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, filing 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 risks 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's 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 the 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 2020 to $7.99 per bushel during the third quarter 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 expense was $5.1 million during the third quarter of 2021, compared to $4.6 million during the third quarter of 2020. As a result of period 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 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, the 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 entered 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 delivered 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 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 blenders tax credits, while reducing operating costs by using waste materials as feedstock. In early 2021, we announced a 5-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're also on track with financing growth using long-term 20-year, low interest rate project financing from the USDA Department of Energy and municipal bond markets. Importantly, our third-quarter earnings are on track with the 5 years. 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 negative $0.39 per share, which is in line with our growth plan. The positive regulatory trends for renewable fuels have continued to improve by the passage of the Federal 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 a billion dollars of expanded funding to provide 20-year, 6% to 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 5-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 a $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, but 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 4 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. Excuse me, 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. Excuse me, 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 1 of the Aemetis Biogas central dairy digester project and commenced operation of the first 2 covered lagoon digesters, including on-site dairy biogas cleanup and pressurization of a 4-mile pipeline owned by Aemetis and a boiler unit used to utilize the biogas as processed 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 negative 426 CI score for our biogas, compared to approximately a positive 100 carbon intensity for petroleum and natural gas. In addition to the 2 dairy digesters and 4 miles of gas pipeline currently in operation, we are now building Phase 2 of the biogas project, including the main biogas cleanup facility, the utility pipeline, interconnection unit, and RNG fueling station at the Keyes plant and an additional 15 dairy digesters, and 32 miles of biogas pipeline. Each of these project components are on schedule for completion of Phase 2 in the third quarter of next year. We have now signed agreements with 22 dairies to install digesters. We are in advanced discussions with 5 more dairies representing approximately 10,000 cows that we expect to sign in the current quarter and have more than a dozen additional dairies under discussion. As the pipeline and digesters are built, we're 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 Meda's 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 the 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 5 digesters and related pipeline in the first half of 2022. To connect the next 5 dairies to our existing biogas pipeline, the installation of 6.5 miles of the 7 miles required for the new biogas pipeline will be completed, weather permitting in the next few weeks. Excavation of 2 of the next 5 dairy digesters has been completed, and the remaining 3 digesters will be under construction in the next 2 weeks. The next 5 dairy digester biogas cleanup skids, which are fully modularized, will be delivered next week for installation at the 5 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. 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 30-year industry veteran, who supervised the installation of our Phase 1 pipeline while working for our lead contractor, has instituted a number of best management practices that have resulted in cost savings and scheduled acceleration. The Aemetis RNG team is in contract review with a number of expected RNG off-take 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 high-value animal feed. The Aemetis ethanol plant produces approximately 65 million gallons per year of renewable ethanol, but also produces about 2 million pounds per day of wet distiller's 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 fuels, and carbon sequestration businesses will be able to be fueled by RNG at compressed natural gas fueling stations and 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 a 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 3 quarters of 2021. Ethanol imports, especially to California from Brazil, were especially persistent in the third quarter of 2021 due to higher fuel prices received by Brazilian ethanol producers as a result of California's low carbon fuel standard. Strong demand and favorable pricing for both wet distillers’ grains and distillers corn oil remained 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 pounds per day being delivered to dairies using about 45 truckloads per day. We're delivering more than 30,000 gallons per week of distiller’s 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 the reduction from 21,000 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 and natural gas, this 75% reduction in steam use 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 megawatts 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 5-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're 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 Airlines 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 Airlines 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 Airlines. 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're 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 renewable energy for America funding that has been reviewed with the USDA. We announced that the $2 billion global EPC contractors 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 plant completion in mid-2022. I'm sorry. And is ideally suited to construct the Aemetis plant quickly and efficiently. The Aemetis 5-year plan announced that Phase 1 of the Riverbank jet 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 of positive cash flow. We plan to expand production in phase 2 of plant construction to 90 million gallons per year after Riverbank site by year 2025, as part of our 5-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 5-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 renewable diesel and a $1.75 per gallon for 45 million gallons per year of Sustainable Aviation Fuel to our updated 5-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 -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 plant 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 45-Q 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, 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 7,000-foot-deep strata, known as a caprock, and 8,000-foot-deep strata known as a basement rack. Between the two layers is the salient formation that was cited by Stanford University as ideal for carbon dioxide sequestration. Over a long period of time, the CO2 reacts with salient to form a mineral that is permanently sequestered underground and does not return 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 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 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 one 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, and there are 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 6 permit. The injection wells will then be drilled at the same site after receiving EPA and other permits. We're 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 biofuel subsidiary in India bid on a portion of a $900 million biodiesel purchase tender offer for about 225 million gallons by the three India 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 India 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 in India. And our Riverbank facility is well-positioned to manage product re-heating 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 3 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 the 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 from the Keyes ethanol plant. The remaining lignin and non-converted sugars are designed to be the feedstock for our gas-fired unit at the Riverbank jet and 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 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 by-products 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. And 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 the contract negotiations. My first and quick clarification here, Eric and thought is, your 2023 5 guidance doesn't have BTC. And when we look at what was being proposed and build back better, and you mentioned it, 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, and because BTC is not taxable at all, your net income jumps by 55. Now, are those numbers making sense as the math adds up? Basically, I'm just taking and adding BTC to your existing guidance. I guess, 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 and then 45 million gallons times a $1.75 and those effectively are $123 million of additional tax credits that we received. And 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 running to the end of the year, and sometimes past the end of the year before they would pass the tax credits. And 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 France that is a native aviation fuel, so we actually designed their 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 at doing that. Our focus on what we believe to be the necessary role of low carbon, at our case, it's carbon negative, renewable fuels and aviation, was a good strategy and has paid out, I think better than we expected and we intend in the first quarter to include that in our updated 5-year plan.

Okay. And 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 peer case being floated that as these projects come on SAF's price will come under a lot of pressure and CARB will just sit on the sidelines and let the SAF's 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 fuel 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 carbon price and not let it dip to something like 80 or 70 where project economics come under pressure. If you could just talk about that.

Absolutely. For those who have been in California, operating active production units. February of 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. And that of course, caused the price of credits to rise from about $120 to $200. And 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, and what occurred then was they held a public hearing saying that they wanted to talk about putting more credits in the marketplace, given them the electric utilities, for example, to make charging stations, as a pure tool to tell the markets that they're not going to 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 Resources Board is absolutely committed to taking whatever necessary steps are needed to try to target a $200 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, everyone. 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 sign-up perspective?

Andy?

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 5 additional dairies that we expect to close by the end of this year. And 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. And for my follow-up regarding CCS, could you speak to how Aemetis is differentiated from a geological 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, 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. And carbon sequestration requires sequestration, which means that if you have a natural gas field with a lot of holes in your caprock, 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 5 miles of your facility and go in and spend up to a half million per well capping the well. It's a very difficult business proposition to have to go and buy every single well in an area. And 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 because your slope is too much to your CO2 sequestration is actually just those up with slope. So, you start looking at where the footprint is of putting these wells and you end up with some spots that work and a lot of spots that don't work in Central Valley, and we spent a lot of time with Baker Hughes and our other partners that makes this and I think we've identified certainly the 2 locations we have. Stanford was correct, these were excellent locations, but in that area around us, we potentially could have additional wells and have certainly a first-mover advantage.

Great. Thanks for your time.

Thank you, Nate.

Thank you. And 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? And 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 could talk through how you view the economic comparison between the gasification for hydrogen and hydro treatment, 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 being popularized today. One is alcohol-to-jet and the other one is what I would call oils-to-jet. And the current production of renewable diesel worldwide, it's virtually all oils-to-jet and it's a highly profitable business. You just look at NESTI, you look at Valero and REGI in the U.S. and it's very publicly known that the margins are $2.50 to $3.28 per gallon because that's what they reported last quarter. And that's taking a renewable oil grown by a plant usually in the field and increasing its energy by adding hydrogen to it. Typically, the hydrogen is petroleum natural gas. It comes out of the ground and it's about a carbon-intensive at a positive 150 under the pathways of proven California. And then use electricity. And most electricity usually is coal because that's the cheapest energy source in Asia and most of the Midwest. So, what we did is we looked at it and said, well, that's interesting. We're the largest distillers corn oil producer in California so we got a part of our feedstock. We happen to have 100%, zero carbon intensity hydroelectric power, comes off of a dam. So, we have zero CI electricity instead of petroleum natural gas electricity or coal electricity. And we also happen to have what I call the Saudi Arabia of carbon negative wood waste, the almonds in the Central Valley, California are our renewable source of wood waste that is currently being burned or sits in the field in terms of nothing. So, it has a negative 100 carbon intensity. And by turning that wood waste into hydrogen, we end up with approximately negative 80 hydrogen input. So, we looked at the existing formula of the most profitable companies in the biofuels business and renewable diesel and derivatively in sustainable aviation fuel. And we just said what's just improved on the carbon intensity of those inputs, because we're sitting in the middle of these tremendous feedstocks to make cellulosic hydrogen, etc. So, obviously, we think if the margins are 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. And as soon as the economics work well for alcohol-to-jet, we are as close with the companies that are in those businesses as anybody. And I think we're very well positioned to take full advantage of optimizing valuable ethanol. If that optimal value is to turn into jet fuel, you can imagine you're going to hear about that from us. Currently, we are enjoying very, very positive support for our ethanol business in California. And 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 a good margin 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. And maybe just a follow-up more specific to your biodiesel business. I wanted to see if you could just talk to if there's been any change at all and how you're thinking about the India biodiesel facility and how it fits into your 5-year plan. And also, any potential means you see to bring forward revenues out of that plant near-term as you wait to see what happens with government purchases and that sort of thing.

Yeah. Our India biodiesel plant is operating instead of an on-off switch. The differential between feedstock and government purchase prices, if you just get slightly positive, suddenly you've literally had a $150 million revenue business in India. The India government, largely due to COVID, it's been very, very slow at moving their prices up. While oil doubled from $40 to $80, they haven't doubled the prices for biodiesel. They've been just going through this recurring process every 3 months of setting out a new price and everybody saying, gosh, that's not keeping up with the price of oil. We do think the India 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. And 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, stated in their national biofuels policy. But they've not been able to execute against that. And so, we went to the government and said, we have a substantial investment, we have a lot of employees, we have 100% of our employees 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. And so, we are within hopefully weeks and maybe even days of getting an approval that took us many years to get. And the natural market is California where we are 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, and so 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. And we have the Riverbank facility that's ideally situated to handle this kind of logistics. We have a 120-railcar rail line already in place, and so we are able to, with very low cost and pretty much just with our existing team, become a supplier of biodiesel into California at what we believe to be very high margins.

Thanks so much.

Thank you. And the next question is coming from Amit Dayal from H.C. Wainwright. Please proceed with your questions.

Hi, guys. Thank you for taking my questions. This coming through some of the near-term execution priorities. Are there any changes to the deployment schedule for those 17 digesters doing supply chain challenges, etc. that are going in the market right now?

Not since last quarter. I think we proactively bought a bunch of materials required for the whole thing. Andy, do you have any.

During COVID, we were able to take advantage of the price of oil, which was significantly lower than in April or May of 2020 when it briefly fell below zero. We pre-purchased materials for ten digesters, including liner material at about 50% of the original cost for two units. We also acquired the HDP pipeline used for gas transmission, achieving approximately 40% margin savings. This proactive approach allowed us to get ahead of the supply chain by capitalizing on lower pricing during COVID. In terms of liners and pipelines, we're in a strong position. As the economy began to recover, we pre-ordered five dairy-based biogas cleanup skids that are essential for pre-treatment at the dairy before processing at the main hub. These skids were modularized and built over the summer into early fall, and they will be delivered next week, ensuring the next five digesters have everything they need. We are currently in the RFP process for another five digester skid units. While we do anticipate some delays in materials, we believe we have accounted for all critical components to avoid significant hold-ups. We're making efforts to stay ahead of potential global supply chain challenges by pre-ordering equipment for the next phase of digester construction.

Thank you for that. And the cash flows from the five digesters deployed, are you starting to receive that yet or is there still a little bit lagged? You highlighted there were some quality checks that needed to happen before you started receiving those cash flows?

Currently, we are monetizing through the Low Carbon Fuel Standard for the ethanol produced at our plant. We received pathway approval in March, which reduced the carbon intensity score for the Keyes ethanol plant from 67 to 65, giving us about a 2-point reduction. We are able to monetize the LCFS by using dairy biogas from two existing digesters in a boiler at the plant to replace carbon-based natural gas for energy. We have already started to monetize the gas from the first two dairies through ethanol production, which provides us an advantage over other developers who must wait for a CI score for their pipelines. Once we complete our pipeline interconnection in roughly 45 to 60 days, we'll gain access to the PG&E pipeline. We will then apply for the pipeline pathway for those two dairies and for all subsequent dairies. Ultimately, we will have three pathways for each dairy: one for using the biogas as processed energy at the ethanol plant, one for sending it to the utility pipeline, and one for our on-site CNG fueling station. This will give us the maximum flexibility in gas monetization. Regarding when we can begin monetizing in the pipeline, we will do that as soon as our interconnection starts. There will be a 30 to 90-day data collection period, and CARB will take about another 90 days to approve the pathway. We can either accept the provisional pathway granted or hold the molecules and then fully monetize them after the pathway approval, which generally takes about 120 to 180 days in total.

Okay. Understood. Thank you for that. And then agreements with Delta and some other that you are working on, should we view them as definitive agreement for the full use?

Yeah. These are not memorandums of understanding or non-binding term sheets or napkins at the local restaurants. These are fully vetted, lawyered, reviewed, signed. There's nothing to do except to start to ship product, and Delta Airlines was a tremendous organization to work with. We worked with their global group and just a wonderful group of people. And we are currently working with several other airlines of that size as well. And we've just found a sincere commitment to sustainable aviation fuel. And they do not really see other ways forward that are going to be quick or fitting with their existing equipment. And certainly, electricity is tough to see in cargo or passenger jets anytime soon, and hydrogen probably is in a similar situation. They have a sincere appetite to decarbonize, and they also understand the incentives are coming along, but the airline incentives are a meaningful number for them. We've found it's a very proactive community, and we happen to, interestingly, know a lot of people in that community because of our backgrounds. And it's gone very quickly, but certainly more quickly than I would have expected if you asked me six months ago. I'm very, very pleased with the progress we're making there.

Okay. And just one last one. If you get the approval for exports in India, how quickly can the plant be utilized, etc. to begin that process?

We would be in production with a matter of few days, plants fully capable of operations and does operate. This will just be a higher volume. And then the export process takes with some scheduling, but our initial shipments will not be bulk shipments so we're not going to have to schedule entire ship. We'll be using what it knows ISO tanks, about 8,000 gallons per and that's got a lot of flexibility around that. We're doing that on purpose just to be able to not have to wait for bulk shipments to be arranged. And so, 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 1, maybe 2 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.

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 going to be the 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, so I think we're going to need to amend those times as they get on the ground. These plants are usually run by the long lead-time equipment, and we're finding ourselves in a position of which because of the contract we're using, we have some distinctive advantages that's going to 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 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, just unfortunately unable to get 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 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.

And it would put us really level with the same quarter last year. Last year we recorded 12.2 million, this year we're reporting 17.5 million adjusting for the 5.3 million. Really sets from that loss at exactly what it was last 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 call 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 Investors section of the Aemetis website where we will post a written version and 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.