California Resources Corp (CRC) 2018 Q1 法說會逐字稿

Good day, and welcome to the California Resources Corporation First Quarter 2018 Earnings Conference Call. (Operator Instructions) Please also 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

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 the CRC executive team. I'd 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 portion 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 security 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 available in the company's 10-Q, which is being filed at 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 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 sell 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 will 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 kickoff 2018. We've completed several value accretive transactions that bolster our operating capabilities and are set to drive cash flow growth. As a result, we've updated our operating and capital plan, which are the most robust since our spend. They're 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 a clear runway to deliver enhanced value to our shareholders. We are primed to build upon this momentum as we invest in our business at a level that provides both stability and value oriented growth for the long term.

CRC benefits from a flexible portfolio of assets that allows for strategic investment throughout the commodity cycle. Since the spend, we quickly adjusted our capital investment levels to align ourselves with 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 low corporate decline rates. This meant our internally funded drilling and work over 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 are now well positioned to transition from preservation mode into a mid-cycle investment environment. We expect to deliver value oriented growth and multiple expansion.

We completed the $750 million Ares midstream joint venture and their $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 act quickly when the opportunity to acquire the remaining interest in our flagship Elk Hills field became available. Lots of credit goes to Chevron and CRC teams for getting this 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 the low teens per BOE. Through this acquisition, we expect our overall corporate LOE and G&A metrics, excluding long-term cash settled compensation, will improve on a per unit basis.

We also expect to generate significant annualized synergies from about $5 million in the short term and additional $15 million over the following 18 months. Further annualized 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 Ares 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 generated a 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 a free cash flow basis, including synergies.

Additionally, we utilized proceeds from the Ares monetization to opportunistically repurchase 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 L.A. Basin.

A portion of our increased capital plan will target additional resource captured through delineation of large assets, such as in the Buena Vista, Ventura and Southern San Joaquin areas. Recall that steam floods and water floods have different production profiles and longer response times than typical conventional wells. As a result, 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 at play here. Our results were impacted, as previously expected, by 400 BOE per day due to California wildfires and mud slides. This production is now completely back online.

Also, the PFC effect associated with key L.A. Basin properties negatively impacted net production and unit cost metrics in the quarter. CRC is probably the only domestic E&P company with US based production affected by production sharing contracts. Since over 25% of our oil production is subjected to PFCs, I'd 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 PFCs in place in the Wilmington field where CRC is the contract operator for the City of Long Beach and the State of California. Under these contracts, CRC pays for 100% of both the operating costs and a capital investment in the field. CRC recovers our partners' portion of the operating and capital costs from the produced oil one month after the expenditure. This is in contrast with traditional international PFCs 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 and capital costs, as reflected in both the fourth quarter of 2017 and the first quarter of 2018. There's no effective cash impact under this arrangement because we receive the same cash amount for cost recoupment but fewer barrels when commodity prices increase.

This results in optically lower net production and higher cost per barrel metrics in CRC's reported data, but the important point is that higher crude prices are better for cash flow and returns because our share of the remaining barrels, our profit barrels, receive the higher prices. The PFC effectively incentivizes CRC to continue investment in this large field.

We have taken steps to enhance disclosure on PSCs. We've provided production and cost guidance at different crude price levels to show the expected PFC impacts from the second quarter of 2018 while in the guidance table and our earnings release, as well as in the supplementary information included in our earnings presentation.

And as usual, we've also provided enhanced disclosure on joint venture capital so that investors can differentiate between the impact of CRC's 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 has led to reductions of up to 20% in certain categories like [surface] rentals 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 wedge 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 seize multiple opportunities to strengthen CRC's financial position and deliver value through disciplined execution.

As we shift to value oriented growth, we're 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 VCIs greater than 1.5. Additionally, we're selectively adding development facilities to drive the next stage of growth in our strong inventory of projects. These facility investments generally target VCIs of 2.5 or better.

In some instances, this value we derive from enhanced production with payout anticipated within 12 months. An example is the installation of compression to lower the line pressure for specific wells in Elk Hills. In others, investment in equipment will reduce operating costs by almost half for the expected duration of the project 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 to 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 principle amount of $95 million for $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 a third traunch of capital and their $50 million of funding is imminent. In addition, our bank group recently reaffirmed our borrowing base at $2.3 billion.

I'd like to note that during our spring redetermination, our bank group was particularly complimentary of the Elk Hills transaction. They recognized that we were able to essentially transfer midstream collateral into upstream collateral, while enhancing our position to drive value oriented growth and improve cash flow. We plan to be prudent in managing our capital structure to maintain sufficient liquidity as we prepare to fund mid-cycle investment programs while also preserving capacity for additional growth opportunities as they may arise.

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 include 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 continued 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 remain strong, reflecting tighter domestic supply and a strength in exports that carried over from last year. Natural gas realizations continue to see seasonality trends magnified due to limited third party storage within California.

Production costs for the first quarter of 2018 were $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 costs 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 costs compared to the guidance was about evenly split between long-term costs 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 as expected with the rise in our stock price, second quarter costs will be higher due to long-term nonexecutive 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 analysts. 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 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 was $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 lift 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 of 2019 we've initially hedged 10,000 barrels of oil per day, providing an effective oil price floor of $65 Brent. The 2019 hedges generally preserve our upside above those floors, but we continue to target up to 50% of our production in order to provide more certainty in 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. The first, a portion of our acquired Elk Hills volumes will not be reported until the third quarter 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 adjusts for the PFC effect, our base production for the second quarter of 2018 is expected to be flat for the first quarter.

CRC is in a markedly improved position. We executed two accretive transactions, we've increased our capital program, we're experiencing a stronger mid-cycle 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'll remain balanced in our approach, responding quickly to opportunities and addressing any challenges proactively as they arise. CRC has always remained focused 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 space.

With our top priorities centered on enhancing value oriented growth and cash margin expansion, we're investing to bring forth our large inventory and increase cash flow investment into 2019. We remain focused on strengthening our financial position and we'll 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 in all of the above strategy to reduce our leverage.

With a favorable outlook on oil prices, a strengthened 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.

(Operator Instructions) Jason Wangler, Imperial Capital LLC.

Wanted to ask on Elk Hills, obviously you already had around 80% of it and that moves up pretty quickly here to 100% as you finish the deal off, so to speak and get it integrated. Is that going to change any of the development plans there or as you're kind of adding this CapEx throughout this year that you intend to? Does that have a bigger focus to go toward 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 -- and I think most people, unless you listen to [myipaa], wouldn't know it is extremely complex because different zones and different reservoirs at Elk Hills all had different equity ownership interests. We say it's around 80%, but they all were slightly different. So that meant different surface gathering, different ways you managed the reservoirs.

And the way we worked with Chevron in the joint operating agreement, they had certain rights over allowing certain types of production and production mechanisms. So there are things now that we're freed up to do clearly and I think clearly capital is going to go up at Elk Hills, but I think it will allow us to reap all the benefits.

Just as a quick aside, just to give you an idea, on average in one year we had to take 750 equity samples of different crude and -- 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 immediately starts accreting the cash flow to CRC.

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 the JV standpoint, are you able to accelerate those as well or are there any governors or there? Or should we just be thinking about the acceleration predominantly in internally generated projects as you move forward?

As we mentioned, and Mark mentioned, we did already bring down another traunch of BSP and that's traunch by traunch. And we are investing more with our partner Macquarie also. I think it's a measured kind of portfolio balanced approach for our CRC, our net capital and theirs, 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.

Kalei Akamine, Bank of America.

First off, congrats on the team for the solid deal earlier this month. I think the response to the use of proceeds has been quite positive.

So my first question is on the joint ventures, so maybe this one's 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'd 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 than the terms we've agreed to. And from a cost of capital, I'll 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 dialog with those joint venture counterparties. And we would expect the all-in return requirements to moderate a bit as we continue to have these discussions.

Second question. So with Brent now here in the 70s, I'd like to get a better sense of how you guys are prioritizing your drilling opportunities. The production response from conventionals is quicker than it would be for something like steam, so there's obviously some tradeoffs between duration and response time. But with higher oil I think that you guys would 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.

I think you see us shifting, as we've always talked about. We've shown the three kind of preservation mode where we were in for a few years. It's more of a mid-cycle pricing versus a high-cycle pricing. I think as we shift to mid-cycle, really focused on value and so you're going to get away from the secondary measure on after VCI of every metric being payback, you're going to start focusing on long-term value creation as the number one criteria.

And you've seen that this year in our investment. We've been -- in the first half of this year, we'll spend two-thirds of our facility 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 steam floods and water floods.

So I think what you'll see is some near-term response, but because of the facility's requirements that we're investing in today, they'll be more backend loaded in 2018 and in 2019, and obviously we have a very resilient base, so these are long-term kind of value creation propositions.

John Herrlin, Societe Generale.

I have some income statement questions for Mark. Your production was flat more or less sequentially, but you had a 10% drop in DD&A. So are you using more aggressive pricing? I mean I saw a footnote, is that using more aggressive pricing on your proven reserves?

Real quick, John, you made a good point. I think what people won't notice is if you took out the PSC effects for the last few quarters, we are effectively flat. But if you get into the minutia, we're actually slightly up each quarter, so as we're going forward here. So I think that's a good thing. But I'll let Mark comment on the DD&A assumptions.

John, relative to the DD&A, right, we had reserve adds go up to the end of the year, so that had an effect in terms of bringing the unit DD&A right down.

But was it at a higher price, Mark, or the standard SEC price?

Standard SEC price.

Then your production expenses went down. Is that because of what you were just discussing in terms of efficiencies? Because you dropped there $15 million.

Yes, we've actually had -- we're obviously, California a service company environment we've always said is rather unique. So 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.

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 with that footnote in the disclosures that we have relative to accounting change. There's an accounting change that made us, basically this quarter, on a prospective basis --

So that's all the FASB process?

Yes.

That's basically the 606?

Yes, that's that FASB change. That's what it is.

And that's all of it?

Yes, that's correct.

But we're not going to have that going forward obviously, so that's fine. All right, thanks.

We'll apply the same methodology going forward so we'll be comparable on a prospective basis.

Oh you will be. All right.

Yes, revenues go up as well, right.

Yes, I get that, but that was a big change.

James Spicer, Wells Fargo.

You talked about increased capital investments 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.

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's going, whether it be drill and 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 currently we see growth in the back half of the year and more growth going into 2019 based on our current plans.

And then with respect to improving the balance sheet or further improvements to the balance sheet, now that you're 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 as 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 where investing in the inventory and putting it back in the ground looks like the best alternative.

As things turn, we will opportunistically take in debt as we've shown in April. And we still can create baskets, as we've done with non-borrowing base assets with the Ares transaction. So we can 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.

Muhammed Ghulam, Raymond James.

The new budget significantly increases the capital allocated to the L.A. Basin. It looks like it. Can you talk about the driver behind this increase and why you chose the L.A. Basin over the San Joaquin?

I don't know if it's dramatically, but if you've got to think about it in the rig lines, then depending on the rig line, the average rig line is going to be $45 million to $50 million for a rig year, depending on the rig. In L.A. Basin, you're seeing us bring up activity in Huntington Beach, you're seeing us bring up activity down in Long Beach in the Wilmington field. So yes, I think what you'll see is a 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.

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 costs. In fact, as we noted, we've had some service costs 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've seen in our production costs, had a material move up. We've had more of a flat to down environment so far.

Robert Ellenbogen, Credit Suisse.

As I recall, at one time I think you had restrictions around the price at which you could do buybacks. I think $0.80 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?

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 with two baskets. The first basket is, 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 as to the extent that that basket can be built by monetizations of non-borrowing base assets.

The second basket is just -- allows for repurchases at simply a discount to par. And that basket gets established by equity raises. So the Ares transaction built both baskets, it monetized midstream assets and it also -- we 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 given 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 or peak capacity you might call it effectively that would allow you to buyback stock or pay dividends or things like that?

The equity attributable to the -- issued under the Chevron transaction doesn't build that basket. It wasn't third party capital raise. So we just have that $50 million basket that is out there and available for our use, above $0.80.

And so do you plan to do anymore of those types of buybacks of --?

I think the best way to describe it is as Todd said, we'll be opportunistic and we'll look at it as market conditions change and present themselves.

Marianna [Krishnar], Nomura Asset Management.

I wanted to clarify in this press release we saw other revenue significantly higher than in previous periods. I was curious if there was an explanation for it.

Yes, as Mark said to John earlier, it had to do with a FASB change that -- so it'll be that way from now on.

That's the transportation costs?

Correct.

It's just simply a reporting change. Costs that were otherwise netted in the revenue line are now broken out, so the revenue line's higher and the cost lines are higher, but there's no change to EBITDAX.

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're unhedged prices.

Unhedged prices. Okay. So if prices were to stabilize then there would be no subsequent PSC volume effect much immediately or is there like a lag impact?

No, you would see it just stabilize and then it would be -- your net wouldn't change.

Jacob Gomolinski-Ekel, Morgan Stanley.

It looks like the production mix has been trending a little bit gas here versus oil there, so just curious if that is solely driven by the PSC or if there's something else that you might be able to provide some color on?

And also how we can think about the production slate for Q2 in 2018 in total.

I think when you look at it, you've 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 a production mix and from that standpoint. But PSC volumes clearly, if oil comes down, it's going to look gassier. That's another artificial impact that you're going to have. But you've got to remember too, 70% of our natural gas is associated gas that's coming with oil. But the PSC impact is going to have an artificial effect there on the oil gas mix.

I guess maybe just -- so and I was also asking what is the -- is it going to kind of stay that 62, 13, 25 range for the year or should we expect a change, given the difference between production and the reserve base?

I think you're seeing it slowly climb and you're seeing it move up over time because that's where our investment dollars are going. So I think you'll see that. But it doesn't happen overnight. If you go back to the spend, I think we were very close to 60

5, 59% oil and we've slowly been investing and obviously not even been investing at maintenance capital levels. So as you see us ramp up investment, and it's going to be more directed towards oilier properties, I think you'll see that mix continue to change.

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 maybe any updates from the six exploration wells drilled in 2017?

I don't think there's anything we can share at this time. We're happy with our exploration program.

And then maybe I can just squeeze one last one in 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 like a little low relative to the sort of at run rate at the preferred. So thinking maybe where is that supposed to trend on a full quarter basis and on an annual basis.

I think that -- remember that closed in February, so that really was only about one month. And so when you see it, it'll -- remember it has a pick component and a cash component and that'll pick up from this second quarter onward.

So the sort of just the back of the envelop, using the cash component times the, whatever I think it was, 750 is the right -- is just the -- what we'll see on a 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 a year.

At this time we'll 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, where we'll further showcase our value creation efforts. We look forward to speaking to you next quarter or seeing you out on the road in the meantime. Thanks, everyone.

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.