Ladies and gentlemen, thank you for standing by, and welcome to the Berry Corporation Second Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions] Please be advised that today’s conference call is being recorded. [Operator Instructions] I will now turn the conference over to your speaker today, Todd Crabtree, Manager of Investor Relations. Please go ahead, sir.

Thank you, [Kristel] and welcome to everyone. Thank you for joining us for Berry's second quarter 2021 earnings teleconference. Yesterday afternoon Berry issued an earnings release highlighting second quarter results. Speaking this morning will be Trem Smith, Chairman and CEO; Fernando Araujo, Chief Operating Officer and Executive Vice President; and Cary Baetz, Chief Financial Officer and Executive Vice President. Trem will discuss our second quarter performance, as well as our expectations for the remainder of 2021. Fernando and then Cary will share further details on how we are addressing the operational and financial aspects of our business. Before turning it over to questions, Trem will make a few concluding remarks. Before we begin, I want to call your attention to the safe harbor language found in our earnings release. The earnings release and today's discussion contain certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. These include risks and other factors outlined in our filings with the SEC. Our website, bry.com, has a link to the earnings release and our most recent investor presentation. Any information, including forward-looking statements made on this call are contained in the earnings release and that presentation reflect our analysis as of the date made. We have no plans or duty to update them, except as required by law. Please refer to the tables in our earnings release and on our website for a reconciliation between all adjusted measures mentioned in today's call and the related GAAP measures. We will also post the replay link of this call and the transcript on our website. I will now turn the call over to Trem Smith.

Thank you, Todd. Good morning, everyone, and thanks for joining us today. The Berry team continues to execute our 2020-2021 plan with excellence. Berry had a solid quarter consistent with our expectations and annual guidance, and we remain committed to our disciplined financial principles and to delivering long-term value to our shareholders. We continue to reduce our non-energy costs on a sustainable basis despite increasing commodity prices without compromising our safety and environmental standards. Our safety record remains exceptional. Furthermore, we grew our production in the second quarter, approximately 1% and are on target to keep production essentially flat year-on-year per our plan. Our business model remains simple, durable, and resilient, and we have proven it generates free cash flow in all, but the most extreme market environments. This is not just a promise for free cash flow in the future. It's what we have already been doing. At Berry, we generate free cash flow today and have for the past four years. Further, and in-line with our key financial tenant, we continue to generate and live out of levered free cash flow. We are not aware of another U.S.-based company that defines it like we do. In addition to the normal expenses like OpEx, taxes, and G&A, we include interest, dividends and the CapEx needed to keep production flat or what we call maintenance capital. Only cash generated after these expenses is considered by Berry to be discretionary free cash flow or levered free cash flow. Our levered free cash flow should only grow going forward as our hedges put in place during the pandemic begin to roll off. As we pass the mid-point of the year, we are seeing positive signs in the industry. The price of oil is up almost $30 from a year ago. The demand for oil is increasing as vehicle miles traveled in the U.S. has bounced back to pre-COVID levels and overall air travel in the U.S. is returning to normal. The oil supply in the U.S. has declined approximately 15% from pre-pandemic levels and is stable for the moment at around 11.2 million barrels of oil per day. However, rig counts in the U.S. and overseas remain well below pre-pandemic levels as many resource companies are spending less capital and completing their significant inventory of DUCs, which are wells drilled but left uncompleted after the market collapsed in pandemic of last year. Therefore, as demand continues to grow and the inventory of DUCs is depleted, supply especially in the U.S. is likely to continue to fall. Berry, however, is in a terrific position to meet the growing demand and continues to create value in its conventional reservoirs through the drill bit in both California where we are currently the most active operator with three rigs drilling at new wells and in Utah. Remember, we are not a resource operator. We produce from shallow, low decline, predictable conventional reservoirs making our drilling programs low-risk and repeatable. In the second quarter, we drilled 50 new wells in California and 8 in Utah. 21 or 42% of the California wells and 5 or 62.5% of the Utah wells are coming on production in Q3. Furthermore, I want to be very clear that once again we have not been impacted in any meaningful way by governmental or regulatory constraints in California. We are continuing to receive permits and we are continuing to drill. In other words, despite political distractions and headlines, we have always maintained or grown our production, lived within our levered free cash flow, and increased shareholder value. By all measures, Berry is on track to have a strong 2021 and beyond. Reflecting this, the Board approved a 50% increase to our third quarter dividend to $0.06 per share, a top-tier return in the small mid-cap E&P space. Our model gives us the visibility to potentially increase incrementally our dividend as we continue to meet our cash needs through free cash flow generation. We believe the current best use of capital is to keep production flat enabling us to return capital and increase shareholder returns. Strategic acquisitions continue to be a priority for the Berry team as we look to increase our scale through accretive, value-adding M&A. To be clear, however, the status quo outlook for Berry is very strong. We continue to create significant value for our shareholders and will continue to, based on the current strength. While we are looking for and evaluating beneficial M&A opportunities, I am encouraged that we have more than 30 years of inventory in our sandstone reservoirs alone that will help meet California's long-term energy demand, which by the way, is not slowing down and provide value to all stakeholders for decades to come. We understand the importance of environmental, social, and governance matters or ESG to all our stakeholders and the growing interest of our investors. We are continuing to enhance our work in this area, as well as our disclosures. Yesterday, we published our quarterly update report, which you can find on the sustainability page of our website, bry.com. Notably, we have introduced disclosures aligned with the SASB metrics for our industry. All in all, our business model continues to work just like it has since we became public, it continues to perform. We continue to generate value for our shareholders, and we are positioned to do so well into the future. I will now turn it over to Fernando.

Thank you, Trem. I want to begin my comments by reaffirming that safety, protection of the environment, and regulatory compliance remain top priorities. At the same time, we continue to create value by optimizing the performance of our current assets and by generating meaningful growth in many of our conventional plays in a safe and responsible manner. I'm proud to report that we continue to achieve excellent health, safety, and environmental results in Q2. In fact, we are approaching the 500-day mark without recordable incidents and 800-days without lost time incidents. We will continue to dedicate the necessary resources to ensure the safety of our employees and contractors, to protect the environment, to meet all regulatory commitments and to maintain the quality of our infrastructure. Moving to operational performance, production in Q2 averaged 27,300 barrels a day. This is 1% higher than Q1. Our California oil production, which constitutes 80% of our total production was essentially flat quarter-on-quarter. For 2021, we expect almost 90% of our total production to be oil. In Q2, we operated with two drilling rigs in California, drilling 50 wells, which included eight injectors and six delineation wells, all in thermal sandstone reservoirs. We drilled successful programs in the Potter and Monarch sands in the Midway-Sunset field. I especially want to highlight our drilling results in the Hill property, part of the giant Belridge field. These are vertical wells targeting the predictable Tulare formation where actual production is exceeding type curves by 10% and our drilling and completion costs are 30% below last year resulting in very attractive returns. The asset is currently producing at a 50 year high. In Q2, we drilled eight wells in Utah's Uinta Basin, three of which are on production and performing better than type curve. In total, for 2021, we have now drilled 10 wells in Utah, seven of which will be completed and put on production in Q3. We have a healthy bank of 70 permits in Utah that provides substantial flexibility to our capital program. The Uinta Basin provides another attractive opportunity to drill in predictable conventional assets. Furthermore, we realized excellent results from our aggressive workover activity. These activities are yielding a rate of return in excess of 100% with approximately 140 wells brought back to production year-to-date. This aggressive workover campaign will continue for the remainder of 2021. As previously stated, we expect to see a slight production growth in the second half of the year with a higher Q4 exit rate compared to last year. As planned, in California, we picked up a third drilling rig in July, targeting additional opportunities in Q3. We are meeting our production targets despite lower production in our Poso Creek field where operating practices by an offset operator along with a reduction in steam injection volumes triggered an unexpected drop in production. The situation is under control and we have already begun to arrange the field's high production decline. Next, let's turn to operating expenses. In Q2, we averaged an operating expense of $17.31 per boe. There is $1.20 per boe improvement when compared to last year and a $3 per boe improvement from 2019. Our non-energy OpEx in Q2 averaged $12.71 per boe. This is flat compared to Q1 and about $1 per boe lower than 2020. Moreover, since 2019, we have been able to cut more than $2 per boe out of our non-energy cost structure. These are sustainable savings stemming from improved operational efficiencies in all parts of our operation. Our energy OpEx in Q2 was higher compared to Q1, but still 6% lower when compared to last year's average. As you may remember, our energy OpEx includes fuel gas purchases, which are mostly hedged offset by electrical sales from our cogeneration plants in California. Now let's turn to capital. CapEx in Q2 was $43.5 million as planned. This was higher than Q1 and within our budget for the first half of the year. During the quarter, we added a drilling rig in Utah in addition to the two-rig program in California. We also saw an acceleration of workover activity in Q2 when compared to Q1. Our capital outlook for full-year 2021 remains unchanged. In terms of well permitting in California, we have enough permits in hand to execute our capital program in 2021. At the same time, we are actively receiving permits for our 2022 program. We currently have 130 permits approved in California for 2021 and 2022 and have applications submitted for the remainder of our 2022 drilling program and part of 2023. To summarize, we're achieving outstanding safety results. Our production has sequentially grown since the beginning of the year. We are within plan with our capital expenditures focusing on revenue-generating projects, and we have taken $3 per boe out of our OpEx structure since 2019 in a sustainable way. We are achieving our goal to become the best operator in the basins where we operate. And with that, I'll turn it over to Cary.

Thanks, Fernando. The quarter was in line with our expectation for oil sales and – as natural gas prices return to more seasonal prices. As you may remember, due to the impact of Winter Storm Uri, our Rockies gas sales were nearly as high in the first quarter of 2021 as they were in all of 2020 adding $10 million to our first quarter adjusted EBITDA. So keep that in mind as you compare our first quarter to second quarter adjusted EBITDA of $41 million, which was in-line with expectations. We remain very focused on natural gas market as it can have a significant impact on our operating cost. We are well hedged through October and have added and will continue to add additional natural gas hedges for the next year. However, because we are gradually gaining access to the Kern River gas pipeline, the need to hedge our natural gas consumption in [all years] will be reduced beginning this fall. This will allow us to move ours or other purchase gas from the Rockies to our operations in California, effectively creating a physical hedge. We have been granted access to up to 15,500 mmbtu per day starting in October of this year, with a high potential to gain another 30,000 mmbtu per day in May of 2022. These contracts are in place for up to 15 years. This is a great opportunity for us to better manage our gas needs in California. Oil fundamentals continue to improve. Global demand for oil is almost at the same level as 2019, but the slope of supply has gone down since 2019. Based on global drilling activity, a major supply increased disruption is not evident. In fact, the U.S. producers seem to be focused on DUCs. However, this will eventually need to be put – they will eventually need to put the drill bit back to work, which for most will mean higher CapEx and lower cash flows. This isn't the case for Berry. We are drilling to maintain production, and we continue to live out of levered free cash flow. In fact, based upon our current cost structure and today's strip prices, Berry should produce enough levered free cash flow that we could be debt free in about 2.5 years. Don't forget our definition of levered free cash flow includes the cost of maintaining our production, paying our interest and our dividends. We are a cash flow machine. I want to hone in on this point a little more. As of today, Berry has returned capital amounting to 115% of the IPO proceeds or $127 million, including $77 million of dividends, and we have done that without compromising production and while improving our oil intensity. All this makes it hard for us to understand why we trade at such a discount to the industry. One possible explanation is that the market has concerns about California politics and its regulatory environment, both of which are publicly and negatively focused on the industry. However, the fact remains that since creating the new Berry just four years ago, we have not been impacted operationally from state or federal legislation. Only the markets kneejerk negative reactions to attention-grabbing headlines have kept our valuations depressed. Capital expenditures are in line with our plan. And per our plan, the majority of our capital is to be spent in the second and third quarters. The timing for spending in the second quarter was weighted to the back end of the quarter, and we could see the majority of production improvements starting in Q3. We would have an additional 600 barrels per day in production if we had not experienced a small production issue Fernando mentioned earlier. We do expect to see the production fully return later this year or early 2022. In short, we are seeing the uplift in production that we expect from our capital spend. We are currently working on a new borrowing base facility that is right-sized for our limited needs. Further exemplifying the point that we live out of levered free cash flow, we have not borrowed under our current facility in over a year. And at the current strip, we don't see a need to do so in the foreseeable future. That said, we are working with a strong bank group to provide the liquidity the market demands. In closing, we are making no changes to our annual guidance. Lastly, we continue to focus on return of capital, and we're happy to announce a 50% increase in our quarterly dividend to $0.06 per share. Our 10-Q will be filed later today if you want to take a deeper dive into the financials. Now, I'll turn it back to Trem for his final remarks.

Thank you, Cary, and Fernando. In summary, it was a good quarter with solid results. As you heard, we are a great company, and I want to close by underscoring what makes us great. We have predictable, shallow, low-decline, averaging about 13% annually, conventional oil reservoirs. Our business model continues to perform. It works. It has shown over-and-over again that it is resilient, durable and able to withstand pandemics, market collapses and political headwinds. We are a cash machine defining levered free cash flow as no one else does. Even with our definition, which includes interest dividends and the CapEx to maintain our production flat, we have discretionary cash flows above $47 Brent. If we exclude those items, like everyone else seems to do, we generate free cash flow above $35 Brent. We continue to return value to shareholders. We have done this since day 1. More than $77 million in dividends out of $127 million in total shareholder returns since going public just three years ago. We have a strong cost management with a more than $3 reduction in OpEx on a sustainable basis, while at the same time increasing our oil mix and gas mix to 90% oil. Remember, oil production is by definition, higher cost than natural gas production. We provide hundreds of high-paying skilled jobs and make substantial contributions to the local economies where we operate. We have an incredible safety and environmental record and adhere to all of California's safety, labor, human rights, and environmental standards. These standards are the strictest in the world and in sharp contrast to the foreign countries, including Saudi Arabia, Ecuador and Iraq where California imports most of its oil. And finally, we are providing equitable and affordable energy for all Californians, while keeping the environment, our employees, our contractors, and our communities safe and healthy. I'll now turn it over for questions.

[Operator Instructions] Your first question comes from the line of Leo Mariani with KeyBanc.

Good morning, Leo.

Hi guys. I was hoping to get maybe a little bit more color on your thoughts on any – just progress on the regulatory situation, particularly with respect to the Lawrence Livermore study. I know you folks talked about kind of having to wait to see what happens with the recall election, so perhaps you can maybe just talk about what you're, kind of seeing there? I guess that will be here in about a month and what – how you think maybe this kind of plays out into the fall?

Sure, Leo. This is Trem. Again, first of all, we are only able to do what CalGEM tells us they're going to do. And a reminder to everyone on the call, the high-pressure cyclic steam moratorium was caused by another operator failing to meet some of the California regulatory requirements, which then caused seven other operators to stop doing that particular mechanism on new wells, not existing production. We have been able to maintain our existing production in those areas as is, and we have no – none of the wells in the current budget or plans for next year or this year. So, that's the setting. To Leo's question, CalGEM continues to state that it is tied up in the political environment of the recall election, and we will have to wait to see how that plays out. And certainly have to wait to see how the outcome plays out to see when that frees up. But it remains done. They remain aware, and I think it's been just tied up in the political wins of the state. And the regulatory – and then Leo, I'd like to also add, we didn't emphasize a big long discussion on the regulatory piece in this earnings call. And the reason is there was nothing to report. We haven't been influenced by the legislative sessions this time. We have a very good relationship with WSPA and ourselves, and there's a strong coalition. And there's a growing recognition in the state that oil and gas is a requirement for them to go down this transition to a more green environment. And so there was no reason to talk about it.

Yes. And the only other thing that was – came through California was about well stimulation and well stimulation does not impact Berry.

That's correct.

Period.

Okay. Well, I guess, no news on that front is good news, you know for you folks at this point in the near-term.

Well, Leo, let me just follow-up. It's not just the near term. The point we were trying to make also is that we've never had any impact on us by it. It's been a topic and so it's one that continues to be managed and mitigated, okay. That's – just want to make sure that's clear.

Okay. And obviously, in your prepared comments, you folks certainly talked about how M&A is something that you're certainly looking to do here. Just wanted to get a sense if there's any high-level update? Do you guys feel like there's some opportunities that might be a bit closer than maybe they were earlier in the year. We obviously have seen a much higher oil price environment in the last several months and feels a little bit more stable than it did at the start of the year. So, just curious as to whether or not maybe there's more deals and maybe just give us a sense of how far down the road do you guys think you are on that front?

I think we're extremely active. Again, it's a very – it's something that's at the forefront of what we're talking about on a consistent basis. Trem and I spend a lot of time on this matter. The reality is, it's got to be an attractive transaction for Berry. The status quo for Berry is extremely attractive right now, Leo, especially at the current strip. And as you know, looking at our trading, it's – our cost of capital is extremely high. One of the most frustrating things we have that we continue to execute, we continue to return capital, we continue to hold our productions flat. But yet when you look at evaluation, we continue to be valued much lower than resource plays, which have dropped their production from $14 million in 2019 to $11.2 million today. And now just talk about returning capital, but they get rewarded. So, with that being said, we are looking for opportunities to grow. Cost of capital is expensive. Current status quo is extremely attractive. If something comes along that works for us and our current shareholders, we will take advantage of it, but it's got to meet those parameters.

Okay. That makes sense. And obviously, you guys did take some action with respect to that with a very healthy dividend increase and if I heard you right on the call, it certainly sounds as though we could see some other dividend increases in the future. And clearly, you guys have some underwater hedges this year. And as those roll off, there's kind of a huge jump in cash flow in 2022. So, I guess in the absence of equity markets deciding to give you guys maybe a more appropriate valuation, it sounds like you're committed to maybe ramping this dividend quite a bit over time.

I would say that is a fair and accurate statement.

Okay. Great. And maybe just lastly, on capital, certainly, you guys talked about spending more money in the middle part of the year. So, for Q3 CapEx, should that be pretty similar to Q2 before it drops off in Q4? Can you just help us with that?

Yes. I would say, yes, Leo. Our CapEx spend and we probably did a poor job of messaging earlier this year, it looks much more like what I would say a bell curve where we're spending the majority in the second and third and lesser amounts in the first and fourth. And that's, kind of traditional as well especially fourth quarter as most people – it ramps down a lot. So, I would say second, third quarter should look a lot like.

Thank you, Cary.

Yes. Leo, just to add a little more color to that. As you know, we've been operating with two drilling rigs in California. And then in mid-July, we picked up a third drilling rig. So, we'll be operating in California with three rigs in Q3, and then we'll drop back to two rigs for Q4.

Okay. Thanks Fernando.

Hey, Leo. Leo?

Yes.

I forgot when you asked, can I go back to your first question for a second? This is Trem.

Sure.

The other part of this is, and we've mentioned it in the call, is that we are well on our way to having – well, we have the permits for 2021. We're well on our way to having everything we need in 2022, and we've even got permits in the system for 2023, okay. So, I just want to make sure that's clear as well.

Okay. That's great additional caller. Thanks Trem.

You bet.

Thanks Leo.

Your next question comes from the line of Charles Meade with Johnson Rice.

Good morning Charles

Good morning Trem and Fernando and Cary. Thank you for all your comments. I was able to speak with Todd a little bit last night on this. But Fernando, I wondered if you could give a little bit more detail on what happened with this offset operator? And I'm sure there's a lot of detail that probably is not appropriate for this form, but what I'm really curious about is how many similar circumstances exist in your portfolio or put differently, how many other places across your asset base could another offset operator affect you in this way?

Yes, Charles. Let me give you a little more detail on that. The problem was really two-fold as we had a decrease in water withdrawals, down dip in our reservoirs, and that was related to the offset operator. And then at the same time, we had a reduction in steam injection rates up dip. So, this allowed the aquifer to encroach or reservoir causing early breakthrough and lowering our reservoir temperatures. As we've mentioned already, thanks to our talented engineers, they've taken corrective measures. We're already seeing a positive response from the reservoir, and we've already arrested the production decline. Now, we really don't have any other places similar – with a similar situation as this. And again, this was in Poso Creek, and we do not have any other fields with a similar situation.

Yes. Charles, in – Poso is a nice field, but it's a small field roughly probably about a thousand barrels a day on average over time. So, again, I think this is, kind of a one-off, but the point of pointing it out at this point in time is because I was concerned, the market is not seeing the visibility to our capital efficiency on new production. So, we don't usually like to point out things like this, but I think it's good to give the transparency and visibility, so the market does understand when we put capital to work we get bonds out of it. And again, as Fernando pointed out, this is starting to move back in the right direction, but you are dealing with steam. And with that, the predictability of when it comes back fully, it takes some time. So, we just want to be full and transparent with that.

Got it. Thank you for that Cary, and I understand there's always a lot – there's a lot of momentum in these thermal operations that can go in both directions. Going back to the – to ask another question about the assets, you mentioned on your prepared comments that the Utah wells that you have – that you brought online or above your type curve, but can you refresh us on what your targets are there in the Uinta Basin and what kind of results you were looking for? What kind of results you got?

Yes, Charles. We do like the flexibility of our development program in Utah, especially at current prices, and we've had excellent results. Generally speaking, our wells in Utah have a better IP than our wells in California, and we're looking at three-digit IPs, and we're getting those IPs from the three wells that are currently on production. And again, we'll have another seven wells on production in Q4 – I'm sorry, in Q3. Again, I want to emphasize that Utah is a very predictable conventional reservoir, and it does provide that flexibility that's very attractive, especially at current prices. And it will be part of our development plan in 2022 as well.

Okay, great. Thank you. I’ve got another two more questions, but I’ll hop back in the queue and let somebody else take the line. Thank you.

Thanks Charles.

[Operator Instructions] Your next question comes from the line of Nicholas Pope with Seaport Research.

Good morning guys.

Good morning Nick.

I was hoping we could talk, you know looking at 2022 strong cash flow profile coming with those hedges rolling off, when you look at the balance sheet with the existing note that you have in place, I guess how are you looking at that $400 million, I guess, the [callability] features of that? And I mean, how is that look – how are you looking at that with kind of this cash flow profile because it's the only piece of debt you have outstanding right now? How are you thinking about that instrument relative to, kind of the balance sheet and what you want the company's balance sheet to look like going forward?

Yes. I would say it's fluid, Nick, obviously. These businesses are easier to manage without leverage, right. But I think the right type of leverage works. I think that piece of note works very well for us because again, high yield, fairly low-cost of capital, plenty of flexibility on the covenant side. So, it doesn't – it's not restrictive. I think that the idea for us is really how does our overall free cash flow, where do we get the greatest value for our shareholders is what I think about when I look to 2022. Is it lower debt? Is it a return of more capital back to the shareholders? I think that's what we're trying to solve at this point in time to figure out where we get the biggest bang for the buck. The maturity on that is still at [indiscernible], so we do have time. We're out of the make-whole period of time on it, so you don't have a huge call premiums that you would normally have. So, we do have flexibility if that's the best use of cash to be able to pull some of that back. But at this point in time, I think it's still a fluid conversation, to be fair.

Got it. And when you look at it relative to your credit facility, is the commitment still $200 million but it's out of – I mean, I think the total revolver is – is the number right, 1.2 billion is that – I guess [indiscernible]?

Yes. I think right now, based on $500 million was a $200 million elected commitment. And again, that's – we really keep the elected commitment as skinny as possible because there's no use to be paying a 50 basis points on an unused of anymore. I think the $200 million is kind of works well with the rating agencies from a liquidity profile point of view. So that's kind of – there is a formula on how we're looking at elective commitments. But again, from a company that lives out of levered free cash flow, who keeps quite a bit of money or cash in the bank at this point in time, the need to have substantially more than that is not needed at this point in time. Obviously, if a transaction comes down the pipe where something's needed, we can move quickly. It's something we could tap into, but that's kind of how we're looking at it.

Got it. Thank you. And just real quick on Utah, just – these wells, is it that – is it still the waxy oil that's, kind of locked into the Utah markets and what's the pricing dynamic right there, if so, on that oil? It's been a while since the focus on Utah.

Yes. I would say it is – we are primarily black wax. It primarily stays only in the Utah market. We have contracts that are up to a year on supply point of view. And right now, we're roughly about 90% of WTI, 88% to 90% of WTI. So from a transport point of view, obviously, local is best because of reduced overall cost. But it's an attractive at current WTI and what that oil is and all that, it's an attractive return. And part of the reason we're also putting it to work is the market is actually clamoring for more oil in that market from local producers. Much like California, we've seen that market’s supply decrease. And those three refiners need to continue to keep their feedstock, and they've looked for producers like Berry who has consistently worked in that market, kept a consistent production profile as somebody they want to work with, and that's allowed us to get longer-term contracts at better pricing.

Yes, there is refining capacity in Salt Lake City, especially for our crude with the black wax that Cary was talking about.

Got it. So, it sounds like there was a signal that was, kind of – it is driving this uptick into activity that there was demand that's kind of pulled in that.

There is demand and it is demand that they're looking for. I mean, it's supply that they're looking for. And I think it's still an attractive market for us. We are what we are. We have organic growth opportunities there, but eventually, we have some level of cap on those organics to make sure we're keeping supply and demand in that market in good shape for Berry.

Got it. Fantastic. That's all I have. Thanks guys.

Thanks. Appreciate it.

You do have a follow-up question from Charles Meade with Johnson Rice.

Thanks for letting me back in. I had this maybe – this question maybe kind of far field, but going back to California operations there's a lot of news that water, like reservoir water is low, and there's an upside to that for you guys in the less hydro generation. And so there's maybe a – and there's the market sees that and talk about California electricity prices being up, and you guys would be a beneficiary that would be – with all your cogen facilities. But is there any exposure that you guys have on – so is that something that's on the horizon? And is it – could it be material to Berry? And then along with that, is there any exposure that you guys have about access to water to actually run your cogen or your steam facilities?

Why don't you start Fernando?

In terms of our operation itself, we've got enough water that we produce and that we treat and to be able to satisfy the needs that we have in terms of steam. In fact, we use about 40% of our total water production to generate steam, and then the rest is used in a water flood that we have and then it's also sent to third parties for disposal as well, and we dispose the water ourselves. So that's – so in short, we don't need any additional water for our operations.

Got it. And then – but is the potential for higher electricity sales something that could actually turn the dial for you or is it not something we should really be attuned to for Berry? Maybe that's more of a question for Cary.

Yes. I think, obviously, Charles, this is the high season for us on electricity sales. And I think right now we're looking at more – I mean, prices can be higher, demand could be higher. We haven't seen the amount of rolling blackouts and brownouts that we saw last year. We have seen an increase in natural gas prices. If you think they're high everywhere else, you should see California at this point in time. I think that would be the trigger what's going to drive it. That for whatever reason we haven't seen, at this point in time, the amount of brownouts that we had last year. So, I think right now, we're trying – I'd say it's going to be more seasonal with a potential for upside and probably not a potential for downside risk. That's how I'd answer that.

That was a characterization I was looking for. Thank you, Cary.

Alright. Thanks Charles. I appreciate it.

Thank you. This concludes today’s Berry Corporation’s second quarter earnings call. You may now disconnect.