Berry Corporation (Bry) (BRY) 2018 Q3 法說會逐字稿

Hello, and welcome to the Berry Petroleum Third Quarter 2018 Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

And I'd now like to introduce your host for today's call, Todd Crabtree, Investor Relations. You may begin.

Thank you, Twanada, and welcome to everyone. 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 third quarter highlights. Gary will discuss our key operational results. Cary will follow with an overview of various 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, reserve estimations and competition.

We refer to non-GAAP financial measures, and we will provide a reconciliation to the GAAP with our financial statements. Today, we will be referencing slides from the November 2018 Investor Presentation deck, which is posted on our investor webpage. The replay link of this call and a transcript will also 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. I want to welcome everyone to Berry Petroleum's Third Quarter Earnings Call. The third quarter has been an exciting one for Berry Petroleum. In addition to the results we are announcing today, we completed our IPO in July and began trading on the NASDAQ on July 26, a great milestone for the company.

Berry is focused on value creation for our shareholders, which means we are focused on executing the plan we have communicated to the markets. Our business model is simple and clear. Our goal is always to generate top-tier EBITDA margin, while operating within our levered free cash flow. We manage the value, not just to production growth, but also operational efficiencies and incident prevention.

Our culture is, by definition, focused on and built on our 5 core values of leadership, entrepreneurship, accountability, ownership and communication. It is a culture the organization and all the employees now own. Our results this quarter reflect this philosophy and culture, and I'm very pleased to share with you how our values contributed to those results.

We are on track to meet our 2018 guidance, with G&A increasing slightly due to costs associated with the growth of the company and becoming a public company in July. We are meeting the guidance because we are executing our plan with excellence. Today, we are going to communicate with you how we are meeting the plan and remind you of the characteristics of our planning process, which are key for us to succeed in the areas we operate. Namely, we have a lot of opportunity on our existing leasehold, and we are proactive in the handling of our external events that might impact the plan positively or negatively.

Let me explain. We are on target to meet our production goals for the year. The third quarter results show a significant increase in production, particularly in September. Despite delayed receipt of some completion permits from the California Division of Oil and Gas, otherwise known as DOGGR, the regulatory agency in California responsible for approving permits - these permits were for our Hill lease wells in the Belridge field- we are receiving those permits now and have worked extensively with DOGGR as we develop a strong working relationship recognizing the needs of both Berry and DOGGR. The permitting issues slowed our 2018 development plan by shifting approximately 40 completions to the first quarter of 2019. Gary will go into more detail in his comments.

The process is now working well and because of our Berry first approach, we are seeing an ever-growing efficiency and speed in our permitting process every day. Prior to our going public, we made the decision to keep our 3-rig program in California going through the remainder of 2018. Not only do we have the cash, but we also have an extensive bullpen of high-quality opportunities. Our teams were able to draw from our bullpen; bring projects forward, including permitting them; and add them to our development program ready to be executed. In other words, we acted prudently and we're focused on value. This is the leadership behavior that the organization now embraces. And given the abundance of opportunities in our assets, we will be able to continue to do this well into the future.

In addition, the new Berry culture, leadership, entrepreneurship and accountability, is bearing fruit and we are seeing excellent results. I'm thrilled to say that our long-time view of the great potential of the Berry assets is becoming a reality. For example, the San Joaquin basin in California is often considered mature, even super-mature by many in the industry. I have always believed that where one finds a world-class petroleum system, one also finds opportunity. As you know, Berry's focus in California is in 3 large fields, Belridge, Midway-Sunset and McKittrick on the west side of the San Joaquin, as shown on Slide 19 of our presentation. These fields have been producing for many decades, some going back to the early 1900s like the Ethel D property. However, there remains a lot of oil to be recovered. One example that is bearing this out is the Potter reservoir in our North Midway-Sunset field. The acreage was developed, produced and shut in by another operator in the 1980s. Our technical teams identified the opportunity for additional reserves in the Potter and, as you may recall on our second quarter call, Gary referred to the first well drilled -- we drilled in the trend, and that it was flowing at 150 barrels of oil per day without thermal stimulation.

As of today, we have drilled 11 horizontal wells in the reservoir and had a total of 7 on production at the end of the third quarter. These 7 wells are all producing without steam to heat the reservoir at approximately 2,000 barrels of oil per day gross. This has opened up a new trend on our property and added reserves and drilling locations to the Berry inventory. I expect to share with you more results on other opportunities developed with the same kind of innovation and entrepreneurship throughout our existing leasehold in the future.

In Utah, we are excited to have completed the first phase of our reservoir management planning and are currently in a drilling program designed to test some concepts new to our operations in the area, such as pin point fracture stimulation and greater pumping capacity, another example of the new culture at work. Gary will be sharing some results and our plans going forward shortly.

Adjusted EBITDA is up significantly for the quarter. OpEx is in line with expectation despite high gas fuel prices in the quarter, and our realizations for the entire company were 89% of Brent. Capital spending is in line with our expectations, and we continue -- and we expect this to continue through the year with our 3-rig drilling in California growing to 4 rigs in 2019.

We continue to execute our stated financial policy as well. Yesterday, our board met here in Bakersfield and approved the fourth quarter dividend of $0.12 per share, consistent with all our previous and ongoing communications with investors. In addition, the board approved our 2019 budget, which we will discuss in a moment.

I'd like to step back for a moment and reiterate that our business model is simple. First, we operate within levered free cash flow, including interest and dividends, returning capital to our shareholders. Our high margins, low all-in cash cost of approximately $40 per barrel and approximately $5 differential to Brent company-wide mean we can sustain the business and pay all our financial commitments, including dividends, throughout the business cycle.

Second, our declines are low, our costs are stable and our wells are shallow, meaning they are low cost, mechanically and operationally straightforward and simple. We often drill, complete and produce them in 6 to 8 days.

Third, our crude production is heavily influenced by Brent pricing. Two-thirds of California energy needs are met by shipborne imports from foreign sources, mainly the Middle East and South America, as seen on Slide 9. To demonstrate the resiliency of Berry's business model, on Slide 12, you will see the impact we believe the most recent cycle would have had on our business if it had been operated by the new Berry.

In other words, there were only about 2 months when the price of Brent may have had a noticeable impact on our business. With continued prudent management, we plan to follow this policy and our operational plan for the foreseeable future. Cary will speak to this in more detail in a moment.

Since we last spoke several events have occurred which are notable. First, we received the approval of the aquifer exemption for the McKittrick field we were expecting. The impact on Berry is we are now open for active and ongoing development on our McKittrick acreage. Great news.

Midway-Sunset is our only aquifer exemption that is outstanding, and it is on track for final approval early next year. These results are another example of the impact of our Berry-first proactive approach that it is having on our business.

Second, we continue to realign our portfolio and recently signed a Purchase and Sale Agreement for our East Texas properties. We expect the deal to close this current quarter. The properties being sold produce 100% gas, and Berry's position is small and distributed. After reviewing its role and potential, we decided East Texas will have more value to a local operator than it will to Berry.

The result of this transaction, in conjunction with the significant growth we are seeing in our oil production, is that we are now even oilier, with approximately 86% of our total company production expected to be black oil in 2019. 100% of our California production is currently and will remain black oil.

Third, we have enhanced the governance of the company by adding two more independent board members-Anne Mariucci and Kent Potter- and created a Nominating and Governance Committee chaired by Anne; in addition to our existing Audit Committee, chaired by Kent; and Compensation Committee, chaired by Gene Voiland. Brent Buckley remains Chairman of the Board.

The results of our organic growth efforts speak for themselves. The inventory of these opportunities continues to expand. We believe we are close completing a couple of new bolt-ons in California in addition to testing a property we acquired earlier in the year adjacent to our North Midway-Sunset assets. Our pipeline of asset and strategic M&A opportunities is also a keen focus of our business development effort.

Looking ahead, we remain committed to our plan and our open and transparent communication with investors. We look forward to continued value creation and growth rates in the mid-teens for years to come. Gary is going to introduce our 2019 guidance, which I'll come back to in the final remarks.

In conclusion, it was an action-packed and game-changing 19 months for the new Berry since its creation in March 2017, and we look forward to continued success. Since our last call, we demonstrated daily that we can execute our plan and create value through the cycle. We have a deep portfolio of development and growth projects in our bullpen that we can and do draw from to manage our development program and growth expectations.

I am thrilled that the entrepreneurial spirit, along with the leadership and accountability now ingrained within the new Berry, is bearing fruit. We continue to demonstrate excellence in planned execution through flexibility, quick decision-making, planning and learning from the results. A very simple and effective plan in line with my overall vision for the company.

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

Now I'll turn it over to Cary, our COO.

Thanks, Trem, and good morning, everyone. Production sales for the third quarter were 27,400 barrels of oil equivalent per day, comprising 81% oil, 17% gas and 2% NGLs. This is sequentially up 3% from 26,500 BOE a day in the second quarter, primarily due to results of our capital development activity and inventory impacts in Utah.

Inventory sales in Utah averaged 300 barrels of oil per day during the quarter. As a reminder, some acute refining conditions required us to build inventory over the last few months. Those conditions lessened in the quarter, and we were able to reduce that stored crude build.

Adjusting for inventory sales changes, production averaged 27,100 BOE a day during the quarter versus 26,800 BOE a day in the second quarter, a sequential 1% increase. However, the effect of our recent capital activity began to truly show up in September as well as when brought online on our Thermal Diatomite and Sandstone areas. The production rate for September averaged 28,200 BOE a day, which is a 5% increase over second quarter production after both are adjusted for the impact of inventory changes.

Of the third quarter production rate of 27,400 BOE a day, 19,500 BOE a day came from California, 5,100 BOE a day from Utah and 2,700 BOE a day from Colorado and Texas. We continue to have 3 rigs running in California during the quarter, resulting in total company capital expenditures of $40 million compared to $39 million for the second quarter, with approximately 90% of our capital being spent in California. Production in the state increased 4% sequentially over the second quarter, while the September rate of 20,300 BOE a day represented an 8% increase over the second quarter production rate of 18,800 BOE a day.

Also again of note, California is 100% oil production. We drilled 68 wells in the quarter versus 58 wells in the second quarter, bringing our year-to-date count to 156 wells drilled. We plan to keep 3 rigs running continually in California through the remainder of the year and 1 rig in Utah to drill a few more vertical producers. We expect to exit the year between 230 and 250 total wells drilled, including 40 wells that we plan to complete next year, which I'll discuss in a moment.

Turning to operating expenses. We had OpEx of $45.6 million or $18.10 per BOE for this quarter. This compares to $16.89 per BOE in the second quarter. Third quarter OpEx is higher than the second quarter, mainly due to seasonally higher fuel gas prices and changes in inventory cost in Utah.

OpEx per BOE for the third quarter was very comparable to the $18.22 per BOE for the first half of 2018, which is an overall better indicator of expected OpEx costs.

The cost of fuel to generate steam for our thermal operations largely drives our OpEx cost. The third quarter saw much higher cost for fuel due to scorching temperatures, pipeline maintenance and reduced storage capacity during the period.

Average prices for Kern delivered were $4.11 per MMBtu versus $2.23 per MMBtu, while SoCal Citygate was $7.56 per MMBtu versus $2.97 per MMBtu for the third and second quarters sequentially.

This price swing would imply a large impact on our OpEx for the quarter. However, as I mentioned in the last call, we have 2 things that protect our overall total OpEx cost from these seasonally higher fuel gas prices. First, we operate 5 cogeneration facilities, 3 of which sell electricity into the grid. Second, we actively employ a risk mitigation program for purchased fuel in the form of forward purchase contracts and purchases.

So what is the true impact for the third quarter? Well, we burned approximately 68,500 MMBtu per day in both the second and third quarters, so our rates were consistent. However, with our price risk mitigation in place, our average price was $3.93 per MMBtu in the third quarter versus $2.39 per MMBtu for the second quarter or an increase of $1.54 per MMBtu or even 64%. That's lower than what you heard me say above.

Doing the math, this equates to about an increase of $9.9 million quarter-over-quarter. But additionally when combined with our increased excess electricity sales from our cogeneration contracts of about $8.3 million over the second quarter, our true increase in OpEx was only $1.6 million for the quarter.

When we internally analyze our current operations, including both the effect of the cogeneration facilities and our risk program versus an operation without either of those components, we calculate an incremental value savings of approximately $12.2 million for the quarter.

So as always, our teams are focused on executing our 2018 development plan, while ensuring our focus on safety and environmental impacts. We strive to operate in a safe, efficient and collaborative manner.

So with that, as a reminder, our 2018 annual guidance includes the following, which is also shown on Slide 24 in the Investor Presentation. 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 $3.75 to $4 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 third 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. As I mentioned earlier, we've been able to move some stored crude in Utah and continue to look for additional opportunities to market that crude. While the situation that occurred early in the year has lessened, we still want to be able to move quickly to ensure the best value for Berry.

As I discussed in the OpEx action, our largest cost in California is for purchased fuel gas. We continue to look for options there to lower our cost and protect against acute swings in the California gas market. While our current risk mitigation program, along with our cogen infrastructure, has been effective in protecting us from rising fuel gas prices, we are proactive in looking for all opportunities to protect our operating cost structure.

Turning to operations in California. We began to stimulate 15 Hill Diatomite producers in August and plan to stimulate an additional 25 wells by the end of the year. Of the 15 wells stimulated to date, 8 are producers and 7 are injectors. Production from the first 8 producers are in line with our expectations.

23 of the remaining 25 wells will be producers. As I mentioned earlier, we now plan to stimulate the 40 wells we are drilling through the end of 2018 in the first quarter of 2019. And are working closely with state agencies involved to complete the required permitting. We feel confident that we'll be able to stimulate the wells according to the 2019 plan and accurately forecast future time in the well stimulation permits for this large development.

Therefore, we've adjusted our 2019 plans accordingly. As a result of this completion timing, our total 2018 production will be impacted. However, this is a pure timing issue and well results to-date are as expected.

In our thermal Diatomite area in North Midway-Sunset, we had a September growth rate of 3,200 BOE a day -- or excuse me, barrels of oil a day as we brought 83 new completions online from both new drilling and recompletions of existing wells. We continue to work on the production process to maximize the value of this large oil in place asset.

With our concentration on value rather than just pure production rate, beginning in 20 -- July of 2017, we have seen gross production increase from 1,750 barrels of oil per day to 300 barrels of oil per day, while steam-oil ratio, or SOR, has decreased from 6 to 8 during the same -- 16 excuse me, to 8 during the same period. In effect, we've doubled production, while injecting slightly lower amount of total steam.

In our McKittrick field, the aquifer exemption was approved in September and we plan to begin a 20-well drilling package in the fourth quarter. This will continue to develop in known areas as well as step out to additional acreage on the property.

During the second quarter, we drilled 1 horizontal thermal sandstone well in the Potter reservoir in a small area near our thermal Diatomite area in North Midway-Sunset. We recorded then during the last call that we were very pleased with the results from that well, and we're making plans to drill additional flood locations.

As I did mention last quarter, that first horizontal well came online and produced over 150 barrels of oil per day before being steamed. As the team continue to study the area, we increased the planned well count by 10 additional horizontal locations and commenced drilling in the third quarter. As Trem mentioned, we continue to see excellent results, with 7 of the wells online at quarter end, producing 2,000 barrels of oil per day gross. To-date, none of the wells have been steamed. Current plans are to monitor the wells and its side wind or if we will add heat to the reservoir.

We also continue to execute our development plans in our other properties, including thermal sandstone developments in South Belridge, Poso Creek and South Midway-Sunset. Overall, our teams are executing our plans and meeting our development expectations.

For our operations in Utah, we drilled and completed 1 vertical well in the second quarter, targeting the Green River and Wasatch formations. This was the first well drilled on Berry's Utah properties since 2014. The well performance has exceeded our internal type curve to-date, especially in oil production. With this recent well information and continued reservoir analysis, we've made the decision to drill an additional 7 wells by the end of the year. We will be employing some different completion and producing techniques to increase the recovery and value of the development in Utah.

As an example, 4 to 7 wells will employ a pin point fracturing technique aimed at increasing effectiveness of our stimulation program. We have a large land footprint here and had been encouraged by the results to-date.

Turning into 2019, as Trem mentioned, our board met this week and approved our 2019 budget and capital plan. I'd like to give 2019 annual guidance, one with a few highlights for 2019, which is what is shown on Slide 25.

Production between 29,000 to 32,000 BOE a day, approximately 86% oil; OpEx ranging from $17 to $18.50 per BOE; taxes, other than income taxes, ranging from $4.25 to $4.75 per BOE; adjusted G&A ranging from $4 to $4.50 per BOE; and capital ranging from $230 million to $260 million for the year.

Compared to 2018, pro forma for the East Texas divestiture of approximately 700 BOE a day and inclusive of the completion timing I mentioned earlier, we expect to grow production in the mid-teens with oil growth being slightly higher than overall BOE growth year-over-year.

Our overall oil mix will increase to approximately 86% from approximately 81% currently as a result of the divestiture and our oil-focused capital program. As part of our 2019 development, we plan to drill between 400 and 450 wells, mostly in California, but inclusive of 20 vertical producers in Utah. This shift in some completion timing from 2018 to early 2019 that I mentioned earlier is also included, and we added some capital to 2019 for further delineation work and corporate capital opportunities.

So in summary, the capital range for 2019 includes base capital, development capital, some step-out delineation capital and corporate capital expenditures.

On behalf of the entire operating team, we are looking forward to executing our plans for the remainder of 2018 and into 2019, while working to realize the value we truly 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. For the third quarter, we reported adjusted EBITDA of $81.7 million, up over 63% compared to $50 million for the second quarter. On an unhedged basis, adjusted EBITDA was $82.8 million in Q3 compared to $78.3 million in Q2, a 5.7% improvement. This quarter-over-quarter improvement reflects higher production with generally flat crude prices, partially offset by higher OpEx and G&A expenses. Adjusted net income for the third quarter was $40.5 million compared to $14.8 million for the prior quarter. The GAAP financials were impacted by various transactions, including conversion of the preferred to common and the related $60 million distribution plus the IPO. We still have some reorganization items and restructuring charges. We are proud of our adjusted results and we continue to demonstrate our commitment to operating within levered free cash flow.

We are pleased to pay our second dividend of $0.12 for the quarter. This demonstrates the company's continued focus on returning meaningful capital to our shareholders. Continued strong global prices led to oil realization before hedges that averaged 91% of Brent for the third quarter in California and 89% for the company overall. Based on our average gravity adjustments, or California crude differentials are in the mid-$4 range. And royalties on a portion of our production is almost $2 per barrel. Brent was up about 1% compared to the second quarter. Our third quarter average realized oil price company-wide before hedges was $67.67, which was essentially flat from the $67.93 we realized in the second quarter.

Realized oil prices, including several hedges, were $67.23 and $53.22 per barrel in the third quarter and second quarter, respectively. Recall that 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 increased our weighted average price of hedged volume to about $70 per barrel brent from from about $53 per barrel of WTI into 2020. Our current hedge portfolio is more representational of the current market and makes the unhedged position a better comparison on a sequential basis. We continue to add to our hedge position and will start expanding to 2020 as the market starts to become more efficient.

We target covering our operating expenses and fixed charges including maintenance capital expenditures for up to 2 years out. As a reminder, OpEx consist 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 pointed out, for the third quarter, OpEx per barrel was $18.10 compared to $16.89 last quarter. The increase in OpEx for the third quarter compared to the second quarter was primarily driven by the increase in higher seasonal fuel and steam cost, which impacts our LOE and our electricity generation costs. To a large degree, these increased costs were offset by an increase in our electricity sales. As Gary explained, we partially mitigate our exposure to natural gas prices by selling a portion of our electricity generated by our cogens as our electricity sales prices are closely tied to the price of gas. As a part of our risk mitigation program, we recently entered into additional forward contracts for a portion of our gas purchases that will further stabilize these costs beginning in the fourth quarter.

LOE on a per -- on a BOE basis increased by approximately 20% to $20.60 in the third quarter, mostly due to the higher seasonal fuel prices and, to a much lesser degree, increased well and service maintenance cost. Electricity generation expenses were notably higher than the preceding quarter due to the high seasonal fuel gas cost. Electricity sales increased quarter-over-quarter, primarily due to the high summer rates, consistent with significantly higher gas prices.

Taxes other than income taxes were $3.30 per BOE, a [$0.32] (corrected by company after the call) decrease from the second quarter. The decrease was largely due to lower severance taxes, partially offset by higher greenhouse gas allowance costs.

On the income tax front, we anticipate leaving 2018 without having to pay any cash taxes for the year.

For the third quarter, G&A expense totaled $13.4 million, which included about $2.7 million nonrecurring transition, restructuring and other expenses as well as noncash stock compensation expense. This resulted in about a $10.7 million in adjusted G&A expense, which is higher than the $9.5 million in prior quarter, primarily associated with the company's growth and public company status. The third quarter also included about $400,000 true-up from prior quarters. On a per barrel basis, including the $400,000 true-up, our ongoing cash G&A ran about $4.10 per barrel in the third quarter. This was slightly higher than the $3.95 per barrel cash G&A last quarter.

I want to remind everyone on the call that our fully loaded cash cost, which includes OpEx, taxes other than income taxes, cash G&A, interest, dividend and the cost to maintain production, which we estimate to be approximately $10 per barrel is just over $40 per barrel. That means taking into account our expected differential at about $45 Brent pricing, we can pay our bills and fixed charges as well as maintain our production, which we think that is one of the key differentiators to our peers and the industry as a whole.

One of the guiding financial principles is to live within levered free cash flow, which is consistent with our year-to-date results. Our third quarter capital expenditures were approximately $40 million on an accrual basis. Our operations generated $24 million more cash than incurred in capital expenditures, interest and dividends to our common shareholders. We ended the quarter with no outstanding balance on the RBL and a total liquidity of $417 million. We are in the process of completing our full RBL borrowing base redetermination, which we expect will be at least as robust as the current $400 million borrowing base with an elected commitment, which currently allows us to increase the facility to $575 million with lender approval, if needed. This week, our Board of Directors declared a $0.12 per share cash dividend on our common stock for the fourth quarter of 2018. This demonstrates the board's confidence in our ability to execute our plan right out of the gate as a new public company as well as through the cycle.

I want to remind everyone that the impact of our IPO and the conversion on our preferred stock to common during the middle of the third quarter skews the weighted average basic shares in our EPS calculation. This should normalize beginning in fourth quarter.

To touch on the 2019 guidance, the increase in adjusted G&A is primarily associated with increased cost of being public and continuing to add tools that help the company to improve visibility into our cost structure, geology and properties.

We expect adjusted G&A per barrel to peak the first half of 2019 and start declining the second half of 2019. Our taxes, other than income taxes, are up due to increases in taxes associated with greenhouse gas compliance due to an increase in steam, as an overwhelming majority of our growth is focused in the California thermal properties.

Lastly, based on the current strip coupled with our current hedges, we should comfortably live within levered free cash flow throughout 2019. We are very pleased with this quarter's results, our first period operating as a public company. We have effectively mitigated the seasonal swings of our operating costs, and we should continue to see operational improvements, especially on a per BOE basis as our production continues to ramp up.

Trem, I'll turn it back to you.

Thank you, Cary. The San Joaquin basin is a great basin. It's been producing oil for over 100 years and has many years of robust production in its future. It is truly a world-class super basin located in one of the great markets in the United States. Today, it isn't thought to be as sexy as the resource plays, but it is; and we'll continue to produce top-tier returns, and Berry is well-positioned to generate those returns well into the future. If you look at Berry on an EBITDA per barrel basis, we are competitive with the rest of the best of the resource players. However, if you look at capital expenditures per barrel, we performed better. In other words, had much more capital intensity.

There is a lot of runway and upside left in this space and as our latest quarter demonstrates. Every day I'm more excited at what we're doing at Berry and look forward to early March to highlight how we closed out 2018 and how we have started 2019.

Thank you for your interest in Berry, and have a great holiday season. And we are ready to open for questions.

(Operator Instructions) Our first question comes from the line of John Nelson with Goldman Sachs.

I was wondering if you all could quantify what the 40-well shift -- I'm sorry, what the capital impact is from the 40-well shift into 1Q '19?

John, it's Gary. So that's going to probably push about $10 million across just the completion of that 40 -- those 40 wells; will be plus or minus $10 million.

Okay, that's helpful. And should we think about then, all else equal, that $10 million kind of coming out of 2018 CapEx? Or towards the lower end of the range? Or you guys are going to shift some other kind of activity?

Yes, I would tell you that we are going to be at the upper end of that range with that $10 million. So right now, I'm telling you I'm pretty comfortable sitting in the midpoint of the range in that between $140 million and $160 million, plus or minus. I'm still very comfortable with that. What it does is it obviously pushes $10 million into 2019. And so we moved this up just a little bit more so from that standpoint. However, what I would also tell you is that we're drilling more wells in the year in 2018 than we have previously planned as well. We've been pretty -- a little bit quicker on drilling and quite frankly are saving a little bit on our drilling costs overall. So we're able to put a few more wells into 2018 in terms of well count than we had previously talked about also.

That's helpful. And then could you maybe just clarify the corporate capital? We're still in that kind of "getting to know you guys" space. What is the corporate, is that leasehold? What's in that bucket?

So it's actually opportunities that we see that wouldn't fall on, what I would call, a standard development package. It's certain pieces of looking to maybe drilling a couple of wells here and there to investigate certain things that would not be considered straight step out a delineation. It's additional maybe just a really small little bolt-on opportunity here or there that would take a little bit of capital to finish up. But it -- quite frankly in the range that we're using for next year, it's plus or minus like $5 million in the total.

Plus, on top of that, we still have some -- from a systems' point of view, we'll probably spend close to $5 million or at least in the budget for systems improvements, overhauls and all that as well.

Yes, and inclusive of that, too, some of the total -- like Cary said, so total it's about $10 million into next year. That includes some fleet vehicles and some other things that you would consider more of a corporate capital expense.

That's helpful. And then, Trem, you mentioned a few bolt-ons or potentially in the pipeline. One man's bolt-on is another man's transformative acquisition. So can you maybe just give us a ballpark on what a bolt-on acquisition is to you?

Yes, I can certainly do that. First of all, most of our bolt-ons to date have been, and probably will continue to be, in the Midway-Sunset area field, which is one of those -- it's one of the largest fields in the United States, John. And it has never been consolidated. And so we have many, believe it or not, as long as that field has been producing, there are many areas in the field that lack infrastructure, including many areas around our existing leasehold. The geology does not stop at da leasehold boundary. It continues across and so we're excited. As you know, we did -- we won a North Midway-Sunset with Chevron earlier in the year that we are now testing. And we expect some throughout Midway-Sunset coming up. I can't go into more detail until we close, but they're actually not transformational maybe but they are significant contributions to existing producing trends. And right next to our existing infrastructure. So very exciting, actually. A key part of our business development is to consolidate areas like that.

The Chevron deal was certainly intriguing in that there wasn't really an upfront capital. I was assuming kind of in these bolt-ons, the expectation was there would be more of an upfront payment? So I guess I was trying to kind of gear more towards that upfront payment, how should we think about how large of a deal we're potentially looking at?

I'm going to say that the deal structures will all vary. Most of them will be more drilling commitment-type deals. So the upfront is going to be minimal. Though, in some cases, there may be some, but I'd consider it quite small. John, these are not acquisitions, so to speak. Cary, did you want to add?

No, no -- I will. We continue to scratch the surface also looking for those transformative, and we will continue to be doing that on a regular basis as well because we do think -- we do love the basin, as Trem pointed out, and we think there's a lot of opportunity in that basin to continue to expand. And we think we're the right team and company to get it done.

And John, I guess I will also add, given some comments in the past, the inventory of potential bolt-ons is significant.

Our next question comes from the line of Jake Roberts with Tudor, Pickering, Holt.

In terms of the delayed procurement in the aquifer exemption and as California transitions to Governor Newsom, I was hoping to hear your guys thoughts on the regulatory landscape going forward.

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Sure, Jake. This is Trem. The business will continue in California. If you'll remember, the landscape is that we're focusing on Kern County. We're in the San Joaquin basin and that's where the -- and we're focused in on the west side of the San Joaquin though. So just in that context, we're in one of the great oil-producing and tax-generating for the State of California areas, in the state of California. And we have a three-pronged approach to manage the government issues and potential legislative actions. And the first, of course, is that we have a full-time government relations person that reports to me. He's got over 30 years of experience. And today, in fact, he's up in Sacramento meeting face-to-face, building on the relationships with DOGGR, who I referenced in the state water board. All people we've grown to know personally and driving our business forward. Second, we have a short list of items that we focus on the Berry first approach. For example, driving and keeping engaged on the aquifer exemption process. So McKittrick came in pretty much as we expected in time, and we are taking the lead in the Midway-Sunset. So things that have been impediments to -- in the past to the industry, here are working very closely. And those are -- the regulators are acting according to administrative rules, okay, in that regard. And third, we are taking a leadership role, and I'm going to be able to talk more about this in the next call. We're taking a leadership role proactively in the industry to engage all stakeholders, not just in the industry but all stakeholders associated with the energy business to address some of these issues that are critical to us. Always focused on the future what regulatory changes might occur. And the reason this is important is that the energy business in California -- and if you remember, California is a bit of an island in terms of the market. There are no -- there's no access to other Lower 48 crude sources. And it generates and uses a lot of energy. So we still want to be on top of what may be coming down the pike. And there's also very much a difference between what a, I need to be a little careful here, but what a politician says and what a politician does as a result. So we are very much in tune with the actions that are occurring in the state. And having the other groups, the other stakeholders engaged in the conversation is going to be quite helpful, and we're taking a leadership role in that. So -- and Gary, did you want to add?

I did. Jake, just one thing. If I heard the first part of your question right, I think it was, is it going to have any impact on the remaining aquifer exemption that we have? My expectation would be no. That is already in process. The public hearing has been set for a portion of it in December. Once that happens and there's public comment, then it actually is prepared in its final form by the Division of Oil and Gas, heads to the EPA, that's plus or minus 10 weeks for them to approve. That's been historic through all the other aquifer exemptions that have gone through. So I don't see really any change of impact there on that one particular item that you mentioned.

Yes, and -- this is Cary, and I'll jump in with at least one last thing, the permitting side of things. Trem did a good job and Gary did a good job. It was really a process. We have been doing a lot since the company emerged in March of 2017. The one thing that we probably are working on better and developing relationship is with DOGGR, understanding exactly what they need, how their process works and getting in front of them. For that reason, we don't think permitting will be -- we'll be talking about permitting issues going forward as we continue to develop that relationship and work with them as a part of the team.

And I guess I'll comment -- I'm sorry, I just can't resist. It truly is, and we've mentioned this before, it truly is a planning process. And so for us, we just continue to refine and define that thought process and what the timing is to allow us to meet the goals that we have set forward as an enterprise and as a company. So with that, we'll have those challenges and we'll look for the ways to go through them and get back to exactly where we want to be. And I think we're doing that as well.

And I will end this by pointing out that you can tell from the answer that we are very engaged in this issue. And it is part of our value creation, so hopefully that was helpful, Jake.

That was very helpful. Just a quick one then. Is there any difference in how the state is treating horizontal permits versus conventional?

Oh, yes, none. And so really when you talk about permitting...

No.

So the answer is no, there's no difference between vertical and horizontal wells. Really, the permitting that we're really talking about is the stimulation permit for the wells that we drill on the Hill property that we do fracture stimulate. So as far as getting the well drilled in that permitting process, that's very smooth. It goes very quickly. We have a county permit that we need to get and then we get the permit from the DOGGR. And if it's on BLM property, we have an additional permit to get from them; all part of our planning cycle and all running very smoothly.

(Operator Instructions) I am showing no further questions at this time. I would now like to turn the call over to Trem Smith, CEO, for closing remarks.

Have a great holiday season, and thank you for participating in the third quarter earnings call for Berry Petroleum. Thanks.

Ladies and gentlemen, that concludes today's conference. Thank you for participating. You may now disconnect. Everyone, have a wonderful day.

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