Welcome to the Aemetis Fourth Quarter and Year-End 2024 Earnings Review Conference Call. At this time, all participants are in a listen-only mode. A 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, the Executive Vice President and Chief Financial Officer of Aemetis. Mr. Waltz, you may begin. Thank you, Tom. Welcome to the Aemetis Fourth Quarter and Year-End 2024 Earnings Review Conference Call. Joining us for the call today is Eric McAfee, the Founder, Chairman, and CEO of Aemetis, and Andy Foster, the President of Aemetis Advanced Fuels. We suggest visiting our website at aemetis.com to review today's earnings press release, the Aemetis corporate and investor presentations, filings with the Securities and Exchange Commission, recent press releases, and previous earnings conference calls. 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 limitations, statements with respect to our future stock performance plans, opportunities, and expectations with respect to financing activity and the execution of our business plans. 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 the SEC EDGAR system and on our own company website. Our discussions on this call will include a review of non-GAAP measures as a supplement to the financial results based on GAAP because we believe these non-GAAP measures serve as a proxy for our company's sources and uses of cash. A reconciliation of the non-GAAP measures to the most directly comparable GAAP measures is included in today's earnings release. Adjusted EBITDA is defined as net income or loss plus, to the extent deducted in calculating such net income, interest and amortization expense, gain on debt extinguishment, USDA cash grants, income tax benefit or expense, intangible and other amortization expense, accretion expense, depreciation expense, loss on asset disposal, and share-based compensation expense. Let's review the financial results for the year ended December 31, 2024. Revenues were $268 million for the 12 months ended December 31, 2024, compared to $187 million for 2023, with all three segments reporting increases. Specifically, California Ethanol increased by $57.7 million from operating during the full year. India Biodiesel increased $15.7 million from stronger oil marketing company tender delivery volumes, and California Renewable Natural Gas increased $7.6 million from increased production, stronger sales of RINs, and sales of LCFS credits. Cost of goods sold increased from $184.7 million during the 12 months ended December 31, 2023, to $268.2 million during the same period in 2024, in keeping with the change in revenue for each of the segments. Gross loss for the 12 months ended December 31, 2024, was $580,000 compared to a gross profit of $2 million during the same period in 2023. Our dairy renewable natural gas segment accounted for $5.4 million of gross profit, principally from the sale of environmental attributes for the year ended December 31, 2024. Selling, general and administrative expenses remained constant at $39.8 million during the 12 months ended December 31, 2024, compared to $39.4 million during the same period in 2023. Operating loss was $40.4 million for the 12 months ended December 31, 2024, compared to an operating loss of $37.4 million for the same period in 2023. Interest expense was $59.3 million during the year ended December 31, 2024, which was a $5.5 million increase from interest expense of $64.8 million during the year ended December 31, 2023. Income tax benefit of $10.8 million during 2024 and $53.7 million during 2023 represent tax credit sales of $12.3 million and $55 million, respectively. Net loss was $87.5 million for the 12 months ended December 31, 2024, compared to a net loss of $46.4 million during the same period in 2023. Cash at the end of the fourth quarter of 2024 was $898,000 compared to $2.7 million on December 31, 2023. Capital expenditures for carbon intensity reduction projects and the expansion of biogas production capacity were $20.3 million for 2024 as our engineering and construction teams moved forward with low-carbon production capacity and energy efficiency projects. Now, I'd like to introduce the Founder, Chairman, and Chief Executive Officer of Aemetis, Eric McAfee, for a business update. Thanks, Todd. Aemetis benefits from public policy that supports domestic energy producers that grow markets for agricultural and waste products. The strong year-over-year growth that we achieved in 2024 in each of our businesses in biogas, ethanol, and biodiesel is expected to be further supported by federal and state policies that are being implemented this year. The President has repeatedly stated his strong support of ethanol and agricultural-based biofuels in executive orders and public statements, so we are hopeful that the new administration will continue to support domestically produced renewable fuels that support energy independence. Let's review some of the key government policy issues that have had a significant impact on our businesses, and we expect will be strongly supportive of our continued growth. First, the California LCFS credits. After four years of policy development, amendments to California's Low-Carbon Fuel Standard were approved by the California Air Resources Board on November 8, 2024, setting 20 years of increasing mandates for low-carbon fuels in California. The LCFS amendments mandate a 9% decrease in carbon intensity for fuels in 2025 and have an ongoing automatic adjustment mechanism to provide confidence in a higher price for LCFS credits in order to attract debt and equity investments in low-emission transportation fuels, infrastructure, and vehicles. In anticipation of the implementation of the new mandates, the price of LCFS credits increased from $44 last year to $75 by February 2025. A surprise delay occurred, however. Recently, the implementation of the amended LCFS was delayed by the California Office of Administrative Law due to a request to CARB to provide clarity and certain new language in the LCFS amendments. This unexpected delay in implementation of the LCFS amendment caused a rapid 30% decrease in the price of LCFS credits as the market waits for final adoption of the LCFS amendments to occur. We expect that the process of final adoption of the LCFS amendments will occur later this year. LCFS prices should increase thereafter as the 9% reduction in 2025 will take effect, as will a 20% limitation on the use of crop-based feedstocks for renewable diesel. Additionally, slower than expected hydrogen truck and electric vehicle adoption anticipated by CARB is expected to result in a rapid decline in the LCFS credit bank during 2025 and 2026. By 2027, the implementation of the LCFS amendments is designed to reduce the 32 million credits currently in the LCFS credit bank to zero. According to CARB's own estimate, the LCFS credit price is expected to increase significantly higher, eventually approaching $200 per ton. Aemetis Biogas, ethanol, carbon sequestration, and other businesses are designed to benefit from an increased LCFS credit price as we produce LCFS credits through the production of low-carbon intensity renewable fuels. To quantify the impact, Aemetis renewable natural gas generates about 40% of the price of an LCFS credit per MMBTU of production. A $200 LCFS price per ton equals about $80 of LCFS credit value per MMBTU once our provisional pathways are in place. At an average LCFS price of $150 per ton, Aemetis Biogas would generate credits worth $60 million per year from the sale of 1 million MMBTU of dairy RNG. Second, the federal renewable fuel standard. In addition to LCFS credits, the sale of renewable natural gas generates D3 RINs with a value from $28-$40 per MMBTU. Combined with the LCFS credit, this represents up to $120 per MMBTU from just these two credits alone. Third, the federal Section 45Z production tax credit, which started on January 1st, 2025. The U.S. Treasury released tax guidance in January 2025 that we are now using for the planned sale of tax credits for both our Keyes Ethanol Plant and our renewable natural gas businesses. We expect further guidance from Treasury will be issued this year to assist in the calculation of the tax credits. Fourth, federal Section 48 investment tax credits. After selling $63 million of investment tax credits in September 2023, we completed the sale of additional investment tax credits generated by the Aemetis Biogas projects and our Keyes plant solar project in December 2024 and February of this year. We received net cash proceeds of about $11 million in January and $6 million in February 2025 for a total of $17 million of cash received from investment tax credits so far this year. We expect the same buyer to purchase additional federal investment tax credits this year and potentially also purchase production tax credits. Fifth, 15% ethanol blend approvals. Two weeks ago, the U.S. EPA approved the year-round sale of gasoline containing up to 15% ethanol, known as E15, for eight Midwestern states, with an indication that all 49 states other than California should be approved this year. Broad use of E15 would increase the size of the U.S. ethanol market by up to 50%. California is the only state that sets its own fuel blends, and currently, E15 is not authorized. However, California Governor Newsom issued a letter instructing CARB to complete the necessary regulatory work to be able to approve E15 in California as soon as possible, thereby reducing the state's current 90% petroleum gasoline mandate that drives higher gasoline prices for consumers and businesses. A 15% ethanol blend in California is projected to decrease gasoline prices by $0.20 per gal, saving drivers about $400 per year in fuel costs equal to $2.7 billion per year statewide, according to a UC Berkeley and Naval Academy study. E15 approval in California would increase the market for ethanol by more than 600 million gal per year, and a 15% ethanol blend nationwide would enable the ethanol industry to grow revenues by up to 50% to more than 20 billion gal per year. Combined, the ongoing implementation of these five policies directly and positively impacts our business by significantly increasing the value of our fuels and by expanding the markets that we supply. Let's review each of our businesses. In the India biofuels business, we completed deliveries of $112 million during the one-year period ending September 2024, driven by biodiesel sales to the three government-owned oil marketing companies, or OMCs, under a cost-plus contract structure. We completed these contracts with excellent production and delivery performance. The positive impact of cost-plus pricing that has been used by the OMCs to purchase biodiesel is expected to continue for the foreseeable future. Our India business has generated positive EBITDA in the past and has funded its own operations and capacity growth from these OMC contracts. Unfortunately, the price of feedstock used in the OMC pricing formula increased significantly in Q4 2024, and OMCs delayed taking deliveries of biodiesel. After a six-month period of negotiations, OMCs are expected to issue a new tender for biodiesel and begin taking deliveries in Q2 2025. This past July, our new Managing Director of the India business joined the company after serving as the Chief Executive Officer of the GE joint venture in India to build renewable power plants. We have signed an employment agreement with an outstanding professional with recent IPO experience who will serve as our Chief Financial Officer beginning in June 2025. We have signed a lease to move our India headquarters into a newly built office building in Hyderabad next month to support our expanding management team for the operation of multiple plant sites and new products. The timing of the planned IPO is currently estimated for late 2025 or the first half of 2026 due to the delay in OMC deliveries. We expect to benefit from a renewed government commitment to biodiesel blending and new OMC orders supporting renewed retail and institutional investor interest in renewable biodiesel later this year. Andy Foster, President of Aemetis Advanced Fuels, will now review our North American businesses. Andy? Thanks, Eric. In the Aemetis Biogas business, we continue to grow the number of dairies and digesters to reach an expected 550,000 MMBTU per year of production capacity in 2025. Aemetis Biogas plans to expand our footprint to 26 dairies operating or under construction by the end of 2025, increasing production capacity to 1 million MMBTU per year in 2026. Our existing projects are funded by 20-year loans guaranteed by the USDA Rural Energy for America, or REAP, program. We have received the draft USDA conditional commitment for the next $25 million Rural Energy for America loan. An additional $50 million of USDA guaranteed funding is in process with expected closings this year for a total of $75 million of new USDA guaranteed long-term financing for biogas digester construction. Our LCFS provisional pathways for seven dairies have been completed and have completed the third-party verification process and are now in the final review and approval stage at CARB. We expect these pathways to be approved in March or April. In the event that the final approval is received in April instead of this month, we would begin to show the increased revenues and cash receipts from LCFS pathway approval in Q3 of 2025. For the Aemetis ethanol business, the eventual approval of an E15 blend in California, as well as at the federal level, is expected to have a positive impact on ethanol industry margins as retailers seek to provide lower-cost fuel to consumers and to significantly expand the market demand for ethanol in California. A major step in improving our cash flow and energy efficiency at the Keyes plant is the installation of a mechanical vapor recompression system, or MVR. We have completed detailed engineering and have begun equipment procurement and fabrication off-site. Over the past year, we have also completed tie-ins and other plant modifications that will accelerate the installation process, minimizing plant operation interruptions during the construction period. The MVR system is designed to reduce fossil natural gas use by 80% at the Keyes plant and increase cash flow by up to $35 million annually, depending on the LCFS credit price and 45Z tax credits when we begin operating the system in 2026. The MVR energy efficiency project is expected to cost approximately $30 million and has been awarded about $20 million in grants and tax credits from the CEC, PG&E, and the U.S. Department of Energy and Treasury. Our Aemetis Carbon Capture subsidiary has received California state approval to drill a characterization well. The first phase of drilling and installation of the conductor pipe for the characterization well was completed late last year. We plan to use the data from the characterization well to obtain a federal Class VI sequestration well permit and then construct a CO2 injection well and compression system at our Riverbank site to sequester approximately 1.4 million tons of CO2 per year. CO2 sequestration has strong support from the oil and gas industry, so we expect the final 45Q federal tax credit to be supported this year and the EPA Class VI well approval process to be faster to obtain than under the prior administration. In the development of our Aemetis sustainable aviation fuel and renewable diesel business, during 2024, we received authority to construct air permits for our planned 90 million gal per year SAF and RD plant to be built in Riverbank, California. When operated to produce only sustainable aviation fuel, the design capacity of the plant is about 78 million gal per year of SAF. With the expanding demand for SAF and with a limited supply, we continue to discuss the use of innovative pricing structures with our airline customers to accelerate the financing, construction, and operation of our SAF plant. A key issue for SAF production is the federal 45Z production tax credit, which replaces the former blender's tax credit. Further clarification and confirmation of the calculation of the 45Z revenues will be needed to support the financing of the SAF /RD plant. Additionally, California regulators need to step up their efforts to enact strong SAF mandates by including this fuel in the LCFS and setting volumetric requirements. Most major airlines have expressed support for adopting SAF and are looking for additional regulatory support from the EPA and states to move investments forward to expand production capacity. Eric? Thanks, Andy. Appreciate that. In summary, all five Aemetis business segments are synergistic and create what we refer to as a circular bioeconomy. We are very pleased with the approval of the updated low-carbon fuel standard in California and look forward to its formal implementation, as well as the expected approval of 15% ethanol blends to reduce gasoline prices at the pump and to expand domestic markets for agricultural and waste products. Continued progress on implementing federal 45Q and 45Z tax credits will drive new investment and job creation as we continue to build new production of natural gas from dairy waste, ethanol from agricultural products, SAF and RD renewable diesel, as well as the sequestration of CO2. We continue to work toward an IPO of the growing India biodiesel business, though our pace was slowed by the delay in biodiesel deliveries to oil marketing companies and now is expected to benefit from a renewed commitment to biodiesel blending by the India government and OMCs. Our company's values include a long-term commitment to building value for our stockholders, 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 some questions from our call participants. Thank you, Mr. McAfee. We will now be conducting a question-and-answer session. If you would like to join the queue to ask a question at this time, please press star one on your telephone keypad. We do ask if listening on speakerphone today that you pick up your handset while asking your question to provide optimal sound quality. Once again, please press star one on your telephone keypad at this time if you wish to join the queue to ask a question. Please hold a moment while we pull for questions. The first question today is coming from Jordan Levy from Truist Securities. Jordan, your line is live. Please go ahead. Thanks for all the details. Eric, maybe if you could just talk to your confidence levels around specifically the REAP financing going forward, given some of the pauses and reductions in government spending under this new administration. We have a high degree of confidence in REAP. We've been very close to the USDA staff, and we expect approvals this month for their next phase. We have two right behind it. There has been a freezing of grants and loans that was throughout the entire government. As they have gone through and looked at every program and, frankly, looked at every single grant and loan, we have been informed that the REAP program, the Business and Industry program, and the 9003 program have all been released for further transactional activity. We've received direct information that we're moving forward this month on our next $25 million REAP loan. Got it. Thanks for that. Just as a follow-up over to Riverbank, I recognize 45Z clarification for SAF is pretty critical to getting financing on that plant and the economics more broadly. I just wanted to get a sense of how you're thinking about, one, how much has been spent from a CapEx perspective there thus far, and then two, if we do get to kind of the end of the year or beginning of next year or however long, and we haven't gotten that clarification from the federal administrations, what's the plan kind of going forward as it relates to that project? Because of the way that the accounting is recognized for the capitalization, there are two different capitalization numbers. One is for project financing, and the other is that our internal accounting is very conservative, so we expense our investments there largely. The GAAP recognition and the project financing recognition are rather significantly different. We do not expect that we are going to be reflecting the entire amount on our GAAP books of what we have invested. About $43 million is what we show in our project financing. Our GAAP books are more conservative because you have to be within a certain short period of time of construction before we can start capitalizing some of these assets. The 45Z plus, as Andy mentioned, California's LCFS, including jet fuel, would be two significant drivers. The inclusion of jet fuel in the LCFS would cause an increase in obligated party amounts. There was actually a 2% goal put in the LCFS amendment last year. It came out late in the process, and they have discussed the process of putting it back in. We think there are several different market drivers, mandates for the physical volumes plus mandates at the federal level for the 45Z production tax credit to be adopted and clarified and the calculation come out in Treasury guidance. We think it will take most of this year for that kind of clarification to occur. We do not think most SAF projects are moving forward, certainly at the pace that we were seeing in 2021, 2022, and 2023 as we go through this transition. Thank you, Eric. Sure. Thank you. Thank you. Thank you. Your next question is from Sameer Joshi with H.C. Wainwright. Please proceed with your question. Hey, guys. Thanks for taking my questions. Eric, do you have any insight into why the OAL asked for revisions late in the game and not earlier on? What was the process like, and what are their concerns? It seems like there's at least going to be a 120-day delay because of this. Just wanted to see what your view is. Oh, the OAL process, Office of Administrative Law. Legal. Administrative Law. The LCFS is a complicated piece of legislation. The surprise was not that it is complicated and needs some clarification. That was no surprise to anybody. The surprise is that that was not resolved prior to the date in which the OAL had to consent to the publishing of the amendment. Since that delay could take another comment period, actually, I would say at this point, we expect it to include another 15-30 day comment period. It is not something that is going to get fixed next week. This will probably be a couple of months of internal process to get this fixed. Lastly, there is no endpoint. They could take three, four, five, six months. That is one of the things that caused the LCFS prices to go down is there is no guaranteed time period in which this gets fixed. That being said, we know from personal experience there's a tremendous amount of staff time being invested at CARB to move this along and get it done as quickly as possible. Did you have any other comments? No, I would just—this is Andy—I would just add to that that I think this is an opportunity for the governor to show some leadership stepping in. This is sort of, I think, an embarrassing handoff between two state agencies that should have been sort of resolved before it happened. I'm being a little harsh, but the stakes are high for the stakeholders in all of this. We are hopeful. I know in my communication with CARB, it seems that that's all the staff is working on instead of processing applications for pathways. We are hoping that the governor will step in, and the governor's office at least will step in and provide some strong leadership to get this resolved because this has been going on for many years and probably is something that should have been worked out in the conference room before it got public. Our hope is that the heat is on and they realize the stakes that are involved in getting this resolved. Understood. Thanks for that color. On the India biodiesel, I know there were some air quality permits that were received late February, which have allowed you to restart the plant. Are you restarting and building inventory, or are you waiting for the OMCs to renew or have a new round of cost-plus awards for you? Are you operating with or waiting? I'll separate that into two parts. One is our production. The second was the OMC tender process. Today, news in India indicates that they will be issuing a new tender, that the new tender actually was papered today. It is in the public domain today. The time period for the allocation is very short. March 20 is the end of the tendering process, and they're expecting shipments in April under this new tender. Regarding our production, we queued up production under the previous tender, and so we're sitting on a significant amount of inventory, which will not require that we have to operate the plant or to get initial shipments started. On the third point about the local pollution control district, this happened to us in the past. This cycle was very similar to the previous cycle, and we engaged with a wide variety of government leaders in resolving their concerns about emissions. I can state that I do not believe our emissions were actually what led to the shutdown notice because we had shut down our plant a month earlier. We shut down in December. The notice was in mid-January, and we believe it was other producers in the local area where there's a wide variety of edible oil and other businesses that use similar feedstocks. That was a part of resolving the issue, that we'd been shut down for 30 days when they gave us a notice of shutdown. It was one of those ironic government issues that we got resolved. Because of the OMC delivery schedule, it had virtually no impact on our production. Understood. Thanks for that. Just one more. I know you did touch upon it in your prepared remarks, the India IPO. Do you expect this to happen during 2025, or should we think of this as an early 2026 event? It's an IPO. We know the market actually controls it. We expect to have our process completed so we can complete it in 2025. As every IPO is discussed, it's always discussed, subject to market conditions. We will be ready to go. We'll be then looking at the market conditions. If we see strong support for biodiesel blending, even in an otherwise not attractive market, we can get a very solid IPO done because of the size of this growth industry. I think that our job is to get the paperwork done and be ready to go. If we delay it for a quarter or two, that'll be purely because we see better market conditions ahead. Understood. Thanks, Eric, for taking my questions. Sure. Thank you. Thank you. Your next question is from Derrick Whitfield from Texas Capital. Please proceed with your question. Good afternoon, and thanks for taking my questions. Hey, Derrick. How are you doing? Good. Good. Thanks. Bigger picture, could you speak to your expected spending plans for 2025 given the turbulence in the regulatory markets and the lack of clarity and/or value with 45Z? We are on course with a $75 million capital budget from USDA Renewable Energy for America program loans. We also have a variety of grants. I think our total grants are in the $65 million range. Of course, we have ongoing investment tax credits who've already netted about $17 million cash proceeds in January and February. This year, we expect additional cash proceeds from that. Our capital spending on Aemetis Biogas is going to be accelerating in 2025. We have some vendor support that helped us in the past. We built our pipeline with very strong financial support from a vendor. We expect to expand that vendor support, which enables us to execute quickly and then pay them off through USDA and other funds that come in, including revenues. We are looking to continue to accelerate biogas. We have 50 signed dairies. We have 16 of them on operating or finishing steps of operations. We have 34 dairies to go, and we have more dairies coming on board. We have gone to the USDA lenders as well as our vendors and laid out a plan that enables us to accelerate in 2025 and 2026. As you know, with 45Z probably taking most of this year to get final Treasury guidance out, we actually are running the numbers based upon low carbon fuel standard credits and D3 RINs as well as selling the actual fuel itself, the molecule. That is supporting all of our expansion plans at the current time. Great. Maybe shifting over to ethanol, as you think about the progression of E15 approvals across the remaining 41 states this year, what's your view on what this will do for ethanol margins for Aemetis and the industry? I think it's going to be a slow mega trend. When people look back on it, it'll seem as if it really happened quickly. Looking forward from where we're sitting, it's going to look like a melting ice cream because it's going to take most of this year for the convenience stores and others to finally realize, "Yep, I guess we can make more money for competitive factors to kick in that the guy across the street is already doing it and his fuel is cheaper." I think we'll see acceleration in 2026 as more states come online. It's a commodity marketplace. The absorption of the gal that are currently out of the market will be all that's necessary for us to recapture probably $0.50 per gal and still have a very significant margin available. Here in California, we sell our product for about $1.80 net of discounts and marketing fees and the like. At the pump, certainly, it's more than $4. Fundamentally, our molecule goes to the blending rack and then gets trucked to a gas station. $2 a gal times 65 million gal is $130 million a year of margin to the oil company for trucking our product around and then dispensing it. I think that they're definitely $0.50 a gal of that, leaving them with over a dollar to profit on the thing. If we get into strong adoption of E15 by probably 2027, I would expect we'd be above $0.50 a gal. It would drive new investment in new capacity. As we've cited, entire capacity in the U.S. is 18 billion gal, 2 billion gal being exported, and we're using about 14 billion gal, a little more than that, domestically. We have a billion and a half gal of capacity that's offline due to maintenance cycles and other things. When that gets absorbed, the only solution is, quite frankly, new capacity. We would exceed 20 billion gal of demand with only, even in an ideal scenario, everybody running 18 billion gal of capacity. You're going to see new investment start to kick in driven by higher margins. Same cycle we saw in 2004, 2005 as the renewable fuel standard was adopted should happen in 2026, 2027, and 2028 as people realize we're short of ethanol in the United States. Eric, one last, if I could, just to put kind of a bow on CARB policy. When would that likely go into effect, in your opinion, and will the obligations be backdated to cover 2025? I personally think we're probably two to three months away, and we have no facts to back that up at all. It's the pace of the internal CARB staff and the internal OAL staff. Frankly, as Andy mentioned, it's the amount of encouragement offered by Governor Newsom for them to work extra hours to get this done. We do know that CARB is working very, very hard on this. We just have no idea about how long that's going to happen. I think with the political tea leaves here, it's going to be sooner rather than later. Thanks, Eric. Thank you. Thank you. Your next question is coming from Matthew Blair with TPH. Please proceed with your question. Thank you and good morning. Eric, could you provide any more color on what drove the negative EBITDA result in the fourth quarter? Was that mostly due to ethanol? Could you also talk about ethanol fundamentals in the first quarter? We're seeing pretty high utilization, very high inventories. Do you think ethanol is on track for an even weaker Q1 than it was in Q4? Thank you. Q4 was oversupply and high corn prices. Corn jumped a dollar, I think, in Q4. Q1 for us is a little better than Q4. We've adjusted some operations to reflect the oversupply of ethanol. The corn prices, as you know, have moved both up as well as down the first quarter, but they've had some downward moves as well. I think our performance of first quarter will probably prove to be a little better than the fourth quarter. We did. I should make note that it's the operational changes that I think led to the improvement. I don't think it was a market. We slowed down our grind. I think what we're seeing, certainly from yesterday's EIA numbers, is that others are responding similarly. The EIA numbers yesterday were the first time we've seen this year that were relatively positive. The folks that we work with from a marketing perspective are sort of seeing light at the end of the tunnel as we get through this period. The other thing I think that influenced some of the price of gas, while not historically high from a use perspective, I just saw a chart that showed that this is the strongest demand for gas, maybe on record. Natural gas pricing went up a little bit. Obviously, corn price went up a little bit or a lot. We've adjusted our grind, as have, I think, other Midwestern plants. In April, you'll start to see some of those plants go into their annual turnaround, which will help us get rid of some of this inventory. We are kind of feeling like hopefully there's some light here at the end of the tunnel as we head into Q2. Sounds good. Could you share any expectations on the D3 RVO going forward? Last time around, we had a three-year RVO. I think the average increase was about 30% a year in the blending obligation. Do you have any expectations on just what that might look like? Should we expect a new two or three-year RVO this spring, and how much would the blending obligations go up by? Two items on that. One was historical. Back in 2024, the EPA a couple of days ago said that they had extended the compliance period because they were intending to adopt the new lower number of D3 RINs mandated for 2024. That is an indirect signal to the market that the proposal of the EPA made to the White House under the previous administration is actually being followed through so that there is not a mandate that is any higher than the actual production in 2024. Actually, I would say it is a very indirect way of saying, "Oh, by the way, guys, you are never going to be short because this was after the year was done. All the investments have been made, all the products have been shipped, and then they changed the rules of the game," which was that the obligated parties did not have to worry about being short. If that becomes the pattern, then it won't matter what the RVO is. I'm just being frank with you. You might as well just skip the RVO, let the oil companies buy whatever they want, and at the end of the year, just set the RVO to whatever the oil companies actually did. Now, why do I say that? Because that's what they did with ethanol for eight years. Starting in 2014, they just didn't issue an RVO. You later had a couple of federal court cases lost by the EPA. They were in violation of federal law. They set the RVO at whatever was actually consumed. It's not a great commentary on the management of the program by the EPA, but let's just face the facts that that's what's going on. The price of the credits was approximately $3.50 prior to this proposal by the EPA to remove excess requirements for D3 RINs. It has settled around $2.45. After this news has hit the market, there's some reasons why that is the case. My personal view is we're probably at $2.45 until the president decides he wants more investment in domestic renewable energy driven by waste. When he decides that, I think we'll be at $4 or even higher because the entire system is structured to attract new investment. When you destroy excess demand, then nobody should make new investment. That is what the signal is from the EPA: "Don't go put more investment into D3 RIN creation because there's no market for the product." We are extremely cynical about the behavior of the last administration on this particular topic. I'm not surprised at all in the current administration, but there is going to be some backlash in which people point out that if the market's not growing, then farmers aren't getting any additional revenue, and there's no new investment, no new job creation in domestic energy, and that violates the unleashing America energy executive order. I think we're all kind of watching the new administration see where the priorities are. I think eventually the D3 RIN RVO will come back into being relevant to new investment growth. The question is whether it's going to be this year or next year. Great. Thanks for your comments. Sure. Thank you, Matthew. Thank you. Your next question is coming from Dave Storms from Stonegate. Please proceed with your question. Good morning, and thank you for taking my questions. My first one, I wanted to start with a modeling question. With seven digesters on the cusp of CARB approval, can you break out maybe the MMBTU contribution from those digesters? Is it as easy as being roughly 45% of your yearly MMBTUs, or is there another way we should think about this? It's approximately 350,000 per year. It's about 25,000 average per dairy from a modeling perspective. We do have larger, and we have smaller dairies, and we have some digesters that actually have multiple dairies feeding them. From the perspective of modeling, 25,000 MMBTU per dairy is probably a decent number to use currently. Understood. That's very helpful. Thank you. I just wanted to ask about the market for the sale of investment tax credits. How has that changed over the last year? It looks like it's roughly a quarter lag and a 10% discount when you go to sell those credits. Is that market anticipated to maybe have condensed spreads for 2025 or anything else that you're expecting in that market? I think the market has settled on a bid-ask spread that, as you've seen in now, our multiple transactions have closed for a total of about $70 million of net proceeds. It's about a 15% total discount between the discount, the lawyers, the insurance policy, the brokers, everybody in the whole process ends up being a little bit less than 15% discount. Understood. Thank you for taking my questions. Good luck in Q1. Yeah. Thank you, Dave. Thank you. Your next question is from Ed Woo from Ascendiant Capital. Please proceed with your question. Yeah. Thank you for taking my question. The India IPO, have you thought further about what you may possibly do with the proceeds, either invest it in India or bring it back to the U.S.? The India IPO process has a very disciplined use of funds component that is not the way it works in the United States. We are being, let's call it diligent, about disclosing our use of funds until we get through the India IPO process. You will see in other IPOs in India funds that are repaying debt from offshore investors or even private equity firms that are getting funds from their IPO. The actual calculation is actually a part of sizing the IPO, and even looking at market acceptance of the IPO will determine the amount of funds that could be repaid to the parent company for funds that were invested in the subsidiary. It is going to be a while before we will come up with a number that is definitive. Great. Previously, you disclosed that India was pretty much self-sufficient. Is that still the case, and you think it will be that way until after the IPO is completed? It is still the case, and we do have a lot of investment in inventory and operations and the like. Beginning shipments to OMCs will free up liquidity to India. It has no long-term debt. It is investing in inventory to be well-positioned for timely delivery. That has been our highest priority. The good news is the India team is well-positioned to do that again on multiple OMC contracts that we expect to see this year. Great. Thank you, and I wish you guys good luck. Thank you, Ed. Appreciate it. There are no further questions at this time. I would like to turn the floor back to management for closing comments. Thank you to Aemetis stockholders, analysts, and others for joining us today. 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 an audio version of this Aemetis Earnings Review and Business Update. Tom? This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.