Berry Corporation (Bry) (BRY) 2018 Q2 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Berry Petroleum Second Quarter 2018 Earnings Conference Call.

(Operator Instructions)

And as a reminder, this conference is being recorded. Now, it's my pleasure to turn the call to your host, Mr. Todd Crabtree with Investor Relations.

Thank you, Carmen. Welcome to the Berry Petroleum Corporation's Second Quarter 2018 Earnings Call. Speaking this morning will be Trem Smith, President and Chief Executive Officer; Gary Grove, Executive Vice President and Chief Operating Officer, and Cary Baetz, Executive Vice President and Chief Financial Officer.

Trem will review our objectives and strategies, our differentiators and second quarter highlights. Gary will discuss our key operational results. Cary will follow with an overview of Berry's financial results. Trem will have a few concluding remarks before we open it up to questions.

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 related to volatility and the price paid for our production, the capital intensive nature of our business, our hedging program, regulations, operations, reserves estimation and competition.

We refer to non-GAAP financial measures and we'll provide a reconciliation of GAAP with our financial statements. Today, we will be referencing slides from the August 2018 investor presentation deck which is posted on our investor webpage. The replay link of this call and a transcript will be made available on our investor webpage.

I will now turn the call over to Trem Smith, Berry's President and CEO.

Thanks, Todd and good morning, everyone. I want to welcome everyone to the first Berry Petroleum earnings call as a public company. Berry is focused on value creation for our shareholders. Our business model is simple and clear. Our goal is always to generate top-tier EBITDA growth while operating within our levered free cash flow. We manage to value and not just to volume growth. We do this through operational efficiencies, production growth and incident prevention. Our results this quarter reflect the implementation of this philosophy as well as our focus on executing our plan with excellence. We are starting to see the results.

Production is growing and in line with our guidance for the year. Operationally, we are in full swing as we have begun completing wells this current quarter in two of the largest oil fields in the Lower 48, 60 wells in our South Belridge Hill lease as well as over 80 completions in our thermal diatomite property in the Midway-Sunset field. Both fields are shown on slide 20.

With three rigs now drilling in California through the rest of the year and four rigs planned for all of 2019, we are well positioned to continue to manage and grow our base production and generate double-digit growth rates into the future. Gary will provide more detail on this later in the call.

Adjusted EBITDA is up for the quarter. Costs are significantly down and our realizations for the entire company were 91% of Brent. We recorded continuing improvement in our safety and environmental metrics in the second quarter, for example our Value Loss metric, a key metric driving our focus on value creation through incident free operations is meeting our expectations.

We restructured our hedge position to reflect the current market and better position us going forward as shown on slide 14. The mark to market impact of the hedges drove our earnings loss which Cary will explain in more detail in a moment.

In addition, the board has approved our first regular quarterly dividend as a public company. It is $0.12 per share for the quarter which equates to a $0.09 per share prorated from the IPO date. The dividend affirms the management's and the board's confidence in our ability to execute and grow our inventory of opportunities and our commitment to returning capital or said another way, immediate value to the shareholders.

Looking ahead, our critical path is to focus on executing our plan, on continuing to optimize our core organizational strengths including oil production and thermal stimulation and on value growth. We intend to do all of this while maintaining the financial discipline of investing within our levered free cash flow as simply described by our financial policy shown on slide 15.

Our successful IPO was completed on July 26 and we are excited to be a public company. Yet even though we are now public, we are still operating with the same core principles we did when we were private. With that in mind, I'd like to remind you about what makes Berry such an attractive business opportunity.

First, we are focused on the production of low risk black oil. Today, over 80% of our production is oil and with our current plan, this percentage will continue to grow. In California, we produce 100% oil. All our production, company-wide, comes from conventional reservoirs. This is important as we are not a resource play company and we do not conform to the typical U.S. resource play thematic narratives as shown in slide 6. Therefore we do not face the "treadmill" conundrum experienced by the unconventional shale players.

Second, our relatively low all-in cash cost of approximately $40 per barrel, which Cary will discuss shortly, and our high margins put us in a position to generate significant levered free cash flow well into the future. Our corporate decline rates as shown in slide 8 are significantly lower than other U.S. E&P companies, we are not seeing service cost inflation. Our wells in California are shallow, in other words low cost to drill and to complete, and for many, the cycle time from drilling operations to sales can be short to six to eight days.

In addition, Berry's crude production is heavily influenced by Brent pricing. As a state, California produces only about a third of its daily energy needs. The remainder comes to the California market, not through pipelines from the Lower 48, so not the Permian, Eagle Ford and Bakken for example, but from tankers, the majority of which originate from foreign sources such as the Middle East and South America as shown on slide 9.

Third, our financial policy remains simple and unchanged. As I just mentioned, we operate within levered free cash flow which includes interest and dividends through the entire price cycle. We manage our balance sheet prudently, return capital to the shareholders, hedge to protect our base production and maintain capital flexibility also through the price cycle.

Fourth, we are focused and proactive in our business approach. Geographically, our operations are concentrated in two large basins with proven hydrocarbon systems and tremendous upside. The San Joaquin in California is an established super basin, with cumulative production to date of about 17.7 billion barrels of oil equivalent, 86% of that is black oil. Our assets are located primarily in one county, in Kern County which happens to be the third largest producing county in the Lower 48 as seen on slide 4.

Our second basin in the Uinta Basin in Utah, also a significant oil province and one in which Berry has a significant continuous leasehold. We are also focused within those basins. In California, for example, our production is located on the rural west side of the San Joaquin Basin in three of the most prolific oil fields in the basin, South Belridge, Midway Sunset and McKittrick as seen on slide 19.

Operationally, we are very good at and intend to improve our core strengths, including our ability to thermally stimulate reservoirs, for example. And I should mention here that we have a "Berry first" proactive approach to permitting and working with our regulatory partners in California, Utah, Colorado and Texas, by planning for activity well in advance, taking the lead on regulatory efforts impacting or potentially impacting Berry and building exceptional relationships with our regulators, we work to mitigate the risks associated with permitting our activities.

Fifth, we are also focused on executing our five-year plan which anticipates double-digit yearly production growth. Due to our large and growing inventory of low-risk, high-return, high-margin drilling opportunities and the short cycle time from spud to sales, we have adopted a two-year budgeting cycle to manage our permitting, supply chain and logistics processes prudently. As I mentioned earlier, we are operating three rigs in California through the end of the year and plan to grow that number to four in 2019. This is compared to averaging only 1.5 rigs in 2017.

Finally, we are well positioned to grow. We are growing our base production and at the same time increasing our inventory of opportunities within our leasehold. All our growth projections are based on opportunities in our existing producing acreage. Our strategy for inorganic growth is primarily through bolt-ons and a robust pipeline of additional M&A opportunities adjacent to and nearby our existing core areas and fields. The number of these opportunities is significant. We are positioned to be a natural consolidator, particularly in California.

In conclusion, it has been an action-packed and a game-changing year and a half for the new Berry since its creation in March, 2017. First, I assembled our executive management team. Together, we divorced Berry completely from its previous owner, rebalanced the portfolio by selling a large non-core asset, optimized the capital structure by completing our bond offering and restructuring the hedges and have successfully executed our IPO. It's another way to demonstrate the team's focus, dedication and devotion to execution with excellence.

These are exciting times for Berry Petroleum and we are extremely excited to have you join us on this journey.

Next up is Gary to give our operations update for the second quarter.

Thanks, Trem, and good morning, everyone. So production for the second quarter was 26,500 barrels of oil equivalent per day comprising 80% oil, 18% gas and 2% NGLs, this is sequentially up 1% from 26,180 BOE a day in the first quarter primarily due to the initial results of our development activity in the first half of 2018.

Of the second quarter production rate of 26,500 of BOE a day, 18,800 of that came from California, 5,200 BOE a day from Utah and 2,500 BOE a day from Colorado and Texas. We commissioned a third rig in California beginning in April and drilled a single well in Utah resulting in capital expenditures of $39 million for the second quarter compared to $16 million for the first quarter.

We drilled 58 wells in the quarter versus 30 wells in the first quarter. Well performance in all areas is as expected, capital expenditures are also in line with our expectations. We plan to keep three rigs running in California through the remainder of the year and are currently evaluating additional opportunities in Utah as we continue to refine our reservoir management program for that area.

Turning to operating expenses, we had OpEx of $41 million or $16.89 per BOE for this quarter. This compares to $19.61 per BOE in the first quarter. The second quarter OpEx benefited from $3 million of lower LOE due to lower fuel gas costs, lower well servicing activity and increased oil inventory caused by the market disruptions in Utah. Electricity generation expenses were about $1.5 million lower than the preceding quarter due to lower fuel gas cost and taking over operating our co-generation facilities with internal staffing versus the past practice of using third-party operators.

For fuel gas, we burned approximately 68,500 MMBtu per day at an average price of $2.39 per MMBtu in the second quarter versus 68,000 MMBtu per day at an average price of $2.78 per MMBtu for the first quarter. Our teams are focusing on executing our 2018 development plan while ensuring our focus on safety and environmental impacts. As a reminder, our plan for 2018 includes volume ranges on key metrics which is also shown on slide 24.

Production between 27,000 to 30,000 BOE a day approximately 80% oil, OpEx ranging from $17 to $18.75 per BOE, taxes other than income taxes ranging from $3.25 to $3.50 per BOE, adjusted G&A ranging from $3.25 to $3.75 per BOE, and capital ranging from $140 million to $160 million for the year.

Now, as I've done previously, I'd like to share a few operating highlights from the second quarter and some that are in progress. Some of these are included on slide 20 in our investor presentation.

On the marketing side, we continue to monitor all areas for opportunities to compete in the market for our commodities. We also look to respond quickly to acute events or stay ahead of any future activity in our particular areas.

For example, in Utah, the HollyFrontier Refinery had a fire in the first quarter causing them to reduce their crude oil intake. We've actively moved a portion of our crude to other short-term sales points during this time. Holly is expected to be back up in the third quarter, we were also looking at additional opportunities to move our crude. The current situation has been brought about by increased production in the area along with some local refining limitations.

As we discussed in the LOE section, we are currently increasing inventory in the field to account for the issue, we expect to see continued pressure through the remainder of the year and are taking appropriate steps to maximize the value of our operations during this period.

In California for purchased gas, we continue to look for options to lower our cost and protect against acute swings in the California gas market. As a reminder, we take gas from mainly two pricing points, the majority of our gas, approximately 56,000 MMBtu per day, is purchased through the Kern delivered system and it's where we also have 15,000 MMBtu a day hedged. The remaining gas, approximately 12,000 MMBtu per day, is purchased through SoCal City Gate. This is primarily for operations at Placerita.

In both pricing areas, we are also protected against upper fuel cost price movement through our PPA contracts for electricity sales as the sale price is partly based on the cost of fuel. Turning to operations in California, as I mentioned earlier, we started to transition the operation of our five fully owned co-generation facilities in the last part of the first quarter. That transition is complete and we are seeing the impact of reduction in LOE during the second quarter.

We completed and brought online two pipelines in April that move fuel gas and soft water between our properties. This project realizes savings of approximately $0.50 per barrel of steam on about 4,000 barrels of steam per day going forward.

We recently began to stimulate 30 Hill diatomite producers in August and plan to stimulate an additional 30 producers later in the year. We drilled 29, and recompleted 23, thermal diatomite wells during the second quarter and have begun to bring them online in mid-July and early August. The majority of these wells have two completions per well. We also cored one of our wells only 40 feet away from an existing producer. We did this to examine the impacts of the thermal recovery process that's been used to date.

While we're still evaluating, we are very encouraged by the remaining development and redevelopment opportunity in this large original oil in place reservoir. The aquifer exemption at Poso Creek was approved in May and we accelerated a modest thermal sandstone drilling package by drilling six producers during the quarter. We have successfully expanded our water disposal options in South Midway Sunset ahead of the aquifer exemption process in that field, allowing us to drill 15 thermal sandstone horizontal producers during the quarter. Those wells began producing in the latter part of the quarter and will have a larger volume impact in the third quarter.

During the second quarter, we drilled the horizontal thermal sandstone well in a smaller aeral Potter reservoir near our thermal diatomite area in North Midway Sunset. The well is performing very well and continues to produce over 150 barrels of oil per day before being steamed. In short, the well is producing cold 13 degree API gravity oil at that rate which is significant considering the high viscosity of the crude at that temperature. We now plan to add five additional horizontal locations starting in the third quarter. While this area is small, we want to accelerate these types of projects when available.

And also, as previously discussed, in April we closed with Chevron on an offset piece of acreage in our thermal diatomite area in Midway Sunset during the quarter. The acreage includes active leases and lease options covering both thermal diatomite and also some thermal sandstone reservoirs. We drilled four appraisal wells on the option acreage and are currently evaluating the results. We've also begun steaming on the thermal sandstone acreage.

Returning to Utah, we drilled and completed one vertical well in the quarter, targeting the Green River and Wasatch Formations. This is the first well drilled on Berry's Utah properties since 2013. The well performance has matched our internal type curve with an IP 30 of approximately 120 BOE a day and we have recently started a production test of our completion method to determine the best reservoirs to economically complete.

Our compression purchase project is continuing. The first of three units has been delivered and is operating, again, as we expected. And lastly there, we continue to monitor production from our offset competitor horizontals wells in the Castle Peak, Uteland Butte and Wasatch Formations. We want to be ready to act as we see opportunity for horizontal drilling in our existing acreage.

And then lastly in Colorado, we've delayed our planned 2018 five-well drilling program in Piceance Basin due to acute increased gas differentials in the Rockies. The wells are permitted so we can react quickly once we feel the market is right to proceed. Basically demonstrating our stated capital flexibility, at this time, this capital is being reallocated to our California and Utah properties for 2018.

On behalf of the entire operating team, we're looking forward to executing our plan for the remainder of 2018 and working to realize the value we all see in Berry as a company. With that, I'd like to turn the call to Cary to discuss our financial results.

Thanks, Gary. And as Trem pointed out, we are excited to be reporting our numbers for the first time as a public company. For the second quarter, we reported adjusted EBITDA of $50 million compared to $44.5 million for the first quarter. On an unhedged basis, adjusted EBITDA was $78.3 million in Q2 compared to $62.4 million in Q1. Improving global prices led to realizations before hedges that averaged 91% of Brent for the second quarter. Our second quarter average realized oil price before hedges was $67.93, a 9% higher than the $62.14 we realized in the first quarter.

Realized oil prices including settled hedges were $53.22 and $52.74 per barrel in the second and third quarters respectively. This slight improvement reflected our significant hedge position that was largely put in place last year due to the revolver requirements at the time when Brent was trading at about $50 a barrel. Towards the end of the second quarter, we significantly improved our hedge position by terminating most of our existing contracts and replacing a significant portion of them with new positions in 2018, '19 and a small portion in 2020. The restructured hedge portfolio increases our weighted average price of hedge volumes to about $70 per barrel Brent from about $53 per barrel WTI through 2020, and as Trem pointed out, this can be seen on slide 14.

Our current hedge portfolio is more representative of current market and makes the unhedged position a better comparison on a sequential basis. We paid about $127 million to restructure our hedge portfolio which essentially means we prepaid the settlement cost which we have paid - would have paid through 2018 to 2020. We continue to add to our hedge position and will start looking into 2020 as the market starts to become more efficient.

As a reminder, OpEx consists of LOE as well as expenses and third-party revenues from our electricity generation, transportation and marketing activities and excludes taxes other than income taxes. As Gary stated for the second quarter, OpEx per barrel was $16.89 compared to $19.61 last quarter. We expect third quarter LOE and our electricity cost to be higher due to fuel gas and power cost caused by seasonal factors. This California summer has experienced hotter than usual temperatures in July and so far August.

Taxes other than income taxes were $8.7 million or $3.62 per BOE as a nearly $500,000 increase from the first quarter. The increase was largely due to increased rates and usage of greenhouse gas allowances. From the second quarter G&A, expenses totaled about $12.5 million which included just under $2 million in non-reoccurring transition, restructuring and other expenses and about $1 million in non-cash stock compensation expense. The $9.5 million in ongoing cash G&A expense is slightly higher than the $8.9 in the prior quarter, primarily due to increased cost as we prepared to become a public company.

On a per barrel basis, our on-going cash G&A excluding stock comp expense ran about $3.95 per barrel in the second quarter. This was slightly higher than the $3.79 per barrel cash G&A last quarter.

I want to remind everyone on the call that our cost are heavily oil influenced. As Trem stated, we are 100% oil production in California, so we have no gas production to artificially lower our oil production cost. Also when we talk fully loaded cash cost, we are including our OpEx, taxes other than income taxes, cash G&A, interest expense, dividend, and the cost to maintain production which is estimated to be approximately $10 per barrel. That totals just over $40 per barrel of cash cost. That means that taking into account our expected differential at $45 Brent pricing, we can pay our bills, our fixed charges, as well as maintain our production. And with our large inventory and low decline curves, we can do that for many years. That is unique.

One of our guiding financial principles is to live within levered free cash flow which is consistent with our year-to-date results. Our second quarter capital expenditures were approximately $39 million on accrual basis. Even with this increase of @23 million over the prior quarter, our operations generated almost @24 million more cash than spent on capital expenditures on a cash basis. Once we adjust for the @127 million pay to terminate and reset our hedge position at a much higher strike price, adjusting this termination payment, our cash flows from operations would have been about $50 million.

We ended the quarter with 66 million outstanding on the RBL and a total liquidity of $331 million. Our current liquidity is $424 million this week after normal working capital adjustments and the use of IPO proceeds to pay down the RBL. As of August 20th, we had cash of almost 36 million on hand.

Recall that last spring, we reaffirmed our $400 million RBL with an elected commitment in the redetermination which allows us to increase the facility to $575 million with lender consent. We received $112 million of net proceeds from the IPO, largely used to pay down the RBL and to make a $60 million distribution in connection with all the preferred shares converting to 39.6 million common shares. The IPO resulted in the issuance of an additional 8.7 million shares of common stock.

Also this week, our board of directors declared a cash dividend on our common stock for the third quarter of 2018, pro rata for the IPO closing date. This, as Trem pointed out, demonstrates the board's confidence in our ability to execute our plan right out of the gate as a new public company and as well through the cycle.

We are very pleased with the progress we've made to date. I want to remind everyone that we have significantly improved our hedge outlook by prepaying our prior position and replace them with much higher strike price. Our new position better reflects current market prices and gives a market better visibility into our cash flow generating capabilities. This strategy is expected to contribute to our growth and should increase market value.

Berry is in a very good financial position and we can grow organically as well as strategically. We should continue to see operational improvements. We will see a seasonal impact of our gas prices in Q3 but that should be more than offset by continued improvement in production. Trem, I will turn it back to you.

Thanks, Cary. Well, that wraps up our report for the second quarter of 2018 results. Cary, Gary and I are happy with where we are and pleased to be able to talk with you today. Thanks again for joining us and now we will open it up for any questions.

Thank you. (Operator Instructions)

And our first question is from the line of John Nelson with Goldman Sachs.

Good morning, John.

Good morning, and thank you for taking my questions. I guess to start off at a high level, I mean relative to your peers, Berry just seems to have pretty differentiated free cash flow today given that investors are still kind of in the getting to know you phase. Can you maybe walk us through the company's priorities or pecking order for allocating that free cash flow?

This is Trem. I'll start with the answer. That's a good question, John. And the first is we have all options on the table and we will do what creates the best value for Berry. We are looking at growth opportunities obviously, those we remain focused in our areas, in our geographic areas, in California and Utah as I mentioned in my section there. We are a natural consolidator.

We also have the option to return to shareholders as is appropriate. Cary, did you want to add anything to that?

Yes, I think again, as we pointed out several times, we have -- these assets have been underappreciated for several years and being able to put that capital to work and to be able to expand the production I think is the highest and best use today. And as we continue to work that and get through that, John, then we'll start looking at, again, continuing returning capital back to our shareholders. But I think right now, the highest and best use is taking advantage of the underappreciated assets and getting them back to the strong performance that we know they can be.

And as you look out, as I kind of dive in on that a little more, as you look out over the next couple of years, is there a preference for -- in that return to capital to shareholders for growing the dividend or should we think about that as kind of growing in line with kind of the volume growth overtime, or are you thinking about being more kind of opportunistic between, you know, that allocation whether it be share buybacks, whether it be back into the upstream?

Yes, I think that they're an overall...

I know you already have a pretty competitive dividend yield I guess is where I'm going with this and so I'm just trying to get your sense for -- if you feel you need to make that kind of more compelling or yeah, go ahead.

Yes. So what I want to do is, you know, from a company's point of view, we want to make sure that we are returning appropriate amount of capital back to our shareholders, but we also don't want to get ourselves into a fixed charge that doesn't weather the cycle quite as well. So I think again, we are paying a fairly fair dividend based upon the industry today.

We haven't indexed exactly what it needs to be, but again I think it will always be substantive especially to the Berry group that I think on your last example is more opportunistic in making sure that we are actually using our capital, what's going to give the investors the best long-term returns is what what we want to do.

That's very helpful. For my second question, we're hearing from some of your peers that the steel tariffs is starting to, you know, show up in capital cost. Can you just maybe comment for us how we should think about what steel costs mean for you guys and what level of inflation if any that you're seeing?

So this is Gary, John. So a couple of things we did, when that started announcing, we actually bought some tubulars before any of those tariffs came in so we protected ourselves a little bit more in this particular calendar year for that and we have inventory in place for that.

I will tell you that we are starting to see some of those impacts today. I know the announced tariffs were in and around 25% on steel. When you look at it for us, on just a particular piece of equipment like a pumping unit, for us, it's really only -- it's probably going to be in and around more like 15% total on that. And again, just to put it in perspective, we're not talking about a large part of our capital for each particular well there either.

So again, the wells we have are shallow and tubulars, as we come forward, there still won't be that much of an increase overall on our capital program. I will tell you that ultimately in 2019, we might see a little bit maybe towards more a total of maybe 5% of the total going forward. We're pretty much set for the remainder of this year in terms of equipment and tubulars that we have on hand.

If I could add, just as a reminder, John, when Gary says that our wells are shallow, I think the deepest well we're drilling in California this year is on the order of 2,800 feet to put it in perspective relative to our peers.

That's helpful. And just a follow-up, kind of Gary, your last sentence there, so the 5%, so think of it as 5% of well cost is exposed, you're saying?

Yes, of the total, yeah, of the total cost. So again, materiality there is just not that much. Again, our drilling costs are in the $300,000 to maybe on the top end $600,000 per well to D and C cost I should say and equipping cost. So, as you look at that number, it's just -- it's not very material overall in terms of impacting economics.

That's really helpful. I'll let somebody else hop on. Thanks guys.

Thanks, John.

Thank you. (Operator Instructions) And I'm not showing any further questions in the queue, sir. I would like to turn the call to Trem Smith for his final remarks.

Thank you very much. That's the end of our call.

And ladies and gentlemen, thank you for participating in today's conference. This concludes the program and you may all disconnect. Have a wonderful day.