Good day, and welcome to the California Resources Corporation Third Quarter 2021 Earnings Conference Call. All participants will be in a listen-only mode. Please note today’s event is being recorded. I would now turn the conference over to Joanna Park, Vice President, Investor Relations.

Welcome to California Resources Corporation’s third quarter 2021 conference call. Participating on today’s call is Mac McFarland, President and Chief Executive Officer; and Francisco Leon, Executive Vice President and Chief Financial Officer, as well as several members of the CRC Executive Team. I would like to highlight that we have provided slides on our Investor Relations section of our website, www.crc.com. These slides provide additional information into our operations and third quarter results, and we have also provided information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures on our website as well as in our earnings release. Today’s conference call contains certain projections and other Forward-Looking Statements and these statements are subject to risks and uncertainties that may cause actual results to differ. Additional information on factors that could cause our results to differ are available in the company’s 10-Q and 10-K. A replay will be available for these 30 days following the call on our website. And as a reminder, we provided additional time for question and answer at the end of our prepared remarks. We would ask that you limit your questions to a primary and one follow-up. And with that, I will now turn the call over to Mac.

Thank you, Joanna, and good morning, good afternoon everyone. And thanks for joining the call. In honor of Veteran’s Day, we would like to thank all of those women and men who served and continue to serve our great nation. Thank you for your service. In the third quarter, we continued our strong performance, maintaining production of low carbon intensity oil, demonstrating our disciplined investment and generating significant free cash flow. I would like to thank the employees of CRC for their dedication to make all of this possible during the pandemic. Their strong and consistent performance has enabled us to generate $328 million of free cash flow year-to-date and announce the following. First, we are updating our annual free cash flow guidance for the year, which we are increasing to a range of $460 million to $510 million. Second, I’m pleased to announce that the Board has approved a dividend of $0.17 per share payable in the fourth quarter of 2021, and has extended the $250 million share repurchase program until the end of the second quarter of 2022. This highlights CRC’s dedication to shareholder returns. I would also like to point out that even with the strong cash returns to shareholders, we still expect to have over $325 million of cash on our balance sheet at year-end. And lastly, we continue to advance our commitment to the energy transition in the sector. Building upon our carbon management strategy, CRC has adopted a 2045 Full-Scope Net Zero Goal for Scope 1, 2, and 3 emissions. This puts us among a handful of industry peers to include Scope 3 emissions in our Net Zero Goals and puts us on a timeframe five years sooner than most, which aligns us with the state of California's 2045 Net Zero ambitions. CRC’s low carbon intensity production combined with our unique asset position and carbon management opportunities are the key differentiators, which allow us to have a clear line of sight to achieving the Full-Scope Net Zero Goal. Said simply, CRC provides low carbon intensity fuel for today and Net Zero fuel for the future. When we couple our unique position with the economic incentives available in California, CRC’s opportunity stands apart even further, because we have the opportunity to reach our Net Zero Goal economically. As previously disclosed, Carbon TerraVault's near-term focused targets up to 200 million metric tons of storage potential or injection of up to five million metric tons per annum by 2027. This represents nearly double our Scope 1 and 2 emissions and provides a clear direction to meaningful progress towards our goals. As I said before, we do not expect it to be easy to achieve, but these are our goals; they are ambitious and we are committed. As we committed before, we have submitted our second permit to the EPA for 26R reservoirs plan. Combined with our initial permit for the A1A2 reservoir at Elk Hills, this makes up approximately a 40 million metric ton project or Carbon TerraVault 1 and supports our goal for first mover advantage in California and the U.S. when it comes to carbon management. We continue to have discussions with various emitters, as we stated before, and we are targeting an announcement on these advancements in 2022. On the solar side, we are progressing our partnership with SunPower on 24 megawatts of behind-the-meter solar projects at the current front and more Shafter fields. This is in addition to the previously announced 12 megawatt project at Mount Poso and advances projects on a total of 36 megawatts of the previously announced 45 megawatts behind in the year. Again, I would like to thank the employees for their dedication and hard work. Our operations team continues to deliver strong results on our maintenance and development programs, which have exceeded expectations from a cost type curve perspective. Thank you for being here today and I will turn the call over to Francisco.

Thanks Mac. Good afternoon everyone. And thank you for joining us on this call. As Mac highlighted, CRC continued strong operational and financial performance in the third quarter of 2021. During the quarter, CRC produced 102,000 net barrels of oil equivalent per day and 62,000 net barrels of oil per day, resulting in modest growth year-to-date in both gross and net oil production. This is largely due to our inventory of high return, quick payback maintenance projects, and it is also supported by only $98 million in drilling, completion, and workover topics year-to-date. With much of our backlog addressed at the current prices, we are beginning to increase our development program to a more normalized level. In September, we added a third drilling rig in our Los Angeles basin and year-to-date our development program has brought online 58 new wells. In the third quarter, we were running 35 maintenance rigs and we were able to bring online an additional 216 maintenance wells as part of our previously announced shift of capital from drilling to downhole maintenance. In Q3, this shift allowed us to return to production an additional 2,600 BOE per day, while sustaining our controllable operating costs. Our commodity realizations remain strong across all of our streams with oil realizations at 100% of rent, NGLs at 73% of rent, and natural gas at 126% of NYMEX. Realizations are expected to remain healthy across all three hydrocarbon streams, particularly for natural gas, which has seen a large increase in the second half of the year. The rising natural gas prices increase CRC's operating costs, which I will discuss further shortly. However, it is important to recall that CRC benefits from this increase since we realize higher prices on the sale of natural gas, which we also produce. Moving on to the cost side of the business, and as shown on Slide 9, our third quarter 2021 G&A costs rose sequentially quarter over quarter, and now average $5.44 per BOE. This is primarily due to increased compensation-related items. Our third quarter 2021 operating costs, excluding PSC effects, rose by $1.69 per BOE compared to the second quarter of 2021, primarily due to the rise in natural gas prices. We purchased natural gas, which is used as fuel for our steam flood operations and to generate electricity from our Elk Hills power plant. Excluding the effects of higher natural gas prices on our cost structure in the third quarter of 2021, our operating costs on a per barrel basis were in line with the first two quarters of this year. Through testament to the operations team’s ongoing efforts, we managed costs that we control. When we look at the effect of natural gas pricing in total, we can see the benefit we derive as the largest natural gas producer in California and the positive impact on our margins. Year-to-date, CRC has produced an average of 160 million cubic feet per day and purchased less than half of that amount for our internal consumption. As we show on Slide 10, for every dollar rise in realized natural gas price in the fourth quarter, we expect to see incremental revenue of $15 million more than offsetting the incremental operating costs of approximately $7 million. During the third quarter, CRC reported an adjusted EBITDAX of $242 million, our highest quarter since we exited bankruptcy a year ago. Furthermore, this year’s modest CapEx requirements helped to generate $131 million of free cash flow in this quarter, our best quarter so far this year, and $328 million of free cash flow year-to-date. Results reflect strong operational performance, higher commodity pricing, and higher margin electricity sales from our Elk Hills power plants. Underpinning CRC’s strong financial performance has been our successful drilling program. Our 2021 development program has predominantly been focused on the Mount Poso, Elk Hills, and Buena Vista fields, with a combined program IRR of over 90%. By focusing on high value, high margin horizontals, we have seen large capital efficiency improvements across the fields. Currently about 90% of our drilling efforts are focused on these promising horizontal opportunities, reflecting stronger economics and lower capital intensity needs. Due to the strength of the drilling program to-date, along with the rising commodity prices, we accelerated certain projects through the fourth quarter of 2021, which were previously scheduled for 2022, including adding a fourth rig in the Buena Vista Shale and incremental workover opportunities. As a result, we are adjusting our guidance to account for changes in our activity in the current price environment as we look towards our year-end. We are raising CRC's total net production guidance by approximately 2% to a point of 100,000 BOE per day. Also increasing capital investments to a range of $180 million to $200 million, and increasing free cash flow guidance by approximately 8% to a range of $460 million to $510 million. The combination of our strong operating results and streamlining of our asset portfolio continues to enhance our financial strength. Earlier this month, we closed on the sale of the majority of our Ventura Basin operations, which was our highest operating cost area. This helps bolster our already strong liquidity position. Post-closing, our cash balance as of November 3rd was $280 million, bringing our pro forma liquidity to approximately $639 million. Our updated guidance takes into account the sale of our Ventura Basin operations. I would also like to point out that the preferred interest held by Benefit Street Partners was redeemed in September, further simplifying our balance sheet and financial flexibility. To conclude, CRC continues to demonstrate our commitment to prioritize shareholder returns. As of November 5th, CRC repurchased 3.1 million shares for $104 million for an average share price of $33.99 per share, which represents over 25% discount to our current share price. With $280 million of cash in our balance sheet, our strong financial position has further optionality regarding our shareholder return strategy. As Mac mentioned, the Board has approved a quarterly dividend of $0.17 per share payable in the fourth quarter, which when annualized equates to approximately $56 million in shareholder returns. Our healthy free cash flow generation allows us to continue to self-fund our capital needs and will allow us to fund our carbon management activities. As we continue to evaluate alternative capital deployment options benefiting our business. Please note that we have provided detailed analysis of our quarterly financial and operational results and our 2021 guidance in the attachments to our earnings release. Thanks. And I will now turn the call back over to Mac for closing remarks.

Great, thank you Francisco. CRC has a uniquely positioned asset base that allows us to provide the needed energy today and to meet the goals of tomorrow with the Net Zero Fuel of the future. CRC continues to exhibit disciplined capital investment in our asset base, which is low decline and low carbon intensity and provides resilient cash flows. We remain committed to our cash flow priorities of building upon our carbon management business and shareholder returns. We have made progress on both with two important announcements, our commitment to 2045 Full-Scope Net Zero and a quarterly dividend. Thank you again for your interest in CRC, and thank you for joining us on today’s call. With that, we will now open the line for questions.

Thank you. Today’s first question comes from Scott Hanold from RBC Capital Markets. Please go ahead.

Thanks. First congratulations on the target to a Net Zero Scope 3. I think you are one of the only oil and gas companies to have good visibility toward that. So congrats on that.

Thanks, Scott.

My first question is probably for Mac and maybe Chris. I understand the sensitivity around the discussions with emitters, but can you give us some sense of based on your discussions, what are you all hearing from them in terms of the interest level, key criteria that they are looking for and just some sense of where the interest is in playing the opportunity? Are they looking to participate in any of the sort of the start, the end of the process, or are they just looking to find a solution and whatever is the easiest?

So, Scott, Chris is here with us, so I will let him jump in, but let me just start by saying that I think that at least as we consider opportunities for sources, we are working with people who are interested in reducing their overall carbon intensity of the products that they make. And therefore, being able to hopefully either avoid having to produce LCFS credits or creating a product that has a premium associated with it due to lower carbon intensity. So that is the high level, but I will let Chris jump in and provide some additional comments.

Yes. So I think that is a great context. And of course, that is going to vary by source, right. There are some emission sources when you start to look at how they price their downstream product, whether they are conventional refiners or renewable refiners or any other source out there, they all have unique attributes. And so I’m encouraged in the work and the discussions that we are having with each of them. And it really speaks to the model that we have approached our go-to-market, which allows for the flexibility in these very early stages to engage with these emissions sources and be able to tailor with them to the types and the needs that they have, where they can monetize the low carbon intensity of their product. So very much advancing the ball across those different sources and very encouraged with the response that we are receiving.

Let me just add onto that. So with the LCFS construct, it is in California, obviously, people can either view that as a carrot for the economics, which have to pay for the capture through the injection system or the stick if you will, if it eventually becomes somewhat of a penalty that they have to buy credits for the deficiency, that is one avenue. The other one I would tell you is, obviously, you have seen and we have included a slide on the proposed changes to 45Q, we also see - in addition to those that are LCFS eligible, we also see increased interest in non-LCFS that are 45Q with the uptick in 45Q that might be interested in siting Greenfield type opportunities. So I think there are the Brownfield opportunities that are LCFS compliance and the Greenfield opportunities with the increase in 45Q, that is driving a lot of interest.

Got it and could you just mention on the last part of that question was whether they are interested in actually the capture process, doing part of the capture process, and then having you sink the CO2 from their transport and sink. Is there any interest in them taking some of the opportunity to hear as well?

I think it without getting into any one particular discretion, it is kind of all over the map. It depends on the source, it depends on the capital funding, it depends on a lot of variables there, Scott. I think that there are some that say, you know what, providing an entire solution for me. And there are some that say, 'Hey, I would like to deploy capital, and put it to work and possibly look at things that look more like a partnership around the cashier system', et cetera. So it really stands the gamut, as we laid out in our October 6th carbon update on that business model, it really does cut across all those different business models.

Got it, understood. And my follow-up question is just on the shareholder return. Maybe just on Mac for yourself, but also Francisco, as you stepped back, you initiated a dividend, you have a stock buyback, you have also made a statement of wanting to utilize 50% of your free cash flow to get toward that Scope 3 Net Zero. Can you at a high level discuss a couple of things? One, where do you go from here on that shareholder return proposition, because even if I take half of the projected $2.5 billion, it still leaves you a lot of flexibility going forward. So if you had some commentary on that?

Yes. Scott, this is Francisco. I will take the question first. So we have to start with, as we said in the script, we are projecting cash of $325 million by the end of the year. So there is a really good accumulation of cash this year and that post already over $100 million, but the work on the SRP and the dividend that we are going to pay out in a few weeks. So the cash flow potential, the cash regeneration of the business continues to deliver and as we discussed earlier, the framework is to first invest in the core business, and we are going to invest less than 50% of our discretionary cash flow into maintaining our core business. So then you have 50% remaining, which we will split roughly in half between shareholder returns and investment in our carbon management business. Right now, we would like the value proposition to the investor do we put a dividend forward, but we will also keep the share repurchase program alive. So we will have two different avenues of returning cash to shareholders. I like the optionality that the share repurchase program gives us. We still see a lot of value in our stock, and we are going to continue putting dollars to work to buy back our shares. But it is something that we will continue to assess. And it gives us an opportunity to pull back at some point. But right now, we are going to be entering the year with both of them open and we will see what the market dictates. So we will allocate accordingly to that 50% and there are two frameworks to do it now, two particular paths to do it. And then the carbon management business, we see kind of a ramp up of investments over the next few years. Right now, we are talking to emitters and making the initial steps to creating this new business segment that is going to ramp up naturally as we get closer to FID and as we get closer to making a decision on a go and no-go for the capture system or the pipelines or the storage tanks. So naturally, you are going to see a progression from potentially heavier weighting in the first few years to shareholder returns in terms of the proportions and then the ramp up in carbon management. So there is a little bit of timing associated with the split of capital. What we are seeing is the financing side of the equation is maturing rapidly; there is a lot of good sources from private equity to government loans to the bond market being attractive to participate in the carbon management business. Now, we said we are not afraid to put our balance sheet forward and we may use some of the cash that we are generating towards these initiatives, but to me, the best point to negotiate, the highest potential negotiating leverage is to have cash on the balance sheet that unlocks the financing sources. I don’t want to commit to only one way of doing this and say we are definitely going to put this much money to work by this stage, because if we find a cheaper source of financing, we will definitely do that. And I think that this stage is set for us to be able to have a lot of different options and then just optimize on the best financial structure as we try to pursue the carbon management business.

Got it. So, in theory, if you all were able to find that cheaper source over time, the shareholder return would take up a larger portion of that free cash flow? Is that what I’m hearing?

Yes. I would say, shareholder returns ultimately, we have discretion on what that incremental source of cash goes to. We will see what the best avenue is, but I don’t want to commit to all kind of shifting back in that instance. It is kind of more of a, you are saying, 'Well, what if this happens?' And I’m trying to provide some feedback, but ultimately, we will see it right. The shareholder return aspect of our business is going to be there given our very low capital intensity assets and the type of assets that we own. So there are going to be opportunities, whether it is acquiring a bolt-on near Elk Hills, for example that we might put the cash forward to work that in, and we might see really good value there. So I don’t want to box us in because if you get sources of financing in carbon management, it all flips back to shareholder returns. We are going to look at it; we are going to explore it. If that is the best avenue, we will do it. But we also have dry powder to do other things with it.

So Scott, just to add a bit from my perspective, what Francisco said is absolutely true. What we have is a framework and we are committed to both sides of the - after we spend and reinvest in maintaining BOE production. Both sides, shareholder return and carbon management, we are committed to both. But what we have is because of the strong cash flows of the core business E&P business, we have ultimate flexibility and we have demonstrated that now for three quarters. I think Francisco is saying projecting avenues of future we remain committed, but we remain flexible. And as we see opportunities, we have the ability to either return the cash to shareholders or invest in projects that we think are shareholder accretive.

Understood, I appreciate the color.

And our next question today comes from Leo Mariani with KeyBanc. Please go ahead.

Hey, guys. Just wanted to ask a question on the fourth rig that you are adding here. Just wanted to get a sense, I guess, as you guys look into 2022, do you think four rigs is kind of the right number to roughly achieve your goals, holding roughly flattish in 2022, or do you think there may have to be an additional rig or the demand to come in here?

Yes, Leo. This is Francisco. We ramped up from one rig to four as we exited the year and we like that entry point into 2022. As we have guided before we talked about it, we see once this backlog inventory is no longer there, we are going to switch more dollars to capital and we see the maintenance capital of our business about $275 million. So that implies somewhere between four to five rigs. We feel really good about the four rigs that we have right now going into the year. Shawn Kerns is here with us, our Head of Operations. I don’t know if you have anything to add.

Yes. I just want to be clear the $275 included is not just DMC; it is a capital number. But yes.

Yes, I will just add Francisco, the four-rig program is very consistent with what we have been drilling this year and in 2021. And so we have our plans laid out, and we will just kind of roll into 2022 with that four-rig program.

Okay, thanks. And then just additionally, one of the seats could provide a little bit more color just around the commercial progress on some of the negotiations with some of these industrial emitters. This might be a bit of a tough way to frame it, but just wanted to get a high-level sense if there is any way to like ballpark quantify the number of like very serious conversations you are having. Is it just a handful or is it like 50 conversations with emitters and then just wanted to get a sense like, have some of these discussions progressed to a fairly late stage? How would you maybe characterize how far you are down the road on some of these key discussions?

Good morning, Leo, it is Mac. What I would say is I would probably go back to some statements that we said before; if we signed everything up, we would be way oversubscribed for Carbon TerraVault 1. I think that the discussions are advancing, I think that based off of the continuation of discussions, we would stick with our type curve. It is still being the type curves that we put out on October 6th. So it has been affirmation of continued affirmation and continued interest in Carbon TerraVault 1.

Okay. And I guess, apart from Carbon TerraVault 1, I know obviously you guys have plans to do more of these classic sequestration projects, I guess the discussions also potentially look at other sites down the road, I’m just trying to get a sense of what the kind of size of the opportunity can be here. Is there just a lot of folks looking at some of the other fields in the future that it gets to be permanent as well?

And short answer is yes, but again, I will go back and say Leo that what we described before; we put Carbon TerraVault 1 together. We filed the permits on it, but we are focused on the next 160 that would get us to 200 million tons. Chris is here. Chris has been working with the team to prioritize our opportunities, because we said we thought we have a fair amount of unique assets that we can convert into Carbon TerraVault 2, 3, 4 or 5. And to get us somehow to some - in some form or fashion, get us to the 200 metric tons that we are focused on first. But Chris, do you want to provide some insight on that?

Yes. I think those conversations in addition to CTV 1 are occurring. We are active, or we have our focus on, as we talked about, we submitted the DTA permit application for 26R; we want to deliver on what we promised and committed to on CTV 1. But in parallel with that, with the goals that we have put out, our 200 million tons, we are advancing in discussions with scoping out different sources across those geographies and prioritizing where we think the next set of opportunities are. So that is to say we are working on it. We are not stopping with CTV 1 or focused on that, but we are progressing to the next 160.

And just to add a quick overlay to what Chris said, we have teams that are advancing the permitting and the defining of the next tons to get us to 200. But concurrent to that, we also have commercial engineering and operations teams that are working on the source of CTV 1. And concurrent to that, as we structure through and where we hope to get with a project, we are working, and Francisco and the finance organization are looking at opportunities for how to finance that either through the debt or equity market. So, it is all going on concurrently, and we are excited about the prospects.

Okay, thanks guys.

Thanks, Leo.

Our next question today comes from Kalei Akamine with Bank of America. Please go ahead.

Perfect. Thanks for getting me on. Mac, I want to hit a couple of topics here. And this first will be on the base business, which I feel is getting perhaps overlooked by the market. That is really focused on low carbon at the moment. So I think the market is trying to understand how CRC fits into this new E&P landscape, which requires you to have a track record. So I will commend you for coming out of the gates very strong this year and showing the gap returns and the capital discipline, but we want to know how long you can do it for. So I’m hoping that you can help put some parameters around the free cash capacity. So what I’m looking for is what is the maintenance capital, what is the breakeven and what production plateaus does that support, and how deep is the inventory to support it? So, in other words, how long?

Yes. So a great question. I appreciate the interest in the core business, because it is a lot of what we do. I mean, there is a lot of conversation around our carbon management activities, but you are absolutely right. We did highlight some of this in the carbon strategy day, but not for the level of details that you asked, but we provided a five-year type projection there. I’m going to let Francisco pick it up from here and talk about maintenance capital, maintaining production. There were some assumptions there. Maybe you want to go through some of those.

Yes, I would be happy to. So Kalei, we have always felt CRC was inventory-rich, and the issue with what we have had since we came out of the gate of CRC has been the balance sheet, in which we addressed this past year. So the inventory looks very attractive. Now it is not shale, so you are not going to hear us talk about these 24-hour IPs and in moving through into that way of guiding the market. So we have a process of really good tanks, really good oil and gas rocks that we can get the oil out of the ground through water floods and steam floods or primary drilling. So it is not always the drilling and completion side of the equation that solves for how attractive your inventory is. If you can get the oil by injecting water, that is a very attractive, very high return business for us. Now in the inventory, what we talked about in the past is on about four rigs, which is our current pace. We have about 10 years of inventory. We are focusing this year on some of the shallower zones in the San Joaquin Basin, but we also have really good opportunities in the LA Basin. I mean, that is a pretty good sustainable level. I mean, we can expand in the LA Basin, but we are seeing a lot of really good returns in the shallow zones in the San Joaquin Basin. So we see about 10 years of inventory. Now that said dynamic view, when we came out and we talked about this, prices were lower than they are today. Price point at $86 makes that inventory pretty significantly attractive, and if you look at our historical filings, you see any reserves of a much higher level; about a billion barrels of 3P reserves. So we see a lot of good projects there. In terms of breakeven, right now we see we have a pretty attractive hedging program that is protecting, giving us a nice floor to work with. So on 2022, we see a breakeven in the $30 per barrel range before we have to pull back on the capital. So we are hedging to support the capital to support the dividend, and we see a very attractive runway here as we go forward.

Yes, Kalei. This is Shawn. And if I add speaking to our inventory that Francisco is talking about, I think a notable change that you have seen lately that is doing really well is drilling more horizontal wells. That is a little bit different than we have done from the past, and we are seeing really good performance there. And when we talk about horizontals in this regard, these are unstimulated because of the quality of the rock in California is so good. So we are able to drill these wells, targeting some horizontal areas in the reservoir and we are able to be more efficient with our capital dollars going forward.

Thank you. I appreciate that. Maybe if you could just hit the maintenance capital spending level, and I will throw a twist on this, but what do you say to those that argue that it is going to take longer to stabilize due to the inconsistent spending in the past several years, and the long lead time between spending and the production response, and add to the fact that we haven’t seen production hold flat for a sustained period of time?

Yes. I mean, I think the evidence Kalei this year, three consecutive quarters; I understand your point though, you need to have multiple quarters. But this year has been a really exceptional year from an operating perspective. We are holding production flat with lower capital were below $200 million to hold the flat. I mean, we will guide to a higher number next year. Just to be clear, we are seeing about $275 million and that is only to clarify the point to hold oil production. So we do see this year as being a year where we had a good backlog of wells we could return back to production. We will move into a kind of a drilling - building that wedge over time to get back to that to keep maintain that production. But the way to think about conventional assets and CRC assets, I understand your point that you don’t have the shale production that immediately comes in, but you get on the treadmill and if you are chasing those barrels that you cannot stop production. For us, it is like a slow rising tide. If we continue putting dollars to work in both OpEx and CapEx and OpEx is a very important tool that we use to invest in getting production out of the ground, if we have a sustained level of investment, what you see is one of the lowest declines in the industry. So you are in the low teens, say 10% to 15% decline, and that allows you to project the business that is very sustainable and has high confidence in those cash flows over time. So, yes it is a different model; we then have to reeducate the market as to how conventional assets work. It is less about drilling and completion; it is more about maintaining reservoir pressure and putting barrels to work there. But that also allows us to plan the business without worrying about, okay prices dropped and we have to back away the drilling rigs, then the production goes away. So it gives us a lot of confidence to plan forward.

So Kalei, this is Mac. Let me say it this way. We believe in what we are doing and the way that we build credibility. I said this during the high yield offering that we did earlier this year. Said it during strategy and say it each quarter, we are going to build that credibility one quarter at a time. We believe that we have the inventory, we have the low decline, and we have the capital discipline, and that is what we are going to execute on.

I wanted to pick up on your comment about hedging. I think as you stated, CRC’s balance sheet is in the best position that it has ever been in. So I’m wondering on the philosophy to hedge; why do it? Is it just to fund the growth in low carbon or a dip on the drilling program? What is the strategy behind it?

Sure, it is a good question. So first let me try to parse some things if I may. If you look at the hedging and the mark-to-market that is going through the income statement in the hedging, the losses that we have seen to date that we are going to realize cash this year as well as the forward mark-to-market losses, those are almost entirely associated with what I will call legacy hedges that were enacted before; the trade dates were all before 12/31/2020. And they were a requirement at that point in time as we exited bankruptcy to meet; they were required by the RBL. If you look at the hedging that we have done since then, which I think is more applicable to your question, it is effectively as of 930 aftermarkets. I know there have been some write-ups, but there are some differences on the shaping of our hedges and when they occurred, etc. They are effectively at market or minimally out of the money. But why do we enter into those hedges? So we have done a couple of things; we have rolled up the strike price on the puts for next year, so that we have an entire floor to protect downside. Without getting into a view on commodity, we think that is prudent management to stabilize cash flows that allows us to have longer rig contracts, more stable production, and more stable investment in production. It also provides stable cash flows. And this is not a 100%. I mean, if you ever look at it, it is not a 100%. And we hedge up to 85%; we can hedge up to 85% of our production but that is only 75% of our revenues. We still have NGLs and natural gas revenues. So the hedging philosophy is to provide coverage for things like doing the carbon management, reinvesting in the business, and adding a dividend. We have low decline assets, but it basically helps us smooth our investment horizon over a longer period of time.

That is perfect. If I could sneak one more in, and this one is on CalCapture. My understanding was that the feed study was completed in the summer. So, I’m wondering what is standing between you and FID on that project?

Yes. So the feed study, we are still there are some things that had to go into it that we are working through on owner's costs, etc. And we have asked to take a second look at the cost and we have gone through with, I will call it a 0.05 pencil or something. We went through it; we gave it back to the engineers said, go back and refine the cost estimates, sharpen our pencil— the phrase I was looking for. So we are working through that. Our views are there are a couple of things associated with that, because everyone I think pretty much understands, but just for sake of clarity, a third of the power plant is used for hydrocarbon production. The other two thirds goes out to market on the California ISO. Okay. So right now, as we understand, the way the rules are written in our interpretation is that only one third of the carbon capture from the plant is LCFS pathway eligible. Now, it still is at some levels of enhanced recovery that would be associated with it. You start to get the economics that could make sense. However, there are some regulatory changes. Right now, there is no avoidance of greenhouse gas emissions for capturing CO2 off of combined cycles in California. We think that that will change over time. And if you did that right now and change over time, we think regulations will eventually get there, because it is necessary to have combined cycles on the grid. And those combined cycles need to have an incentive to have carbon sequestered. That is the only way basically to have a combined cycle. You can’t do it unless you are using hydrogen as an essential, which is a whole another ball game—the CO2. So we think that there is a movement in that direction. And if we were to offset greenhouse gas emissions for the full lot of the emissions by sequestering CO2, right now, those allowances are trading around $30, $32 a ton. And so, because it produces roughly two million tons, you start to two million tons from the power plant, you start to add to the economic returns on CalCapture. So when you ask the question about feed study, we are refining it. When you ask about getting to FID, I would say we are a ways away and we need to see some regulatory changes, but we continue to think that it is coming towards us and that is a project that we continue to invest in early stage development dollars.

I appreciate that. Thank you for answering all the questions and I look forward to catching up with you more on the low carbon part of the business next week at the BMA conference.

We look forward to it.

Thanks for hosting us.

And our final question today comes from Ray Deacon from Petro Lotus. Please go ahead.

Yes, hi. My question was on the Elk Hills power plant and how much of the gas is supplied from the Elk Hills fields. And would you like to put your hands on more gas resources? And is that possible?

Hey Ray. It is effectively a 100% source. I mean, you could talk about it - but it is 100% sourced, right. And the other thing that I would tell you just as we look at it, so you probably see our - we are being very effective on our cost discipline standpoint from on non-energy operating expenses, but the energy costs go up. And that is because when we look at that as a floating price of energy, whether it be on the steam generators or whether it be in the gas will supply the power plants. But we are a net gas producer. We generate roughly 60 Bcf of gas a year, and we consume 30 Bcf of gas a year. So again, give or take. And so that is why we had the slide in there that shows the fourth quarter sensitivity to gas. So we are a net gas producer, but a 100% give or take for the most part is behind us in our fields.

And just one more, I have read that California was going to shut in a fairly big nuclear plant this year. And I was just wondering, do you think the gas market could get even tighter from here or no?

It is hard to say. I think if the expectation that the plant is going to be shut down that somewhat makes its way into the market, but...

The more incremental generation you actually, Chris, the more support you need in the form of reliable resources. So yes, there is the concern that more gas generation will be needed to support that incremental - so if that is the case gas prices should weld in.

Got it, thanks very much.

Thanks Ray.

Our final question today comes from Eric Seeve from GoldenTree. Please go ahead.

Hey guys, thanks for the call. Great quarter and great to hear all the sale side interest that is building in a great story. It was a terrific quarter. I just wondering where you guys really blew the cover off the ball was on the natural gas trading and on electricity where gross profit was well above what you guys have guided historically for those businesses. Can you maybe level set and just give a sort of updated view on what we should expect for profitability from those areas going forward?

So, with natural gas prices higher obviously if I’m going to get into an electricity term - if we beat the market with the rate of our unit. Our unit can expand and expand our margins by dispatching into the market with higher gas prices and so our electricity revenues have been higher; there has been some higher demand, obviously; hydro has been a bit depleted here and it comes from the north. So, there has been increased demand of the unit and so increased profits and increased spreads, our margins, if you will. And that is what is contributing to that. And then as far as gas, we have just had opportunities to move gas around as we have several transport agreements and we have been able to optimize that better. We generally think that Jay and the team are going to do a good job, but sometimes not everything is repeatable, but right now, as we look forward, energy margins that being the electricity that is being sold into the future remains strong. Anything you want to add, Jay?

No, I think you got one or two things straight in the California gas market last 30 days. You said you leased up - capacity and moved up from 34 Bcf to nearly 42 Bcf. So that should be linfield, should be stabilizing element and maybe a depressing element on price. The second thing is you have had a major line on Elk Hill gas be restorative to greater use. It is about 800,000 MMBtu per day. In the past we didn’t have before. I think, we have seen the market receive that very well. Unfortunately, the response has been the lower gas prices. California has got a unique circumstance. We have got a limited amount of gas supply, we have got a limited amount of gas storage, but our needs from a power perspective tend to be hinged on gas incremental needs. So it is likely this will be a volatile market for both gas and power for some time to come.

Derek, I think with Jay, and obviously watching the market, there were some things that made the market tighter. There are a couple of things announced that should relieve the market a bit. I think time will tell, I think that as we go through this, there was an interesting report that came out recently. And I think the title was something to the effect of the turbulence of the energy transition. And I think in California perhaps at the (Ph) of that, or the forefront, whatever the right thing or the tip of the sphere, mixed metaphors, but we are seeing it as the state moves through this energy transition, that is creating this volatility. So it is really tough to predict what happen in the years to come other than continued volatility. So with that, let me just say thanks for everyone’s interest in CRC, and have a good Veteran’s Day.

This concludes today’s conference call. We thank you all for attending today’s presentation. You may now disconnect your lines and have a wonderful day.