Welcome to the Aemetis third quarter 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 Aemetis, Inc. Mr. Waltz, you may begin. Thank you, Paul. Welcome to the Aemetis third quarter 2021 earnings review conference call. Joining us today for the call is Eric McAfee, Founder, Chairman, and CEO of Aemetis, and Andy Foster, President of Aemetis Advanced Fuels and Aemetis Biogas. We suggest visiting our website at aemetis.com to review today's earnings press release, the Aemetis corporate and investor presentations, filings with the Securities and Exchange Commission, recent press releases, and previous earnings conference calls. The presentation for today's call is available for review or download on the investors section of the aemetis.com website. Before we begin our discussion today, I'd like to read the following disclaimer statement. 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 uncertainties, and that future events may differ materially from the statements made. For additional information, please refer to the company's Securities and Exchange Commission filings, which are posted on our website and are available from the company without charge. Our discussion on the call today 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 September 30, 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, gain 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 this third quarter of 2021. Revenues during the third quarter of 2021 were $49.9 million compared to $40.9 million for the third quarter of 2020. Our North America operation in the third quarter of 2021 as compared to the third quarter of 2020 experienced an increase in the selling price of ethanol from $1.59 per gallon to $2.84 per gallon, but also saw an increase in the delivered corn price from an average of $4.92 per bushel during the third quarter of 2020 to $7.99 per bushel during the third quarter of 2021. Gross loss for the third quarter of 2021 was $4.8 million compared to a gross income of $771,000 during the third quarter of 2020. Gross margin was negatively impacted by the establishment of a reserve of $5.3 million for California emission-compliant credits for the Keyes plant in September. Selling, general, and administrative expenses were $5.1 million during the third quarter of 2021 compared to $4.6 million during the third quarter of 2020 as a result of payroll expenses, specifically personnel and insurance incurred as part of the development of our low carbon and negative carbon intensity initiatives. Operating loss was $9.9 million for the third quarter of 2021 compared to an operating loss of $3.8 million for the third quarter of 2020, principally driven by the establishment of a reserve of $5.3 million for California emission compliance credits related to our ethanol plant operations. Interest expense during the third quarter of 2021 was $5.5 million, excluding accretion and other expense in connection with Series A preferred units in our Aemetis Biogas LLC subsidiary, compared to $6.5 million during the third quarter of 2020. Additionally, our Aemetis Biogas subsidiary recognized $2.2 million of accretion and other expenses in connection with preference payments on its preferred stock during the third quarter of 2021 compared to $1.8 million during the third quarter of 2020. Net loss was $17.6 million for the third quarter of 2021 compared to a net loss of $12.2 million for the third quarter of 2020. After adjusting for the establishment of a $5.3 million compliance reserve, net loss would have been $12.2 million or $0.39 per share. Cash at the end of the third quarter of 2021 increased to $6.4 million compared to $592,000 at the end of 2020. Capital expenditures increased property, plant, and equipment by $18.8 million, driven by investment in our low carbon and negative carbon intensity initiatives. Company debt decreased by $44.6 million by the end of the third quarter of 2021 compared to December 31, 2020. As we enter into the fourth quarter, ethanol pricing has rebounded strongly with current pricing at $3.50 per gallon in today's market, while at the same time the average delivery cost of corn has decreased to about $7.50 per bushel. These market changes indicate a healthy fourth quarter for our traditional fuels business, while our construction teams continue to move forward with the engineering and construction of the low carbon projects. That completes our financial review of the third quarter of 2021. Now I'd like to introduce the Founder, Chairman, and Chief Executive Officer of Aemetis, Eric McAfee, for a business update. Eric? Thank you, Todd. Aemetis 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 revenue and $325 million of annual cash flow. We are on track with the five-year plan. This year, we have paid $63 million on the higher interest rate bridge loans from Third Eye Capital. We are also on track with financing growth using long-term, 20-year low interest rate project financing from the USDA, U.S. Department of Energy, and municipal bond markets. Importantly, our third quarter earnings are on track with the five-year plan. After adjusting for the establishment of a one-time $5.3 million reserve for California emission credits related to the Keyes Ethanol plant, our net loss would have been $12.2 million for the third quarter, which is a -$0.39 per share, which is in line with our aggressive growth plan. The positive regulatory trends for renewable fuels have continued to improve by the passage of the Infrastructure Investment and Jobs Act last week. This legislation supports all of Aemetis' low carbon renewable fuels businesses in both the U.S. and in India in various ways. First, the USDA and Department of Energy loan programs have received billions of dollars of expanded funding to provide 20-year 6%-8% low interest rate, government guaranteed or direct loans. Aemetis is working closely with these organizations to provide funding for the 52 dairy biogas digester and pipeline project, the sustainable aviation fuel and renewable diesel plant, and the carbon sequestration project that is under development. Second, the biodiesel and renewable diesel products to be produced at the Riverbank Carbon Zero plant will benefit from the five-year extension of the $1 per gallon tax credit instead of requiring Congress to act annually. This adds greater stability and predictability as we proceed with our project to produce renewable diesel and sustainable aviation fuel. Third, in addition, the sustainable aviation fuel produced by the Riverbank plant will generate up to $1.75 per gallon tax credit. Fourth, the carbon sequestration projects will receive $85 per metric ton of federal tax credit, up from $60 per ton. The tax credits are expected to be paid in cash each year under the direct pay structure. With our planned 2 million metric tons per year of CO2 injection, the direct pay program could provide $170 million per year of funding to the Aemetis carbon capture and sequestration project directly transferred from the federal government. During the third quarter of 2021, Aemetis achieved important milestones toward revenue growth and sustained profitability in each of our four lines of business. Now, Andy Foster, the President of the Aemetis Biogas and Aemetis Advanced Fuels businesses, will review highlights of our renewable natural gas and ethanol businesses. Andy? Thanks, Eric. As Eric mentioned, we are focused on producing below zero carbon intensity products, including the production of negative carbon intensity, renewable natural gas and renewable fuels. A prime example is our dairy-based renewable natural gas business, which recently marked the one-year anniversary of commercial production in September. RNG is a negative carbon renewable fuel that perfectly exemplifies the circular bioeconomy that Eric often refers to when describing our approach to reducing greenhouse gas emissions while producing sustainable below zero carbon 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 September 2020, we completed phase I of the Aemetis Biogas Central Dairy Digester project and commenced operation of the first two covered lagoon digesters, including on-site dairy biogas cleanup and pressurization, a 4 -mi pipeline owned by Aemetis, and a boiler unit used to utilize the biogas as process energy at the Keyes plant, which allows us to monetize the LCFS credits through a lower CI score for the ethanol produced. During Q1 2021, the California Air Resources Board issued an updated carbon intensity fuel pathway for the Keyes ethanol plant utilizing a -426 CI score for our biogas, compared to approximately a + 100 carbon intensity for petroleum and natural gas. In addition to the two dairy digesters and 4 mi of gas pipeline currently in operation, we are now building phase two of the biogas project, including the main biogas cleanup facility, the utility pipeline interconnection unit, an RNG fueling station at the Keyes plant, and an additional 15 dairy digesters and 32 mi of biogas pipeline. Each of these project components are on schedule for completion of phase II in the third quarter of next year. We have now signed agreements with 22 dairies to install digesters. We are in advanced discussions with five more dairies representing approximately 10,000 cows that we expect to sign in the current quarter and have more than a dozen additional dairies in under discussion. As the pipeline and digesters are built, we are also receiving inquiries from other local dairies in the area who would like to participate in the Aemetis Biogas project. This week, Pacific Gas and Electric achieved mechanical completion of the gas interconnection unit that connects the Aemetis Biogas cleanup facility to the PG&E natural gas pipeline. We expect the interconnection system to be fully installed by Thanksgiving, with commissioning to be completed in January 2022, when the Aemetis Biogas upgrading facility becomes operational. During the third quarter, we began construction of the main biogas upgrading facility located at Keyes ethanol plant to convert dairy biogas into renewable natural gas. The foundations have been completed, the major equipment has been placed, the roof structure and fire prevention systems have all been completed, and now electrical systems and calibration equipment are being installed. The biogas upgrading facility is scheduled to be completed in January 2022. During the third quarter, Aemetis was granted an encroachment permit to use the right of way in local county roads for construction of the 21-mile Stanislaus County segment of our pressurized biogas pipeline. Five additional digester projects are now permitted and construction is underway, with expected completion of these five digesters and related pipeline in the first half of 2022. To connect the next five dairies to our existing biogas pipeline, the installation of 6.5 mi of the 7 mi required for the new biogas pipeline will be completed, weather permitting, in the next few weeks. Excavation of two of the next five dairy digesters has been completed, and the remaining three digesters will be under construction in the next two weeks. The next five dairy digester biogas cleanup skids, which are fully modularized, will be delivered next week for installation at the five dairies currently under construction. A USDA guaranteed loan under the Renewable Energy for America Program, known as REAP, is nearing completion for a $50 million financing for dairy digesters, gas cleanup and pipeline construction at about a 6% interest rate to be repaid over 20 years. The term sheet was signed with the bank in May of 2021, and closing is expected by the end of this quarter, subject, of course, to delays associated with upcoming holidays. An additional $50 million USDA REAP financing is in process for closing in Q2 of 2022, with another $50 million expected to close in Q4 of 2022 on the same terms. Overall, the second half of 2021 has been a highly productive period for advancing the construction of the Aemetis Dairy Renewable Gas Project, and we continue to sign up additional dairies to further expand our digester network. We've made some key new hires on 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, a third-year industry veteran who supervised the installation of our phase one pipeline while working for our lead contractor, has instituted a number of best management practices that have resulted in cost savings and schedule acceleration. The Aemetis RNG team is in contract review with a number of expected RNG offtake partners, and we expect to begin announcing these agreements by the end of the current quarter. To date, Aemetis has been awarded approximately $23 million worth of grants from the California Department of Food and Agriculture, the California Energy Commission, PG&E's energy efficiency program, 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 Keyes ethanol plant, which uses agricultural feedstock that absorbs CO2 from the atmosphere during plant growth, from which our production facility produces ethanol and a high-value animal feed. The Aemetis ethanol plant produces approximately 65 million gallons per year of renewable ethanol, but also produces about 2 million lbs per day of wet distillers' grains that supply about 80 local dairies to feed more than 100,000 cows. Those cows eat the renewable feedstock produced by Aemetis 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 will be able to be fueled by our RNG at compressed natural gas fueling stations at locations throughout California or at our on-site RNG fueling station at the Keyes plant. Let's take a moment to discuss our California ethanol plant. As Todd mentioned earlier, we saw a 50% year-over-year increase in revenues from ethanol sales in the third quarter compared to last year. Since the economy began to reopen in the first half of 2021, demand for ethanol has been robust and ethanol margins have improved significantly in the current quarter. High corn prices reduced profitability in the third quarter with the tighter corn supply and ongoing logistical issues with the railroads. An increase in the price of ethanol from about $2.50 per gallon to today's $3.50 per gallon in California has significantly improved margins, while margins were also positively impacted by a decrease in the delivered price of corn over the past few months, from more than $9 per bushel this past summer to today's $7.50 per bushel. While U.S. domestic gasoline demand has been favorable at approximately 95% of 2019 levels, U.S. ethanol exports have lagged for the first three quarters of 2021. Ethanol imports, especially to California from Brazil, were especially persistent in the third quarter of 2021 due to higher prices received by Brazil ethanol producers as a result of California's Low Carbon Fuel Standard. Strong demand and favorable pricing for both wet distillers' grains and Distiller's Corn Oil remain bright spots in the overall product mix, and we expect that to continue. Let me just take a few moments to provide an update on the projects that are expected to increase cash flow by approximately $23 million when the projects are fully completed. The Keyes ethanol plant is operating at full capacity of about 65 million gallons per year, taking advantage of strong ethanol distillers' corn oil and distillers' grain pricing. The ethanol plant is completely sold out of wet distillers grain, with more than 2.2 million lbs per day being delivered to dairies using about 45 truckloads per day. We are delivering more than 30,000 gallons per week of distillers' corn oil at favorable prices, driven by the use of non-edible corn oil in biodiesel and renewable diesel production, as well as poultry feed. The Keyes plant produces approximately 400 metric tons per day of CO2, which is being upgraded, compressed and delivered to local food processors by Messer, which generates about $4.5 million per year of tax credits at $30 per metric ton under the current law. The Mitsubishi ZEBREX unit, which separates ethanol and water, has been fully installed, test runs have been completed, and the system has been meeting or exceeding the key system design milestones. The goal of significantly reducing steam consumption in the plant has been demonstrated in stable operations with a reduction from 21,000 lbs of steam per hour to less than 5,000 lbs of steam per hour. Since steam is currently mostly produced from carbon-intensive, expensive petroleum natural gas, this 75% reduction in steam used for ethanol dehydration reduces our operating costs and increases our revenues through lower carbon intensity ethanol. Additional optimization is currently underway, and we expect to commission the ZEBREX system during Q1 of 2022. Additionally, we expect to sign an EPC contract with SunPower for the installation of a $12 million solar array with battery backup and microgrid by the end of this month. Detailed engineering is already underway. Permitting is in process. A power interconnection agreement with the utility district is being arranged, and equipment procurement is expected to begin in December. The solar unit is designed to generate approximately 1.5 MW of zero carbon intensity electric power at low cost, especially considering the $8 million California Energy Commission grant that funds 2/3 of the total project cost. Finally, the mechanical vapor recompression system to further reduce our petroleum natural gas and steam use is moving forward with detailed negotiations underway for engineering, procurement, and construction. When completed, these upgrades to the Keyes ethanol plant are designed to significantly reduce or even potentially eliminate petroleum natural gas use at the Aemetis ethanol plant. We also expect to reduce or eliminate our steam-driven turbine cogeneration system, saving up to $14 million per year of natural gas and utility pipe transmission costs. Our California biorefinery is being upgraded to primarily operate using high-efficiency electric motors and pumps powered by zero carbon intensity renewable power sources, including our solar array and local hydroelectric power. In summary, operational performance and project milestones for the Aemetis biogas and ethanol plant businesses are on track with the five-year plan. Eric? Thank you, Andy. Thank you all for all the excellent work that your team is doing. Let's discuss our Carbon Zero renewable jet and diesel fuel project using negative carbon intensity hydrogen from waste orchard wood in Riverbank, California. We are pleased that the Aemetis Carbon Zero biorefinery under development in Riverbank near Modesto continues to achieve major milestones. Recently, we announced a $1 billion sales agreement with Delta Air Lines to supply 250 million gallons of blended sustainable aviation fuel over 10 years at the rate of 25 million gallons per year. Known as blended SAF, the contract provides for 10 million gallons of neat unblended SAF, combined with 15 million gallons of petroleum jet fuel each year. Under the Delta Air Lines agreement, the neat SAF will be trucked from the Riverbank production plant to a tank farm in the Bay Area for blending with jet fuel. The blended SAF will be delivered via pipeline to San Francisco Airport for use by Delta Air Lines. We are in final contract review for additional aviation fuel agreements with other major airlines, including foreign airlines, that service the San Francisco and Los Angeles airports. We expect to announce about $3.5 billion of additional aviation fuel sales agreements starting later this month and continuing through the second quarter of 2022. In addition to major U.S. and international airlines, we have received a high level of interest from leading private jet FBOs due to corporate jet owner interest in sustainable aviation fuel. For example, FBO chains with California locations have requested us to truck blended sustainable aviation fuel to Aspen and Vail airports for use by corporate and private jets in addition to California locations. In addition to the $4.5 billion of blended sustainable aviation fuel sales agreements that we have signed or expect to sign in the next few months, we are in final contract review for a $3 billion renewable diesel sales agreement to deliver 45 million gallons per year under a 10-year sales contract with a major truck stop chain for its 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 $125 million of 20-year USDA debt financing that has already been signed with the USDA, and an additional $100 million of USDA Rural Energy for America funding that has been reviewed with the USDA. We announced that the $2 billion global EPC co-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, just south of our location, with planned completion in mid 2022, and is ideally suited to construct the Aemetis plant quickly and efficiently. The Aemetis five-year plan announced that phase I of the Riverbank jet and diesel plant is designed to produce 45 million gallons per year of renewable jet and diesel fuel, generating more than $230 million of annual revenue and more than $65 million per year positive cash flow. We plan to expand production in phase II of plant construction to 90 million gallons per year at the Riverbank site by 2025 as part of our five-year plan to generate approximately $460 million of revenues and $130 million of annual positive cash flow from renewable jet and diesel production. However, the five-year plan that we announced in Q1 2021 did not include the value of the $1 per gallon federal tax credit due to the uncertainty of the incentive. The recent passage of the Infrastructure Act has provided stability in the incentive, so we expect to add the $1 per gallon for 45 million gallons per year of renewable diesel and $1.75 per gallon for 45 million gallons per year of sustainable aviation fuel to our updated five-year plan that we expect to release in Q1 2022. The Riverbank plant is designed to use waste orchard wood and other waste biomass, such as dead forest wood, to produce cellulosic hydrogen using zero carbon intensity hydroelectric power and vegetable and other renewable oils to produce sustainable aviation fuel and renewable diesel fuel. Combined with carbon sequestration at the Riverbank site, we expect a negative 10 carbon intensity for our aviation fuel and renewable diesel. Let's review our new subsidiary, Aemetis Carbon Capture. In October 2020, the Aemetis plant in California was identified in a study issued by the Stanford University Center for Carbon Capture, as one of three ethanol plants CO2 sources in California that have the highest potential return on investment from building a carbon capture and sequestration facility compared to oil refineries, cement plants, and natural gas power plants that comprise the 61 largest CO2 emission sources in California. Our ethanol plant already captures about 150,000 metric tons per year of CO2 and already 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 up to $4.5 million per year of tax credits for Aemetis. We selected Baker Hughes as the drilling vendor for the carbon sequestration 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 Aemetis Keyes plant and the Riverbank plant site are located above a 7,000-ft deep strata known as a cap rock and an 8,000-ft deep strata known as a basement rock. Between the two layers is a saline formation that was cited by Stanford University as ideal for carbon dioxide sequestration. Over a long period of time, the CO2 reacts with saline to form a mineral that is permanently sequestered underground that's not returned to the atmosphere. We expanded the team managing the Aemetis Carbon Capture subsidiary by adding Mehagan Hopkins as manager of regulatory and compliance to lead the EPA Class VI 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 Central California permitting experience for industrial and commercial projects, Mehagan worked at Chevron for 10 years and recently managed Chevron's global waste remediation. In phase I of the Aemetis Carbon Capture project, we plan to inject up to 400,000 metric tons per year of CO2 emissions from our own 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, in addition to our own, supplied by oil refineries and other sources to inject 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 can drill the first characterization well in the first quarter of next year. Let's review our biodiesel business in India. Our Universal Biofuels subsidiary in India bid on a portion of a $900 million biodiesel purchase tender offer for about 225 million gallons by the three Indian government oil marketing companies. Due to increased feedstock prices, the OMC bidding process in 2021 has not resulted in pricing that has been accepted by biodiesel producers. The bidding process continues, with a higher price of crude oil resulting in higher prices for diesel in India and increasing the bid prices offered by the Indian marketing companies. However, a major approval is in process in India for our distilled biodiesel production plant. We are expecting to receive an approval to export biodiesel, opening the export market, which has been previously prohibited under the India National Biofuels Policy. The price of biodiesel in California is significantly higher than India, and our Riverbank facility is well positioned to manage product reheating and transloading for local truck delivery in California. Since our Indian 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 government purchases of renewable biodiesel to occur to meet climate change and air quality goals once the current COVID crisis facing India begins to subside and Indian government procurement activities for biodiesel are expanded. Let's finish with a brief review of an important innovation, which is in the commercialization process from the Aemetis 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. Goutham Vemuri as our Vice President of Technology Development, working with our laboratory staff in Minnesota and at the Keyes ethanol plant in California, the Aemetis 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 corn starch 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 corn starch is expected to generate about $30 million per year of increased EBITDA from the Keyes ethanol plant. The remaining lignin and non-converted sugars are designed to be the feedstock for our gasifier unit at the Riverbank jet and diesel plant to produce carbon-negative cellulosic hydrogen for the hydrotreatment of vegetable and other oils to produce sustainable aviation and diesel fuels. A $3 million California Energy Commission grant was awarded to JBEI and Aemetis, which partially funded the years of collaborative work and lab testing that led to the granted patents. Recently, Aemetis was awarded a $250,000 U.S. Forest Service grant to further develop the sugar extraction technology by extracting 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, strongly supported by the Infrastructure Act, Aemetis is expanding a diversified portfolio of negative carbon intensity projects from dairy, renewable natural gas, and low carbon ethanol to renewable jet and diesel fuel, to waste wood sugars to produce ethanol and carbon sequestration of CO2. All of these projects are highly synergistic and create a circular bioeconomy in which we use byproducts and waste materials 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. Paul? Thank you, Mr. McAfee. We will now be conducting a question and answer session. If you have any questions or comments, please press star one on your phone at this time. We ask that while posing your question, you please pick up your handset if listening on a speakerphone to provide optimum sound quality. Once again, please press star one if you wish to enter the queue to ask a question. We did have some questions in queue. The first question is coming from Manav Gupta from Credit Suisse. Please proceed with your question. Hey, Eric and team. Congrats on the Delta deal and all the other positive developments that are happening, $3.5 billion in net contract negotiations. My first and quick clarification here, Eric and Todd, and it is your 2025 guidance doesn't have BTC. When we look at what was being proposed in build back better, and you mentioned it's about $1 BTC for RD and $1.75 for SAF, and most likely you will completely qualify for it till 2031. Very simply adding those numbers in your guidance means your EBITDA jumps by about $123 million. That's a 38% increase. Because BTC is not taxable at all, your net income jumps by $55 million. Now, though, are those numbers making sense? Is the math adds up? Basically, I'm just taking and adding BTC to your existing guidance. I just, if you could walk us through that math a little bit. Thank you, Manav, and thank you for pulling out the calculator and doing the math, but you're exactly correct. It's 45 million gallons times $1. That's our renewable diesel business. Then 45 million gallons times $1.75. And those effectively are $123 million of additional tax credits that we received. Largely it comes to us as basically just additional profit because as you know, our costs don't change at all. The reason why we did not include that in our first quarter five-year plan was because we thought it was very unstable policy with every year Congress kind of running to the end of the year and sometimes past the end of the year before they would pass the tax credits. We thought it would not be supportive of the execution of our five-year plan to increase our cash flow by including it. What has come to pass is frankly what we expected, which is that aviation fuel requires a larger tax credit in order to overcome some of the lower yields and higher capital costs that occur in the production of sustainable aviation fuel. We selected a technology from Axens in France that is a native aviation fuel. We actually designed our plant with the intention of producing 50% aviation fuel. Most of the other producers of renewable diesel do not have renewable aviation fuel capacity. If they wanted to upgrade their plant, they have to build essentially a separate facility and take a bit of a yield hit doing that. Our focus on what we believe to be the necessary role of low carbon, in our case, carbon negative, renewable fuels and aviation was a good strategy and has paid out, I think, better than we expected. We intend in the first quarter to include that in our updated five-year plan. Okay. Eric, second and very quick follow-up here is, you do speak to a lot of people at CARB, and as we understand, you speak to the higher level people. There is this bear case being floated that as these projects come on, LCFS price will come under a lot of pressure, and CARB will just sit on the sidelines and let the LCFS price crash. Is that the feeling you get when you talk to these people, or there is more developed feeling over there that they actually want to lower the carbon intensity of fuels, and they would try and help companies like yours who are actually making a difference here, and in the process, whatever they have to do, they have to do, but they'll try and be supportive of a minimum kind of carbon price and not let it drip to something like 80 or 70, where project economics comes under pressure. If you could just talk about that. Absolutely. For those who've been in California operating active production units, February 2019 was an interesting month because the California Air Resources Board met and decided to change the number of carbon credits required for the next 12 years, all the way until 2030. They just in one meeting decided that the price of the LCFS credits was not high enough to support projects, and so they changed the rules and made it 1.25% every single year. That of course caused the price of the credits to rise from about $120- $200. As you may know, in the original negotiations roughly 10 years ago, $200 plus the cost of living index increase every year was set up as an informal price limit. We hit almost $220 within about a year or so after they had taken this action. What occurred then was they held public hearings saying that they wanted to talk about putting more credits in the marketplace, giving them to electric utilities, for example, to make charging stations as a pure tool to tell the markets that they're not gonna let the price go to $300 or $500 and cause the program to fail. We're now at the final phase of this, where we think that the California Air Resources Board is absolutely committed to taking whatever necessary steps are needed to try to target a $200 kind of price and $200 plus cost of living index would not be too far to ask them to go. They are very concerned that their actions would not support what Aemetis is doing and are working closely with us to take necessary steps over the next year to give us the LCFS credit value necessary to fund our project. Thank you so much for taking my questions, and congrats on all the positive developments. Thanks, Manav. Thank you. The next question is coming from Nate Pendleton from Stifel. Please proceed with your question. Good morning, all, and thanks for taking my questions. For my first question, regarding dairy RNG, could you provide an update on where your operations stand relative to your initial plan from both a build-out and a sign-up perspective? Andy? Yeah. We've been fully operating our first two dairies for a year now, and they are meeting or exceeding expectations from a production perspective. As far as additional dairies, we have 22 dairies that we have under contract right now. We have five additional dairies that we expect to close by the end of this year. Then there's about 12 or so that we are in active discussions with. I think we're feeling like we're right on track with our goals in terms of the overall scope of the project. Great. Thank you. For my follow-up, regarding CCS, could you speak to how Aemetis is differentiated from a geologic perspective compared to others in the Central Valley, and how you're able to qualify for IRS 45Q credits given the CO2 capture thresholds are quite high and serve as a barrier for other smaller potential operations? One of the big advantages we have is we have our own CO2, and so the minimum thresholds we exceed with what we're already producing from our own facilities, which is a helpful component for us. The Central Valley of California has very extensive natural gas and oil production, especially as you get down near Bakersfield, but frankly, if you go north of us much, you get a lot of natural gas fields. Carbon sequestration requires sequestration, which means that if you have natural gas field with a lot of holes in your cap rock, when you put an injection of liquid CO2 at very high pressure, more than 2,000 PSI below that shale layer, you actually have holes that allow that liquid CO2 to turn into a gas and come back up. It's not really effective if you go to a place that has a lot of natural gas or oil production and you're using those formations for sequestration because you have to buy every single well within probably five miles of your facility and go in and spend up to half a million dollars per well capping the well. It's a very difficult business proposition to have to go and buy every single well in an area. That restricts the number of areas that really are appropriate. You have to have the correct underground formation. You don't really want a population of people on the surface. You need to be in really a rural or agricultural area. You cannot be up against the mountains 'cause your slope is too much, so your CO2 doesn't stay sequestered. It actually just goes up a slope. You start looking at where the footprint is of putting these wells, and you end up with kind of a you know some spots that work and a lot of spots that don't work in Central Valley. We've spent a lot of time with Baker Hughes and our other partners on this, and I think we've identified certainly the two locations we have. Stanford was correct. These were excellent locations. In that area around us, we potentially could do additional wells and have certainly a first-mover advantage. Great. Thanks for your time. Thank you, Nate. Thank you. The next question is coming from Jordan Levy from Truist Securities. Please proceed with your question. Afternoon, all. I wanted to start with a question on Riverbank and specifically, Eric, if you could talk us through how you view the unit economics there, and maybe more so why you view this as the right combination of technologies to deploy. The reason I ask this is given some of the recent buzz around things like alcohol to jet or ethanol to jet, and maybe you can talk through how you view the economic comparison between the gasification for hydrogen and hydrotreatment of veg oils and other oils for renewable diesel versus or SAF versus some of the other technologies out there. Okay. I'll give you a really short answer. There are basically two jet production technologies that are being popularized today. One is alcohol to jet, and the other one is what I would call oils to jet. The current production of renewable diesel worldwide is virtually all oils to jet, and it's a highly profitable business. You just look at Neste, you look at Valero and REGI in the U.S., and it's very publicly known that the margins are $2.50-$3.28 per gallon because that's what they reported last quarter. That's taking a renewable oil grown by a plant, usually in a field, and increasing its energy by adding hydrogen to it. Typically, the hydrogen from petroleum natural gas comes out of the ground and it's about a carbon intensity of about a + 150 under the pathways approved in California, and then use electricity. Most electricity usually is coal because that's the cheapest energy source in Asia and most of the Midwest. What we did is we looked at it and said, "Well, that's interesting. We're the largest distiller's corn oil producer in California, so we got a part of our feedstock. We happen to have 100% zero carbon intensity hydroelectric power that comes off of a dam. We have zero CI electricity instead of petroleum natural gas electricity or coal electricity. We also happen to have what I call the Saudi Arabia of carbon negative wood waste. The almonds in the Central Valley of California are a renewable source of wood waste that is currently being burned or sits in the field and turns into methane. It has a negative 100 carbon intensity. By turning that wood waste into hydrogen, we end up with approximately a negative 80 hydrogen input. We looked at the existing formula of the most profitable companies in the biofuels business in renewable diesel and derivatively in sustainable aviation fuel. We just said, "Let's just improve on the carbon intensity of those inputs because we're sitting in the middle of these tremendous feedstocks to make cellulosic hydrogen and, et cetera." Obviously, we think if the margins are as strong for those folks using those carbon intensive inputs and shipping into California, we think we have a sustainable, let's call it competitive advantage by having lower cost, and lower carbon inputs and therefore more valuable output. Alcohol-to-jet, interestingly, is also one of our businesses. We don't talk about it, but we happen to be the largest ethanol producer in California. As soon as the economics work well for alcohol-to-jet, we are as close and with the companies that are in that business as anybody. I think we're very well-positioned to take full advantage of optimizing the value of our ethanol. If that optimal value is to turn into jet fuel, you can imagine you're gonna hear about that from us. Currently, we are enjoying very, very positive support for our ethanol business in California. Especially with the recovery in LCFS prices, which we expect next year through actions by CARB, I think we're going to continue to enjoy good margins in the ethanol business and be well-positioned to do an upgrade to alcohol-to-jet if and when that opportunity is necessary. That's great. Thanks for that, Eric. Maybe just a follow-up more specific to your biodiesel business. I wanted to see if you could just talk about if there's been any change at all in how you're thinking about the India biodiesel facility and how it fits into your five-year plan. Also any potential means you see to bring forward revenues out of that plant near-term as you know wait to see what happens with government purchases and that sort of thing. Yeah. Our India biodiesel plant is operating in sort of an on-off switch. The differential between feedstock and government purchase prices, if you just get slightly positive, suddenly you literally have a $150 million revenue business in India. The Indian government, largely due to COVID, has been very slow at moving their prices up. While oil doubled from $40 to $80, they haven't doubled the prices for biodiesel. They've just been going through this recurring process every three months of sending out a new price and everybody saying, "Gosh, that's not keeping up with the price of oil." We do think the Indian government will catch up, and if you listen to Prime Minister Modi's presentation at COP26 in Glasgow, they're certainly committed to playing a role in decarbonization. We think India will catch up and play the role they would like to play. What we've been trying to achieve, though, is to have a global market for our India product. India has a view that they have such a strong demand, 5% of 25 billion gallons a year is 1.25 billion gallons of biodiesel. That's stated in their National Policy on Biofuels. They've not been able to execute against that. We went to the government and said, "We have a substantial investment. We have a lot of employees. We have 100% of our employees still working for us, and we are well-positioned to create additional investment and, frankly, revenue for India by exporting out of India, which is tremendous for their balance of trade." We are within, hopefully, weeks and maybe even days of getting an approval that took us many years to get. The natural market is California, where, of course, we're very well-positioned because when it's shipped across the ocean, the biodiesel turns into a solid. It's kind of cold on the ocean. When it arrives, you just can't pour it into a tank or into a truck. You actually have logistics of steam heating the tanks and turning it back into liquid and then transloading into trucks. We have the Riverbank facility that's ideally situated to handle this kind of logistics. We have 120 rail car rail line already in place. We are able to, with very low cost and pretty much just with our existing team, able to become a supplier of biodiesel into California at what we believe to be very high margins. Thanks so much. Sure. Thank you. The next question is coming from Amit Dayal from H.C. Wainwright. Please proceed with your question. Hi, guys. Thank you for taking my questions. Just coming to some of the near-term execution priorities, Eric, are there any changes to the deployment schedule for your 17 digesters due to supply chain challenges, et cetera, that are ongoing in the market right now? Not since last quarter. I think we proactively bought a bunch of materials required for the whole thing. Andy, you have any- Yeah, during COVID, we were able to take advantage of, you know, it's interesting to think about the price of oil today versus, you know, where it was in April or May of 2020, when it actually went below zero. We were able to go out and pre-purchase material for 10 digesters, the liner material at about 50% of the cost of the original two. We were able to go out and purchase the HDPE pipe, pipeline that we use for the transmission of the gas at similar margin savings. So I think probably 40% margin. So we've already sort of jumped ahead of the supply chain, fortuitously taking advantage of that during COVID, to take advantage of the lower pricing. From a longer perspective as far as that goes and pipeline, we're in very good shape of being ahead of the curve. When the economy really started to pick up, we also went ahead and pre-ordered five of our dairy-based biogas cleanup skids. We do a little pre-treatment at the dairy before we send it to the main hub. Those are now modularized. They were built during the summertime and into the early fall. They'll be delivered to us next week. The next five digesters will have, you know, everything that they need. We're currently in the RFP process for the next five after that for those digester skid units. It's not out of question to say that we do see delays in materials, but we don't think there's any one piece that we've overlooked that will create a substantial delay for us. We're trying to stay ahead of it as much as possible by you know- Pre-ordering equipment for the next phase of digesters to be built so that we're trying to stay ahead of the global supply chain challenges. Okay, thank you for that. Mm-hmm. Cash flows from the two digesters deployed, are you starting to receive that yet or is there still a little bit lag? You know, you had highlighted there were some, quality checks, et cetera, that needed to happen before you start receiving those cash flows. The way we're monetizing that currently is through the LCFS for the ethanol produced at the plant. We received a pathway approval in March of this year, which lowered the CI score for the ethanol plant in Keyes from, call it 67 to 65. We got about a two-point reduction or close to a two-point reduction. We're able to monetize the LCFS by taking the dairy biogas from the two existing digesters and utilizing it in a boiler at the plant to replace carbon-based natural gas as a source for energy at the plant. We've been able to already monetize the gas coming off those first two dairies through the production of ethanol. That kind of gives us a little bit of an advantage over some of the other developers who have to sit around and wait for CI score to be issued for the pipeline. As soon as we are able to complete our pipeline interconnect, which will happen in the next 45-50 days, something like 60 days, we'll have access to the PG&E pipeline. We'll then apply for the pipeline pathway for those two dairies and then all the dairies that come after that. When it's all said and done, we'll have three different pathways for each dairy. One for using the biogas as process energy at the ethanol plant, one for transmission to the utility pipeline, and one for our on-site CNG fueling station. We'll have maximum flexibility in terms of where we can send the gas to, and we'll be able to monetize. As far as to your question about when can we monetize in the pipeline, we'll do that as soon as our interconnection begins. As you know, there's about a 90-day data collection period, and then CARB takes about another 90 days to give you the approval on the pathway. We can either, you know, take the provisional pathway that's granted, or we can store those molecules and then monetize the full amount once the pathway's been granted, which usually takes, you know, from start to finish, it's about a 120-day or a 180-day process. Okay. Understood. Thank you for that. Then. Uh-huh. These offtake agreements with Delta and some other that you are, you know, working on, should we view them as definitive agreements for these MOUs? Yeah. These are not memorandums of understanding or non-binding term sheets or napkins at the local restaurant. These are fully vetted, lawyered, reviewed, signed. There's nothing to do except start shipping product. Delta Air Lines was a tremendous organization to work with. We worked with their global group and just a wonderful group of people. We are currently working with several other airlines of that size as well. We've just found a sincere commitment to sustainable aviation fuel, and they do not really see other ways forward that are gonna be quick or fit in with their existing equipment. Certainly electricity is tough to see in cargo or passenger jets anytime soon. Hydrogen probably is in a similar situation. They have a sincere appetite to decarbonize, and they also understand the incentives are coming along. The CORSIA airline incentives are a meaningful number for them. We found it's a very proactive community and we happen to, interestingly, know a lot of the people in that community because of our backgrounds. It's gone very quickly. Certainly more quickly than I would have expected if you would ask me six months ago. I'm very pleased with the progress we're making there. Okay. Just one last one. You know, if you get the approval for exports in India, how quickly can, you know, the plant be mobilized, et cetera, to begin, you know, that process? We would be in production within a matter of a few days. The plant's fully capable of operation and does operate. This would just be a higher volume. Then the export process takes some scheduling, but our initial shipments will not be bulk shipments, so we're not going to have to schedule an entire ship. We'll be using what are known as ISO tanks, about 8,000 gallons per. That's got a lot of flexibility around it. We're doing that on purpose just to be able to not have to wait for bulk shipments to be arranged. We could easily be shipping in the first quarter. Okay. Understood. That's all I have, guys. Thank you so much. Thank you, Amit. Paul, we're running out of time. Let's take one, maybe two more calls. Okay. There are two left in queue. The first one is coming from Ed Woo from Ascendiant Capital. Please proceed with your question, Ed. Yeah. Congratulations on all the milestones. My question is on Riverbank. When do you anticipate groundbreaking, and when do you think that the plant will be operational? We're expecting groundbreaking is gonna be third quarter of next year. I think that operational would be roughly 24 months after that. I say roughly because the particular contractor we're working with is completing a 225 million gallon plant and already has the vendors and supervising staff, and they are just really ahead of the game. I think we're gonna need to amend those times as they get on the ground. These plants are usually run by the long lead time equipment, and we are finding ourselves in a position in which, because of the contract we're using, we have some distinctive advantage that's gonna save us a lot of time here. So we'll be updating those numbers as we get closer to the third quarter next year. Great. Thanks for the update, and good luck. Thank you, Ed. Paul, are there any additional callers or questions? We did have a question coming from Marco Rodriguez. Marco, your line is live. Marco is calling from Stonegate Capital. Good afternoon, guys. Thanks for taking my questions. Most have been asked and answered. Just kinda wanted to go through just a real quick housekeeping item on the gross loss in the quarter. I believe you made some comments in prepared remarks. I just unfortunately wasn't able to get it all down. But even if I took a look at excluding the reserves, it still looked like it was down year-over-year. Can you maybe talk a little bit about the drivers behind that? What was down? I didn't get the metric. The gross profit. We have a $5.3 million reserve for the California emissions credits that caused our cost of goods sold during the quarter to be increased by $5.3 million, if that's what you're comparing. This is Todd. It would put us really level with the same quarter last year. Last year, we recorded $12.2. This year, reporting $17.5, adjusting for the $5.3, really sets the net loss at exactly what it was a quarter a year ago. All right. Thanks. Appreciate it. Thank you, Marco. Thank you. There are no further questions at this time. I would like to turn the floor back over to the management. Thank you, Paul. Thanks to the Aemetis shareholders, analysts, and others for joining us today. Please review the Aemetis corporate presentation and the Aemetis investor presentation that was on the Aemetis website. We look forward to talking with you about participating in the growth opportunities at Aemetis. Todd? Thank you for attending today's Aemetis earnings conference call. Please visit the investor section of the Aemetis website, where we'll post a written version and an audio version of this Aemetis earnings review and business update. Paul? Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.