Berry Corporation (NASDAQ:BRY) Q1 2020 Earnings Conference Call May 7, 2020 9:00 AM ET
Todd Crabtree – Manager-Investor Relations
Trem Smith – Board Chair and Chief Executive Officer
Gary Grove – Executive Vice President and Chief Operating Officer
Cary Baetz – Executive Vice President and Chief Financial Officer
Conference Call Participants
Charles Meade – Johnson Rice
Steve Dechert – KeyBanc
Kashy Harrison – Simmons Energy
Ladies and gentlemen, thank you for standing by. Welcome to the Berry Corporation Q1 2020 Earnings Call. [Operator Instructions]
I would now like to hand today’s conference call to Todd Crabtree, Investor Relations. You may begin.
Thank you, Kevin, and welcome to everyone, and we apologize for the delay in the start this morning. Thank you for joining us for Berry’s First Quarter Earnings Teleconference.
Yesterday afternoon, Berry issued an earnings release with our 2020 first quarter results and highlighting our current and planned response to the financial and operating uncertainties caused by COVID-19 and the oil price environment. Addressing these and other issues this morning will be Trem Smith, Board Chair and CEO; Gary Grove, Chief Operating Officer and Executive Vice President; and Cary Baetz, Chief Financial Officer and Executive Vice President.
Trem will discuss Berry’s response to these unprecedented times and plans for the remainder of the year. Gary and then Cary will share further details on how we are addressing the operational and financial issues we are currently facing. Before turning it over for questions, Trem will make a few concluding remarks.
Before we begin, I want to call your attention to the safe harbor language found in our earnings release. The earnings release and today’s discussion 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 materially from those expressed or implied in these statements. These include risks and other factors outlined in our filings with the SEC.
Our website, bry.com, has a link to the earnings release and our most recent investor presentation. Any information, including forward-looking statements made on this call or contained in the earnings release and that presentation, reflect our analysis as of the date made. We have no plans or duty to update them, except as required by law.
Please refer to the tables in our earnings release and on our website for a reconciliation between all adjusted measures mentioned during today’s call and the related GAAP measures. We will also post the replay link of this call and the transcript on our website. I will now turn the call over to our CEO, Trem Smith.
Thank you, Todd, and thanks everyone for joining us today for Berry’s first quarter 2020 earnings call. This is a challenging time for our people and their families, our industry, and for the world’s economies. I sincerely hope you and your loved ones are safe and well.
The entire Berry team continues to work tirelessly during this unprecedented and dynamic market environment. We are proud of our team’s proactive response to both the COVID-19 pandemic and the impact of the OPEC plus created oversupply. Today, I’ll highlight our response and how it is completely aligned with our business model and core values.
Our business is designed to create value for our shareholders through any market cycle, including this one, and we have historically demonstrated we can do so. Since our last earnings call, the world has changed. The dual impact of the demand destruction caused by COVID-19 and the oversupply caused by the price war initiated by Saudi Arabia and Russia has had a significant negative impact on economies around the world. The excess supply is global and is intensified by dwindling storage capacity, driving oil prices to 20-year lows on a monthly average.
When we last spoke in late February, the price of Brent was around $60 per barrel and we were focused on creating value for our shareholders through production growth, cost management, return of capital, and free cash flow generation. Today, the price of Brent is widely volatile and around $30 per barrel. Still, we remain focused on creating value by managing our production, focusing on sustainable, long-term cost reductions and process improvements, and by continuing to generate free cash flow.
As Cary will describe, Barry will end the year with substantial cash on hand and our strong liquidity position intact. We could not do this without our people and given the financial strength of our company and the essential nature of our business, we’ve had no layoffs or furloughs to date. The health and safety of our employees and their families remain our highest priority.
In March, we provided corporate wide, online training, on how our employees can protect, recognize, and prevent the spread of the virus. For essential personnel actively working in our oilfield operations, we have taken extra precautionary and protective measures to ensure their hygienic safety and all are following social distancing procedures.
We are closely monitoring the COVID-19 situation and following the guidelines from the federal government, Centers for Disease Control and Prevention, and the state and local governments where we operate. And I’m happy to report that as of today, we have had no employee cases of COVID-19. Through our proactive planning and decisive actions, our employees and therefore, our company, well positioned to weather this storm and emerge in a strong, competitive position.
In addition, we have recently made donations to several nonprofits in our communities to help alleviate the economic and social impacts of this unprecedented crisis.
Our first quarter results met our expectations. The details are well documented in our press release and the 10-Q. I’m very pleased that as soon as we got the first indications that Russia was balking at OPEC Plus production cuts, we hedged 100% of the remainder of our projected 2020 oil production, resulting in an average price of $59.87.
We also began to manage the trajectory of our production in light of market prices, taking advantage of our low decline rates, currently approximately 13% corporate wide. I want to stress that our CapEx guidance for the year remains unchanged. In the past, we have told you that we could maintain our production levels for $10 to $12 per barrel.
This quarter, we did it for significantly less than that. A portion of our capital was spent on facilities, preventative maintenance, and permitting in preparation for potential expansion later in the year, and to ensure state and environmentally clean, ongoing operations.
Although our first quarter results were not significantly impacted by the convergence of these events, we anticipate that the ramifications of these global crises could affect our business well into 2021.
The seasoned Berry management team has led many organizations and teams through a number of downturns. We will use our past experience to navigate Berry through this one. We understand that no one knows how or when the turnaround will occur. We do know, however, that the market will turn around. Therefore, we have implemented a strategic plan to help mitigate the impact during the downturn, while preparing us to take full advantage when the cycle returns.
Berry is exceptionally well positioned to handle this. Creating value has always been our mission. Whenever our product value has declined due to price, we have created value through intense management of our cost structure and implementing sustainable, long-lasting cost reductions, and process improvements.
This is true now. Since our last call, we announced a slightly more than 50% cut to our capital. We have temporarily suspended our dividend and developed a set of contingency plans for 2020-2021 timeframe. Right now, our teams are implementing numerous projects that will further reduce cost and improve processes.
Many of these projects will result in tangible, sustainable enhancements to our cost structure. In addition, we have plans, which we will implement only if needed to deal with managed curtailment shutdowns as well as access to storage. Gary will discuss a few examples of our cost-savings efforts in our contingency planning in a moment.
Bottom line, our cash generation, and excellent liquidity allow us to make strategic and thoughtful decisions. We will not be forced to make impulsive decisions that may have long lasting, negative unintended consequences on our people, our business, and the environment.
Oil and gas operations have been deemed as an essential industry by the governors of Utah, Colorado, and California. It is more important than ever that we continue to advance our environmental, social, and governance initiatives, maintaining safe, environmentally friendly, and clean operations, and managing our collaborative and supportive relationships with regulatory agencies and policymakers, especially in California.
We will not let the downturn distract us from being a good corporate citizen and we will not defer or shy away from our obligations, including our idle well management plan. I will now turn it over to Gary.
Thank you, Trem, and thanks everyone for being here. We are in very uncertain times, but Berry will continue to do what it has always done, controlling what we can control. I will point out that our first quarter production and operating results are in line with our expectations and in line with the previous quarter. Additional details can be found in our earnings release and 10-Q.
Moving onto the next quarter and beyond, things are moving rapidly but we will remain focused on managing our entire operating cash cost structure, including OpEx, capital, and abandonment, to ensure our operations are safe and compliant.
We spent more than half the capital for the year in the first quarter. We drilled 19 sandstone wells, of which two were injectors, nine were delineation, and eight were producers. Of the total capital for the quarter, about 39% was for facilities and equipping to bring online wells drilled in the fourth quarter of 2019, and about 11% for well permitting fees for 2020 and beyond.
That equipping and facilities cost were mainly for projects started in the higher price periods at the end of last year and that we felt prudent to complete in this first quarter. Additionally, we proactively began an intense permitting program in the quarter to be ready once we decided to begin our next drilling program.
As of today, we have more than 100 wells permitted and another 200 plus moving through the California regulatory system. Currently, we plan to focus the remainder of the capital in the latter half of this year, subject to market conditions. Our calculated capital efficiency for the first half of 2020 will be better than in the past. However, looking forward, we anticipate that our capital efficiencies will return to more historical levels.
For context, the updated capital budget assumes contracting one drilling rig no earlier than September of 2020, primarily for sandstone development projects that have strong returns at current prices. As we get more clarity into the next few months, we can adjust capital accordingly in line with our business model.
For full year 2020, we plan to spend nearly $15 million on plugging and abandonment activities, or ARO. That satisfies our obligations under the California mandated idle well management plan. We will continue to be a leader in environmental, social, and governance initiatives across the entirety of our operations, showcasing our operating processes and methods of safely producing both from the sandstones and diatomite assets.
Berry sells about 70% of its California crude at prices tied either directly or with significant linkage to Brent. This will minimize the financial impact of a widening differential between Brent and the California oil markets, Midway, Sunset, and Buena Vista, due to demand destruction in California.
And because we price so heavily to Brent, we are not seeing nearly the same impact to our pricing that the WTI market is currently seeing. We expect these bases differentials to return to more normal levels over time as demand increases.
There’s been a lot of conversation around storage during this period. Though Berry does not currently intend to curtail economic production in order to mitigate risk associated with demand destruction due to COVID-19, we have been proactively managing our storage situation.
Currently, between its existing infrastructure and third party options, Berry has approximately 455,000 barrels of available storage in California and 60,000 barrels in Utah. We are continuing to source additional third party storage in California and as such, have an option on an additional 315,000 barrels at this time.
I’d like to highlight that the primary storage issue in California is centered on refined product storage, particularly jet fuel and gasoline. And here is really the potential problem. California imports 2/3 of its oil. If you exclude imported oil, the state should have plenty of onshore storage for domestic production.
In normal times, we estimate that there’s an excess of 40 days of storage for domestic production. Unfortunately, in the latter part of April, there were 26 ships containing crude anchored off the California coast, which could take several months to churn through at current run rates.
Gasoline inventories have recently built at a high rate, so we want to be prepared for whatever happens first – gasoline storage hits capacity or the inventory off the coast drops to the point where there is lessened risk to domestic production curtailments.
In the last week, we’ve seen a slight uptick in gasoline demand. That is really good news. Additionally, as of yesterday, Bloomberg is showing only 18 ships anchored off of the California coast, inferring that crude is moving through the system.
Cost control will be a key area of focus as we move forward. We will continue to concentrate on efforts on cost reduction and safety and process improvements. We will operate our properties at base cost levels, reducing steam where appropriate, and eliminating or delaying certain longer-term projects.
It is very important to note that we need to be conscious of the long-term impact of shutting in too much steam during these periods. Things are evolving all the time but our sub-service teams are working to ensure we do not materially damage the performance of our thermal reservoirs during this period.
We want to make the most logical and programmatic decisions, using all of the data available to us at any time. Some examples of those cost controls we’ve implemented are, again, reducing or delaying steam in areas that are either very young in development or very mature; utilizing our new computerized maintenance system to optimize our long-term maintenance work across the company; looking for contractor rate reductions; reducing overtime and overall labor costs, both company and contractors; and continuing to manage our remaining highest cost categories, including well servicing, chemicals, and processing costs.
And these are just a few of the numerous projects that Trem referenced that we are working on currently. And with that, I’ll now turn it over to Cary.
Thanks, Gary. We are in a very dynamic environment and things are changing rapidly. Therefore, the most important point I’d like to make is that we are valuing our cash and providing ourselves with tremendous flexibility.
The outlook is uncertain and until we see visibility on demand improvement and supply coming down, we will manage our business to ensure we maintain ample flexibility. For the most part, I will not repeat the financial information that you can read in our earnings release and our 10-Q.
The three areas I’ll touch on are expenses, the balance sheet, and our long-term liquidity. As both Trem and Gary have pointed out, we are focused on our cost and improving our efficiencies. We have a robust plan that was built from the bottom’s up to improve our cost structure while focusing on process enhancements. This will continue to pay off in good and challenging times.
On April 1, we highlighted G&A reduction. These measures started to take place in late March and as Gary and Trem pointed out, we have more in process. Also, I’d like to highlight that Berry has historically not capitalized a great deal of our G&A costs. In fact, we currently capitalize less than 10% of our G&A costs. This is substantially lower than the industry average of about 25% with many companies capitalizing almost 50% of their G&A.
Another major difference between Berry and the resource plays is we are almost exclusively oil. This skews our cost higher but historically has provided us with a stronger cash margin. Additionally, we have more than 4,000 wells to monitor, which means a few more employed. I bring this up after reading many analyst reports on the resource play companies and I thought I would help investors make a better apples to apples comparison.
I want to reiterate that we have a strong balance sheet. We are building cash and we have almost full availability under our RBL. In fact, as of today, we have less than $10 million drawn. Berry faces no near term debt maturity as our revolving credit facility matures in July of 2022 and our notes don’t mature until 2026.
We are still going through a spring redetermination as the banks moved us towards the end of the line. But we are well over collateralized versus our revolved. We had very little borrowings on the line, have no covenant concerns, and our hedge position protects us through 2020 and well into 2021.
Our borrowing base will probably come down given current price environments. However, we are not planning on using the line over the next two or three years, other than the occasional short-term working capital fluctuations.
Most imply, our rapid actions to adjust our 2020 budget will allow us to continue to be flexible through this cycle. Prudent hedging allowed us to stabilize oil prices and fuel gas purchases. As of March 31, 2020, Berry had 24,000 barrels per day of oil hedged at approximately $59.87 Brent through 2020 with an additional 9,000 barrels per day hedged at approximately $47.19 Brent for 2021.
We have also been adding to our gas purchase hedges to manage our cost better into 2021. Berry’s current oil hedge book is approximately worth $211 million as of May 1. We now have 47,000 MMBtu per day hedged through October 2021 at an average price of $2.81 an Mcf.
All of our hedges are purely financial instruments with no physical delivery requirements. It’s important to note that shut-ins are happening across the industry. While we have not had to have any shut-in, as Gary explained, we believe we have more than adequate storage to be able to manage excess supply, the impact on refinery demand, and the impact on differentials should these situations occur.
We have temporarily suspended our dividend at this time. However, even in the current depressed environments, we’re still committed on maximizing shareholder value and we believe we will be able to – we will have opportunities to return capital, which now include the potential of debt repurchases as the board provided us with authority repurchase up to $75 million of our bonds in the open market, of which we still have full capacity.
Due to the significant drop in oil prices, we took a $289 million pretax, non-cash impairment charge on our Utah property and particular California locations. This is not an indication of long-term value of our properties but simply a required charge based upon accounting rules.
I will end on highlighting our liquidity. We expect to end the year generating approximately $100 million of excess leveraged free cash flow. This gives us a lot of flexibility on how to manage 2021. We are partially hedged in 2021 and based upon the current strip, we can manage the PDP decline with little impact on our year-end 2021 levered free cash flow position.
The same can be said about 2022. In short, we are in a very good position to be a survivor and we have the flexibility to quickly scale up or down. While we don’t know when the market will improve, we are working to ensure that Berry is in the best position for success when that day comes.
I’ll now turn it back to you, Trem.
Thanks, Cary and Gary. Summarizing the year to date, we started this year with the price of Brent at nearly $70 per barrel and the anticipation of a great year of value growth. We finished the first quarter with a changed world with Brent in the low 20s, but certain that Berry will end the year healthy and poised to take advantage of the upturn.
In that context, I would like to briefly make a comment on the remaining 2020 business, market sentiment, and the importance of oil in the energy sector of California. First, our current plan for this year is to pick up a rig late in the third quarter, contingent on oil price improvements. We heavily weighted our CapEx spend to the first quarter when we increased permitting efforts in the last couple of months. And as Gary mentioned, we have over 100 permits in hand and another 200 plus permits moving through the California regulatory system as we speak.
In other words, the permitting process works through the downturn and we will have plenty of wells to drill. You may also recall that Governor Newsom put all new high-pressure cyclic-steam projects in moratorium late last year while a joint CalGEM-Lawrence Livermore Lab study on safe operations with high-pressure cyclic-steam was conducted. This only impacted our new thermal diatomite projects.
The study, led by CalGEM, is underway now and Berry is proactively engaged. Our thermal diatomite team met with remotely with the study team on May 1 and discussed our processes and best practices. We are hopeful the study will conclude later this year.
Second, market sentiment. The industry’s lack of capital discipline and accountability over the past years is catching up with it. We will see a lot of changes, including restructuring activities in consolidation as the downturn continues. This creates an opportunity for Berry.
The surplus of oil in the global markets will work its way through the refining and distribution system as transportation demand recovers. This includes California and Energy Island, which is dependent on California-based oil production from operators like Berry, but mainly, more than 60%, from waterborne deliveries from Saudi Arabia and other OPEC nations for its energy needs.
It is clear now that Saudi Arabia and the other OPEC members’ self-interests are not aligned with the well-being of California and its citizens, nor the state’s long-term environmental goals. On the other hand, Berry is a proven, safe, clean producer of oil in California and is positioned for growth. With our focus on value and cash flow and our Berry first approach, we will be in a better position than many of our fellow producers when the market recovers.
Oil is now, more than ever, an integral part of the energy solution for California and its people. By working with renewable energy providers, together we can reduce California’s dependence on risky foreign sourced oil.
Finally, we understand that by definition, plans are dynamic and may need to be altered or redirected as situations change. The cratered demand and global oversupply represent a perfect storm and shine a light on Berry’s strengths, including our ability to make quick, informed decisions, as well as our adaptability, flexibility, and resiliency.
We will maximize our cash position to ensure we have great flexibility regardless of market fluctuations. Managing cash flow is nothing new for Berry. As we’ve historically demonstrated, we will manage the company to ensure it is strongly positioned to capitalize on the eventual market improvements. Our shareholders will benefit from these efforts. Thank you and I’ll now open it up for questions.
[Operator Instructions] Our first question comes from Charles Meade with Johnson Rice.
Good morning, Trem to you and your whole team there. And I apologize, I was interrupted a couple times during your prepared remarks so I apologize if I’m asking something you addressed already. But can you tell us – I understand you have no shut-ins, no wells that you’ve shut in. But can you tell us the degree to which maybe you’ve curtailed wells. And you made mention of delaying some steam injections, maybe reducing rates. And it seems to me that could fall under curtailments as well. But could you just address that level for May and perhaps what you think for June.
Hi, Charles. Good morning. This is Gary. So yes, we have not – as I mentioned, we have not actively shut in anything at this point in time. I will tell you that we look at every single well from an economic basis and determine whether or not we’ll continue to produce that well at any given time, especially if it goes down for a well failure, as an example, rod part, or goes down with a bad pump or something like that. We look at do we want to spend that expense dollar today to return that well to production.
And again, we might see some small impacts of that as this time continues. But going back to my original comment, we have not proactively shut in production at this time.
Now, on the steam side, yes, we have reduced some steam in certain areas. A lot of those are in conjunction with maybe some profile control we want to do. By that, how we inject steam in a particular injector and where that steam goes in that particular well to sweep oil to those surrounding producers.
So we’ve done some of that to date. And I think more importantly though, is that we look at areas where we can reduce steam that won’t have any immediate or long-term impact, if you will, to the reservoirs themselves. So we’re taking advantage of that and right now, I would say, we’ve earned about 81 million a day, plus or minus, in the quarter, MMBtus per day. And we’re looking to probably burn at least initially probably in the mid-70 millions going forward into the second quarter, plus or minus, as we look at all of the reservoirs.
And then I’ll just conclude with this. When we look at those reservoirs from the sub-surface standpoint, the thing we want to be very careful about is shutting in continuous injection. Because that is the area that has the most long-term impact when you try to bring it back online, as an example. And it’s not a linear relationship. So if you were to shut in steam for a month, as an example, you couldn’t expect to inject steam for a month when you do come back online, and see production rebound to the same level. There are a lot more complex issues happening in the reservoir than just a simple linear relationship. Did that answer your question for you?
That was a lot of great detail, Gary. Thank you for that, particularly that kind of non-linear relationship with the steam. It makes sense. My follow-up question is around the mechanics of this storage. I’m not sure that we should – I don’t know if this is worth spending a lot of time on but does that suggest or should we kind of conclude that you guys are evaluating perhaps producing into storage and then actually selling into barrels at a later date? Or is that not the role that you guys envision or the option that storage gives you?
I think that’s exactly correct, Charles and our storage is a combination of two things. One, what we have intrinsically on the property sitting at each particular facility. And then two, some third party storage options that we have, either through pipeline or trucking. And our intent is to evaluate and keep online economic production through that period and take it to storage for sale at a later date. I’ve got to caveat it. Always depending on the market, conditions at the time and what we expect to see those market conditions to be in the future.
Charles, this is Cary. I’ll say it basically serves as an insurance policy as well. Again, we’re extremely well hedged for 2020 and we want to maximize that free cash flow. So that if we do see differentials blow out, it gives us an option to be able to store that and sell it. As Trem pointed out, we’re starting to see green shoots of activity improvement on demand. So, as demand comes back up, we think there could be a hurdle, a couple of months where we’ll see wide differentials. So it gives us the flexibility to maximize the differential in the cash flow. So it really is an insurance policy as well.
Our next question from Steve Dechert with KeyBanc.
Hey, good morning. I just wanted to get any kind of indication you guys might have gotten from CalGEM on which way they might be leaning on their thermal diatomite wells.
Trem, why don’t you start that real quick and I’ll add some…
I certainly will. Steve, thanks for the question. As I mentioned in the remarks, what is really very good news for the industry in California is during this downturn, CalGEM has continued to perform and do their job. So just remember, the moratorium that the Governor announced last November is only for new projects. So right now, it’s not impacting any of our existing thermal diatomite. And in fact, the previous question was addressing – Gary addressed a lot of how we’re going to manage the steam, et cetera, on those.
The new projects, however, are in this moratorium and we have plans for those. Our team, I’m very proud of our team. Our technical team, first of all, we went from office work to remote shelter-at-home work without skipping a beat. That includes the technical work. And in that timeframe, we created a very extensive technical paper. We call it a white paper but it’s over 60 pages long that went to Lawrence Livermore and to CalGEM, at this request, outlining our best practices.
And so we are very supportive. We’re the only company to have done that. And it provides them with the data and the insights of how we actually perform safely with that thermal diatomite. So we’re very proactive and I guess my point is that we look forward to being at the head of the table when the CalGEM study progresses and ultimately, we come out of moratorium.
So that’s where we are and I’m very pleased to say that CalGEM and Lawrence Livermore are working well together at this point. So we’re encouraged. Gary was in the meeting, the technical meeting, so he may have a few comments he’d like to add to that.
I just would add – good morning, Steve. I would just add that the interaction was very good. CalGEM and the lab together are meeting individually with all of the operators impacted by the moratorium, of which there are approximately seven. They’re having an initial one-on-one meeting with all of those operators and gathering data. And then the next steps will be for them to take all that data, have continued correspondence with each of the operators, and then put the study together. And again, in conjunction with best practices that are currently being applied. As far as timeframe goes, I’d love to tell you when and if that might happen. But I’ll just rest back on the remarks Trem made earlier is that we hope to see that conclude prior to end of the year.
And Steve, I have to say something. Remember, everybody, we don’t have thermal diatomite development in our budget for 2020. So it doesn’t impact anything we’re talking about for our production or anything like that. We’re walking through the steps to make sure that we have access to it in 2021 and beyond. But for 2020, it doesn’t impact the budget.
Got it. That’s great. Appreciate the color.
Our next question comes from Kashy Harrison with Simmons Energy.
Good morning, everyone. Thank you for taking my questions. My first one, I was just wondering if you all could provide some color on how we should think about production exit rates for 2020 and the oil price you would need to see before adding that rig that you discussed earlier?
I think right now – I’ll jump in Gary, and then I’ll let you talk. But just right now, we’re not updating guidance. So I think we still are – what we put out April 1 is still where we’re thinking about at this point in time. Obviously, it’s a dynamic market. Things could improve where we would put more capital to work. Things could get worse where we put less capital to work. But at this point in time, we’re not updating guidance. So Gary, I’ll let you jump on the rest of it.
And I’ll just add on the other part of your question, Kashy, was currently, right now, those wells at the current strip have strong returns, the ones that we would plan to drill with that one particular rig in September. So again, there are other conditions that we will look at and see what the sentiment looks like at that point in time. But right now, as we sit here today in the current strip, that would be our plan is to look at bringing a rig online no sooner than September, but to drill those strong return projects.
This is Trem. Can I just add a little more color to that, which is from the strategic point. So the economics of those wells are good today in terms of return. So really, what we’re doing is looking to understand better the trajectories of the COVID and oversupply situations.
We’re actually in a position where we can turn that lever once we see an opportunity, okay?
And that’s a good point, Trem, I should mention is that we can gear up quickly and gear down quickly. And so we have that flexibility. We don’t have any long-term commitments, as we’ve mentioned many times. And that allowed us to take very decisive action during this first quarter as far as our activity level goes.
But it also allows us to do that when we gear back up again as well. Remember, our inventory of wells, they’re not very deep. They don’t take a long time to drill and so that does give us some strategic advantages on gearing up and gearing down, if you will.
That’s great color from all of you. And then my next question. I think earlier, Trem, it might have been you saying maintenance CapEx was about $10 to $11 per BOE. As you think about the production base potentially be lowering Q4 to Q4, how should we think about that maintenance CapEx per BOE moving forward? Are there any fixed components that may be biased higher or is that a good assumption to use looking forward into 2021?
Great. It’s good you ask that because that’s an important point to clarify. What I said is historically, our what we call maintenance capital is $10 to $12 per barrel. And in the first quarter of this year, our capital efficiency for a variety of reasons was – we spent less than $10 per barrel.
However, as Gary pointed out, over time, we expect those numbers to return to the historical values. So our capital efficiency will be in that $10 to $12 a barrel. And Gary, do you want to add any color to that?
Just a little bit. As production comes down on an annual basis year-over-year, you’d expected us to be on the lower end of that range. And as production ramps up year-over-year, you would expect us to be on the higher end of that range just purely from the math, when you look at the capital employed to kind of maintain our production over that period if that helps.
So I think Trem said it really well. We’re in a kind of unique period today but as we get back to what we consider a more typical development scheme for us and a pace, you should expect us to be in that range going forward.
And then my final question. I’m sorry, I may have missed this in the prepared remarks, but can you share some more specific detail on how we should think about California differentials during Q2 relative to Brent?
We’ve seen – so relative to Brent, again, most of our contracts are Brent-based. So we don’t get as much squeezed as I think some people perceive we do. But what we’ve seen as far as differentials, I think last year, we ended about a total differential of about Brent minus one just about, right now, average for the company. Right now, if you’re looking at differentials, they’re about Brent minus five, 5.54, I think, as of last week, if you wanted to be exact.
So we’ve seen them widen out a little bit but we haven’t seen them blow out in any way whatsoever, Kashy. And we assume we will see widening out. Our expectations in our model are they widen out in June and July and they start coming back a little bit in August. Though we do think we’ll see a widening over the three months and it’s kind of the reason it’s important that we added to the storage capacity just…
And Kashy, just a little bit of additional color. If you were to go out and ping, and look at the posting on Midway, Sunset, or Buena Vista and track that versus Brent, you would see that recent expansion of differential between the two a little bit earlier. It’s very important to note that up to 70% of our contracts have either direct or indirect links directly to Brent, and not referencing a four posting Midway Sunset price, as an example.
So as Cary mentioned, that shelters us and protect us a little bit from the numbers he quoted but I don’t want you to get unnerved if you were to go out and plot Brent versus Midway Sunset, as an example. Because currently, that’s not a good mark to marker to use for us in how our contracts are currently structured.
And especially, ANF is not a market whatsoever for us.
Got it. that’s helpful – very helpful. Thank you guys for the color and have a good day.
All right. Thank you.
[Operator Instructions] And I’m not showing any further questions at this time. I would like to turn the call back over to Trem.
Great. Thank you very much and thanks everyone for joining us and if you have any follow-up questions, do not ever hesitate to give us a call. This concludes our call for today. Thanks.
Ladies and gentlemen, this does conclude today’s presentation. You may now disconnect and have a wonderful day.