Good afternoon, ladies and gentlemen, and welcome to the Berry Corporation Third Quarter 2019 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded. And without further delay, I would like to hand over the conference to your host, Mr. Todd Crabtree of Investor Relations.

Thank you, Ian, and welcome to everyone. Speaking this afternoon will be Trem Smith, Board Chair, CEO and President; Gary Grove, Chief Operating Officer and Executive Vice President; and Cary Baetz, Chief Financial Officer and Executive Vice President. Trem will review activities and highlights from the quarter, Gary and then Cary will discuss our key operational and financial results. Trem will have a few concluding remarks. As a reminder, today’s call contains 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 from those expressed or implied in these statements. These include risks outlined in our public filings. Our website bry.com has a link to the November Investor Presentation. Our website also includes reconciliations for the non-GAAP financial measures we use to the related GAAP measures from our financial statements. Later, we will also post the replay link of this call and the transcript on the site and we will file the 10-Q later today. I will now turn the call over to Trem Smith.

Thank you, Todd, and thanks everyone for joining us today for our third quarter earnings call. This quarter was extremely productive for Berry. We delivered according to plan, growing total Company production by 8% and California production by 10%, since the second quarter. And we’re confident this growth will continue into the fourth quarter. Our focus continues to be on creating value for our shareholders across market cycles through a combination of growth and returning capital. Specifically, this year, we expect to see double-digit production growth of about 12% companywide, providing attractive dividend yield, and have repurchased 4% of our stock. We’re also pleased to announce that the Board has approved a fourth quarter dividend of $0.12 per share. We are delivering on our promises, and we are executing within levered free cash flow, which we define as free cash flow, less dividends and the capital to maintain production. Towards the end of the second quarter, we began to see the fruits of our 2019 capital program and that production growth continues today. The Company’s third quarter production was in-line with our plan at 29,600 barrels of oil equivalent per day. We are projected to end the year in-line with our full year production guidance. In California, where we spent 91% of our capital year-to-date, we grew 10% in the third quarter. Importantly, we are demonstrating that our assets respond to capital investment, and if we can toggle our capital spend and therefore production up or down to best maximize shareholder returns through all market conditions. We’ve recognized our business model is distinct from most other E&P companies in the market. Unlike the resource plays in which each well starts off at a maximum production rates, IPs, a significant portion of Berry’s California production ramps up over a period of time, reaching peak performance, sometimes four to six months after initial production. We have included type curves on Slides 13 and 14 of our November Investor Presentation that illustrate this significant difference. In addition to help you with your modeling, moving forward, we will provide CapEx projections a quarter in advance, as CapEx is not linear from quarter-to-quarter. For the fourth quarter, we expect to invest $35 million to $40 million, which will put total 2019 CapEx slightly below the midpoint of our guidance. In 2020, we expect to continue to deliver shareholder total returns in the mid-teens through production growth and return of capital to our shareholders by utilizing all the tools available to us, as outlined on Slide 22. The regulatory landscape in California continues to be a topic of interest to our shareholder base. The California legislative session closed September 13, and will begin again on January 6 next year. However, our Berry First efforts continue. We’re committed to protecting our assets. Our Corporate Affairs department, our government and regulatory teams and I, are all actively participating in the California regulatory process with various outreach strategies and programs. With our investments and focus in this area, we are now well positioned to respond to potential regulatory and legislative activities. So far, our approach has been effective in helping to minimize the impact of these actions on our business. Last, this past quarter, we engaged a third-party consulting firm to conduct a perception study to gauge how the investment community views Berry’s performance as a newly public company, as well as to better understand the Street’s perception of the industry as a whole. Overall, one of the key takeaways from this study was that the investment community values strong free cash flow, a healthy capital return strategy, and a conservative leverage profile. And we believe Berry delivers on all of these points. Berry has lived within levered free cash flow through all market conditions, has consistently paid the dividends since going public, and maintains low leverage at 1.4 times its debt to EBITDA. Additionally, Berry has grown low-risk production from the existing asset base, has production heavily weighted towards oil benefits from Brent-based pricing resulting in attractive margins, and has based on management estimates at least a 20-year inventory of future drilling locations. On top of that, we are well hedged for the remainder of 2019 and throughout 2020. Accordingly, Berry is in a strong position to continue to create and deliver top tier value in the space. I’ll now turn it over to Gary, who will give you greater insight into our operational performance for the third quarter.

Thank you, Trem, and thanks everyone for joining us this afternoon. First, I’ll speak to production. Third quarter production growth continued to build on the momentum that began at the end of the second quarter, and we are pleased results are in line with our full-year guidance. Our companywide third quarter production of 29,600 BOE per day was up 8% compared to last quarter. To further illustrate this growth, September’s average production rate was 31,700 BOE a day compared to June’s average of 27,400 BOE a day, resulting in a monthly exit rate in September that was 16% higher compared to June’s exit rate in the prior quarter. Our production mix in the third quarter was 87% oil, 12% gas and 1% NGLs, with California making up 78% of total production. For the month of September, production was 88% oil. In California specifically, production for the quarter consisting of 100% Brent-based oil was up 10% compared to the second quarter and 18% from the third quarter of 2018 to third quarter of 2019. The monthly production exit rate for the quarter was 25,400 BOE a day, up 25% compared to the second quarter’s exit rate. As Trem noted, this improved growth in our California production is directly attributed to our strategic capital deployment in the first half of the year. That brings me to capital expenditures. Overall, our spending is in-line with our expectations. Consistent with our plan, CapEx for the third quarter of 2019 was $63 million, compared to $57 million in the second quarter. We drilled a total of 82 wells in the third quarter, 31 thermal sandstone wells of which 30 were producers, and one was an injector, and 50 thermal Diatomite wells in California, as well as we also drilled one well in the Rockies. We also hydraulically stimulated 25 wells in our Belridge field during the quarter, which completed our stimulation plans for the year in that area. This work compares to 114 total wells drilled and 10 hydraulically stimulated in the second quarter. We are currently running three rigs in California, and plan to continue running up to three rigs for the remainder of 2019. The increasing capital quarter-over-quarter is a result of equipping and bringing wells online that were drilled in the first half of the year, as well as costs associated with hydraulic stimulations. We do not expect the same proportional increase in equipping costs in the fourth quarter. Additionally, we have spent $20 million year-to-date, $8 million of which was in the third quarter for plugging and abandonment requirements. As you may know, earlier this year, the state implemented new regulations, which essentially require all oil and gas companies to accelerate the abandonment activities on older idle wells. We have submitted our plan to address these idle wells, and are working with the California Department of Oil and Gas for its final approval. Last, I want to touch on expenses. Our third quarter unhedged OpEx was $18.13 per BOE versus $18.94 per BOE in the second quarter, a reduction of 4%. Including fuel purchase hedge contributions, OpEx per BOE in the third quarter was $18.90 versus $20.38 in the second quarter, a reduction of 7%. This OpEx reduction during the quarter was primarily driven by holding costs stable, while growing volumes. As we expected and planned, our natural gas fuel usage rate remained flat from the second quarter to the third quarter at approximately 75,000 MMBtu per day. Our average unhedged purchase price for the third quarter was $2.67 per MMBtu compared to $2.03 per MMBtu in the previous quarter. And with that, I’ll now turn it over to Cary for our financial performance.

Thanks, Gary. To start, third quarter and year-to-date production and capital spending are in-line with our expectations and our full year guidance. Our adjusted EBITDA increased 34% to $83.9 million, largely due to increased production from our California Brent-based oil assets. We accomplished this, despite the 9% quarter-over-quarter drop in Brent oil prices. As Gary highlighted, our third quarter OpEx per BOE notably improved versus the second quarter, primarily due to our ability to hold absolute non-energy operating costs flat, while increasing production. The non-energy portion of our OpEx was $14.09 per BOE in the third quarter compared to $15.53 in the prior quarter. The energy portion of our OpEx was up about $1 million more than the second quarter. Due to unusually high fuel costs in the first quarter of 2019, we expect our full year OpEx per BOE, including fuel costs to be on the high side of our original guidance. We began heavily hedging fuel gas prices – purchases in April of this year to mitigate volatility that resulted from unseasonably cold weather and caused gas prices despite to levels much higher than they had been in at least four years. Given that the system remains vulnerable to disruptions and increased volatility, we have hedged the majority of our fuel gas needs through the end of 2020 at roughly $3 per MMBtu, and have begun the layering in hedges for this first quarter of 2020 at approximately $2.50 per MMBtu. Please see Slides 21 and 29 of our November Investor Presentation. Oil hedges were effective in protecting our cash flow from lower Brent pricing during the third quarter. Compared to the second quarter, lower prices had a $9 million negative oil price impact. However, our hedge settlements contributed a positive $17 million on a quarter-over-quarter basis. On an unhedged basis, adjusted EBITDA was $68.8 million in the third quarter compared to $66.1 million in the second quarter as the result of increased production. We continue to manage our oil hedge portfolio, and now have Brent swaps at $70.20 per barrel on more than 60% of our expected fourth quarter 2019 oil sales. We’ve continued to layer in the 2020 hedges and have 16,000 barrels per day of 2020 production hedged at $64.25 Brent and another 1,000 barrels per day hedged through April at $61.75 WTI. Please see Slide 20 of our November Investor Presentation. General and administrative expenses dropped 7% to $6.04 per BOE in the third quarter compared to the second quarter. Adjusted G&A expenses, which exclude non-cash stock compensation and certain non-recurring costs equaling $0.91 per BOE in the third quarter, were $5.13 per BOE compared to $4.92 per BOE for the second quarter. This increase was partially due to higher insurance renewals and true ups. However, the primary driver was and continues to be the development in growth of our Corporate Affairs department and the activities intended to support our efforts and participation in the regulatory, political and legislative process, primarily in California. We have been building our capabilities and expertise in this area and our investment has already provided positive results due to the team’s ongoing efforts to partner with the state to bring affordable energy to its citizens and becoming less reliant on foreign energy sources. As a result of this initiative as well as our continuing efforts to improve our internal systems and comply with public company requirements, our full year adjusted G&A will be on the high-side of guidance. For 2020, adjusted G&A costs should come down on a per BOE basis. Our taxes other than income taxes are comprised of ad valorem, property taxes, and severance taxes. In total, costs were $2 million lower in the third quarter compared to the second quarter, largely due to decreased market rates for our greenhouse gas allowance requirements in the third quarter. Additionally, taxes other than income taxes will come in on the low-end of our 2019 full-year guidance. Capital expenditures in the third quarter were $63 million, a large portion of which were used to equip and bring online a significant number of wells, which were drilled in the first half of the year. Per our 2019 plan, we expect fourth quarter capital spending to drop off significantly such that, total year capital is expected to come in slightly below the mid-point of our guidance. We expect fourth quarter total capital to be in the range of $35 million to $40 million. Our third quarter adjusted EBITDA exceeded our capital expenditures of $63 million by more than $20 million, and we generated positive levered free cash flow for the quarter, which includes interest and dividends. Year-to-date, we have spent $36 million in stock repurchases. At the end of September, we had availability of $381 million on our $400 million RBL Facility, which included $9 million of letters of credit and borrowings of $10 million. Based upon current pricing, we expect no borrowings on the revolver by year-end. We manage our business over the cycle, not on a quarterly basis. Our capital plan is set each year and is designed to operate within levered free cash flow. On a trailing 12-month basis, at the end of the third quarter, we had a break-even levered free cash flow, which included $222 million of capital expenditures, $35 million of interest, and $40 million of dividends declared. At the current prices, we expect realized positive levered free cash flow for the full year of 2019. Now, I’ll turn it back over to you, Trem.

Thanks Cary. Before turning it over for questions, I’d like to make a quick comment about our 2020 budget. We are currently in the process of preparing next year’s budget. But we do know the spending will be down, and we will see strong year-over-year growth. We look forward to disclosing more in February. In the meantime, we will continue to keep our heads down and to execute our plan with excellence. I will now open it up for questions.

[Operator Instructions] Your first question is from Leo Mariani from KeyBanc.

Yes. Hey guys, just a question here on free cash flow. So obviously, you’re expecting significant free cash flow in the fourth quarter. How do you think about sort of deploying that? You talked about paying down small revolver balance. Obviously, there will be more cash as well, do what you want with it. Are you thinking about getting more aggressive with the buyback or thinking about kind of boosting the dividend? How do you think about free cash flow in the fourth quarter going forward?

Yes. I think, we’ll talk about excess free cash flow, not only in the – this is Cary by the way – not only in the fourth quarter, but actually talking in 2020 and beyond. I think the opportunities for us to do with that excess levered free cash flow will include various things, special dividends, increasing the dividend, bond repurchases, and continuing to grow our assets. And it’s all going to be based on the return and what gives the best return and creates the greatest value for our investors. So, it’s probably a more generic answer than what you want, Leo. But I think it’s hard to put ourselves in the box until we actually get to the point to understand which one is going to give the greatest amount of value back to us and to our investors.

Okay, understood. I guess, I know you didn’t mention buybacks of shares on that list. Is that something that’s on pause for now?

Yes, I missed that, but yes, that’s still an option out there for us and we have that. And that will also still be, as Trem would like to say, one of the tools in our toolbox.

Okay, that’s helpful. And I guess, perhaps you could talk a little bit more about the regulatory environment in California. It seems like the new Head of DOGGR has been a little bit more aggressive than the previous head. And I know he has levered some fines on some companies, and I guess there were some trading over some frac permits that were issued as well. How do you think about what the administration from DOGGR’s perspective feels about fracking out there these days in California? And how do you think the new head kind of feels about some of the proposed set-backs that were talked about this past spring?

Hi, Leo, this is Trem. I’m going to start, and then Gary can bring in some more detail. First of all, the new Head of DOGGR is just or maybe hasn’t yet taken his seat, okay. So the fines that were levied against Chevron were in the works and are related directly to the activities there. And that’s all I’m going to say about that. That wasn’t necessarily unusual. There have been a lots of calls and meetings with DOGGR and the Department of Conservation about the well stimulation permits, which are the – what you call the fracking, which are very different in California than the fracking in the Permian for example. And those are going to be under way, is my understanding. There is no intent to stop them. And we are very much and very active in the Western States Petroleum Association as part of our activities, and that has been a front and center with the Governor and the Governor’s offices. So, we’re very pleased with the way that’s going. The other permitting is DOGGR’s business as usual. So right now, we’re waiting and seeing, obviously. But the new DOGGR Head actually has oil industry experience and he is coming from LA. And so, he is very familiar with California and the political environment as well as the need for energy in California. I look forward to meeting him. Gary?

I’ll just reiterate a couple of things that Trem has mentioned. So as far as permits for fracking or hydraulic stimulation, they’re called WSTs. That has been a little bit delayed, as you mentioned. However, for us that has no impact on us for this year or into the part of 2020 is that we do not have any outstanding request in for WST permitting at this time. But it is a direct result of them, putting someone in that share, which has been done. And I would just add the fact that we’re in communication with them, our teams led by our Corporate Affairs Group is – and Trem has been very active in making sure that we are in participation with regulations going forward. So it’s probably easiest thing to say. But right now for us, we don’t see any impact there. And lastly, as Trem mentioned, our other permitting is not associated with this. It just permits to drill. And those are moving forward, as you might expect.

Hi, Leo, this is Cary. You’re going to get a triple on us on this one. I just wanted to point out in the November Investor Presentation, on Slide 32, we now start to list the status of California Legislation and also the expected impact on Berry, so people can go out there and see at least what current legislation is and our view of the impact on Berry, to give a little more transparency.

That’s helpful for sure. And I guess, I certainly noticed that your Utah oil prices were better this quarter, much tighter dips. Is anything sort of changed out there or maybe that was just kind of timing on sales or whatever?

No. This is Gary. So it’s a little bit of a reflection of the current market, as it moves in that particular area. I think you noticed that we drilled one well or may have not noticed, but we drilled one well in the quarter in the Rockies. And we’re always paying attention to that. We like what we have there. And when we see those market conditions rise to a favorable position, we like to take advantage of it.

All right. Thank you.

Thanks, Leo.

Thank you. The next question is from Charles Meade from Johnson Rice.

Yes. Good afternoon to the whole team out there. I want to say, thanks ahead of time for this update on Page 14. But I wondered, if you could just give us a quick refresh of – which of these three type curves you see as most attractive right now, given not just oil pricing, but also which you referenced with the increased fuel pricing and of course capital costs and all the other things?

Excellent. Well, this is Gary again. So I’d tell you that, the one to concentrate right now on this page would be the thermal Diatomite, which has been a bulk of the opportunity that we’ve been taking advantage of in this quarter and then looking at how these – if this is essentially a comparison of Berry to the resource plays. But for us, we’ve been spending a lot of our capital in thermal Diatomite during this period, and also in the sandstones. So, those are the two type curves that I would tell you, you want to pay the most attention to at this point in time. As I did mention, we drilled – of the 82 wells we drilled in the quarter, 30 of them were in the sandstones plus or minus and 50 of them are in the thermal Diatomite.

Right. I see that on Slide 31. I’m sorry to interject you but – but just what we should be taking away is that’s where you’re focusing on your activity, those are your best returns right now. Am I understanding that?

Yes. That is correct. So we’re – and we always try and do that obviously concentrate on the best returns that we have in the opportunity list. But definitely for this quarter, that is where the capital was employed.

And I’d like to just – this is Trem, just one more point. Those type curves are based on hundreds, if not thousands of wells, okay. Those are not one or two wells that define that type curve. Okay. And so, there is a lot of data that suggests that those are good type curves.

Got it, got it. Thank you. And then one other question. This is more of a bigger picture question. But one of the big themes in the E&P space broadly I think maybe – you can call it the unconventional E&P space. Is getting to the right scale. And I’m curious, is that a relevant question for you guys whether the scale big – perhaps not of your total asset footprint, but of your – the right scale for your operational pace? And I guess you could apply the question to, are you at the right scale in California? And also, are you at the right scale in some of your more Rockies assets, like Uinta and Piceance?

This is Trem. I can answer that several ways. But the feedback we get in the sense we have is that scale is important to Berry. Our teams are in place and our ability to execute are fully in place and scale is a big deal going forward. I will say, however, we’re continually looking at how to improve the scale or grow the scale. And we do small bolt-ons we’ve talked about in the past. We are focused in areas that we do well in, that would be the west side of the San Joaquin, the Midway Sunset field in particular, as well as we’re very, very good in Utah. Now that said, we’re always looking at transactions, but we’re looking for value-adding transactions. And otherwise at this stage, we don’t comment any further on the status of those.

I’ll add on as well Charles, it needs to fit within our financial policy. We have a very good asset base. We have a very good operation. And we don’t need to have a balance sheet that screws up what we’re already providing from growth and return of capital. So as Trem says, that needs to be a value-added transaction.

That’s an important point to add. Thank you.

Thanks, Charles.

You’re welcome.

Thank you. The next question is from Kashy Harrison from Simmons Energy.

Good morning. Hey, good evening. And thank you for taking my questions. I guess maybe the first one, big picture. You highlighted that and I know you don’t want to share much details on 2020, but you did highlight that capital should be moving lower on a longer-term basis and maybe not necessarily 2020, but as we look through the next three or five years. Do you have a sense of how you think about the amount of growth you want to have, the amount of free cash flow yield you want to have? So do you want to be like a 5% grow over the next five years? Do you want to be a 10% grower? Just trying to give a sense of how we should think about Berry’s growth rate over the medium term?

Yes, Kashy, it’s, I don’t want to be pinned into a corner neither is Trem or Gary. I think the idea for us is looking at it at total return and what makes the most sense during any particular year. As Trem pointed out, we have a unique asset base that allows us to toggle both up and down. And as you have heard in the past, we keep a two-year plus ball-pin of things we can move in and out at fairly quickly. So I think it gets all back to what maximizes the value back to our investors. So is it growth? Some years, it may be growth, and some years, it may be returning more capital back to us. So I think what our idea is at least from a total return point of view, even in very tough markets trying to focus on a 10%-plus type of total return, which would be a combination of growth and return of capital either in the form of the dividend, share repurchases, special dividends, and/or bond repurchases, as well. But we do have a – I mean, again I want to act like, we have a five-year plan, but as you know that is good as, it’s not much worth more than the paper it is written on based upon market conditions, right. So I think we have pretty good visibility for the next couple of years. Beyond that, it’s just kind of speculation on strip pricing.

And this is Trem, Kashy. I guess, I would like to add to that is the context of what our business model is. And we are focusing California, which you’ll remember is Brent based, it’s isolated from the rest of the United States. And the energy, every barrel of oil, we produce in California is used in California. And so, we have a very captive market here, as their energy needs actually grow. And we have now, so when I say at the end, probably the most important piece of this is all of this is based on our ability to execute and keeping our head down and executing through the market cycles. It gives us the opportunity to discuss the distribution of the value back to our shareholders, which is – we want to maximize that value. So we look at it as growth, plus the return to shareholders together. And we have luxury of being able to go either way or both.

Okay. That makes sense. And I guess, maybe just for my quick follow-up. You guys highlighted really strong volumes in September. I think, it was about 31,700 barrels of oil equivalent per day with an 88% oil cut. Is the expectation that as you guys look at production in October and November, December that you’re sort of holding that September rate flat? Or with all the wells that came online in Q3, will the expectation be for that rate to maybe inch a little bit higher entering 4Q?

Kashy, this is Gary. And so, we’re excited about where we are on rate and we like where we are and we’re happy with where that projection is going to be. Let me answer it this way, if I can, without just giving you a straight number, using the information that’s available to us all. I think we’re guiding you to – in line with our annual guidance. And I think if you take the first nine months and you figure roughly around the midpoint of guidance, then you can figure out what the fourth quarter is going to look like on an average rate. And you can kind of see what that change would be from that September rate.

Okay. Thank you.

I think answers your question I think with the information that’s available to us all.

I am doing the math now and want to look at further confirmation. Okay.

And remember we spend money now and we spend money in the first half, as we’ve said. And we’re seeing the results. So, the results for the rest of the year are based in large part on capital that’s already been spent.

Got it. Thank you.

You bet.

Thank you. [Operator Instructions] I’m showing no further questions at this time. I would like to turn the conference back to CEO, Mr. Trem Smith for closing.

This will be very brief. We appreciate all the participants and thank you very much for joining, and we look forward to talking to you next quarter.

Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation and have a wonderful day.