Welcome to the Aemetis third quarter 2022 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 2022 earnings review conference call. Joining us for the call today 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 investor section of the aemetis.com website. Before we begin our discussion, I'd like to read the following disclosure, 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 filings, which are posted on our website and available from the company without charge. Our discussion on this call will include a review of non-GAAP measures as a supplement to financial statements 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 three and nine months ended September 30, 2022, which is available on our website. Adjusted EBITDA is defined as net income or loss, plus to the extent deductible in calculating such net income, interest expense, loss or gain on debt extinguishment, income tax expense, intangible and other amortization expense, accretion and other expenses of Series A preferred units, loss on lease termination, gain on litigation, depreciation expense, and share-based compensation expense. Now I'd like to review the financial results for the third quarter of 2022. Revenue during the third quarter of 2022 increased 44% to $71.8 million, compared to $50 million for the third quarter of 2021. Our California ethanol business experienced steady sales pricing with an increase in the volume of ethanol produced and sold at 15.7 million gal in the third quarter of 2022, up from 13.8 million gal in the third quarter of 2021. Delivered corn price increased 20% from an average price of $7.99 per bushel during the third quarter of 2021 to $9.59 per bushel during the third quarter of 2022. Our India Biodiesel segment began delivering product under a tender offer to governmental oil marketing companies in mid-September, delivering $11 million of biodiesel in about two weeks under this tender offer. Gross loss for the third quarter of 2022 was $1.1 million, compared to $4.8 million gross loss during the third quarter of 2021. Our California Ethanol segment accounted for $3.8 million of gross loss, with offsetting gross profits of $2.8 million from our India Biodiesel segment. Selling, general, and administrative expenses were $6.9 million during the third quarter of 2022, compared to $5.1 million during the third quarter of 2021, as a result of investments in our ultra-low carbon initiatives and non-cash charges for stock compensation. Operating loss was $7.6 million for the third quarter of 2022, compared to an operating loss of $9.9 million for the third quarter of 2021. Interest expense for the third quarter of 2022 was $7.1 million, excluding accretion and other expenses in connection with Series A preferred units in our Aemetis Biogas subsidiary, compared to $5.5 million during the third quarter of 2021. Additionally, our Aemetis Biogas subsidiary recognized $1.3 million of accretion and other expense in connection with preference payments on its Series A preferred units during the third quarter of 2022, compared to $2.2 million during the third quarter of 2021, along with a loss on extinguishment on Series A preferred units of $53.9 million during the third quarter of 2022 as a result of a charge related to the redemption of Series A preferred units as part of the amendment to the preferred unit purchase agreement. The redemption charge reflects the expected valuation premium for the redemption of Series A preferred units by Aemetis. Management engaged third parties to assist with the accounting and fair value calculation. Management is completing our final review of the accounting and related charges. At this time, we do not believe the amounts will materially change during the third quarter as a result of filing the Form 10-Q, which will be subsequently filed to this earnings release. Net loss was $69.8 million for the third quarter of 2022 compared to a net loss of $17.6 million for the third quarter of 2021, driven primarily by the one-time unitholder redemption charge of $53.9 million or $1.55 per share. Absent this one-time charge, the net loss was $16 million, representing $0.46 per share. Cash at the end of the third quarter of 2022 was $251,000 compared to $7.8 million at the close of the fourth quarter of 2021. Investment in capital projects of $13.7 million were made during the third quarter of 2022, further highlighting our commitment to execution of multiple low carbon products, projects. This completes our review of the third quarter of 2022. 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 negative carbon intensity, renewable natural gas, and renewable aviation and diesel fuel with renewable hydrogen and carbon sequestration. Our projects generate sustainable and innovative renewable fuels that benefit our communities and restore our environment while generating tax and other credits from federal and state carbon reduction programs. We seek to reduce feedstock and operating costs by using waste materials and zero carbon intensity energy for the production of renewable fuels. Let's start by talking about the estimated $55 million unit holder redemption charge in the third quarter related to our Aemetis Biogas business. The unit holder redemption charge is related to the repurchase of preferred units from the preferred investor in the Aemetis Biogas subsidiary. Before counting the redemption charge, Aemetis had a loss of $0.46 per share in the third quarter, which is within the range of expectations. The unit holder redemption charge is a non-cash accounting entry that was taken in Q3 2022 related to an agreement that was reached between Aemetis and the Aemetis Biogas preferred equity investor to repurchase 100% of the outstanding preferred equity in Aemetis Biogas. The motivation for the expected redemption of the preferred equity by Aemetis includes several factors, including Biogas industry transactions at high valuations that increase the value of the Aemetis Biogas preferred units, as well as discussion of whether a spin-out of the subsidiary into a SPAC, IPO, or sale should be considered. As most of you know, OPAL went public at a pre-money valuation of about $1.2 billion last year, and recently, Archaea was sold for $4.1 billion to BP, which included $800 million of Archaea d ebt. We believe these transactions are interesting comparables to Aemetis Biogas, especially considering that dairy renewable natural gas generates an estimated 10 times more California Low Carbon Fuel Standard credits compared to the landfill renewable gas primarily produced by both OPAL and Archaea. Aemetis Biogas, with a carbon intensity score of - 426, is expected to generate about 500 LCFS credits compared to landfill gas at a +30 carbon intensity, which generates only about 50 LCFS credits. After considering the future value of over 60 digesters planned by Aemetis Biogas to generate an expected 1.65 million MMBtus per year, compared to the approximately 2 million MMBtus of landfill RNG currently produced by Archaea at one-tenth the number of LCFS credits, Aemetis made a strategic decision to acquire the preferred equity in Aemetis Biogas from our investor, who was seeking a liquidity event without waiting for the completion of project development. In the third quarter of 2022, Aemetis negotiated redemption of all of the preferred equity of the Aemetis Biogas subsidiary and booked an estimated $55 million non-cash Series A preferred unitholder redemption expense in Q3. This $55 million charge was not paid in cash, but represents an expected future transaction in which Aemetis has the right to redeem 100% of the Aemetis Biogas preferred equity. Usually, the redemption of preferred equity is shown as a dividend, not as a non-operating charge on the income statement that reduces earnings per share. In this case, the accounting guidance determined that the certainty of the redemption and other known features of the buyout of the preferred unit holder supported recognizing the $55 million as debt that was redeemed at a premium rather than as a dividend to the preferred equity owners that would have been shown on the balance sheet, not on the income statement, and would not have reduced earnings per share. Let's discuss our financing plan and the progress we're making in funding the growth of Aemetis. In early 2022, we announced an updated five-year plan which projected revenues to grow to about $1.5 billion and projected annual EBITDA to increase to more than $460 million per year by 2026. In 2021 and 2022, Aemetis repaid more than $80 million to Third Eye Capital to reduce higher interest rate bridge loans, which has now expanded our access to lower interest rate funding. Our plan is to fund growth by using positive cash flow from our ethanol, biogas, and India biodiesel and glycerin production facilities, enhanced by a new up to $100 million working capital and project development financing credit facility that was signed with Third Eye Capital in March of this year. After completing preliminary engineering, permitting, and site control for each project, we then plan to obtain project financing at the project level using low-interest-rate, U.S. government guaranteed long-term 20-year loans to fund project construction and operations. This financing model minimizes or eliminates shareholder dilution while enabling rapid growth in revenues and earnings as projects are built. This financing model is working even with rising interest rates creating difficult debt market conditions and currently low LCFS credit prices. In the past two quarters, we have received funding of about $50 million from the two credit facilities provided by Third Eye Capital at interest rates of only 8% and 10% per year. This new $50 million of growth funding has supported the construction of a solar energy system and many other carbon reduction projects at the Keyes Ethanol plant. The financing land purchases, the engineering permitting and related equipment for the renewable aviation and diesel fuel plant, and the pre-project engineering and drilling pad construction for CO₂ characterization and sequestration wells. As an example of our long-term financing strategy, Aemetis recently closed a $25 million project financing supported by the U.S. Department of Agriculture Renewable Energy for America, known as REAP program, to fund dairy biogas digesters and biogas pipelines to produce renewable natural gas. The financing this month was completed at a 6.2% interest rate that is fixed for five years and has a highly favorable 20-year repayment of principal. Let me clarify that was the month of October. Regarding regulatory credit price trends, in August of this year, Governor Newsom issued a letter to the chairman of the California Air Resources Board, specifically requesting a significant increase in the pace of decarbonization in California. The letter stated 100 million metric tons of total CO₂ sequestration as a specific goal. The release of the draft California Air Resources Board LCFS scoping plan in early 2023 is expected to increase the number of credits required under the Low Carbon Fuel Standard program. We expect that LCFS credit prices will rebound as traders learn more about the number of LCFS credits that will be required to meet the expanded decarbonization goals set forth by CARB. In addition, the Inflation Reduction Act was passed recently and is expected to have a significant positive impact on renewable energy in general and our businesses specifically. We are completing a review process of the IRA with our tax advisors and expect to release a revised five-year plan in Q1 2023 that will include the impact of the legislation on our business. We are investing a significant amount of tax lawyer and tax accounting resources into the IRA review process to develop and implement specific business structures that should maximize the value of the tax credits available under the Inflation Reduction Act. As a reminder of the provisions of the Inflation Reduction Act related to Aemetis, first, a 30% investment tax credit for renewable natural gas capital investments. The ITC for renewable natural gas projects is expected to result in up to $180 million of cash received by Aemetis at the rate of approximately $30 million per year for the next five years from Inflation Reduction Act investment tax credits. Next, $1.25-$1.75 tax credit for sustainable aviation fuel and a $1 tax credit for renewable diesel. The IRA Sustainable Aviation and Renewable Diesel Fuel Tax Credit is expected to result in up to $112 million per year to support the construction and operation of the 90 million gal per year Aemetis Carbon Zero plant in Riverbank, California. If extended over the 10-year period of our contracts with certain airlines and monetized efficiently, the SAF and RD tax credits in the Clean Fuel Program of the Inflation Reduction Act could provide more than $1 billion of cash to repay an estimated $400 million of project funding. This potential $1 billion from IRA tax credits over 10 years is in addition to the revenues from California Low Carbon Fuel Standard credits, federal Renewable Fuel Standard D5 RINs, and the sale of the aviation and diesel fuel. Next, an increase in the carbon sequestration tax credit from $50- $85 per metric ton of CO₂, but paying the credit in cash as an IRS tax refund to companies in a process called direct pay for the first five years, followed by seven years of additional tax credits. We are developing two injection wells located at the two Aemetis biofuels plant sites in California to sequester a planned 2 million metric tons per year of CO₂ into a saline formation approximately 7,000 ft underground. A planned 2 million tons times $85 per ton equals $170 million per year of cash that could potentially be paid to Aemetis by the IRS each year for the first five years of the project. Providing approximately $850 million of IRS funding in the aggregate to repay the capital costs and operating costs of the two projects. With another seven years thereafter at the same yearly rate, generating an expected aggregate amount of tax credits valued by management at an additional $1.2 billion, the total value of the $85 per metric ton tax credit would be $2 billion in the first 12 years of operation of the two Aemetis carbon wells. Lastly, several positive provisions in the IRA legislation are valuable to the Aemetis ethanol business, including a tax credit for low carbon intensity ethanol, $500 million for biofuels fueling infrastructure to support 15%-85% ethanol blends, and adopting the Argonne Labs GREET model to correctly calculate the carbon intensity of ethanol and other renewable fuels. These regulations are driven by initiatives to decarbonize transportation, the need to reduce the cost of fuels as petroleum prices increase, a renewed interest in energy security, and greenhouse gas reductions. Let's review our biodiesel business in India. The national biofuels policy in India was updated in 2022, and is now being implemented to achieve a 5% blend of biodiesel that's equal to about 1.25 billion gal of biodiesel per year. This summer, the three government oil marketing companies issued a tender offer to purchase up to 180 million gal per month of biodiesel. For the past 15 years, the pricing formulas have largely been driven by petroleum diesel prices. For the first time, a feedstock plus pricing formula was used for the OMC tender, reflecting the actual cost for feedstock to produce biodiesel in India. The pricing formula and timing of the two-month tender by the oil marketing companies is expected to be the ongoing format for sales to the oil marketing companies. We expect the formula to be a successful mechanism for the rapid growth of biodiesel production in India due to the predictability of the pricing formula. After a 45-day delay from August 1 to September 15th, due to a requirement by the India oil marketing companies for two rounds of laboratory testing and documentation, we began deliveries of biodiesel from our India biodiesel plant in mid-September and shipped biodiesel for the last two weeks of the quarter. Despite the delay in testing approvals to September 15th, we delivered $11 million of biodiesel in 15 days by the end of September. Production and deliveries have continued to the end of October, after the OMCs extended the delivery period for the biodiesel purchase orders. We believe the revised OMC purchasing process, based on a cost plus calculation, will allow us to maintain ongoing production, though the OMCs continue to generate uncertainty by slow and burdensome procurement processes. The glycerin unit is operational now, converting about 10% of the product from the biodiesel plant into high-grade glycerin for sale in India. The feedstock pretreatment unit is expected to be utilized for the refining of crude tallow for export to the U.S. and Europe to these renewable diesel and sustainable aviation fuel. Negotiations of refined tallow offtake agreements has been underway since early Q3 of this year, and refined tallow production is expected to begin in early 2023, with export shipments soon thereafter. Since our India subsidiary has no debt and the 50-million-gal-per-year biodiesel plant, the glycerin plant, and the tallow refining facility are fully constructed, we are well positioned for continued operation at high yields. Now, Andy Foster, the President of the Aemetis Biogas and Aemetis Advanced Fuels businesses, will review highlights. Andy? Thanks, Eric. With the recent closing of our first $25 million financing that utilized the USDA Renewable Energy for America program, the Aemetis Biogas renewable natural gas project in California is on track to deliver on in-service dates in Q1 2023 for several key projects. We are completing construction and commissioning of five additional dairy digesters. Our contractor has installed 40 miles of biogas pipeline and is now completing feeder pipeline interconnections, as well as testing and commissioning of the final sections. We have completed construction and are now in the final testing for the centralized dairy biogas to RNG upgrading facility and accompanying PG&E gas interconnection unit. The new digesters, pipeline upgrading facility, and utility interconnection are expected to be fully in service in Q1 2023. After receiving CARB LCFS carbon intensity pathways for the RNG, the five new digesters, plus the original two digesters that have been in service since 2020, are expected to generate approximately 200,000 MMBtus per year of RNG. While we await LCFS pathways for credit generation, we plan to store the RNG produced underground to preserve maximum credit value. Due to the high volume of LCFS applications, the CARB review process and approval process can take from six to nine months. We anticipate working closely with CARB staff to help facilitate a timely approval. We are currently in the advanced stages of closing a second $25 million USDA REAP financing. Operationally, we are focused on briskly executing the construction of dairy digesters to fill the Aemetis biogas pipeline and the centralized cleanup facility and interconnection unit. We have signed almost 30 dairy leases or participation agreements and have multiple additional dairies in process. While continued supply chains challenges for items such as compressors or rainy winter weather could temporarily slow down project schedules, our existing backlog of new dairy digesters carries us into 2024. During 2023, we expect to be on track with the dairy digester rollout as described in the five-year plan. To date, Aemetis has been awarded $23 million of grants related to the biogas project from the California Department of Food and Agriculture, the California Energy Commission, Pacific Gas and Electric, and other government agencies for the dairy biogas project and the production of renewable natural gas. Let's briefly discuss progress at our California ethanol plant. As Todd mentioned earlier, we generated a 14% year-over-year increase in revenues from ethanol sales in Q3 2022 compared to Q3 of 2021. However, higher energy and corn prices, combined with volatile rail pricing and ongoing poor railroad operational performance, have increased the delivered cost of corn to about $10 per bushel. Ongoing labor and operational issues with the major rail carriers continue to cast a negative shadow on our industry and the economy as a whole. Additionally, the drought-stricken Mississippi River has disrupted rail operations in the U.S. and is likely to cause ongoing challenges for corn delivery and pricing. On a positive note, continued strong demand and favorable pricing for ethanol in California, steady wet distillers grains pricing, and increasing value for distillers corn oil used as animal feed or for renewable diesel production are helping to offset the increased cost of corn and energy. As I previously outlined, our California ethanol plant is being upgraded to operate using high-efficiency electric motors and pumps powered by low or zero carbon intensity renewable power sources, including our solar microgrid and local renewable electricity. As a strong endorsement of this strategy, Aemetis has been awarded $16 million worth of energy efficiency grants by PG&E and the California Public Utilities Commission and other entities to supplement our own funding to complete these projects. Our goal is to significantly reduce or completely eliminate the use of petroleum-based natural gas at the Keyes Ethanol Plant, and this year we've achieved meaningful steps toward decarbonization. Let me take a moment to provide a few key updates on the Keyes Ethanol Plant projects that are expected to materially increase cash flow when the projects are fully completed. First, the Mitsubishi ZEBREX ethanol dehydration unit has been installed and operated in full production mode for over two months. While we continue to work closely with our partners at Mitsubishi to refine the ongoing operation of the ZEBREX unit, our early results are extremely positive. In August and September, the ZEBREX unit reduced our natural gas usage by over 20%, which when annualized is expected to save Aemetis millions of dollars in energy costs on an annual basis. Just last week, we began construction of our solar microgrid. Working closely with our EPC and technology provider, TotalEnergies, we are installing a $12 million solar array with battery backup for load balancing and emergency operations. This project is supported by an $8 million grant from the California Energy Commission. The solar unit is designed to generate approximately 1.9 MW of zero carbon intensity electric power at low cost for operation of the ethanol plant. We expect to complete the solar installation in Q2 of 2023 to lower energy costs and reduce the carbon intensity of our ethanol. The mechanical vapor recompression, or MVR system, will further reduce petroleum natural gas and steam use and is in the final detail engineering and equipment procurement phase. We expect the MVR system to reduce our fossil natural gas use by approximately 65% at the Keyes plant when the system becomes operational in late 2023. Currently, natural gas cost for the Keyes plant is more than $10 million per year, so an approximate 65% savings in natural gas cost and a significant reduction in ethanol carbon intensity is expected once the MVR system is fully operational. These expected cost and carbon intensity reductions are in addition to the 20% natural gas reduction expected from the ZEBREX dehydration system. One additional item of note, in January we will begin the process of changing ethanol production enzymes that will then allow us to recognize a portion of our ethanol production as cellulosic. This will add additional LCFS value, and with the recent rule announced by the EPA, is expected to qualify the cellulosic gal for valuable D3 RINs worth about $3 per gal and the federal tax credit of $1.01 per gal of cellulosic ethanol. The overall financial impact of this change is expected to be between $6 million and $12 million annually. In summary, operational performance and project milestones for Aemetis Biogas and the ethanol business continue to be on track with the five-year plan. Eric? Thanks, Andy. Let's discuss our Carbon Zero sustainable aviation fuel and renewable diesel project in Riverbank, California. In December 2021, after three years of negotiations with the City of Riverbank and the U.S. Army, Aemetis signed the acquisition of the 125-acre Riverbank Industrial Complex under a sale and lease agreement. The Riverbank site is a former U.S. Army ammunition production facility with 710,000 sq ft of existing manufacturing space, a rail loop with storage space for 120 rail cars on site, a 20 MW electricity substation, and 100% zero carbon intensity renewable power with a direct power line connection to a hydroelectric dam. Earlier this year, Aemetis took operational control of the Riverbank site for construction of our sustainable aviation fuel and renewable diesel plant, as well as the construction of the Riverbank portion of our CO₂ sequestration well project. Aemetis completed the purchase of 24 acres at the Riverbank site and built a heavy equipment access road and well drilling pad for the soil characterization well and the carbon capture and sequestration CO₂ injection wells. We have signed and announced more than $3.8 billion of sales contracts with Delta Air Lines, American Airlines, Japan Airlines, Qantas, and other airlines. We've now completed offtake contracts for about 45 million gal per year of blended sustainable aviation fuel to be produced at the Riverbank plant. Under the sustainable aviation fuel sales agreements, the Neat SAF will be trucked from the Riverbank production plant to the San Francisco Bay Area for blending with jet fuel. The blended SAF will then be delivered via pipeline to the San Francisco Airport for use by airlines. Incentives included in the pending federal legislation, I should say the now passed federal legislation, expand the market for sustainable aviation fuel by allowing a price to airlines that is competitive with petroleum jet fuel. We look forward to completing engineering and permitting in order to begin construction of the plant early next year. In addition, we signed a $3.2 billion renewable diesel sales agreement to deliver 45 million gal per year under a 10-year sales contract with a major travel stop chain for its Northern California locations. Let's review our subsidiary, Aemetis Carbon Capture. In October 2020, the Aemetis ethanol plant in California was identified in a study issued by the Stanford Center for Carbon Capture as one of three ethanol plant CO₂ sources in California that have the highest potential return on investment from building a carbon capture and sequestration facility compared to the oil refineries, cement plants, and natural gas power plants that comprise the 61 largest CO₂ emission sources in California. 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 biogas, ethanol, and jet diesel plants into two sequestration wells, which we plan to drill near our two biofuels plant sites in California. We expect to construct two CO₂ injection wells that each have a minimum of 1 million metric tons per year of injection capacity, with additional CO₂ supplied by other emission sources to sequester a planned total of 2 million metric tons per year of CO₂. The initial phase of construction includes drilling two characterization wells to provide empirical data for the EPA Class VI permit. The injection wells will then be drilled at the same site after receiving EPA and other permits. We are currently in the engineering and permitting process for the two characterization wells, with an expectation that we will drill the first characterization well at the Riverbank site. The direct pay feature of the Inflation Reduction Act provides a federal tax credit of $85 per metric ton of CO₂ as a cash refund to Aemetis each year for the first five years of production. The planned 2 million metric tons of CO₂ per year from the Aemetis Carbon Capture project would generate an expected $170 million per year from the federal direct pay tax credit, as well as an estimated $400 million per year at a projected $200 per ton of sequestered CO₂ from the Low Carbon Fuel Standard. We believe the fixed amount of $850 million provided by the direct pay funding over the first five years of the project should adequately support funding the estimated $250 million capital cost of the two injection wells and related equipment. In summary, Aemetis is expanding a diversified portfolio of negative carbon intensity projects, dairy renewable natural gas, biodiesel in India, sustainable aviation and renewable diesel fuel, low carbon ethanol using zero carbon intensity electricity, renewable hydrogen, and CO₂ sequestration. All of these projects are synergistic and create what we refer to as a circular bioeconomy within Aemetis, in which we use byproducts and waste products from our own facilities and local areas as feedstock to produce low and negative carbon intensity renewable fuels. Our company's values include a long-term commitment to building value for shareholders, the empowerment of 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 speakerphone to provide optimum sound quality. Once again, please press star one if you have any questions, and please hold while we poll for questions. The first question is coming from Derrick Whitfield from Stifel. Derrick, your line is live. Please proceed with your question. Thanks, good morning, Eric and team. Thank you, Derrick. Morning. Morning. First and foremost, congratulations on closing the USDA REAP. I know it was a lengthy process for you guys and complex based on our discussions with industry. Perhaps for the benefit of investors, could you share with us some of the lessons learned from the first loan, and then your expectations on timing for the next few? It seems to us if that process is truly ironed out, financing the expansion of the biogas business is significantly de-risked. Finally, if I could ask, maybe if you could also touch on financing plans and the leverage you have at your disposal for the Riverbank RDA SAF facility. Good. We look at the first round that we closed of $25 million as being a one-time education process, both of Aemetis as well as frankly introducing the project to the commercial lender as well as the USDA staff. What we're doing now is just repeating the project documents, but not really doing a reeducation of the array of environmental consultants and other kind of feasibility study consultants, all the people that work on our side, as well as the USDA, who's now very familiar with our project, and we don't have to replicate that process for sure. The commercial lender, who's very familiar with our entire project now with the 40 mi pipeline and other kind of things that are sort of one-time learning opportunities. The paperwork itself is largely just changing locations and amounts. It's not really changing the structure of our documents at all. These are special purpose entities that are set up that we borrow $25 million, which is the max under the REAP program per entity. We contribute about $8 million of equity. This one, we contribute about $11 million of equity to the SPV in form of assets we've already built. We're ahead of this equity investment significantly. We have about $53 million of both our preferred equity that's been invested as well as the grants that are in the project. That's a whole lot of SPVs at only $8 million of equity required per SPV. An SPV is $25 million of additional capital. As Andy mentioned, we're working on closing the second funding here in the next month or two, and then we'll do the third thereafter, and a fourth and a fifth. It's just something we've already put the equity in. We're ahead of it on the construction and signing up dairies. I would say that the one item that is necessary for any developer looking at this project is that one-time education is a lengthy process. The environmental issues, just going up through USDA's committee process to the federal level, all requires a one-time education. In our case, we started in January 2021, and it closed October 2022. You have to have a long-term commitment, and the USDA definitely has long-term commitment. Our bank has a long-term commitment, and Aemetis proved that we have a long-term commitment. Now that we are over that first learning cycle, I think we'll be looking at what we're doing now, which is only a few months between fundings. Regarding SAF, we have a signed $125 million Biorefinery Assistance Program 9003 document with the USDA. We are already in the process of completing our EPC agreement, which is a full wrap EPC agreement with a $2 billion contractor. The authority to construct it, so the necessary permits to be able to break ground. Those are the two documents necessary for us to then go back and wrap up the completion of our project financing. In addition to the USDA, the California Municipal Tax-Exempt Bond market is a very attractive market for us with very low interest rates. The Department of Energy has been very proactive in supporting sustainable aviation projects. I'll be presenting November 9th in Washington, D.C. My panel has a couple of airlines on the panel. Jigar Shah, the head of the Loan Programs Office at the DOE, is actually introducing our panel, and it's moderated by Kate Gordon, who's the White House head of SAF and related fuels issues. We have a strategic interest from the White House as well as the DOE in our project. Then lastly, it's frankly just monetizing this Inflation Reduction Act. When you look at the value of $1 billion over 10 years in these various incentives, monetizing that into debt and equity instruments is one of the great opportunities we have. We have not one or two open markets. I would say we have four open markets for our growth of SAF. Right now we're doing the simplest ones, and certainly the USDA having closed with only a 6.2% interest rate and a 20-year amortization is a very, very attractive partner for us in our growth. But we're in a difficult debt environment. I don't wanna in any way make that sound like it's easy. For us to complete a transaction in this market and have another transaction closing in this market at very attractive interest rates and long-term amortizations, that's key. If it's a seven-year amortization, you got troubles. A 20-year amortization is fantastic. Then we're proving that we can deliver on those kind of financings. Eric, just to clarify on the USDA loan, if I recall, that comprised a 45 million gal facility and is expandable. Am I thinking about that correctly? That's correct. We're building a 90 million gal facility, so your math is accurate. That we'll be doing a larger transaction than the original, 'cause that was only for the. We were originally gonna do this in two phases, but the amount of interest from our customers caused us to actually double the capacity and build it in just one phase rather than two phases. As my follow-up regarding India, it was certainly nice to see a contribution from the business, even if it was only for a couple of weeks. Could you comment on your expectation for biodiesel sales in Q4 and your view on when refined tallow production could start to show up in your financials and how that business could grow over the coming years? Q4 is already one-third done, and as I described, the orders we got for August and September got shifted to the middle of September and into October. We have very good visibility on our October deliveries, they are done. We announced a total revenues from all sources of $41 million, and we have shipped a majority of that already. We still have two months to go in the quarter. The quarter is looking very strong from a revenues perspective. We are waiting for the oil marketing companies who were expected to come out with a November tender so we could just keep on shipping, right? We're expecting that to happen in November, and that will materially increase the Q4 revenues that we've already booked. We are seeing, as I mentioned, sort of a burdensome procurement process, but they are definitely making progress and continuing to move forward and something that will allow us to run our plant at full capacity. I think as the OMCs learn how to do this, they'll be more proficient at it, and we won't see this sort of a start-stop situation that we see now with a couple of weeks of delays coming in. The tallow business is a facility that's already completely constructed and capable of operating. We're currently just running our offtake agreement negotiations. There are approximately five renewable diesel companies in the United States that are currently under discussion. We're working on getting that worked out in the first quarter next year and begin shipments. That's great. Thanks for your time. Thank you. Thank you. The next question is coming from Jordan Levy from Truist Securities. Jordan, your line is live. Please proceed with your question. Thanks so much for taking my questions. Maybe starting on the biogas side, exciting announcement about the pref deal there. I think it makes a lot of sense given the activity in the market. Could you just provide a little more detail on the financing for that transaction and how we should expect that to kind of play out from a timing perspective? The financing of the buyout or the financing of the underlying project? Yeah. Yeah, the buyout. Yeah. We have a debt instrument opportunity, and we have an equity instrument opportunity. We have a number of large counterparties starting with oil companies, but going to strategic trading and other companies who are very interested in that preferred. This is -426 carbon intensity product. It's a dairy renewable natural gas. It's not +30 landfill natural gas. I would actually say we're just managing which relationship we want to have, maybe even extend into other factors of our business because our counterparties all have strong interests in sustainable aviation fuel and renewable diesel, as well as even low carbon ethanol. We've been spending a lot of time building long-term relationships, and I think this preferred is really the first opportunity people have to come in in a meaningful way. I expect it'll be potentially 100% preferred structure, maybe 100% debt structure. Either way, it's going to be very accretive to our interests in the Biogas subsidiary. What we're doing is we're cashing in on the comparables of that OPAL and then Archaea created for us. This is the first opportunity for institutional, operational companies to get into this business in a meaningful way with Aemetis. Got you. That makes sense. Maybe bouncing over to the SAF side, given the provision in the IRA for sustainable aviation fuel, I think it might be helpful if you could remind us how the offtake agreements you've signed for SAF and renewable diesel are generally priced and how the federal and state incentives flow through those. The structure is a clean structure in which until the fuel passes the flange into the customer's tank, any tax credits, Low Carbon Fuel Standard, California credits, federal Renewable Fuel Standard credits, other incentives, even ones in the future we don't even know about, all 100% and they are to the account of Aemetis. Oh, I forgot. The actual value of the molecule that we're selling, the $3 plus $1 per gal, all that is to Aemetis' account. We receive approximately a 10% premium above the price of jet fuel. The value of this contract structure for our customer is they can hedge jet fuel, add 10% as the premium, but they get all of the airline incentives, starting with CORSIA, C-O-R-S-I-A, which is the airlines trading among themselves. If they're, let's say, somebody has access to SAF from Aemetis, and they have more than what their CORSIA requirements are, they can sell those credits to other airlines. In so doing, that 10% increase, let's call it $0.35 per gal. For every 10 million gal, it's about $3 million or more being paid to Aemetis, can be offset by the sale of credits by our customer to other companies. There's a mechanism which they're paying as a premium, but then they have their own trading markets, some voluntary, some not so voluntary, that, for example, avoiding penalties in Europe, that can help them actually get back to the price of jet fuel. At the end of the process, it's possible that our customers actually are largely paying the price of jet fuel, which is fully hedgeable and of course, extremely attractive to have scope one, scope two, and even scope three emissions reduced from buying SAF from us. Very helpful. Thanks for taking my questions, Eric. Sure. Thank you, Jordan. Thank you. The next question is coming from Amit Dayal from H.C. Wainwright. Amit, your line is live. You may proceed with your question. The 180 million gal per month, is that for the kind of a mandate that is out there, and they're trying to, you know, just kind of set some, yeah. In schedule some or is, you know, target that these folks are working with- Amit, we're getting about 25% of your question, but the part that I got was whether the customers in India will continue to have the 100+ million gal per month of demand. They're seeking a 1.25 billion per year supply of biodiesel in India, which is a 5% blend of the 25 billion gal of diesel in the country. There is a tax passed into law earlier this year that is currently scheduled to go into place in April of 2023, so approximately five months from now, that actually taxes diesel an additional $0.10 per gal equivalent if it's not blended with biodiesel. If you blended a 5% blend, that is equal to $2 per gal of biodiesel, additional price that could be paid to us in order to avoid payment of that $0.10 per gal tax. We do perceive that there will be this ongoing demand by oil marketing companies as well as the private refiners in India to not have to pay a $0.10 per diesel gal penalty for failure to blend biodiesel at 5%. That will help this be a much smoother market, especially with a cost-plus structure and procurement by the OMCs. Thank you. I lost my other question. I would like to hear that just as. You know, these seven are completed, Q1 next year. Do you plan to do with the next set of digesters? Yeah. As Andy described, end of this year, we'll have seven digesters in the commissioning and testing process expected to be what's known as in service. We accept it from our contractor as meeting performance specifications in the first quarter of next year. We have an additional five that are already in the process of construction, permitting, environmental approvals, that sort of thing. We're not waiting until these are in service in Q1 before we do the next five. We're actually in the process of those next five. What's really important for all of us to recognize, though, is a long lead time item here was the gas utility interconnection unit with Pacific Gas and Electric, which is in commissioning and testing now and expected to be in service in the first quarter, and the centralized gas cleanup and the 40 mi pipeline. Those are the long lead time items. It took us probably three years to get the PG&E unit that had to be built by them, permitted by them, you know, managed by them. It's their project. We just put up the many millions of dollars to build it, but they actually had to do it. That's behind us. What we are doing now is building rectangular dirt football field-sized digesters in these locations that have already been signed with customers. It's a much more rapid process with the same contractors doing the same thing they've already done seven times. Our ability to accelerate now, especially with the financing relationship with USDA working smoothly, I think is going to meet or exceed expectations in 2023. Thank you. The next question is coming from Matthew Blair from TPH. Matthew, your line is live. Hey. Hey, Eric. Congrats on getting the India Biodiesel program going again. Could you share the EBIT margin on those gal in Q3? You know, I know it's just going for a couple of weeks. Is that EBIT margin gonna be a good run rate for Q4 and beyond? We're operating under the same contract for the Q4 deliveries we've already completed. That was the contract that was slated for August and September got pushed back to 15th September through the end of October. Yes, it's the same margin. You could just apply the number that was applied there, $11 million for the quarter, $2.8 million. That's all linear to what we continue to ship in October. We have approximately 1.5 times as much revenue in October as what we saw in the two weeks in September. Easy math to do there. We do have winter specifications. In the winter, we use a different feedstock in order to have a lower cold flow plugging point, which is the ability to handle colder weather. We do expect lower margins in the wintertime. We have, however, expectation that we'll see the revenue flow continue, and by the time we're in mid-February, we're out of the winter specs. India is a very warm country, and many of our companies and our customers start actually buying early on that. There's just a. It's actually the procurement process is our primary issue in India. Just moving smoothly to an ongoing process of every two months, getting purchase orders on time is really the only issue. It's not really production for us, or even the winter specs. It's really getting the OMCs to deliver on these tender offers. Great. Thanks. Then on the RNG side, if I heard you correctly, the long-term target is 60 dairies and 1.65 million MMBtu of dairy RNG production. It sounds like you have seven digesters running by the end of the year with another five under construction. Do you have any more digesters that you've won, you know, projects that you've won that you haven't started construction on yet? I'm just trying to get a sense of how far along are you on the 60 digester target? Andy commented we have about 30 signed. There's what's called participation agreement. We have 30 signed. We have additional working. Right now, actually, it's the opposite frustration. Our dairies are signing and then saying, "But wait a minute, you can't start building this thing for, you know, mid-2024. You're 18 months plus out before you're gonna be building this thing. Can't you guys hurry this thing up?" We are targeting 66 in our five-year plan that was published earlier this year. We'll be updating that in February. About half of that is already signed in some phase of these agreements, and we're rapidly looking to fill out the other half of it over the next couple years. Again, the frustrations that, by the dairymen is exactly the opposite, which is, "Wait a minute, it's a five-year plan. That means I gotta wait four years before you're gonna build this thing. Can't you guys hurry up?" We have every intention of doing so. Just to clarify the numbers, the seven operating in final commission and test go in service in Q1. As in-service run rates, we expect approximately 200,000 MMBtu per year. That would then be incremented by an additional five plus whatever we start next year. Our five-year plan has an annual number, and that annual number would be seven at the end of this year, and then it increases next year. Got it. Thank you very much. Yeah. Thank you, Matt. Thank you. The next question is coming from Dave Storms from Stonegate. Dave, your line is live. Please proceed with your question. Perfect. Thanks for taking my question. Just touching back on the current credit environment, how are you seeing the being able to get on things like the USDA REAP program as either a competitive advantage, against, you know, industry peers or, conversely, you know, again, that same credit environment being maybe an issue for end users, going forward? We have credits and then we have loan guarantees. We use the loan guarantee process to build the project, and then the tax credits, specifically production tax credits and investment tax credits, basically reimburse us for the cost of construction. In biogas, we're eligible for up to a 50% investment tax credit. As we make investments to build assets, we then can submit for up to a 50% tax credit for that one-time investment of building the asset. On a go-forward basis, we then get production tax credits for producing actual fuels. Our ethanol plant under the Clean Fuels Initiative is expected to be eligible for some tax credits. Certainly biogas, as a low carbon fuel, has potential for that sustainable aviation fuel, et cetera. These are production tax credits. Then in carbon sequestration we have a different set of tax credits with Direct Pay features and the like. Now, those tax credits are separate from the loan guarantees. Loan guarantees basically make our debt much less expensive, and far more important than that is the amount of time we have to repay it. Most commercial banks today would be talking five to seven year term. That's almost impossible to build a biofuels facility and have it economic that you pay back all your debt in five to seven years. A 20-year term and a year or so during construction and not even have to pay any principal is an extremely attractive structure for building these assets. That's exactly what we closed with the USDA and the Rural Energy for America Program, and that's what we're gonna continue to do in multiple phases of that program. That's perfect. Thank you. Thank you, Dave. Thank you once again, ladies and gentlemen. If there were any other questions, please press star one on your phone to enter the Q&A queue. The next question is coming from Edward Woo from Ascendiant Capital. Edward, your line is live. Yeah. Please proceed with your question. Yeah. Congratulations. My question is, what is your outlook for oil price and gasoline prices and its impact on demand for ethanol? We think that oil prices are largely under the control of OPEC+, which means OPEC+ Russia. There are only a couple guys that have to cooperate to make that happen, and they're sitting in Saudi Arabia and in Russia largely. They have expressed deep concern about letting the price of crude oil fall below $80. They said that two weeks ago when they told Joe Biden, "Nope, I'm not gonna increase production. I'm going to actually decrease production by 2 million barrels per day in order to drive the price of crude oil up." It had fallen down into late 70s, and they wanted to push it up above 85. I think we're in an environment in which as long as those entities are reasonably cooperative, we've got $80 plus crude oil prices. In the United States we have refining capacity. Remember, it's not crude oil that you buy at the pump. It's actually gasoline, diesel, or sustainable aviation fuels. You have to add the profit of the refineries. Well, in California alone, we went from 22- 15 refineries. Refineries have tremendous pricing power, as you see in the, I think it was 500% increase in profit, profitability of the major oil companies announced here in the last week or two. That oil refining margin is an additional price at the pump, which is comparable to what is actually relevant to selling our biofuel. Put in crude oil prices at $80 or higher and then high refining margins, according to the CEO of Chevron, for at least three years, and that's a relatively stable oil pricing model for us to produce against. Then, of course, with the Inflation Reduction Act, we're getting encouraged to make lower and lower carbon fuels, which is the point of those incentives is to make dramatically lower carbon intensity fuels compared to these petroleum products. Great. Thanks for answering my questions, and I wish you guys good luck. Thank you. Thank you. We'll talk soon. Thank you. There are no further questions at this time. I would like to turn the floor back over to management for closing comments. Perfect. Thank you. Thanks for Aemetis shareholders, analysts, and others that joined us today. Please review the company presentation and the investor presentation that's posted on the homepage of the Aemetis website. We look forward to talking with you about participating in the growth opportunities at Aemetis. 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 audio version of this Aemetis earnings review and business update. Paul? This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.