But we get to build it in two phases. So with the The hole in the ground, you actually only have to build about 20% of the compression equipment above ground in order to handle the 200,000 tons at the Keys plant and the 200,000 tons at the Riverbank plant. So our total investment there is less than $100 million to build out all the above ground, unloading the whole shoot and match for all of the CO2 we have. We're not really building a CO2 pipeline. We're just basically just building compression equipment and engineering activities. So with the equity investment we have, we'd be able to borrow the funding to do that phase. At that point in time, we'll be injecting 400,000 or 500,000 tons, and actually it's technically a little more than 400,000 tons, generating approximately 100 million in revenue, generating approximately 70 million a year of positive cash flow. And at that point in time, it's pretty easy to go borrow the next tranche of funding, which would be expansion in 2026. So as you see the five-year plan roll out, what we see is that all we do is just put the first $18 million in from our credit lines, and that acts as the layer of equity under a smaller funding, and then that acts as the equity for the bigger funding. And we end up with the entire project, about $250 million, 248-something dollars, ends up being in place, and with 2.4 million total potential tons, we just start trucking in CO2 from our refining partners, and Chevron alone generates over 4 million metric tons a year, and most oil refineries will be over a million tons a year between their SMR and flue gas revenues. So we just start trucking in that, but it's already built, right? You've got the compression equipment above and you've got the well that we'll be building anyway, just because there's no reason to put in two wells, just build one well with a million tons per year. So these two wells actually are fully, all the capex is in our five-year plan, but we're only showing about 20% of the actual revenue potential. There's a substantial increase in revenue potential going from 500,000 metric tons to 2.4 million. We'll have all that capacity there, but we just are not projecting all revenues in the 2026 time frame. And so there's a very, very significant revenues scale up. And in terms of operating costs, it's a little bit more trucking with R&G gas trucks, and then electricity. Those are the two operating costs that kick in. So we retained ourselves a lot of upside in the model. And mostly it's in order to offset any potential EPA delays. Because we can achieve these numbers even if the APA is another year late. Even if they're two years late, we still would achieve the numbers that we put up here. If it's on time, then we could obviously increase revenue substantially to somewhere in the $500 million range.

That's great. Thanks so much, guys. Nice quarter. Thanks.

Thank you.

Our next question today is coming from Ed Wu at Ascendant Capital. Your line is live. You may begin.

Yeah, I was just curious. Obviously, there's a lot of volatility with gasoline and oil. What's your outlook on oil prices and how it's going to affect the ethanol market in California?

My view is that we're under sort of a worldwide case of uncertainty in oil prices, and so Today alone, I think we saw a $10 increase in West Texas Intermediate as traders were betting on what's happening in the Ukraine. My personal view is that we have a fundamental $80 West Texas Intermediate, $85 Brent price. Brent, of course, is Brent England, because that's how much it takes for the Saudi Arabians to pay for what essentially is a welfare economy that they're trying to transition into. And 70% of people under the age of 35 in Saudi Arabia are unemployed. They have free housing, free education, and basically are wards of the state. And you can't run that country without $85 Brent crude oil. So I think we're structurally an $80 global economy. And the fact it's $120, I think, is relatively temporary. That's my view. So I think we have high oil and gas prices as long as there's a Ukraine and Russian problem. When that gets resolved, we probably are in the $80 range, which was double what we were about 18 months ago, and that that $80 is probably going to sustain for quite a long time.

And you think that's going to keep up ethanol prices?

Ethanol prices, frankly, have continued to be a discount of gasoline. At every price of discount, ethanol is discounted below that, and ethanol is more about how committed we all are as a society to having cleaner, domestic, lower-cost fuels. And as we become more committed to that, ethanol just becomes playing more and more of a solution. Nebraska did a five-year study with 30% biofuels running in regular old engines and regular old cars and found that 30% ethanol actually provided significantly better emissions and lower costs and all the other benefits job creation as well that you get from using ethanol. So I think we're headed toward 30%, and it's just a matter of how fast we get there.

Great. Thanks, and I wish you guys good luck.

Thank you so much, Ed.

Thank you. Our final question today is coming from Marco Rodriguez at StoneGate Capital Partners. Your line is live. You may begin.

Good afternoon, everybody. Thank you for taking the questions. Most of my questions have already been asked and answered. Just a real quick modeling question. Just kind of wondering how you guys are thinking about the cadence of gross margin in fiscal 22. Thanks.

We are in a pattern of uncertainty, which ethanol sold by our company is about $2 a gallon less than what you pay at the pump in California. If you take the price we sell, plus about 70 cents of taxes, you're actually a little below the pump. So when you're selling a commodity molecule at $2 per gallon less than the market, and we do about 60-plus million gallons of that per year, that's $120 million a year of subsidy, essentially, of the oil industry. So we're very, very good at subsidizing the oil industry right now, I do not think that's a sustainable gap. I think the policymakers are going to want to have some of that discount available to consumers. And all you have to do in California is have a 15% ethanol blend, and you have a pretty significant direct impact on the price of the pump. Hopefully at the federal level, the enforcement of the renewable fuel standard likewise is an opportunity to tap into the roughly a billion gallons of ethanol that's currently in storage in the U.S., unlike petroleum gasoline, which is not in shortage, I'm sorry, which has a shortage, ethanol is not in shortage. And so this is an immediate opportunity to decrease the price at the pump by both federal as well as state policy supporting ethanol and renewable fuels in general.

Got it. Appreciate your time. Thank you.

Thank you, Marco.

We have no further questions in queue at this time. I'd now like to turn it back to management for closing remarks.

Thank you, Kate. Thank you to Amedis shareholders, analysts, and others for joining us today. We review the, please review the Amedis company presentation and the Amedis investor presentation that's posted on the homepage of the Amedis website. We also look forward to talking with you or even touring our facilities as we invite you to participate in the growth opportunities at AMETIS.

Thank you for attending today's AMETIS earnings conference call. Please visit the investor section of the AMETIS website, where we'll post a written version and audio version of this AMETIS earnings review and business update. Kate?

Thank you, ladies and gentlemen. This does conclude today's event. You may disconnect your lines at this time and have a wonderful day. We thank you for your participation.