California Resources Corporation (NYSEMKT:CRC)
Q2 2016 Earnings Conference Call
August 4, 2016 5:00 PM ET
Scott Espenshade - Vice President, Investor Relations
Todd Stevens - President and Chief Executive Officer
Marshall Smith - Senior Executive Vice President and Chief Financial Officer
Evan Calio - Morgan Stanley & Co., LLC.
James Spicer - Wells Fargo & Company
Pavel Molchanov - Raymond James & Associates, Inc.,
John Herrlin - Societe Generale Corporate & Investment Banking
Brian Singer - Goldman Sachs & Co.
Michael Ainge - TIAA Global Asset Management
Biju Perincheril - Susquehanna International Group, LLP
Paul Sankey - Wolfe Research, LLC
Good morning and welcome to the California Resources Second Quarter Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference call over to Scott Espenshade. Mr. Espenshade, please go ahead.
Thank you. I am Scott Espenshade, Vice President of Investor Relations. Welcome to California Resources Corporation’s second quarter 2016 conference call. Participating on today’s call is Todd Stevens, President and Chief Executive Officer of CRC and Mark Smith, Senior Executive Vice President and Chief Financial Officer and also several members of the CRC’s executive team.
I would like to highlight that we have provided slides on our Investor Relations section on our website, www.crc.com. These slides provide additional insight into our operations and second quarter results information. Also, information reconciling non-GAAP financial measures discussed to their most directly comparable GAAP financial measures is available on the Investor Relations portion of our website and in our earnings release.
Today’s call will focus on second quarter earnings and is not intended to cover specifics of our recent tender offer or the new loan. Todd and Mark will touch on some of the highlights of those potential transactions in the earnings call. Of course, you can always consult here in CRC’s Investor Relations Department.
As a reminder, today’s conference call will contains certain projections and other forward-looking statements within the meanings of Federal Securities Laws. These statements are subject to the risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements.
Additional information on factors that could cause results to differ is available in the Company’s 10-Q, which is being filed today. We would ask that you review it, and the cautionary statements in our earnings release. A replay and a transcript will be made available on our website following today’s call and will be available for at least 30 days following the call. We have allotted so more for time for earnings of Q&A at the end of our prepared remarks and would ask that participants limit their questions to a primary and a follow-up.
Again, Investor Relations should direct specific deal related questions to the brokers handling the transactions and others should contact Investor Relations with any questions following the call.
I will now turn the call over to Todd.
Thank you, Scott and thank you everyone for attending our earnings call. While the second quarter price improvements were welcome, we continued our commitment to executing on items within our control, remaining focused on our core financial and operating tenets. Over the past year, we have reduced our debt by approximately $700 million from the post spend peak reached in early 2015.
The recently announced tender will take us another step closer to our long-term goals and we remain focused on continued deleveraging efforts. We witnessed high levels of commodity price fluctuation during the first half of 2016, resulting in volatility in the price of CRC Securities.
These market movements provide opportunities for us and our investors. We took a number of steps in the first half to take advantage of these opportunities to strengthen our balance sheet. We bought back over $100 million of bonds in the open market for less than $30 million in the first quarter. We exchanged 2.1 million shares of our common stock for approximately $80 million face value of debt in the second quarter.
Most recently, we launched a tender of up to $525 million in cash to capture the trading discount on our bonds. We also had a small non-core asset divestiture located in the Los Angeles Basin. Assuming successful completion of our tender offer, we will have achieved a substantial portion of our initial deleveraging goal by reducing our debt from its post spend peak of approximately $6.6 billion without any significant asset disposals or notably burdening the income statement.
Also we believe the related proposed bank amendment should provide additional runway to the end of the first quarter of 2018 through covenant changes. Given the state of the commodity markets, we believe we need to further strengthen our balance sheet to competitively position the Company for the longer-term and to continue to look at all available options with our upstream and midstream assets, as well as additional capital market opportunities.
Reaching our longer term deleveraging goals will likely require a series of steps and transactions that extends through 2016 and beyond. We strive to capture significant deleveraging from transactions in the near term while balancing the long-term effect on CRC. We’re not interested in short-term gain for long-term pain.
Our resource base, as well as the commitment and creativity of our workforce continue to impress us, delivering best in class decline rates. These decline rates are further validated by our greatly reduced capital program this year. I noted last quarter that 2016 is the year of blocking and tackling by our operations teams.
Through the first half of 2016 we remained focused on the task at hand. We did an excellent job of protecting margins, reducing costs and maximizing revenues while protecting our base production and increasing our drillable inventory.
Our second quarter production came in at approximately 140,000 barrels of oil equivalent per day, which is about the midpoint of our guidance range. We really hit the brakes, especially in the first quarter, pulling back on virtually all discretionary activity. In the second quarter, our capital investment was just $5 million all of which was directed to mechanical integrity and safe operations.
In addition, two third party pipeline disruptions forced us to inventory over 1,000 barrels of oil per day in certain fields, which we will report as production in the third quarter. Both pipelines are now fully functional. We experienced the effect of lower investment activity in the first half, however we started to increase our workover activity towards the end of the quarter.
As I mentioned, we continue to focus on our costs and posted better than expected results from both an absolute and per barrel basis. We are proud of the efforts put forth at all levels of our organization to find and implement efficiencies and cost savings. An example of this is Elk Hills, where our operations teams have been able to manage down both per unit and per well cost significantly over time. We expect that the majority of the cost reductions we realized since the spin will be sustainable over the longer term.
Our 2016 capital program of $15 million is focused on investments designed to ensure safe and reliable long-term operations and is front loaded due to the first quarter power plant turnaround, which was the single largest item in our capital budget. We significantly slowed second quarter capital investments in response to low commodity prices.
Our decision to withhold development capital and defer well maintenance activity in the first half of the year reduced our production levels, particularly in the second quarter. While we certainly recognize that Brent is still well below $50, our confidence is building in the level in our projected cash flows for the year, taking into account the effect of the hedges in place.
As a result, we are increasing our activity in the second half of the year to a pace that will bring full year investment to a level that is consistent with our plans. Our continued focus on our resource space and process improvements are bearing fruit. For example, over the last year, we doubled our drilling inventory at $40 Brent and a VCI greater than 1.3.
With this in mind, we are mobilizing two drilling rigs back into the field that will largely focus on drilling and capital workovers in our water flood and steam flood operations in the second half of the year. We are also continuing to optimize and build inventory across our vast land position and rank our projects by our VCI metrics to ensure the biggest bang for our bucks.
As you recall, our first half production reflects the effects of one-off events, such as the power plant turnaround in the first quarter and the third party pipeline interruptions in the second quarter. With the resilient performance of our asset base and the impact of these events dissipate, we expect the decline rate in our second half to be well under what we experienced in the first half.
As a result, we expect our full year decline rate to be closer to the midpoint of our stated range of 10% to 15%. With that in perspective, our total average production on a BOE basis is expected to range between 134,000 to 139,000 BOE per day in the third quarter.
Realized crude prices improved in the second quarter relative to the first quarter, even after the temporary negative effects of third party pipeline disruptions in May and June. We expect realizations in California to stabilize going forward. After the softness in the first half of the year, we are also seeing significant increases in natural gas index prices going into the second half of the year.
In addition, an outage at a third party storage facility, coupled with the peak summer demand, are expected to further improve our gas realizations in the second half. As a reminder, we are the largest gas producer in the state, which puts us in a strong position in the current storage constrained environment. Our hedging program enhanced our second quarter cash flow and continues to support our strategic objectives to protect our cash flows and margins and improve our ability to comply with our credit facility covenants in case of further price deterioration.
Our marketing team works to take advantage of dislocations in the commodity markets with the goal to hedge up to 50% of our crude production. To date, we have hedged more than a third of our estimated oil production on average for the rest of 2016 and reduced our call exposure in 2017. We will continue to opportunistically increase our hedge positions for 2017 as appropriate.
I will now turn the call over to Mark to discuss the details of our second quarter results.
Thanks, Todd. During the second quarter we saw modest improvements in crude oil prices, breaking the extended downward cycle that began the second half of 2014. We believe the severe reduction of investment in this sector will lead to higher prices over time, but with the recent pullback in prices, the current strip suggests only modest improvement through the remainder of the year and supports continued prudence on our part.
While we welcome the second quarter increases in prices, we continue our focus on the controllable portion of our costs. Living within our means, managing our debt, and eliminating our production decline.
Our second quarter realized crude price of $43.70 per barrel, including hedges, was 20% higher sequentially, but 23% lower than the prior year period. Our hedges increased our realized prices by $2.29 per barrel during the quarter. Our realized NGL price increased 38% sequentially to $22.54 per barrel, which was also up 10% year-over-year. These higher prices were due to tighter supplies and better contract prices on natural gasoline.
Realized natural gas prices of $1.66 per Mcf reflected a 19% decline over the prior quarter due to lower demand as we transition out of winter months. Prices were also affected by less storage capacity during the seasonal injection period as a result of a disruption in Aliso Canyon third party gas storage facility. Natural gas prices during the quarter were 33% lower than the prior year levels following the overall downward trend in commodity prices. As Todd noted, we expect the ongoing Aliso Canyon storage outage to put upward pressure on prices during the gas withdrawal season.
Moving to production, total daily production volumes averaged 140,000 barrels of oil equivalent during the quarter, representing a 13% decline year-over-year. Oil production for the quarter averaged 90,000 barrels per day, while NGL production averaged 16,000 barrels per day and natural gas production averaged 202 million cubic feet per day. Additionally, third-party pipeline disruptions negatively impacted our ability to sell a portion of our oil production during the quarter, causing us to store over 90,000 barrels through the period.
These pipeline eruptions are fully resolved and we expect this crude inventory to be sold in the third quarter. Our continued focus on costs resulted in a $54 million decrease in production costs year-over-year, below our second quarter guidance levels. This 22% reduction occurred across our operations, particularly in well servicing, field personnel and lower gas prices. Our production costs were also affected by our decision to selectively defer workovers and downhole maintenance activity in the current price environment.
Toward the end of the quarter, we began to ramp our workover and downhole maintenance activities as oil prices began to improve. As a result of this increasing activity, combined with higher seasonal power prices, our per unit production costs were slightly higher sequentially. We expect a further modest increase in our third quarter production costs resulting from higher activity levels, as well as the effect of higher power cost due to seasonal factors, together with higher prices for natural gas used in our steam flood operations.
We believe higher workover activity levels will help us moderate production declines in this low oil price environment and we’re committed to sustaining and improving upon our efficiency gains over the longer term. Our focus on cost containment also helped bring second quarter general and administrative expenses down 28% or $24 million below last year’s second quarter level.
Our adjusted G&A expenses registered $57 million, representing a 24% decline year-over-year. Sequentially our adjusted G&A costs increased by 8%. This was a result of higher non-cash equity compensation expense, largely due to the improved split adjusted stock price over the period and management’s decision to restore previously reduced employee benefits, such as contributions to benefit plans.
Current quarter taxes, other than on income, were 21% or $11 million lower than the prior year period, due to lower property taxes assessed in the lower price environment. Exploration expense was $2 million lower year-over-year as we continue to defer investment and exploration projects in the current commodity price environment. DD&A expense is significantly lower this year due to the 2015 impairment charge and its effect on the current year DD&A rate.
Interest expense for the quarter was $9 million or 11% lower than prior year levels. Our debt level at the end of the second quarter was $5.9 billion, representing an approximate $700 million reduction from our peak following the spin. As Todd mentioned, our combined deleveraging actions taken to date continue to demonstrate our strong focus on reducing our debt in a prudent and fiscally responsible manner.
During the quarter, we recorded a $44 million gain on the debt for equity exchange that I previously discussed, a $31 million gain on an LA Basin asset divestiture, $137 million of non-cash hedge losses that represent the mark-to-market position on our outstanding hedges and a $19 million realized gain related to our second quarter settled contracts.
During the second quarter of 2016, we recorded a net loss of $140 million $3.51 per diluted share. This compares to a net loss of $50 million or $1.30 per diluted share in the first quarter and a net loss of $68 million or $1.78 per diluted share in the prior year period.
The adjusted net loss for the quarter were $72 million or $1.80 per diluted share compared to an adjusted net loss of $100 million or $2.60 per diluted share for the first quarter of 2016. The adjusted net loss of the second quarter of 2015 was $51 million or $1.33 per diluted share. Adjusted EBITDAX for the quarter was $160 million, up over 29% from the $124 million registered in the prior quarter and compares to $270 million year-over-year.
Capital investment for the quarter amounted to $5 million slightly lower than our guidance, highlighting our disciplined approach to managing our cash flow. The low to kind nature of our asset base allows us to reduce investing to such low levels without significant increases in our decline rate.
Operating cash flow for the current quarter represented a use of $71 million, which included a $41 million property tax payment in April and $133 million of interest payments for the quarter. The interest payments for the quarter were $85 higher than the first quarter simply due to the different payment dates for our various notes.
The first half of the year we generated positive free cash flow after capital, excluding working capital, of $76 million, demonstrating our ability to live within our means. We believe this sets us apart from many of our peers in this sector who continue to outspend their cash flows.
As Todd noted, we initiated a cash tender for a portion of our outstanding bonds on Monday. The tender’s condition to point several items, including the tendering of a minimum of $500 million in principal amount of bonds and availability of funds under our bank revolving credit facility. We’re well advanced on our proposed amendment with our bank group that would allow for the tender transaction.
A couple of the other notable amendment items include our grant of additional collateral from our unencumbered assets, reduction of the revolver commitment by $200 million while maintaining liquidity, and revised financial covenants to the end of the first quarter of 2018, all while maintaining flexibility for future potential monetization and additional deleveraging activity. In connection with the credit facility amendment, we’re marketing a new syndicated loan facility, the proceeds of which would be used to reduce outstanding bank debt.
Finally we executed a reverse stock split in the second quarter, which addressed listing requirements, trading price criteria for our institutional investors and reduces expenses. The reverse stock split reduced our outstanding shares on a one for 10 basis and we’ve restated all historical first share and outstanding share amounts.
Now please note that we’ve provided key third quarter 2016 guidance information in the attachments to our earnings release and I’ll be happy to take any questions you may have on that information, as well as other aspects of our results during the Q&A portion of the call.
I will now turn the call over to Todd.
Thank you, Mark. CRC’s second quarter of 2016 was characterized by focused execution, which delivered another quarter of solid production, cost reductions and continued deleveraging. Our management and operating teams have demonstrated their extensive experience with these assets in all phases of the commodity cycle, which has helped us defend margins and enhance value, even in a downturn. We remain determined to capitalize on all opportunities that present themselves as a result of market dynamics.
In the meantime, we believe we have sufficient liquidity and flexibility from our banks to pursue initiatives that strengthen our balance sheet. The sustained lower price environment will likely require patience for us to achieve all of our balance sheet initiatives and objectives. We believe each deleveraging step has strengthened our balance sheet and we continue to execute opportunities designed to maximize shareholder value over the long-term.
This concludes our remarks and we now welcome your questions.
Thank you. [Operator Instructions] And the first question comes from Evan Calio from Morgan Stanley.
Hey, good morning, guys. And I guess I’m happy to find you in an earlier time slot today. My first question you released asset sales I guess. I mean how does the bond tender if it’s successful and prove or change your negotiating position as it relates to assets sales, maybe even particularly the power plant? And as you list the various asset options on Slide 6, which of the various options are most advanced and the highest probability of potentially closing by year end? And any color there, please.
Yes, Evan. This is Todd. Just to give you color as you think back going back to the original spin, we always said we’re pursuing all alternatives and trying to do what makes the most sense for the Company. I’d say last year we were pursuing alternatives that really involved assets of the Company, our midstream power plants and those things.
And I think as the market went into freefall late last year, I think there was some uncertainty around the counterparty risk associated with the Company. So that changed the dynamic and really the required returns I think of the counterparty investors that were dealing with it to that point in time.
So that alternative didn’t become as attractive. I think what happens here post this transaction, obviously we’ve taken some leverage off the table and we continue to want to improve our balance sheet. I think it alleviates some of the more counterparty risk and enables us to potentially execute on some joint ventures both in the upstream and the midstream side of the business.
And I think clearly the focus will be more on that part of the business after this capital market solution, but there still are other capital market solutions that we will look to pursue. But again, we’re looking at what makes the most sense for the long-term for our shareholders, not, like I said, short-term gain for long-term pain. We want to make sure we do something that gives us the best bang for our buck that helps us out longer term.
Great. My second question is a little bit of outlook into 2017. I mean what’s the minimum level of 2017 CapEx, given your 2016 deferrals to allow you to operate safely? Any color or guidance? I know you mentioned in your comments that declines would mitigate year-over-year in that scenario. And then somewhat related, given the Slide 13 with improved economics, successful cost improvements, is $500 million still a good maintenance CapEx number to manage back to flat production?
So if you want to think about safe operations and basic maintenance to do so, I think that’s sort of 50 plus or minus. Obviously this year it was right around 50, but remember 19 of that was the power plant turnaround, but you do have those type of things that occur every year.
So that’s why I’ll say 50 plus or minus. If you want to think about holding oil production flat, that’s a few hundred million dollars. If you want to think about holding BOE production flat, that’s a little bit more. So I don’t think it’s as large as the $500 million number you quote, but we really don’t focus on the BOE basis. We’re really focusing on maintaining the business and then incrementing investments using our VCI metric.
Maybe as just a follow-up, if I could. I mean how does that balance work into 2017 between debt pay down goals and a CapEx beyond minimum levels? I mean is the first call for any excess cash flow, whether it be higher commodity price or asset sales, on to the debt side or is there a goal to work to flat production first or other? I’m just trying to understand how that plays out in 2017?
Well, I think we have to balance out numerous things here. We’re trying to deleverage the balance sheet. We’re trying to preserve liquidity and we’re also trying to maintain our production base. And when you have investment opportunities with VCIs greater than 2 at $40 Brent, those really are compelling items for you. And a lot of those are workovers. I mean we have a business that has an enormous amount of stack pay, so we don’t necessarily need a drilling rig to keep our production flat in some cases.
So I think that’s the one thing that’s lost on a lot of folks. So from our perspective, we’re going to invest in the business and especially when it has compelling returns, and we’ll opportunistically pay down debt going forward. But it goes back to the basic tenet, we will live within cash flow and we’ll do whatever necessary to do so to maintain the business and manage the business that way.
Okay, guys. I will leave it there. Thanks.
Thank you. And the next question comes from James Spicer with Wells Fargo.
Hey, good morning.
Hey, good morning. This is a follow-up to the previous question. In terms of maintenance capital, if you were to start actually deploying capital at those levels, for example in the event of a recovery, how long would it take for production to begin to stabilize? And I’m thinking about just the longer term impacts of some of the deferred maintenance and activity that you’ve been going through so far.
Yes. So if you think about it, like we said, we came into the year, the market was on freefall. We cut all discretionary activity and I mean all. Expense workovers, capital workovers, everything, except for the power plant turnaround. So if you thought about how are we going to stabilize production, you’re talking about somewhere between four to six months that you could probably start engaging enough with workover rigs and drilling rigs to flatten and maybe start growing production.
Okay. Great. That’s helpful. And then secondly, you managed to get some debt for equity swaps done during the quarter. Wondering if there’s more opportunity for this sort of deleveraging activity.
I think definitely there’s opportunity, but for us it has to meet specific criteria. Obviously everything we’re evaluating it and how it creates value for our shareholders. And we felt like those opportunities were opportunistic and took advantage of those. We will take advantage of opportunities like that as we see going forward.
Okay. Thank you.
Thank you. And the next question comes from Pavel Molchanov of Raymond James.
Thanks for taking the question guys. Thinking kind of forward to 2017, there is obviously a lag between how the commodity curve moves and the responsiveness of your banking group to accommodating those higher prices. Have you had discussions with banks to perhaps set some guideposts for the kind of CapEx that they will allow you to implement in 2017 under a higher price stack?
Yes. We actually, as most of you, the $50 million this year for ourselves was self imposed, again managing within our cash flow. And I’ll let Mark comment on our discussions with the banks along these lines.
Pavel, Mark here. Thanks for the question. One of the things I want to point out is that we work hard to develop the relationships, cultivate the relationships with the banks. We appreciate their support with this very – the transaction that we’re looking at now is not an easy transaction and we’ve had their support as we’ve gone along. I want to point out that the banks are not setting the business plan. Rather what we see is covenant levels set to provide kind of a reasonable runway around what we think it reasonable for the Company given the outlook.
One of the things that we’ve disclosed recently relative to where we stand on the amendment, in terms of capital expenditure going forward, that’s been raised for 2016 to $125 million from $100 million currently. And now we’re looking at $200 million in 2017 with the unused carry forward in 2016 for 2017. I think that just demonstrates the support of the banks. And if we were to see commodity prices ramp and saw excess cash flow that we want to put back on the ground, I’m confident we’d be able to go back to the banks and work with them on those kinds of things. We have to this point very successfully.
Okay. And then question also about the bond tender that you’re proposing. Part of the tender or component of it at least is some pretty short-term maturities, looking out three, four years. For maturities that are that nearby, what gives you the confidence that you’ll be able to repurchase those at $0.55, $0.60 on the dollar? Since presumably the Company will still be around to refinance and/or repay those in the foreseeable future.
We can’t comment on a deal that’s in the market right now. I mean at this point in time we feel confident of our advisors and ourselves being able to execute on this, but it’s apparently in the market and we just don’t feel like we shouldn’t be commenting on this at this time.
Okay. Fair enough, guys. Thanks.
Thank you. And the next question comes from John Herrlin, Societe Generale.
Yes, hi, just a quick one for me. During the quarter, prices ran up. Many of the companies added more hedges. Are you constrained at all by your balance sheet in putting a larger hedge book on to support your cash flow?
We’ve put hedges on opportunistically going forward and as you know, John, hedges value are a function at time and volatility and what we really try to optimize that from the perspective of going how many quarters out we try to hedge. When volatility ticks down and we have external events that shake up the market, we try to opportunistically layer them in at that point in time.
But really from our perspective, we want to layer among numerous counterparties also. So we are really trying to work with numerous folks and not have too much overexposure to one bank or counterparty ultimately along those lines. So we are trying to put on hedges opportunistically as you can see from our changes of what we disclosed today, we continue to do that opportunistically out into the future.
Okay. Thanks Todd. With the Elk Hills power plant, how long did the turnaround take?
It took about two months.
Okay. With steaming in the ground, how long can you go before it becomes an issue in terms of your productivity?
The one thing I think about from heat in a reservoir is I look at some of these reservoirs from properties we bought, and one in particular, Mount Pozo we bought and it had been steam flooded certain zone back in the 1980s and early 1990s and then we purchased it in the 2000s and there’s still a hot plate effect in the reservoir from that time period.
I think heat and steam management and surveillance, whether it be in a steam flood or water surveillance management and a water flood, it’s something that I don’t think people appreciate or understand as well as you might be and how long the heat can maintain itself in the reservoir and how you manage that heat and that steam. So it’s not an issue that over quarters or even years, I think it’s something you manage over 5-year, 10-year increments when you think about heat in the reservoir.
I was just wondering if you curtail that expenditure more for that reason? That exact reason.
No, I think that’s exactly right and I think that’s something – I think if you remember our Analyst Day that we had Jeff talk about was how do you manage heat appropriate in the reservoir to make it – truly optimize it? And I think that’s something that we continue to work on and continue to get better at as we look to manage costs in the downturn.
Thank you. And next question comes from Brian Singer with Goldman Sachs.
Thank you. Good morning.
I wanted to follow-up on the cost front. Can you kind of talk about where you are in the cost reduction process, mainly on the operating side? And then to the extent that we do see higher oil prices, how much of those operating costs will be sustainable versus what level – or if you would expect some of those costs to go up? And I’m probably talking about the non energy piece of it here as obviously if gas costs go up, that will have an impact on your…
Brian, I think that’s a good point. Obviously we’ve gone into the summer rates here in California, our energy prices go up until October. So that’s outside of our control. But we feel like the reductions we’ve seen on both the capital and the operating costs that are – I would at best guess 80% of them are sustainable over the long-term and really process improvement and the like.
Operating costs, you’ll see they’re picking up coming into the quarter and I think there’s a few functions going on. But the primary one there is increased expense workovers. Remember we planned on the breaks, now we’re picking up more workover rigs and trying to get back and doing the things we would have ordinarily done and ordinary course of business.
Going forward we will continue to do that in this kind of price environment. Obviously when it was kind of freefall into the high 20s early low 30s, it wasn’t something that we wanted to do, but I think that’s the biggest single thing you’ll see in the very short-term is an increase in expense workovers. But obviously you’re going to get a benefit for that over the next few months also.
Got it. Thanks and then where is that threshold point where beyond the freefall no activity and beyond just be in kind of normal workover activity you would pick things up? And how do you see that breakeven evolving?
As you saw, where we talked about that our inventory of drillable prospect to have VCIs greater than 1.3 doubled year-over-year from our focus on the resource base. So from our perspective we’re looking to increase activity right as we’re speaking. We’ve been increasing activity both with the drilling rig on a very modest basis and with much more with the workover rigs. So we feel like prices in this environment are something that we can increase both activity, and as I’ve stated in water floods and steam floods around the state.
Thank you. [Operator Instructions] And the next question comes from Michael Ainge with TIAA
Hi. Thank you for taking my question. I wanted to just drill down a little bit. You’ve touched on it a few times, but I just - I guess I want to understand it a little bit better. I’ve seen some of your peers report and a lot of them have had unit cost declines first quarter to second quarter. Yours ticked up a bit and I just want to kind of get my arms around that a little better in term of the unit costs going up from 1Q to 2Q.
Yes. Michael, I mean I think the issue is just what we were talking about in the first quarter coming into the year, we really slammed all on the brakes for an all discretional activity. So you’re talking about workover rigs, you’re talking about everything except the Elk Hills power plant turning around. We weren’t fixing wells and doing things we typically would do. The markets with the price environment were screaming at us to not accelerate any production into that environment and we weren’t going to do so.
So as we came into the second quarter, clearly we have two things working. One is we have a declining asset base and then we also have increased activity. And then we have power rates in California go up in the summer. So all those factors are going to contribute to increasing operating costs. But I would focus you on the absolute operating costs where we’re bringing the absolute dollars down. Again so declining - modestly declining base. So I think that’s why you see it the way it is at this point in time.
Okay. And just to follow-up on that, it looks like you’re guiding towards increased production costs on a unit basis second quarter to third quarter. Could you just touch a little bit on what’s driving that? I mean is it basically just the same issues or…
Same exact issues, yes. Same exact. Increased activity and again power costs are the two biggest factors at this point in time.
And so on the power cost side, so that would run up in 2Q and 3Q for obvious reasons. And then I would imagine you would expect that to drop back down in 4Q.
Yes. And the other thing is obviously natural gas costs too. As natural gas creeps up, that’s a cost for us on the steam flood, but it’s a benefit from [indiscernible] costs, yes.
Okay. Thank you very much.
Thank you. And the next question comes from Biju Perincheril with Susquehanna.
Hi, good morning. I’ve got a question going back onto the maintenance CapEx. The few hundred million that you recited for keeping oil production flat. Wondering how long of a timeframe that is valid. Or is something next couple of years and if that’ll look out a longer time period, does that number go up? And by how much?
I think when you think about it, there’s a few different things, factors going on from a macro perspective. The investments we’re making in steam floods and water floods are flattening to the decline curve over time. So that’s going to cause that number to shrink over time. We’re also able to sustain our cost reductions that our operations teams have done an outstanding job on in both the capital side and the operating side.
But then obviously you’re going against a smaller declining base, but a lot of the production that was from prior years that were in the upper Monterey, that has a higher initial decline, is now further out on the hyperbolic curve and flattening too. So I think it’s going to be as the smaller production base, it’s going to be actually easier than you think to maintain production going forward once we get through the bottom of this cycle.
Does that include any sort of midstream investments or at the lower base you have sufficient midstream capacity?
We definitely have sufficient midstream capacity. And obviously you’re going to have the maintenance that goes year by year, but that’s again, that’s in that 50 plus or minus number I quoted earlier.
Perfect. Thank you.
Thank you. And the next question is a follow-up from Pavel Molchanov with Raymond James.
Hey, guys. Just one maybe slightly esoteric item. In Monterey County there is a referendum on the ballot this November on essentially banning fracking. Do you have any properties in that county that would be affected if that were to pass?
We have no production in that county and I don’t think there’s very much production in that county.
Okay. Appreciate it.
Thank you. And the next question comes from Paul Sankey with Wolfe Research.
Hi, good morning. It’s a follow-up to the pre, pre question, which is you said that your decline rates will moderate if you let this. The smaller the base gets, that makes sense. So I was wondering how much more gassy you’ll be getting over time? And can you just remind me, I’m sorry if I missed this. But are you saying that you think you can actually maintain $5 million a quarter of spending and have decline rates, I think you said in the 10% to 15% range? It seems extraordinarily low CapEx. I just wanted to sort of double confirm that. And then the actual question is the gassiness of the future production, how that will change? Thanks.
Yes. The low decline rate we think $50 million a year of maintenance CapEx we can maintain that 10% to 15% decline going forward. And from a gas mix, obviously we have an enormous gas inventory, both some associated gas at some properties and in the Sacramento Basin. We’re looking to take advantage of some of that. You see we placed small amount of gas hedges on to support a small program up in our Sacramento Basis. So we feel like there’s some opportunities there, but we keep close tabs on the market and how those opportunities compete with our other opportunities versus our VCI metric.
So I guess that you are kind of voluntarily getting more gassy. Is that what happened this quarter?
We are actually – we are not getting more gassy. The gas has been declining quicker over oil because we’ve been preferentially drilling oil. But if we talk back way to the beginning, again we have so much gas inventory, if gas prices change materially relative to oil, we could sift the Company to a gassy Company. But at this point we’re becoming less gassy over time as we preferentially go after oil projects.
Got it. And you’ve made some money from your hedging, you say you’ll do it opportunistically. Is this the level at which you would be hedging? Or I mean the sort of strip that we’ve got now just in case prices go even lower? Or do we get to a point where it’s like, okay, we can’t really lock in here?
We monitor it daily and we’re really – if we thought about it from a very high level, we’re trying to hedge out about 18 months and at least 50% of our crude oil production. Sometimes a little more, sometimes a little less. But you just don’t want to get in a situation where you’re always a price taker. You’re trying to get in situations where there’s dislocations in the market the day after Brexit, those kind of things that occur.
Or you think about trying to take advantage of fear or panic in the market so you can do that. So I mean and the good thing about tracking Brent and how we’re priced off Brent is it’s a worldwide commodity, so our marketing group’s monitoring things in Singapore, London, you name it, so that we’re always try and take advantage of any opportunities. You don’t see us layer on enormous hedges. You’ll see us be smart and do 1,000, maybe 5,000 here and there to try to be really opportunistic ultimately.
End of Q&A
Thank you. As there are no more questions, I would like to return the call to management for any closing comments.
Thank you, everyone. And thanks for anyone who got up on the West Coast nice and early with us today. And please call Scott if you have any questions or myself or Mark. Thank you.
Thank you. This concludes today’s teleconference. Thank you for attending today’s presentation. You may now disconnect.
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