Newfield Exploration Company (NYSE:NFX)
Capital One Southcoast Energy Conference
December 12, 2013; 11:40 a.m. ET
Gary Packer - Executive Vice President & Chief Operating Officer
Danny Aguirre - Investor Relations
And so as we make a quick transition here, I think Gary Packer is coming up. Gary is Executive Vice President and COO and is joined by Danny Aguirre as well on the Investor Relations side. So Gary.
Okay, thank you Capital One for hosting us. I really appreciate the opportunity. My name is Gary Packer. I’m the Chief Operating Officer for Newfield. A lot of familiar faces here and some new ones as well, so I look forward to catching up with you in the breakout or afterwards.
Lets go ahead. I got a few things I’d like to accomplish today. One, kind of bring you up on our highlights for 2013. I think we had a really breakout year. In 2013, we executed very, very well and if you’ve not watched us throughout the year, we were able to bring our guidance up a number of times and actually beat on our cost structure as we went out throughout the year as well.
We’ve recently brought forward our new three-year plan as a follow up to the one we put out in February 2013. I’m sure there’ll be some questions about that. Substantially, unchanged and there’s some details I think its important that you understand as we talk about that three year plan, but its, we’ve added 2016 and it really continues the trajectory of growth that we brought forward, when we brought forward our plan last year, exiting international and focusing on our domestic resource plays.
And then finally it’s with so much capital that we’re actually moving in rigs into the SCOOP and STACK plays of the Anadarko Basin. I want to make sure we leave some time at the end to really do a little deeper dive and update you on a few new wells that we have coming there and then just reaffirm where we are heading as an organization.
So first as far as the 2013 highlights, clearly when we entered 2013 the announced sale of international was going to force focus on our domestic liquids plays. As we think about that and where we’re at today, first of all on our international plays you may or may not have noticed that we have shareholder approval by SapuraKencana to go ahead and purchase Malaysian assets and that’s something that you ought to see flown through in the first quarter of 2014.
In regards to China, we are going to be brining forward more clarity on that as it develops, but just notionally you got to be thinking about us putting that back out for bid in the first quarter and it would be our hope and our expectation that that would be something that would be closed by year end 2014. But again that’s an uncertainty that we’re working through for you.
As far as our execution, as I’ve already said we’ve brought forward what I remember in 2000 February as being a robust, aggressive, lofty, I think were some of the terms that were used to describe the plan of growth over the next three years and we’ve made the numbers. I think we raised guidance three times throughout the year and again when you actually think of our individual cost structure, in every single item we either made it or beat it in 2013 and we worked very hard to make sure that trend is going to continue in ’14 and ’15 and now also in 2016 and that’s all going to be through liquids derived growth primarily in our four major resource plays.
And then finally the inventory. When we entered the year last year we had some ideas and we now brought those forward in public, with what we did in our STACK play. The SCOOP was enjoying very strong industry competitive returns, but we were able to put together a play that we already had in kind of our hit pockets, some ideas and some well results early on. We’ve now brought that to public and you’ve seen we’ve added about 100,000 acres and we did that within the capital structure that we had talked earlier in the year. And some of that is embedded as you look forward into ’14, ’15 and ’16 as well.
And then finally the operational efficiencies in our development plays like the Williston Basin and Eagle Ford, you saw us make substantial reductions in our cost structure in those plays. I think we took about $2 million a well out of our Williston Basin activity and about $1 million a well out of our Eagle Ford.
Now the common question that we’ll get and I’m sure we’ll talk about it later on is why doesn’t that translate to increased or reduced capital budget for this year and why don’t we see that in 2014 and beyond? And the reality is we embed a lot of the curves in the savings that we are going to see into our projections as we bring them forward.
So a lot of the reasons why you may have thought of a lofty aggressive plan and when we put it out in February its because it had a lot of these things already embedded in it. So we expected to save on our well cost in the Williston Basin and we’ve expected to do the same thing in Eagle Ford, and those are things that were consistently building into out plans on a going forward basis.
So our goals for this year, and over the next several years and the three-year plan is to achieve free cash flow generation. Clearly everybody pursues that. We communicated last year that we were going to deficit fund in ’14 and ’15 and we were going to subsidize our underwrite debt with the sale of our international assets and then that would substantially place us in a balanced position in 2016 and that’s still our vision.
We want to continue to build the quality inventory with that incremental dollar that we have out of that plan or we will debate whether we pay down debt or we expand our inventory just like we did this year.
We added what we believe to be several thousand wells of potential locations in the Anadarko Basin that did not exist a year ago. We created well over $1 billion of value. We believe in that asset and consistently look for opportunities like that and we have to fund that within our plan. These aren’t M&A opportunities. These are things that we are coming across on our own acreage base that we have today.
And then finally rest assured we absolutely are aligned in the fact that shareholder returns matter and we believe that the plan we have bringing forth with improving cash flows and liquids growth will deliver upon that.
The other graphs that you have here are the details of that. That was all in our public releases you can see in 2014. We tightened up on our projections of $44 million to $48 million. This is all domestic, this is in our continuing operations and obviously we have disc-ops that our out there in regards to China and international overall.
While you have the breakout of CapEx in 2014 in the top right, I think the best place to look at that is on this slide, where we actually walk you through the capital allocation in each on these. So 2014, $1.6 billion; that is excluding capitalized cost that will deliver overall absolute production growth of 16%, but most importantly the things that you ought to be thinking about or I suspect are is what that do for liquids and liquids growth, over that period is about 2014, 30%. That’s consistent with what we’ll see over the period as far as the CAGR goes and that’s we believe very, very storing.
Now there is no doubt that a portion of that is driven by NGLs. About three quarters of a liquids growth that you are seeing in that number embedded is from black oil, but there certainly is an increase, at least in the near term NGL component to that as we move into the SCOOP play in the south Anadarko Basin. That’s an area that’s primary – it’s a lot of NGLs and I’ll expand upon this in a minute. What you ought to see over time is we move our rig fleets to the east into the SCOOP oil play, which I have some information and the STACK play. That is a higher representation of Black Oil and you ought to see that trend turn on this as well.
And then finally the CAGR growth. We can’t be growing liquids if we are not growing cash flow and you certainly will see that in the period in your models. As I look at the actual allocations, there is really no material change in the Williston Basin and the Eagle Ford. Williston Basin is going to grow about 40%. We will continue to have four rigs running there. We have the opportunity to add more if the opportunity presents itself.
You also see in the Eagle Ford us grow about 30% there year-over-year and you will see our rig fleets stay in the West Asherton area and also move into the Fashion field in the Atascosa County. The things where you see more material moves in capital are the two in the middle. So we’ve talked time and time again about the capacity constrains in regard to the refining markets in the Uinta Basin and quite honestly in 2013 I personally was very disappointed to see some of these projects get delayed.
You’re familiar with the Holly delays. They have delayed three different times and most recently they just got the air permit approved. What that means to us, is that the contacted volumes of 38,000 barrels a day are absolutely intact, but they got moved out of 2015 into 2016.
So it makes no sense for us to invest capital in the Uinta Basin without surety of being able to deliver to market. I played too many times with building inventories and had to live with that, but we are not going to do it again. Therefore we pull the capital out of the Uinta Basin; we’ll continue to progress the horizontal campaigns there that continue to deliver exiting results.
But we aren’t going to move our capital into the Anadarko Basin and I’ll talk a little bit more about that in a moment, where we’ll see increased well count, increased rig activity pursuing industry leading returns in that play and that translates to 100% growth in a business which is now the single largest business unit we have in the company going from essentially a dead stop a few years ago. For the first quarter we’ll be at 30,000 barrels a day and we’ll be at 50,000 barrels a day by the time we exist this year; a really incredible story of growth there.
So here are the results. I’ve already referenced these. As you think through, certainly the liquids growth as I talked about, 30% CAGR our of 2012, through the three year plan that we currently have in place today, three quarters of that is oil driven, the balance being NGLs. Cash flow, its 20% as its calculated here. If you actually look at it from ‘13 on, its about 25% cash flow growth over that period and we think that’s a pretty good story.
We will continue to look for opportunities to improve our efficiencies. I expect that we will see improving cost structure not only in well account or in well cost, but I think you will still see that in our operating expenses, both the G&A and operating expenses over that period of time and that’s something that we owe you some additional feedback as we bring our plan out early next year.
This gives you the detailed production by area, so the things that will jump out at you hear or I hope to is when we entered 2013 in the first quarter, we were at 50,000 barrels a day from our major four plays. This is substantially 95%-plus of our capital. This is 70% of our production. The balance that you don’t see here is conventional, largely conventional gas in the Gulf Coast we are now drilling, the Arkoma Basin and our Woodford Shale that we are not active in and the Granite Wash, but we still have opportunist that we are lacking to focus on the better returns within these four plays.
So any dilution in our growth is coming at the expense of the 28% CAGR that you see here and this is absolute growth over the security. Again, you see if you look at the print, you’ll see 15% over this period absolute, but its 28% in the plays that we are currently investing in. So what you see is when we entered our three-year plan last year we had 50,000 barrels a day. We will exit next year at 100,000 a day. We will double the volumes in that time period.
The other thing that you ought to take note of is the rapidly expanding orange interval here. That is the Anadarko Basin, that is our SCOOP and STACK plays and if you actually look at volumes produced in 2013 relative to volumes produced in 2014 over that period, we will double 100% growth over that period.
And then the other thing that I would ask you to take a look at is looking late in life you see the increase in the Uinta Basin in 2016 and I’m getting back to refinery expansion that I talked about and the contracted volumes that we have in place to come online with the HollyFrontier refinery expansion that takes place at that time.
So lets talk a little bit about the SCOOP and STACK plays again. Again, we are moving a lot of capital here, its important for you to understand that. I guess in summary what I would say is that when we make a decision like that its driven by lot of factors. Not only industry leading returns, but its also the opportunity to build a legacy asset for the organization. It is already the largest producing business unit we have in play in the company, that’s just gong to continue, and we have an opportunity to expand that and we will talk a little bit about that.
We certainly have a favorable environment in order to invest, not only from a regulatory structure that’s very supportive, but we also have infrastructure out there. We always are thinking about takeaway and so forth. Certainly the Anadarko Basin provides a lot of benefits in that regard. I also think reflects on the fact that this is the same group of individuals that have been delivering on and out of the mid continent for quite a few years.
So the Arkoma, the same teams that have built that business up are the same folks that are delivering here and have a lot of confidence in their ability to execute on their plans and then finally we’ve talked about the growth, the opportunity to double next year and continue that growth on into the future is a lot of the driving factors.
So lets start here. You can see that our, the specific discreet acreage position we have here now, we added 100,000 acres in 2013. We did that within the cost structure that we previously talked about. We’re now at the 225,000 acres. The good news is that gives us an opportunity to exploit about 325,000 acres of opportunity, because it is a considerable overlap when you actually look at what the Meramec play outline is in green here, relative to the Woodford outline that you see here.
This play as many of you know is about 75 miles across. So it has a lot of breadth and it’s a lot of opportunity to leverage our experiences that we’re developing in the south to the north and I’ll talk to you in a moment about what we’re doing with our rig count standpoint. But very material position that we built in this particular play and it’s really the focus of our going forward plan.
So what’s the STACK? Well, first of all the STACK is exactly what it says. It stacks up two different objectives, both the Meramec, which is a calcareous silky shale on top of the Woodford. Now the Woodford’s a Devonian aged shale. We stepped above it. We did not anticipate finding a Mississippian age shale above it, but honestly we expected to see a carbonate limestone.
When we drilled our early wells, we saw that the facing was quite a bit different than what we expected. It couldn’t be further from the Chap (ph) play which is further up in North and we had to talk to a lot of people about what that means and this isn’t the high producing water Mississippian play, but this is a shale play and we really get the leverage once again. What we are doing in the horizontal Woodford in the Anadarko in this new play, its very, very thick.
So 275 to 475 foot; you put that on top of the thick Woodford that we had already been drilling and I’ll show you some results; you end up with a 700 foot interval. So when we talk about play expansion and inventory growth, this is really what’s going to drive that.
So I reflect on the rigs that we’re running up in the Williston Basin for instance where we’ve now drilled Bakken in first bench Three Forks and now we built second bench Three Forks and we’re generating great results out of that over the last few years; industry has and now Newfield is as well.
But this interval is quite a bit thicker than that and its all hydrocarbon charged and I’ll show you, we got wells across the entire interval. So there really is truly an opportunity to add thousands of wells over a position; that’s 225,000 acres in discreet acres, which I’ve already talked to you about.
EURs; in the north we’re seeing 800,000 to 1 million barrel wells and again as I alluded to earlier, you think about the liquids growth. Now you got 70% liquids, but 40% of that’s oil and I want you to be clear, that’s over the life of these wells. So if you look at some competitor data that’s announced in these same areas, what you typically will see is the initial IP oil percentages.
It’s our experience and what we expect is those will moderate over time. So, today we actually see 70% black oil, but we expect that number is going to drop to something in the order of 40%, which is what’s illustrated here and returns already are over 35%. We continue and I’ll just show you here in a moment, we just drilled our best well yet.
So lets start – we’ll start in the north with the STACK. You can see the overall acreage position in this area up there. These are 1,000 barrel a day IPs, good strong 90-day volumes. You consistently see us when we have the data communicating 30, 60 and 90-day rates and you can see that we’re still making 600 barrels a day from the eight wells that we’ve already drilled across this position.
So the well that I would ask you to look at is this Yost well. It’s new; you haven’t seen this before, it’s a 1,400-barrel a day well. It’s the best well we’ve drilled yet and what’s really nice about it is that the materials step out to the Northwest.
The pipe curves here communicated to you. There is nothing magic and it should be no surprise that the production is falling in the pipe curve, because that’s where the pipe curve came from, but nevertheless you have now all the information necessary to back into the numbers that we’ve communicated to you. And I think this next slide here gives you an idea for where we’ve stood.
So very early on in a play, where half of our wells have been in the Meramec and half of our wells have been in the Woodford, we see very little difference in the decline profiles between either of these wells that cost a similar amount to drill and we have similar AURs and I can tell you that from what we’ve seen from a well controlled standpoint and there’s vertical wells across the entire acreage position.
So there is no uncertainty in what the geological and the subsurface looks like, but we have now drilled horizontal wells, over 150 square miles and as I have already referenced, we had to Bredel which is a very good well. We stepped out about six miles to the Northwest and once again we’ve extended with the Yost and we’ve made another very good well; 75% black oil. Again, this is what the future holds as we look to transition out of the NGLs to the south and the oil to the North.
So is there more acreage to test there? Absolutely, and that’s what 2014 is going to be about. We’ll continue to hit development in this area, but we’ll have somewhere between two and three rigs running up in this area and you should look for us to continue to look to expand out and give you and ourselves higher degrees of confidence and the forecast that we’ll make coming out of the Anadarko Basin as a result of this.
So now we’ll step out of the north, which is down here, and we’re going to move to the south. In the slide deck, I think the handouts that you have probably do this better, but if you think about, I think you can maybe see this, there is the transition between the yellow and green that sits right through there. So about 45,000 acres, a little bit more than half of the 75,000 acres we have in the south are in this oil window.
Now the early drilling that’s taken place here has been in this area right here and you can see we’re making very, very good wells as a result of that. 1,500 barrel a day IP, 1,100 barrel a day, 90 day rate. Relatively flat declines and you can see this translate into the decline here.
Now this came up in the last earnings call and I think I addressed it in Q&A, is I’d suggest to you that we would probably have some improvement, an increase is coming in our pipe curve on the oil side, but the reason you see this tremendous over production here is part of this, because as you move out of the wet gas phase to where my pointer is, in that area and you move across this oil window, its not as simple as drawing a bright line.
The phase change is rather gradual, so you’re going to see more oil, which if I’m only looking at it from a BOE standpoint, this curve will come down. It’s likely – it’s going to still exceed what you have built into our own internal pipe curves and this is what we’re forecasting off of in our current budgets and plans. So is there upside? Certainly, and it’s because of that. But it’s not obvious how that transition is going to take place over the entire area, so we tend to stick to a more conservative representation, but that’s really why you’re seeing this.
So seven wells under our belt; very good, these are all SXLs. We drilled one short well in this area and that’s going to be the play going forward. Just like in the north, those are going to be all SXLs; this will be SXLs as well.
As I move a little bit to the west into the wet gas, this is the area that’s enjoying quite a bit and very robust returns, but it certainly has a higher NGL representation; its about 30,000 acres. We drilled 11 wells, 1800 barrels equivalent a day on IPs and is again a very robust 90-day numbers relative to the industry.
We have another new well, we just posted almost 1500 barrel a day IP in the Yandell well. Just don’t have the 30-day numbers. But you also see once again us over delivering the curve that we got embedded into our plants here and a lot of industry activity.
I saw this morning, I think Marathon is going to be increasing their activity in there and I know we saw our friends at Continental have also announced increase. So they are all seeing very similar type of results, which we like because one, it gives us an opportunity to certainly leverage the industry experiences of others and with this I’ll kind of bring it to a close.
As we sit here today, just reaffirm for you what matters to Newfield, first and foremost lets focus on these liquid rich plays that’s not – we’re not going to waiver from that. We are consistently bringing in higher returns in the plays that we are pursuing. That’s why we are increasing the capital where we are, building out the inventory, I’ve talked to you about that and ultimately each one of these plays who have got very high working interest, we operate each one of them. The OBO representation we have is small, which gives us the ability to kind of move capital to the best returns.
So with that I’ll close and I think we have a break out session to pursue I guess.
[No Q&A Session for this event]
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