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California Resources Corp
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Good day and welcome to the California Resources Corporation First Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, today’s event is being recorded.
I would now like to turn the conference call over to Mr. Scott Espenshade, Senior President. Please go-ahead sir.
Thank you. I'm Scott Espenshade, Senior Vice President of Investor Relations. Welcome to California Resources Corporation's first quarter 2018 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, as well as several members of CRC's executive team.
I would like to highlight that we have provided slides in our Investor Relations section on our website, at www.crc.com. These slides provide additional insight into our operations, and first quarter results, plus additional information. Also, information reconciling non-GAAP financial measures discussed to their most directly comparable GAAP financial measures is available in the Investor Relations portions of our website and in our earnings release.
Today's conference call contains certain projections and other forward-looking statements within the meanings 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. Additional information on factors that could cause results to differ is also available in the company's 10-Q, which is being filed at our annual meeting, our annual shareholder meeting on May 9. We would ask that you review it when available and the cautionary statement 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. Please note, CRC will be hosting an Analyst Day on October 3 in New York City for institutional investors and self-side analysts. We believe this will be a great opportunity to get an update on our operations and run through our strategic plans in detail.
As a reminder, we have allotted similar time for earnings Q&A at the end of our prepared remarks; and would ask that participants limit their questions to a primary and a follow-up.
I’ll now turn the call over to Todd.
Thank you, Scott, and thank you to everyone for attending CRC's first quarter 2018 earnings call. Building on our efforts in the second half of last year, we have taken bold steps to kick-off 2018. We completed several value accretive transactions that bolster our operating capabilities and our steps to drive cash flow growth.
As a result, we’ve updated our operating and capital plans, which were the most robust since our spin. They are designed to drive thoughtful production growth beginning in the latter part of 2018 with a more meaningful ramp in 2019. Our financial position has been strengthened with runway to deliver enhanced value to our shareholders.
We’re prone to build upon this momentum as we invest in our business at a level that provide both stability and value-oriented growth for the long term. CRC benefits from a flexible portfolio of assets that allows for strategic investments throughout the commodity cycle. Since the spin, we quickly adjusted our capital investment levels to align ourselves to the changing commodity price environment.
We focus on projects to protect our base, providing low cost, high value support to our legacy production and yielding very well corporate decline rates. This meant our internally funded drilling and workover capital was below our maintenance capital levels. We also leveraged our JV partnerships to preserve and otherwise reduce our capital, particularly during the second and third quarter of 2017. This ultimately had the effect of arresting our production declines and pushing out our production response into the first part of 2018.
At the same time, this type of prudent allocation of capital delivered free cash flow through the downturn and provided the flexibility to reduce our debt. These results validate the work of our team and demonstrate the resilience of our asset base as we pursue long-term value. Aided by a series of impactful transactions we believe we’re now well-positioned to transition from preservation mode into a midcycle investment environment. We expect to deliver value-oriented growth in multiple expansion.
We completed the $750 million midstream venture and a $50 million equity investment in February. These transactions helped on multiple fronts from validating the value of our midstream infrastructure to funding key strategic and financial objectives. We applied the Ares proceeds to pay down our revolver, as well as providing liquidity to add quickly when the opportunity required the remaining interest in our flagship Elk Hills field became available. Lots of credit goes to Chevron and CRC teams for getting us across the finish line.
Consolidating full-ownership of our flagship Elk Hills field has been a long-term objective and will maximize the value of Elk Hills and its integrated infrastructure together with surrounding fields. The acquisition allows us to bring the full weight of our expertise to bear with deep experience cultivated over the last 20 years of operating Elk Hills. We’ve already begun centralizing facilities and streamlining operations to reduce cost, expand margins, and most importantly increase cash flow.
Proved reserves alone for these acquired interests are estimated to be approximately 64 million BOE based on SEC year-end 2017 pricing. Operating costs at Elk Hills are some of the CRC's lowest, currently running in a low-teens per BOE. Through this acquisition, we expect our overall corporate LOE and G&A metrics excluding long-term cash filled compensation will improve on a per-unit basis. We also expect to generate significant NOI synergies from about $5 million in the short-term and additional $15 million over the following 18 months.
Further NOIs operating cash flow, even without synergies will be increased by approximately $100 million at $65 Brent. We executed on the ideal use of proceeds from the trade area transactions. These transactions allowed us to pay down over 300 million in debt by monetizing midstream assets that weren't fully being valued by the market. They also generate the liquidity to acquire the balance of Elk Hills. And we strengthen our operating and credit metrics with minimal execution risk. Net, net after allowing for the Ares preferred distributions, CRC is $30 million to $50 million ahead on our free cash flow basis, including synergies.
Additionally, we utilize proceeds from the Ares monetization to opportunistically repurchased some of our debt in April. This further demonstrates our ongoing commitment to strengthen our balance sheet through multiple avenues. CRC is transitioning to a growth trajectory. We are increasing our capital investment plan to a range of $550 million to $600 million. This includes approximately $100 million to $150 million in JV capital and is up from our previous budget of $500 million to $550 million.
Our increased capital will largely be deployed toward drilling activities in the San Joaquin basin with the remainder largely directed to the LA basin. A portion of our increased capital plan will target additional resource capture to delineation of large assets such as in the Buena Vista, Ventura, and southern San Joaquin areas.
We call that steamfloods and waterfloods have different production profiles and longer response times and typical conventional wells, as a result of we may not experience full production contribution in the year that the well is drilled. As such, we expect to see the additional production associated with our capital plan later this year with a large ramp in production expected in 2019.
Now turning to our first quarter 2018 performance. We produced 123,000 BOE per day. Above the midpoint of our guidance range. I want to point out there were two primary factors that play here. Our results were impacted as previously expected by 400 BOE per day, due to California wildfires and mudslides. This production is completely back online. Also, the PSC effect associated with key LA basin properties negatively impacted net production and unit cost metrics in the quarter.
CRC is probably the only domestic E&P company with the U.S.-based production affected by production sharing contracts. Since over 25% of our oil production is subjected to PSC, I like to spend some time outlining their impact on our reported oil production to provide greater sense of clarity on this point. We have three separate PSCs in place in the Wilmington field where CRC is the contracted operator for the City of Long Beach and the State of California.
Under these contracts, CRC pays for 100% of both the operating cost and the capital investment in the field. CRC recovers our partners portion of the operating and capital cost from the produced oil one month after the expenditure. This is in contrast with traditional international PSCs where such costs are often deferred and amortized over a longer period. We receive about half of the production remaining after cost recovery as profit barrels.
In a rising crude oil price environment it takes fewer barrels to reimburse the same amount of cash to recover our partners share of operating capital cost, as reflected in both the fourth quarter of 2017 and the first quarter of 2018. There is no effective cash impact under this arrangement because we receive the same cash amount for cost recruitment by fewer barrels when commodity prices increase. This result an optically lower net production and higher cost per barrel metrics and CRCs reported data, but the important point is that higher crude prices are better for cash flow and returns because our shares of the remaining barrels are profit barrels, receive the higher prices.
The PSC effectively incentivizes CRC to continue investment in this large field. We have taken steps to enhance disclosure on PSCs. We have provided production and cost guidance at different crude price levels that showed the expected PSC impact from the second quarter of 2018 both in the guidance table and our earnings release as well as in the supplemental information included in our earnings presentation.
And as usual we have also provided enhanced disclosure on joint venture capital so that investors can differentiate between the impact of CRCs capital compared to the contribution of development capital funded from JV partners BSP and Macquarie. Our investor relations team will be available to walk through these details should you still have any questions.
Looking at our operational execution, we saw good progress on cost this quarter coming in below expectations. We achieved about half of this improvement through sustainable cost reductions with the remaining half due to timing of activity. We recently pushed more cost accountability down further into the organization with this effort beginning to show real results. We are finding savings both by consolidating providers and increasing competition among our vendors by having greater visibility and communication across the organization. This has allowed us to continue to be selective with our suppliers and have led to reductions of up to 20% in certain categories like [indiscernible] as an example.
Overall, we are pleased with our performance for the quarter. We restored production interrupted by the wildfires and mudslides, while remaining focused on driving cash margin expansion. Through continued operational execution we expect to reap sustained cash flow growth from our base, our drilling edge, and our accretive transactions to enhance long-term shareholder value.
Now, I’d like to turn the call over to Mark.
Thanks Todd. The first quarter represents a strong start to 2018 as we continue to cease multiple opportunities to strengthen CRC's financial position and deliver value through disciplined execution. As we shift to value-oriented growth we are investing our time, effort, and resources to deliver cash flow and margin growth. We expect to deploy our increased capital budget to pursue our high graded portfolio across most drive mechanisms and targeting BCI is greater than 1.5.
Additionally, we are selectively adding development facilities to drive the next stage of growth in our strong inventory of projects. These facility investments generally target BCIs of 2.5 or better. In some instances, this value we drive from enhanced production will payout anticipated within 12 months. An example of the installation of compression to lower the line pressure for specific wells in Elk Hills.
In others, investment and equipment will reduce operating cost by almost half of the expected duration of the product life. Investments such as these are pivotal on our strategic approach and will ensure we deliver long-term value through our development program and capitalize on the strengthening commodity environment. As Todd discussed, we used a portion of the proceeds from our midstream transaction to proactively reduce debt.
In February, we paid $297 million of the then outstanding balance on our 2014 revolving credit facility. We followed that up in April with a series of repurchases of our second lien notes in an aggregate principal amount of 95 million or 79 million in cash. This is another example of our ongoing commitment to strengthen our financial position. I’m pleased to report that BSP recently committed to its third tranche of capital under $50 million of funding is imminent.
In addition, our bank group recently reaffirmed our borrowing base of 2.3 billion. I’d like to note that during our spring redetermination, our bank group was particularly complementary of the Elk Hills transaction. They recognize that we were able to essentially transfer mainstream collateral in the upstream collateral, while enhancing our position to drive value-oriented growth and improved cash flow. We plan to be prudent in managing our capital structure to maintain sufficient liquidity as we prepare to fund a midcycle investment programs, while also preserving capacity for additional growth opportunities as they may arise.
Now turning to our performance for the first quarter of 2018, we produced an average of 123,000 BOE per day in-line with our previous guidance. As Todd noted, sequentially our results included approximately 2,400 BOE per day of reduced production volumes, due to PSC effects resulting from higher realized prices, compared to the fourth quarter of 2017. This demonstrates the flattening we’re seeing in our production that Todd mentioned.
During the quarter, we continue to benefit from premium Brent based pricing in favorable realizations. Oil differentials were healthy registering a strong 100% of Brent and 93% after the effect of hedges. NGL realizations also remained strong, reflecting tighter domestic supply and the strength in exports that carry over from last year. Natural gas realizations continue to see seasonality trends magnify, due to limited third-party storage within California.
Production costs for the first quarter of 2018 were $12 million or excuse me $212 million or $19.08 per BOE, below our stated guidance range. Total production costs were flat year-over-year, while the increase in unit production cost was driven by lower production volumes. Production costs, excluding PSC effects would have been $17.47 per BOE. As Todd mentioned the decrease in first quarter cost compared to guidance was about evenly split between long-term cost reductions and timing.
General and administrative costs were $5.67 per BOE, which were lower than expected primarily due to the timing of certain corporate expenses. Note that it is expected with the rise in our stock price second quarter cost will be higher due to long-term non-executive compensation component of G&A, which is paid in cash based on our stock price. For the first quarter, we reported a net loss of $2 million attributable to our common stock or $0.05 per diluted share, adjusting for unusual and infrequent items such as non-cash derivative losses that are generally excluded from core earnings by investment analyst.
Our net income would have been $8 million or $0.18 per diluted share. Adjusted EBITDAX for the first quarter was $250 million, up 25% from the prior year period reflecting margin expansion from 39% to 41%. Note that under newly adopted accounting rules we’re now required to report transportation costs as a cost item as opposed to offsetting them against revenue. If we were to calculate our first quarter’s 2018 EBITDAX margin under prior rules, it would have been 44%, an impressive 5 percentage point expansion.
We reported cash flow from operating activities of $200 million in the first quarter and positive free cash flow of $61 million. Our hedge program currently covers a significant portion of our oil production for full-year 2018 and we’ve added to our position in 2019 as well. We actively manage our hedge book and have worked to proactively let some of our prior ceiling as we saw ourselves moving into a stronger price environment. In the first and second quarters of 2019 we hedged approximately 35,000 and 20,000 barrels per day respectively. The hedges generally form an effective floor around $63 Brent.
For the third quarter 2019, we’ve initially hedged 10,000 barrels of oil per day providing an effective oil price for a 65 barrels Brent. The 2019 hedges generally preserve our upside about those flows. We continue to target up to 50% of our production in order to provide more certainty and cash flows and underpin our capital program. Please refer to our earnings release for the details on our hedging positions and counterparty options.
I’d like to highlight a few guidance related items. Now first, a portion of our acquired Elk Hills volumes will not be reported until the third quarter of this year, due to the mechanics of the transition. Second, our guidance reflects our confidence that we’ve arrested our base production decline. If one excludes the acquired Elk Hills interest and holds pricing consistent with that of the first quarter that is adjust for the PSC effect, our base production for the second quarter of 2018 is expected to be flat with the first quarter.
CRC is in a market leading improved position. We executed two accretive transactions, we've increased our capital program, we’re experiencing a stronger midcycle pricing environment, and our strategic priorities are clear. To enhance value driven production growth and margin expansion, while continuing to strengthen our financial position. We will remain balanced in our approach responding quickly to opportunities in addressing any challenges proactively as they arise.
CRC has always remained focus on delivering value for our shareholders. Please note that we’ve provided detailed analysis of adjusted items, as well as key second quarter 2018 guidance information in the attachments to our earnings release. I’ll be happy to take any questions you may have on that information and on other aspects of our results during the Q&A portion of the call.
I’ll now turn it back over to Todd.
Thanks Mark. We’re excited for the remainder of 2018. We increased our capital program in-line with the expected cash flows from Elk Hills and related synergies. This will help us target the next phase of development for our company. Further delineate growth areas and showcase the tremendous value held within our rich resource base. With our top priorities centered on enhancing value-oriented growth and cash margin expansion we’re investing to bring forward our large inventory and to increase cash flow investment into 2019.
We remain focused on strengthening our financial position and will continue to further address our debt by reducing the numerator of our leverage ratio, while also growing the denominator EBITDAX. As I’ve always said, it is an all of the above strategy to reduce our leverage. With a favorable outlook on oil prices, a strength in balance sheet, substantial liquidity, and focused execution we look to capture the full potential of our assets and deliver lasting value for our shareholders. We now welcome your questions.
Thank you, sir. [Operator Instructions] The first question we have will come from Jason Wangler of Imperial Capital LLC. Please go ahead.
Good afternoon.
Hi Jason.
I wanted to ask on Elk Hills, obviously you already had around 80% of it and that moves up pretty quickly here to 100% you had finished the deal also to speak and get integrated, is that going to change any of the development plans there or as your kind of adding this CapEx throughout this year that you intend to, does that have a bigger focus to go towards that or anything change I guess as you increase that interest?
Yes, I think it will change a lot of things Jason. I think the most important thing to understand is, I think most people, unless you listen to my IPAA, I wouldn't know. It is extremely complex because different zones and different reservoirs at Elk Hills all had different equity ownership interest. We say it was around 80%, but they all were slightly different. So that meant different surface gathering, different ways you manage the reservoirs, and the way we worked with Chevron and the joint operating agreement they had certain rights over allowing certain types of production and production mechanism.
So, there are things that were freed up to do clearly, and I think clearly capital is going to go out at Elk Hills, but I think it will allow us to reap all the benefits. Just as a quicker side, just to give you an idea, on average in one year we had to take 750 equity samples of different crew, sorry a month in gas and it was costing us over $400,000 a year just to do this kind of sampling for quality assurances around the field with the different equity zones. So that’s just one area of many that just merely starts accreting the cash flow to CRC.
Okay. That’s helpful. And then again you guys are adding a little bit of CapEx here obviously with the cash flows going up, I was wondering as you look at that too from a JV standpoint, are you able to accelerate those as well or are there any governors there or should we just be thinking about the acceleration predominantly in internally generated projects as you move forward?
As we mentioned, Mark mentioned, we did already bring down another tranche of BSP and that’s tranche by tranche and we are investing more with our partner Macquarie also. I think it is a measured kind of portfolio balanced approach for our CRC, our net capital and there’s, and it gives us the unique tool to be able to manage dips in prices or upticks in prices that we might think are not sustainable, so that we can really just manage cash flow for our company so that we don't outspend our cash flow.
That’s helpful. I’ll turn it back. Thank you.
Thanks Jason.
The next question we have will come from Kalei Akamine of Bank of America.
Hi guys. First off, congrats on the team for the solid deal earlier this month. I think the response to use of proceeds have been quite positive. So, my first question is on the joint ventures. So maybe this one is for Mark, just wondering if you can talk about how the cost of capital compensations are evolving today? You have some positives and some negatives I think. Oil prices are higher and the portfolio looks more stable, but interest rates are also changing. So, do you think that the terms on the additional JVs could be more favorable than what’s already on BSP and the MIRA.
This is Todd. I’ll let Mark speak to them in particular, but I would say overall, the overarching comment whether it be on the exploration or development JV we’ve had a lot more inbounds on our side and a lot more discussions and generally the terms are more favorable in the terms we’ve agreed to. And from a cost of capital let Mark give you his thoughts.
I agree with what Todd just said. As our financial position, as our balance sheet continues to strengthen, it puts us in a stronger position to have dialogue with those joint venture counterparties and we would expect all-in return requirements to moderate a bit as we continue to have these discussions.
Got it. Second question, so with Bret now here in the 70s, I would just like to get a better sense of how you guys are prioritizing your drilling opportunities. The production response from conventional is quicker than it would be for something like steam. So, there is obviously some trade-offs between duration and response time, but with higher oil, I think that you guys will be inclined to grow quicker. So, can you talk about the potential rate of change that you see in the portfolio from quicker response opportunities at this oil price?
Yes, I think you see us shifting as we’ve always talked about, we’ve shown that three kind of preservation mode where we were in for a few years to more of a midcycle pricing versus high cycle pricing, I think as we shift to midcycle we’re really focused on value, and so you're going to get away from the secondary measure on after BCI of every metric being payback, you're going to start focusing on long-term value creation as the number one criteria. And you have seen that this year in our investment, we’ve been – in the first half of this year we will spend two-thirds of our facilities spend for the year will be done in the first half of the year.
So that will help us more on the back half as we look to continue our drilling programs on conventional and on the steamfloods and waterfloods. So, I think what you will see is some near-term response, but because of the facilities requirement that we’re investing in today there will be more back-end loaded and in 2018 and 2019 and obviously we have a very resilient base, so these are long term kind of value creation proposition.
Got it. Thanks for the answers guys.
Thanks, Kalei.
The next question we have comes from John Herrlin of Societe Generale.
Hi. I have some income statement questions for Mark. Your production was flat more or less sequentially, but you had a 10% drop in the DD&A, so are you seeing more aggressive pricing? I mean, I saw a footnote, it said that you are using more aggressive pricing on your proved reserves?
Yes, real quick John, you made a good quick point, I think what people won't notice is that if you took out the CSC effect for the last few quarters, we are effectively flat, but if you get into the [indiscernible] we’re actually slightly up each quarter. So, as we are going forward here, so I think that’s a good thing, but I’ll let Mark comment on the DD&A’s assumptions.
John, relative to the DD&A rate, we had reserve edge go through the end of the year. So that had an effect in terms of bringing the unit cost, unit DD&A rate down.
Okay, but what it at a higher price mark or the standard SEC price?
Standard SEC price.
Okay. Then your production expenses went down, is that because what you were just discussing? In terms of efficiencies, because you dropped there, $15 million.
Yes, we’ve actually had – we are obviously – California’s service environment is, service company environment we've already said is rather unique. So, we’ve been, we had a little bit of timing issues, but we've had about half of those production expenses actually be sustainable things that we're going to hold onto.
Okay. And then last one is, your other revenue was up basically 50%, what is it all, and how can we model this because it was a swing factor?
John that goes to that foot note in the disclosures that we have relative to the accounting change. There is an accounting change that made us, basically this quarter on a prospect…
So that’s all the FASB processing and basically the …
Yes, that's it. That will be changed. That’s what it is.
And that is all of it?
Yes. That’s correct.
We’re not going to have that going forward, obviously, so that’s fine. Alright, thanks.
We will apply the same methodology going forward. So, we will be comparable on a prospective basis.
Oh, you will be?
Yes. So, revenues go up as well.
I get that, but that was a big change. Alright, thank you.
Next, we have James Spicer, Wells Fargo.
Hi, good afternoon. You talked about increased capital investment setting up for some acceleration of growth in the second half of the year and then even more so in 2019, I was wondering if you could just provide a little bit more commentary around what those growth drivers are and any parameters we can think about in terms of the rate of that growth?
Yes, I think if you look at, again we're focusing on value ultimately, but if you look at our distribution in our slide, we talk about what drive mechanisms and where the capital is going, whether it be drilling complete or facilities, I think that’s important to understand, I think you can get a feel for what’s going on from a trajectory standpoint and see that we’ve clearly bottomed out and now we’re poised to continue to grow and create value for our shareholders. We don't guide towards full-year production, but we can just tell you, clearly, we see growth in the back half of the year and more growth going into 2019 based on our current plans.
Okay. Thank you. And then with respect to improving the balance sheet, further improvements of the balance sheet now that your second lien bonds are trading above 80, just wondering if there are other opportunities to directly reduce debt or is the focus at this point really on production and cash flow growth?
I think we look at everything from a portfolio perspective on what’s the best value and obviously at one point we weren't pleased about it, but liability management was that. Now, we’re in a different environment. We’re investing in the inventory and putting it back in the ground. It looks like the best alternative. As things turn, we will opportunistically take in debt as we have shown in April and we still can create baskets as we’ve done with non-borrowing-based assets with Ares transaction. So, we continue to look at things, but again as you noted with the debt trading above 80 in the second liens, the best value proposition for us is really going to continue to invest in our business.
Okay great. Thank you.
Thanks James.
Next, we have Muhammed Ghulam of Raymond James.
Hi, thanks for taking the question guys. The new budget significantly increases the capital allocated to LA Basin, it looks like it, can you talk about the driver behind this increase and why you chose the LA Basin or the San Joaquin?
I don't know if it’s dramatically, but if you guys think about it in the rig lines, depending on the rig lines, the average rig line is going to be $45 million to $50 million for a rig year, depending on the rig. In LA Basin you are seeing us bring up activity in Huntington Beach, you are seeing us bring up activity down in Long Beach in the Wilmington field. So, I think what you will see is little more activity in the Wilmington field, particularly in the onshore part of the Wilmington field at this point in time. That’s really what’s going on, but I do see more of a ramp too also up in the San Joaquin basin, particularly the southern San Joaquin.
Okay. And Brent’s nearly 75 today, have you guys started seeing pressure on service costs in California yet or if not, then what price do you expect service cost increases to materially begin to impact the company?
We haven't seen a material move in service cost. In fact, as we noted we have had some service cost come down due to competition and people getting involved, but clearly with prices up there are price pressures, but it’s not to the point that you read about elsewhere. We really haven't as you have seen in our production cost had a material move up, we’ve had more of a flat to down environment so far.
That’s all from me. Thank you.
Thanks Muhammed.
The next question we have will come from Robert Ellenbogen of Credit Suisse.
Hi, thanks for taking my question. As I recall one time, I think you had restrictions around the price at which you could do buybacks, I think 80 may have been the max, could you confirm that and to the extent you did have restrictions, what was the mechanism that allowed you to do it and then secondly any plans to do more? Thanks.
Yes, we have a lot of mechanisms there. I’ll let Mark walk you through all the mechanics of that.
Those mechanics can generally be framed within two baskets. The first basket is usually as you said the 80s. And those baskets are defined in the senior bank facility, generally. The first basket is as you described $0.80 and it is to the extent that basket can be built by monetization of non-borrowing-based assets. The second basket is just – it allows for repurchases at simply a discount to par and that basket gets established by equity raises. So, the Ares transaction both baskets if monetized midstream assets and it also, you know we had built a $50 million basket to allow repurchases of debt up to $50 million associated with their equity contribution. Does that help you?
Yes, it does. Actually, that leads into my second question, just giving you just raised equity twice, and so as you described, how much cash do you have then that’s free of those restrictions and the various indentures I guess are peak capacity, you might call it effectively that it will allow you to buy back stock or pay dividends or things like that?
The equity attributable to the issue under the Chevron transaction does not build that basket, it wasn’t third-party capital raise. So, we just had that $50 million basket that it’s out there and available for use.
Got it.
Above 80.
Got it. And so, do you plan to do any more of types those buybacks?
I think the best way to describe it as Todd said, we will be opportunistic and we will look at it as market conditions change and present themselves.
Got it. Thank you very much.
Thanks Robert.
Next, we have [indiscernible] of Nomura Asset Management. Please go ahead.
Hi. I wanted to clarify, in this press release we saw other revenue significantly higher than in previous periods, I was curious if there is explanation for it?
Yes, as Mark said to John earlier, it had to do with the FASB change that it will be that way from now on.
That’s the transportation cost or?
Correct.
Just simply reporting change. Cost or otherwise netted in the revenue line are now broken out. So, the revenue line is higher and the cost lines are higher, but there is no change to EBITDAX.
Okay. And then on the production sharing calculation, also another clarification, when those volumes are calculated do you use the unhedged prices or hedged prices?
They are unhedged prices.
Unhedged prices, okay. So, if prices were to stabilize then, there would be no subsequent PSC volume affect much immediately or is there like a lag in impact?
No, you would see it just stabilize and then it would be – your net wouldn't change.
Okay. Thank you.
Thank you.
And our last question will come from Jacob Gomolinski-Ekel with Morgan Stanley.
Hi, thanks for squeezing me in. It looks like the production mix has been trending a little bit gas here versus oil here, so just curious if that is solely driven by the PSC or if there is something else that you might be able to provide some color on, and also how we could think about the production slate for Q2 and 2018 in total?
Yes, I think when you look at, you got to remember overall, we're producing about 62% oil and our reserve mix is in the low 70s. So, we’re transitioning and moving it to be more production mix from that standpoint, but PSC volume is clearly if oil comes down it’s going to look gas here. That’s another artificial impact that you're going to have, but you got to remember two – 70% of our natural gas is associated gas, so it’s coming with the oil. But the PSC impact is going to have an artificial affect there on the oil gas mix.
Got you. I guess maybe just, so and I was also asking what is the, is it going to kind of stay at that 62, 13, 25 range for year or should we expect it to change given the difference between production and the reserve base?
I think you are seeing it slowly climbing and you are seeing it move up over time because that is where our investment dollars are going. So, I think you will see that, but it does not happen overnight, if you go back to the spin, I think we're very close to 60%, 59% oil and we have slowly been investing and obviously not even been investing at maintenance capital levels. So, as you see us a ramp up investment and it’s going to be more directed towards earlier properties. I think you will see that mix continue to change.
Got it. And then, are there any early results you might be able to share from the exploration wells in the San Joaquin and Ventura during the quarter and may be any updates from the six exploration wells drilled in 2017?
I don't think there is anything we can shared at this time. We’re happy with our exploration program.
Okay, got it. And then maybe I can just squeeze one last one and since I was the last one in queue anyway, is the 5 million of distribution to Ares that was sort of in the release, maybe you could just refresh our memory when that transaction closed, it seems a little low relative to sort of run rate that the preferred, so thinking probably where is that supposed to trend on a full quarter basis and then on an annual basis?
Yes, I think that would remember that closed in February. So that really was only about one month, and so when you see it, it will remember it has a component and a cash component and that will pick-up from this second quarter onwards.
Okay. So, the, sort of just back of the envelope using the cash component times, where I think it was 750 is the right [indiscernible] run rate basis quarterly?
I think Scott and Joanna could do it, but overall on a cash basis right now it’s probably 71 million quarter, sorry a year, my bad.
Okay. Go ahead. That’s what we had before, alright great. Thanks very much.
Thanks Jacob.
Well at this time, we will go ahead and conclude the question-and-answer session. I would now like to turn the conference back over to Mr. Todd Stevens for any closing remarks. Sir?
Thanks Mike. Thank you for joining us on today's call. As a reminder, please remember to join us at our analyst and investor day in New York on October 3. We will further showcase our value creation efforts. We look forward to speaking to you next quarter or seeing out on the road in the meantime. Thanks everyone.
And we thank you sir and also to the rest of the management team for your time also today. The conference call is now concluded. At this time, you may disconnect your lines. Thank you again everyone. Take care and have a great day.