May 8, 2013
Executives
Clarence P. Cazalot Jr.
- Chairman of the Board, President and Chief Executive Officer Janet F. Clark - Chief Financial Officer and Executive Vice President Howard J.
Thill Sr. - Vice President of Investor Relations and Public Affairs
Analysts
Ed Westlake - Credit Suisse Doug Leggate – Bank of America Merrill Lynch Raymond James - Pavel Molchanov Eliot Javanmardi - Capital One Roger Reed - Wells Fargo
Howard Thill
Good morning and welcome to Marathon Oil Corporation’s First Quarter 2013 Earnings Webcast and Conference Call. The synchronized slides that accompany this call can be found on our website at marathonoil.com.
On the call today are Clarence Cazalot, Chairman, President and CEO and Janet Clark, Executive Vice President and CFO. Slide two contains a discussion of forward-looking statements and other information included in this presentation.
Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2012 and subsequent Form’s 8-K cautionary language identifying important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Please note in the appendix to this presentation, there is a reconciliation of quarterly net income to adjusted net income for the periods presented as well as operating estimates and other data you may find useful. Turning to slide three, beginning in 2013, we changed the company’s reportable segments to better reflect the growing importance of our U.S unconventional resource plays.
All periods presented have been recast in this new segment view. There are still three reportable operating segments, with each organized and managed based primarily upon geographic location and the nature of its products and services.
The three segments are North American E&P which explores for, produces and markets liquid hydrocarbons and natural gas in North America and includes our in-situ position in Canada; International E&P which explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets liquefied natural gas and methanol; and Oil Sands Mining which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil. As discussed on slide 4, we also changed the presentation of our consolidated statements of income primarily to present additional revenue and expense details and to report certain expenses more consistently with our peers.
To effect these changes, certain reclassifications of previously reported amounts were made and as a result, general and administrative expenses for the first and fourth quarters of 2012 increased by $39 million and $38 million respectively, offset by reductions in production, other operating and exploration expenses and taxes other than income. Full year 2011 and 2012, along with second and third quarter 2012 data will be added to future published documents.
Slide 5 provides an analysis of cash flows for the first quarter 2013. Operating cash flow before changes in working capital was $1.6 billion, a 40% increase over the fourth quarter as a result of higher sales volumes, lower production cost per BOE and better U.S.
liquids realizations particularly for Bakken crude. Proceeds from dispositions of $312 million almost completely offset the debt repayment of $314 million.
While working capital changes resulted in a $73 million use of cash and we paid dividends of $120 million. We ended the quarter with $768 million in cash, $84 million higher than year-end 2012, while total debt was $6.5 billion bringing our net cash adjusted debt to capital ratio down slightly to 24%.
Slide six reconciles quarter-to-quarter adjusted net income. The first quarter 2013 was 7% lower than the fourth quarter 2012.
Our North America E&P first quarter after-tax earnings decreased to $160 million, largely a result of a $218 million after-tax unproved property impairment in the Eagle Ford. The first quarter 2013 effective tax rate was 73% or 65% excluding Libya.
Slide seven shows the North America E&P segments first quarter 2013 earnings decreased from income of $101 million in the fourth quarter 2012 to a loss of $59 million in the current quarter. Again, this loss was primarily the result of the unproved property impairments I just discussed.
Lower natural gas prices and volumes driven by the disposition of the company's assets in Alaska were more than offset by higher production from the lower 48 resource plays and stronger crude prices in the lower 48, again particularly for the Bakken. Slide eight shows the changes driving our first quarter 2013 international E&P earnings.
The segment income of $453 million in the first quarter was little changed from the $446 million recorded in the fourth quarter 2012. The first quarter saw an underlift in Libya driving a negative volume variance which was offset by lower income taxes.
Higher DD&A was seen in the quarter as a result of first sales from Angola, which was offset by a positive variance in the other category as a result of higher earnings from our equity investments in EG and lower indirect cost because of employee bonus accruals in the fourth quarter 2012. Slide nine shows quarter-over-quarter data for LNG and methanol sale.
LNG sales volumes were higher as a result of an additional lifting in the first quarter compared to the fourth quarter of 2012, while methanol sales volumes were down slightly over the same period. Slide ten shows our oil sands and mining segment income increase $21 million sequentially, primarily because of higher volumes driven by reliability improvements.
Combined production from the Jackpine and Muskeg River mines set a record at bitumen production rate in the first quarter. In addition, the upgrader availability was 100% for the first quarter, allowing the facility to maximize production of lighter synthetic crude which improved realizations and profit margins.
This was partially offset by higher cost at the mine related to contract labor associated with seasonal activity. I will now turn the call over to Clarence to discuss the operations.
Clarence Cazalot
Good morning. Slide 11 summarizes the key highlights for the first quarter.
We had strong production growth and cash flow from operations. Our available for sale production was up 4% over the prior quarter and up 19% over the first quarter of 2012, excluding Libya and Alaska.
We continued our focus on controlling our cash cost and this along with other factors led to a 40% increase in cash flow from operations before working capital changes. We continued our solid execution in the U.S.
unconventional plays, particularly the Eagle Ford and the Bakken. And indeed, increased our 2013 production guidance in the Bakken to 40,000 BOE per day net.
We also increased our overall production guidance for 2013 for our worldwide operations to 7% to 10% growth over 2012 versus our prior guidance of 6% to 8%. Moving to slide 12.
I will comment on our execution in our key resource plays and future expectations. Eagle Ford first quarter production averaged 72,000 barrels of oil equivalent per day, a 22% increase over the prior quarter.
The migration to pad drilling is ahead of schedule, with 80% of wells drilled in the first quarter drilled off multi-well pads. Our 2013 target for drilling between 215 and 250 net wells remains unchanged.
We’re currently operating 16 rigs and we’ll continue to monitor rig efficiency in order to hit our targeted annual well count. We’ve also began testing Austin Chalk and Pearsall formations within our acreage to assess their potential.
Production in the Bakken averaged 37,000 barrels of oil equivalent per day during the first quarter. The strong performance of our asset team has allowed us to once again raise the 2013 targeted annual production to approximately 40,000 barrels of oil equivalent per day.
The targeted 2013 well count of between 65 to 70 net wells remains unchanged. Approximately 45% of our oil production was transported to market via rail in the first quarter.
In the Oklahoma resource basin, our targeted 2013 well count of between 15 to 19 net wells remains unchanged. And during 2013, we will drill four wells to assess the potential resource within the Mississippian line and granite wash horizons.
Slide 13 shows our 2013 refocused and very active exploration drilling schedule. The program has already resulted in the successful appraisal of the outside operated Shenandoah prospect in the Gulf of Mexico during the first quarter.
We’re currently participating in eight exploration or appraisal wells and expect to evaluate the potential of this program over the next 12 months. Slide 14 demonstrates since the first quarter of 2012, our quarterly worldwide production available for sale, excluding Alaska and Libya, has drawn approximately 18%.
The growth wedge over this time was primarily driven by lower 48 onshore production. Slide 15 shows that our lower 48 onshore production available for sale has drawn approximately 100,000 barrels of oil equivalent per day in the third quarter of 2011 to the first quarter 2013.
Importantly, liquids volumes increased from 55% to 72% of total volumes over the same period. The 2013 first quarter production was 9% higher than the fourth quarter of 2012.
The target for fourth quarter production is between 190,000 and 210,000 barrels of oil equivalent per day which is an increase from the 185,000 to 205,000 BOE per day range we previously provided. Slide 16 shows the historical available for sale and sales volumes for the North America and international E&P segments, including Libya and Alaska since the first quarter of 2012.
Production available for sale increased 16% and 2% over the first and fourth quarters of 2012 respectively. New production brought on stream in the first quarter of 2013 was partially offset by the sale of our Alaskan assets.
Correspondingly, sales volumes in the first quarter were 15,000 barrels of oil equivalent, lower compared to the fourth quarter of 2012. However, if you exclude Libya and Alaska, sales volumes increased 19% and 4% compared to the first quarter and fourth quarter respectively.
At the end of the first quarter, we had a cumulative under lift of approximately 3 million BOE. Of this, approximately 2.2 million BOE is natural gas in Libya.
On the liquid side, we are under lifted 1 million barrels in Libya and 166,000 barrels in Norway. We are over lifted 273,000 barrels in the UK, 78,000 barrels in Angola and 64,000 barrels in EG.
The first quarter saw our first liftings from Angola. Slide 17 compares total company liquid hydrocarbon sales volumes, excluding Libya for the first quarter of 2012, fourth quarter 2012 and first quarter 2013.
Actual sales volumes grew approximately 27% between the first quarter of 2012 and 2013, with the U.S percentage growing from 34% in the first quarter of 2012 to 42% in the first quarter of 2013. Slide 18 shows the same comparison for actual first quarter 2013 to estimated second quarter 2013 sales volumes.
U.S. sales continue to grow as a percentage of the total.
Slide 19 shows our progress towards our stated goal of achieving a 5% to 7% compounded average growth rate between 2010 and 2017. The impact of the growth being delivered by our onshore U.S.
plays is evident in this chart. Slide 20 shows our international E&P quarterly cost structure per BOE.
Our operated international production in Norway, Equatorial Guinea and the UK, maintained excellent reliability. DD&A per BOE in the first quarter of 2013 was impacted by our first liftings from Angola.
Slide 21 depicts the international E&P cost per barrel of oil equivalent trend without Libya. By excluding the low cost Libya barrels, we see an increase in our overall cost per barrel compared to the prior slide.
Slide 22 provides our estimate for the 2013 international E&P cost per barrel of oil equivalent, and this excluded Libya. The forecast reflects a combination of the projected decline in our Norway production and a continued ramp up of production from the non-operated Angola Block 31 PSVM development.
The higher operating cost per BOE also reflects the cost of turnarounds and workovers scheduled later in 2013. As shown on slide 23, total North America E&P cost per BOE increased quarter-over-quarter primarily because of higher exploration cost associated with the impairment of certain unproved leases in the Eagle Ford.
But excluding the Eagle Ford impact, overall costs were lower than the fourth quarter and cash costs were lower by approximately $0.90 per BOE. Slide 24 provides the estimated 2013 operating cost per BOE for overall North America E&P and the Eagle Ford.
With that I will turn it back to Howard for the Q&A.
Howard Thill
Thanks, Clarence. And before I turn it back to Brandon, I would like to remind everyone to please limit yourself to two questions along with follow-ups, clarifications, so we can get everyone in the queue.
And if we have time you can re-queue for additional questions. With that, Brandon, we will turn it over to you to open up the line.
Operator
(Operator Instructions) From Credit Suisse we have Ed Westlake on the line. Please go ahead.
Ed Westlake - Credit Suisse
Congratulations on the progress in the Eagle Ford. Just diving into a bit of the detail, and obviously we can all download data from the Texas Railroad Commission, but one of the things that you are doing is changing the completion design.
I think you are operating certain frac spreads with an improved completion design and seeing some good results. As you look overall in the first quarter, can you give us some color of, say how many wells you completed?
Where on the old design, how many on the design, so that we can sort of date your progress on IP rates against what you are doing in the wells. And if there is any color on longer laterals as well, that would be helpful.
Clarence Cazalot
Yeah, Ed, this is Clarence. I don’t have that kind of detail to give you today.
We will certainly look at --including some of that color as we put together or future investor presentations. But I think as you recall when we look at the investor presentations, we have been showing -- we have got a couple of slides in there that show the progress that we have seen, particularly in the Excelsior, East Longhorn and South Barnhart areas, comparing if you will, sort of our original completion design to what we have seen of late.
And of course we have seen relative to the 30-day IP rates, anywhere from a 33% to a 75% improvement. And then we give greater detail by quarter in Excelsior where we show the improvement in the 30-day IPs, again where we have seen upwards of a 75%.
I think we will continue to show that kind of improvement with our first quarter results. And I also know, Ed, you had had some questions about the state data perhaps not reflecting some of the higher rates that we have shown.
We have to certainly look at and understand why the state data doesn’t show certainly the results we are seeing. Part of it we believe is that the data is reported on a lease level rather than a well level.
But we certainly when we look at some of our more recent wells, we’re seeing rates of anywhere from 2,000 BOE per day to 3,800 BOE per day of which liquids or oil I should say ranging from 1,600 to 3,000 barrels a day. So really outstanding results, reflective I think of the improvements we’re making in our completion methods.
But we’ll look to provide some of that additional detail and color going forward.
Ed Westlake - Credit Suisse
Yeah, helpful color on those recent 24 hour IPs. Could you just update us on the well cost as well that you’re running because I think service cost has built a little bit coming down.
Clarence Cazalot
It is and I think we are targeting a drilling and completion cost here in the second quarter of about $7.6 million per well and we see that trending down by the fourth quarter to about $7.2 million. On top of that drilling completion cost, you have about $600,000 per well of facilities cost.
So we are seeing continued reduction in our costs. But I think we’ve extracted pretty good efficiencies out of our operations as well as cost improvements from some of our vendors.
Operator
From Bank of America we have Doug Leggate online. Please go ahead.
Doug Leggate – Bank of America Merrill Lynch
Clarence, if I could maybe follow-up on Ed's question, over the last several quarters I guess, we've had discussions backwards and forwards about not so much the completions, but your operating philosophy as it relates to choke sizes and so on and my understanding was you're going to be experimenting with that somewhat. So I'm wondering if you can provide us an update as to whether or not you've decided to open these things up a little more aggressively in the early days.
Clarence Cazalot
Well, again I think the choke management, Doug, is one of the outcomes that will provide more guidance on when we’re through with the pilot testing. The pilot testing as you know is both lateral spacing, vertical placement and certainly completion methods to include choke size.
So, more detail to come on that. But I would simply say that I think we continue I would say to remain a bit on the conservative side at this point of not opening these wells up.
And we continue to believe stress dependent permeability is an issue out here and we’d rather constrain the early flow rates and enhance recovery as opposed to opening the wells up and getting higher initial rates. So again more detail to come on that I think as we -- in the second half of the year we provide guidance on the results of the pilot program and what it really means if you will in terms of the wells that we’ll drill, the resource and how we’ll best complete these wells.
Doug Leggate – Bank of America Merrill Lynch
Got it. Thanks.
My follow-up is somewhat unrelated. I guess you reported the first region exploration results.
I'm guessing that didn't quite come in as you expected. My question is, if Norway exploration doesn't work, you've got obviously a big organization in Norway, what is the prognosis for Norway as a core asset for Marathon going forward?
I'll leave it at that. Thanks.
Clarence Cazalot
I think as you recognize we have said pretty clearly that 2013 will be the year that we begin to see the decline in our Norway producing assets. Again the asset has outperformed our expectation in the first quarter.
We’ll continue to do what we can to maximize its recovery. But pretty clearly it is going into decline.
Having said that, we continue to look for opportunities in and around Alvheim to extend the life of this asset and we’ll continue to do so. We are hopeful that the exploration we do there in the third quarter is successful and that will give us an additional future development in Norway.
But as you recognized this is an asset that generates very significant cash flow for us. It’s an asset that I think is pretty clearly misunderstood by the investment community.
I continue to see it referred to as low margin barrels. They’re not low margin either on a earnings basis and certainly not on a cash flow basis and it’s a very high return asset.
And so I think it is an essential part of our portfolio today. There will be a point in time, obviously, when it reaches a certain level of production that we would look to divest of it and perhaps put in the hands of someone for whom it creates greater value.
But at this point in time, Norway is a key producing asset and we believe it has upside.
Operator
From Raymond James we have Pavel Molchanov on the line. Please go ahead.
Raymond James - Pavel Molchanov
Can I ask one about Poland? Obviously you are not the first U.S.
company to exit Poland, but I am curious how many wells you have drilled and other analytical work you have done before making that decision.
Clarence Cazalot
Pavel, let me just check. I want to say off hand, it's about 11 wells that we have drilled -- I am sorry, 6 wells that we have drilled.
And we have done some testing there. And I would simply say that we believe the results are fairly conclusive.
These wells were drilled across the extent of our 11 concessions. And basically what we found was thinner section than we anticipated and lower pressures which for the most part high pressures are pretty important in these unconventional plays.
And after recognizing this was initial stage of exploration but costs are pretty high. And so we have come to a conclusion that while there may be some potential here ultimately, it certainly doesn’t fit our criteria and as we have said, we are mobilizing to move out of our Poland concessions.
Raymond James - Pavel Molchanov
Okay. Appreciate that.
And then another one about, kind of in front tier opportunity you guys are pursuing in Kurdistan where you have had a fair amount of success already. You know what's the sequencing for moving into development mode on any of the blocks that you are currently working on?
Clarence Cazalot
Yeah, we are in the process of preparing a plan of development on the non-operated Atrush Block. That plan of development will contemplate a development of initially of around 12,000 barrels a day scaling up to a larger operation.
And that’s on the Atrush Block that we now have a 15% interest in. And in the Sarsang Block, we are preparing for a declaration of commerciality.
On that non-operated block we have been producing the initial discovery well there on an interim basis to see how the reservoir performs and look at the commercial elements of marketing those barrels. But those are the two existing discoveries, both non-operated at this point that we are moving towards commercial development of.
We are -- with our two operated wells drilling today at Mirawa and Safen, we are hopeful that we will have our first operated discovery on our existing operated acreage and will determine what's success there and what's the best way to proceed to development.
Operator
(Operator Instructions) From Capital One we have Eliot Javanmardi on line. Please go ahead.
Eliot Javanmardi - Capital One
Just curious if you can provide any color on the Three Forks and the Bakken. Any progress you are seeing there in testing wise.
And also if you could talk a little bit about the well cost you are seeing out there.
Clarence Cazalot
Yeah, the well cost in the Bakken for us are about -- and just to put on the same basis, I did the Eagle Ford there, they are running about $7.9 million, drilling and completion, and an additional $800,000 for facilities and equipment. So about an $8.7 million well cost.
And we will continue to do what we can indeed to drive that further down. In terms of the Bakken and the Three Forks, we continue to develop those jointly.
I think as we have talked about, we see very substantial potential in the Three Forks that’s been an upgrade to our overall resource assessment for the Bakken. In terms of current drilling activity I don’t have any numbers on that.
We’ll look to get back to you Eliot with any detail we can provide on that. But certainly we are continuing to evaluate the additional zones and the additional benches in the Three Forks.
Eliot Javanmardi - Capital One
Thank you, appreciate that color. And also just as a follow up, just get your macro perspective Clarence on the gas pricing in the U.S for 2013 and 2014 going forward.
Just curious your thoughts there.
Clarence Cazalot
Well, our position has been one of I guess a bit bearish. We continue to believe that the governor out there in terms of preventing gas prices from rising too much is simply the degree of switching back to coal and I think as we saw, gas prices get above $4 and begin to rise a bit.
We saw coal come back into the mix pretty aggressively. And so once again we see gas prices back down.
So we remain rather bearish and rather conservative in our views about natural gas. We don’t really see recovery to $5 or better until 2014 or beyond.
And obviously we put our money where our mouth is when you look at where we’re spending our drilling dollars. We continue to focus on liquids in the U.S and North America in general and it’s reflected in as we said before our lower 48 liquids production going from 55% to 72%.
So we’re well positioned. We’ve got an opportunity set for natural gas, particularly in Oklahoma.
We’ve got upside to Henry Hub prices in our EG L&G business. So we’d love to see gas prices go up.
But at this point our discretionary investment dollars are going to liquids, particularly crude and condensate.
Operator
From Wells Fargo we have Roger Reed online. Please go ahead.
Roger Reed - Wells Fargo
I apologize. I’m on a cellphone if there’s background noise, but I just wanted to ask quickly, on the Eagle Ford shale, did you discuss at all or can you discuss at all the progress to date on the down spacing, what you’ve seen and any update to this point?
Clarence Cazalot
Roger, we really have said consistently and have said again today, you won’t see the detailed results until the second half of this year in terms of us having enough production history and comparisons to actually then begin to come out. Not just talk about the results, but I think what you really want to hear is what are we going to do about it, how many wells are we going to drill?
How much resource do we expect to recover? What does the program look like for the next 10 or 12 years?
So that’s information you’ll see later this year. I would say we’ve come out I l believe in the press release and actually said we believe 80 acres is appropriate across the entire core area.
So that is what we’ll develop at the very least, including in the areas that we don’t see down spacing potential. But again we’re increasing with drilling on 60 acre spacings now, beginning to move in that direction and continue and assess 40 acres as well.
So you’ll see those results and hear the impacts of it later this year.
Operator
From Credit Suisse we have Ed Westlake back on the line. Please go ahead.
Ed Westlake - Credit Suisse
This is more of a bigger picture question. Could you just maybe talk through where you are on potential disposals?
Obviously you gave a book loss for some of the Niobrara acreage which was non-core. I don’t know what the cash value of that would be.
But I’m more thinking the oil sands, any other assets around the portfolio.
Clarence Cazalot
Let me just say, Ed, I think that the Niobrara we talked about that that will be a second quarter event. So it was not in there and at this point we are not able to talk about the cash side.
Once the deal closes we’ll be able to disclose what the cash number is on that sale. In terms of to your point our earlier comment, we are in discussions around a potential sale of a portion of our interest in AOSP.
As I’ve indicated there, one way or the other we will tell you what happens there. If we don’t have a deal we’ll let you know and if we do, we’ll let you know that as well.
so at this point you can appreciate that discussions are still under way. And they are taking longer perhaps than we would have liked.
It is our intent to bring this to a conclusion at quickly as possible. But, again, it takes two to tango on this but we are still in those discussions.
Outside of that, I think as we have said, we have closed transactions of $1.3 billion and we are confident of meeting our $1.5 billion to $3 billion target by the end of this year.
Operator
From Bank of America, we have Doug Leggate back on the line. Please go ahead.
Doug Leggate – Bank of America Merrill Lynch
I am also taking advantage of this somewhat lately attended call so apologies for the follow up. Two for me, Austin Chalk, Pearsall, can you give us any color as to what proportion of your acreage you believe might be potentially perspective and when can we expect to hear a little bit more in terms of your expectations of drilling plan.
Clarence Cazalot
Yeah, starting with the Austin Chalk, Doug, it's still up in the air as to how much exact acreage we have. We believe it could be as much as 20,000 net acres.
But that number is subject to change. To date we have drilled three wells in Austin Chalk, we have one in progress.
None of those have been fraced yet, so results yet to come. And in the Pearsall, our view is that we have somewhere around 45,000 net acres in the Pearsall We have drilled five wells to date, four of which were vertical delineation wells that we were able to better understand the reservoir.
We drilled one horizontal well and we will be fracking that well next week. So early days I think both on the Pearsall and the Austin Chalk, but certainly we see upside in these reservoirs beyond what we have in the Eagle Ford.
Doug Leggate – Bank of America Merrill Lynch
Thank you. My follow up, I don’t know if Janet is on the line this morning, but my follow up is really on cash flow.
The cash flow this quarter looked particularly strong so I am quite keen to see what's happening on the deferred tax line particularly in the U.S. If you could help us just on the moving parts as to why the cash flow was so strong this quarter?
I am talking pre-working capital, Janet. Thanks.
Janet Clark
I can tell you this is probably the first quarter where deferred tax a source of cash as opposed to use of cash. I.e.
the deferred tax in the U.S. exceeded the negative deferred tax internationally.
And of course we expect that to continue to see that grow over time. You know I think, as you know, because we are spending so heavily in the U.S., we are not paying cash taxes here.
And our typically our international taxes are primarily cash.
Doug Leggate – Bank of America Merrill Lynch
So (inaudible) a $6 billion prospect cash flow number, so any thoughts on use of surplus cash?
Janet Clark
Yeah. I think it's probably the same answer we give you every time we get that question, which is, we look at the priority uses for cash is reinvesting in the business if we have the opportunities and value accretive way to do that.
And we can do it in a way that it's cost efficient. Beyond that, we continue to look at our dividend.
We think it's a very, very important part of the total shareholder return, and make sure that we have a competitive and growing dividend. We need to strengthen the balance sheet.
And when we look at asset sales are chunkier cash inflows, that could potentially cause us to look at stock buyback.
Operator
Thank you. I will now turn it back to Howard Thill for final remarks.
Howard Thill
Thank you, Brandon, and thanks everyone for your attention to our conference call. And if you have any additional follow ups, please let Chris and myself know.
Thank you, good bye.
Operator
This concludes today's conference, thank you for joining us. You may now disconnect.