Noble Energy's CEO Hosts 2013 Analyst Conference (Transcript)

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Noble Energy, Inc. (NYSE:NBL)

2013 Analyst Conference

December 17, 2013 9:00 am ET


David R. Larson - Vice President of Investor Relations

Charles D. Davidson - Chairman, Chief Executive Officer and Member of Environment, Health & Safety Committee

David L. Stover - President and Chief Operating Officer

Kenneth M. Fisher - Chief Financial Officer and Senior Vice President

Gary W. Willingham - Senior Vice President of the U.S. Onshore Region

Dan Kelly

Donnie Moore

Brad Whitmarsh

Susan M. Cunningham - Senior Vice President for the U.S. GOM, Africa and Frontier Region

J. Keith Elliott - Senior Vice President of the Eastern Mediterranean Region

Michael W. Putnam - Vice President


Michael Kelly - Global Hunter Securities, LLC, Research Division

David R. Larson

Good morning, everyone. I think we're going to go ahead and get started. All right. I want to welcome everybody to Noble Energy's 2013 Analyst Conference. I want to thank everyone for coming today, who are listening on the Web. I think you are in for a really exciting several hours hearing about all the great things that are going on here at Noble Energy and getting a good look at the bright outlook that we have for our future.

Those here in Houston, you ought to have a an investor book in front of you that has all the presentation material that we've put together and you'll see here today. As well, you should see 2 news releases, both which were released earlier this morning, 1 summarizing the conference that we're having today and the other announcing our 2014 guidance for the year.

One thing in the book, if you look at the last section of the book, the appendix, that includes a lot of terms and different measures that we're going to be using and discussing here today. It also includes the price deck that was used to calculate all the returns, the present values and the cash flow projections that are in a number of the slides in your book today.

Just to note, for example, WTI and Henry Hub starts out in 2014 at about $95 per barrel and $3.75 in MMBtu, and then averages over the next 5 years about $91 and $4.45 for the 5-year rolling plan. That's pretty much flat with what we told you guys last year.

Those who are listening on the Web, you can download the material off of our website. The presentation is broken down by speaker sections to make printing a little bit more manageable. We are talking about some 180 pages here to go through. And then all these documents, of course, we have filed with the SEC this morning as well.

One legal slide to cover real quick. I want to remind everyone that the presentation and the webcast here today contains projections and forward-looking statements. We provide no assurances on these statements as a number of factors and uncertainties could actually cause the actual results in future periods to differ materially from what we discuss. You should read our full disclosures on forward-looking statements in our latest news releases and SEC filings for discussion of the risk factors that influence our business.

All right. So let's take a quick look at the agenda for the day. We plan to start off the meeting with high overview look of Noble Energy, and then move on to the operations, where we'll touch on each of the core areas, as well as the exploration and new ventures activities. As you can see from this slide, we'll have a break right after the U.S. onshore, which I estimate about 9:45, 10:00 would be about right. Here's the second half of the conference. And we hope to about finish up about 11:30 a.m. or about 12 noon, all depending, I guess, on the questions and answers that you guys may want to cover in the final session.

The last thing I want to do and mention is a safety moment for everyone. There's no fire alarm test scheduled for today. So if you do hear an alarm, please make your way out into the hallway and exit out the nearest exit. Please keep this in mind today while we're going through the meeting.

With that, let me turn the podium over to Chuck Davidson.

Charles D. Davidson

Good morning, everybody. David warned me that we were going to have a full room, and that is definitely the case. You must have all gotten your holiday shopping done early. Versus the rest of us with Noble, we start after this day is over. But it is great to be sharing our story and our outlook with all of you here today. This is an exciting time for us. We look forward to this. There's a lot of work that goes into it. I want to say this upfront, thanks to the whole Noble team that has been working, not weeks but months, to put this together because this is our plan, this is our commitment, this is what we see as the future and we're very excited about that.

One thing I was going to mention, similar to last year, we are also releasing today our corporate social responsibility annual report. And there'll be copies available for you. We think this is becoming increasingly important to investors. We take it very seriously. At Noble Energy, we're not only proud of our operational and financial results, but we're very proud of how we carry out our business. We're committed to conducting our operations with integrity, respect, high standards for environmental health and safety and environmental stewardship. And you'll be -- as we go through the presentations this morning, you'll be seeing examples of that in literally every one of the regional sections. So again, I think it's very important from the perspective of how we do our business. And also our transparency on how we do our business, it's very important.

So let's jump in. I'm really excited about what we have to talk about today. Similar to previous years, we're going to be as transparent as we can regarding our plans, so there's a lot of details, some of which we won't be covering verbally. But I encourage you to dig into the materials that are presented. Similar to prior years, we'll be showing you our 5-year plan. The key, though, is that we're adding another year. So we're adding another year, which is 2018, to our 5-year plan.

And the real theme of it is it just extends the strong growth rate that we've shared with you in the past. If you look at our production outlook now for the next 5 years, it works out to be 18% per year compounded annual growth. And that would result in 2018 production of being well above 600,000 barrels a day equivalent, which when you look at it and adjusting for the divestitures we've made over the last couple of years, when you look at that, that is roughly 3x what our production was in 2011 when we started this growth journey. And that's something that I'll talk a little bit more about as we get into, but it's very transparent. We know where it's coming from. In 2018, 96% of that production is coming from our existing development projects from discovered resources. There's only 4% that's really tied to exploration, very transparent. We have it in hand. We know what it is. It's all about execution.

Our resources continue to grow. You'll see that in a number of categories. I'd like to focus in on proven plus discovered unbooked because that's key. That's what we've got in hand. And that this year has grown to 7.5 billion barrels equivalent of proven plus discovered unbooked. When you put that in perspective of our 2013 production, that's 75 years of production. That's if we never discovered another drop, which I'll tell you we do. It's certainly a plan to do because we're going to continue our commitment to world-class exploration as well. And we've got the capabilities to deliver from a financial and operation standpoint. So it's -- for us, we think this provides a very exciting story, a very exciting opportunity and certainly positions us well to create value, not just for 1 or 2 or 3 years but for many years in the future.

And it's not been easy. When we look at the history -- and again we're not going to spend a lot of time on history in these presentation. This is intended to be more forward-looking. But over the years, we've invested a lot in the portfolio and people and processes. Some of these boxes were checked, not last year but several years ago. But we've continued to enhance, continuing to improve as we've gone forward. We did so by a number things, by diversifying the portfolio, strengthening the U.S. position, particularly in the DJ Basin and the Marcellus. And we've reduced risk. We've reduced risk, not only in areas such as reinvestment risk but also in reducing volatility and several years ago, in terms of greatly reducing our debt. We've talked about processes in the past, some of that will come out again today. But we believe we've really put in place some world-class processes. And certainly, when it gets to the people side of the equation, it's critically important. I wouldn't trade our leadership and staff with anyone. They're a great organization and we have invested in a lot of them to help them do the type of job that we expect to deliver on all these plans that we're going to share with you. And finally and probably more recently, we've solidified our long-term vision. And in a minute or 2, I'm going to share some more on that with you.

A lot has happened since a year ago. This is a nice time for us to present our outlook. We've got our budget all approved. We've got our plans in place. So this is just a quick snapshot here of kind of the report card for the past year. And I think it's a long list. These are the most important things. First of all, we continue to deliver on the major projects. It notes there 3 of them, 2 of them are the more classical major projects we've talked about in the past, Tamar and Alen, that have started up and are producing.

And then a new category you're going to hear more about today, and that is the major projects that are part of the onshore unconventional, Integrated Development Plans as part of the DJ Basin and the Marcellus, which we believe is really the future of these developments as you look at major projects within overall field developments. We've continued to feed the pipeline. We've sanctioned a record 6 new major projects this year. That's the most that we've ever sanctioned in a year. And really they're designed to help build out the program and certainly is helpful in the latter years of our plan. It's been a nice year for exploration. Mike Putnam will talk some more about that. But we've had 4 discoveries, some early encouragement in Nevada that we'll share. But remember, it's still very early there. And really our only disappointment was recently in Nicaragua. And there, we continue to do more work, and we'll have some things to talk about there as well.

I've talked about our proven and discovered unbooked. Just looking at the discovered unbooked, last year, we talked about it being up 50%. This year, it's up another 25% in terms of resources, up to 6.4 billion barrels. We've strengthened our portfolio over the last year. We've continued with divestitures of noncore assets. We made what I think is a fantastic acreage exchange in the DJ Basin up there, which creates immediate value. And finally, Dave is going to talk some of our safety and operational excellence, which is really critical to our success. Ken will also share about our financial strength, which is all part of delivering this program. So a lot of accomplishments over the past year, a lot of things that put us in position, not only in delivering what we said we're going to deliver a year ago but also put us in position to deliver on these plans going forward.

So what's our vision? What about the next 10 years? What are we trying to accomplish? Well, we've been doing a lot of thinking and designing about that as we really focus in on what are the attributes that Noble Energy should be taking on as we enter really into the next decade. We are thinking about 2020 and beyond right now. It's hard to believe, but in our portfolio, in our business, we have to be thinking that far ahead. And so here on this slide just I thought we would share with you some of the elements of our vision. One is it's a company that is successful in all ways in delivering its purpose. We've talked about our purpose before. It's "Energizing the World, Bettering People's Lives." It's critical that we do both. We develop energy, but we also as an energy company have to make sure that we're always bettering people's lives that are associated with it. It's a company that's connected with its values, a company that everyone wants to be associated with, a company that not only accomplishes amazing things but always has a bright future. And to me, of the list, they're all important. But this is one I focused in on because the last thing I want Noble Energy to be is a company that people remember about, "Well, they were the company had the great run, and then they ran out of gas." That's not what it's all about.

To me, when you're talking about vision, you're talking about in any point in time, in space, in your plan, you always have a bright future. So we have to be able to be in position. So in 2018, we're talking to you about what our incredibly bright future this company has for all of us that are associated with it. So that's about the vision. It's always thinking about the future and always moving forward. And finally, connected with that is, is a company that does not believe in limits but really, as I say, believe in limitless possibility. That's how we got here today is believing in things that perhaps others didn't believe were possible. And that's how we're going to go into the future. So that's really the vision, and that's what -- and you ask yourself, "How do you do that? How do you accomplish that vision?" That's why we're here today. This is what this morning is all about, is to talk about the plan and how we deliver on our vision.

It's kind of hard to argue with this picture. We've shown versions of this over the years. It was 2011 when we kicked off this period of double-digit growth. What we did here is we stripped out the divestitures so that everything was kind of on an organic basis, so you could see exactly it's kind of a same-store growth rate going forward. And you can see that, as we said back in 2011, it'd last at least 5 years. Well, then we added again and again and again. So now we're showing an 8-year picture of double-digit growth for this company, 18%, as I said before, between now and 2018. And you can see when you look at a back reference to 2011, it's triple the production. We've also -- we didn't show 2018 in our earlier plans. But for reference, you just have to trust us on this, is we've pulled those plans and we put little red and black diamonds on the 2018 bar. And that references what those earlier plans were in terms of 2018. You can see that actually our current plan has grown from the earlier plans as well.

Pretty exciting outlook, but it's not just about production, it's also about cash flow, it's reserves, it's returns. Everything is up and to the right as it should be. And for reference this year, we have shown 2017 from last year's plan. And the reason is we kind of want to show how this year's the addition of '18 builds on what we showed you last year as the final year for our plan. And again, some nice growth as we continue forward in that.

I'm sure some of you would have bet that you'd be seeing this chart again. You bet. I look forward every year. And that is this is the fourth year that we have been showing debt-adjusted growth rates. These again -- just as a reminder, these are 5-year growth rates. So we've shown each year's plan, 5-year growth rates that we've presented to you. So it starts with our plan that we presented in June of 2010, and then steps through for the '11, '12, '13 plans as well. When you look at production, nice, steady step-up, which means one thing, we're accelerating, we're continuing to improve the plan and, of course, we're continuing to extend the double-digit growth rates.

Just for curiosity, I went back and looked at the June 2010 plan. And it's one of these things, where if it turned out bad, I wouldn't share it with you. But -- so you know the answer to it. But I was just curious because there was a lot of distractions. And many of you were in the room in June of 2010. We were just in the midst of Macondo, the Deepwater Horizon incident. Our Deepwater Gulf of Mexico program was completely up in the air, a lot of things were happening. But I looked at -- and we projected a 10% growth rate over the next 5 years, and that it was stepping through. So I went into that plan and I looked at what did we say 2013 was going to be, 2014 was going to be and what 2015 was going to be. I had an extra of 2 minutes.

Well, it turns out we projected 2013 would be 271,000 barrels a day equivalent, which if you're following us, it's right on target with what we're delivering in 2013. 2014, we projected 310,000. You've looked at our guidance, that's right in the range of our guidance for next year. And we projected because it was the last year of the plan, we projected that 2015, the headline was we will grow double-digit over the 5 years to 350,000 barrels a day in 2015. If you look at the plan we're presenting today, and we'll probably beat that. It looks like we'll be above that.

So that's -- how does that happen? There were so many ins and outs, it's unbelievable. The biggest out was all the divestitures that we've made that were still in those production numbers, the end was we had the Marcellus. We had to change our deepwater program because of Macondo and a lot of things. But when I really went back and looked at it, that only happens when, number one, plans are very solid, well-thought-out; and two, a company has the flexibility to reallocate and to change as the environment changes. And that's exactly what we have done. And yet we've been able to deliver the plan that we showed back in 2010. That's what it gets really exciting. And hopefully, that is something that will give you more confidence as we present the plan today, that this is a plan we will deliver on. This is a plan we are committed to deliver on. It will take a lot of hard work and there will certainly be changes along the way. But that's what our full intention is.

We're also showing something new and we borrowed from Barclays again. And it's a balance sheet-adjusted. It's similar to the debt-adjusted growth, but it's a little bit different methodology. According to some of the work that Barclays has put out and maybe it has a little better correlation long term with shareholder return, time will tell. But we shamelessly stole it again, mainly so that we could show a comparison with the other peer companies that are in our group. This is a 5-year look-back on a sheet-adjusted. Be careful. The production in this one is adjusted using 20:1 for gas and 8:1 for NGL. So it's a little different than what I presented before. But that's to get things more value-neutral. If you look at what Noble's debt projection is for the next 5 years versus the E&P peers over the past 5 years, we're only second to 1 on production. And in cash flow growth, there's nobody even close. So it's all about delivery. If we deliver this, we should be able to deliver not only an outstanding plan but deliver outstanding returns to our shareholders as well.

So a bit on the environment before we launch into our program. No question that our world continues to change. We've had a lot of technology and innovation that's come about. We know also that our development comes with new obligations now. The public has to be assured that development is safe. And for that reason, just as an example, we are embarking on a major education program in Colorado, one that help everyone there understand better about our business. It's all about trust. And trust comes through knowledge and confidence. And we plan to provide that to the constituents in Colorado, as well as other places that we work. We keep saying over and over the public doesn't need to choose between the benefits of energy and a safe environment. They can have both and they deserve both and we intend to deliver both as part of our operations.

So to wrap it up in terms of things that you'll be seeing, it's really -- it all ties back to what our annual report was earlier this year, unique by design, nothing is by accident. Certainly, at Noble Energy, we are not here by accident. Everything that we're doing is not by accident, it's by design. And we think we provide a lot of uniqueness as part of that. And we just step through all of those in terms of unique purpose; a unique strategy that involves both international and domestic, unconventional as well as exploration and also a very long-term perspective; unique assets, Dave will talk about many of these assets are assets that you would expect to see in a major company versus an independent; unique execution; unique growth, which I've just talked about; unique results, all of this leading to what we say is a very unique future of company that in 5 years will be triple what it was just 2 years ago, when we transitioned into this period of growth. So it's a really exciting story. We're really looking forward to sharing with it, sharing the entire story with you today, and even more excited about delivering it as we go forward.

With that, I'm going to turn it over to Dave. And he's going to get started into some of the operational pieces.

David L. Stover

Thanks, Chuck. As you mentioned, it is a real pleasure to be back here again this year and talk about our story and actually share our story with you.

Chuck mentioned some of the unique attributes of the company. And when I step back and look at it with over 30 years, rapidly going on 35 years experience in the industry, I've listed here some of what I'd say are combination of things that really stand out about Noble. When you think about it and you think about the core areas and long-term view indicative of a major and you combine that with the agility to execute in scale of a large independent, which delivers the high-growth rates, large growth rates, continued large growth rates of a small independent, now to me that is truly unique. And you think about the things that we're doing now, the core areas as we step back over the last year. We've looked at our core areas and readjusted and aligned those core areas in a way that it creates some tremendous synergy among the different parts of our business.

I think you'll see that as we go through the areas and as the folks in the team present some of the items, whether it's in the onshore or in the offshore arena. We'll talk about our 3 regions, onshore U.S., the Eastern Med, and then the rest of our offshore business, what we call our global offshore, that Susan will go into. So all of these have unique attributes. But what's truly exciting is they all have a tremendous amount of running room and continued growth in each and every area. So when you think about it, that's all part of why we're eager to share with you today this future that we're creating and what underpins the excitement of this future. So I think you'll see a lot of detail on that as we go through that today.

One of the things that we pride ourselves is taking a leadership position in each and every area where we operate and where we work around the world. And I've shown here on this slide some of the key things that we've taken leadership on. There's representative examples from every place around the world that we touch. But this is important to us because it's living our purpose. Chuck mentioned our purpose, but it's making a sustainable and positive impact in everything we touch. When you think about it we believe it's imperative to continue to set new standards and drive performance improvement, not just as a company but as an industry. We are proactively working to gain and, I would say, increase the public's trust every place we operate, whether it's here in the U.S. or in the countries around the world. It's an approach we take that's consistent, as I mentioned, everywhere, whether it's in established areas, like Colorado or West Virginia, whether it's maturing a new industry in Israel or starting and maybe introducing a new industry in a new venture area like Nicaragua, where we recently drilled. So it places a great importance on partnerships and relationships, partnerships and relationships with the government agencies, regulatory agencies and also the communities where we work.

So a most recent example, and I just want to point out one, and it's on the third bullet there, is we recently participated with some industry partners and a leading environmental group to propose new air regulations in Colorado. We think these are among the most and probably are the most progressive in the nation. I'll tell you another thing I'm particularly proud about is our leading industry safety record. And we show that on the bottom of this slide. We look at safety and operation excellence as going hand-in-hand. There's no tradeoff on either. And we expect the same standards from everybody that works on our location, whether it's our employees or our contractors.

But here's a few examples of -- and you'll see this on probably each and every area that's presented today, a few examples of living our purpose and how we give back in the community and how we work with the communities in every area we operate. Chuck mentioned the sustainability report out today. I encourage you to take a look at that because that again will highlight some of these activities, social investment, if you will, in each of these areas in the number of these areas and how we live our values, our core values.

I'd tell you, it's inspiring when you look at it and visit with the employees and see what's going on in the communities. Whether it's a response to flooding in Colorado, tornadoes in Oklahoma, providing continuous education and increasing education, we provided needed medical supplies around the globe. This is a true return on investment, a high return on investment that pays forward over and over and over.

So let's step forward and take a look a little bit and talk some about our 5-year plan, and Chuck mentioned it. The tagline here talks about the $1 billion savings over 5 years compared to what we showed last year or what plan we had put together last year. But what I want to talk about goes way beyond that. Now I want to mention and talk about creating more value out of all parts of our business. Chuck mentioned the long-term view. We think there's a tremendous benefit in taking a long-term view and approach to our business. In the industry, you would continue to hear and we'll show examples and you continue to see the improvement in well performance. But what you'll hear more about today and what we think is unique about us and what you'll see more about is the massive value opportunity that we have in taking a holistic approach to our business. Putting together these onshore integrated development plans which you'll hear more about, when you take a look at integrating all aspects of the system from drilling, well placement, facilities, operations, transportation, it's just a tremendous opportunity. We'll show you examples today that, coupled with the continued well performance improvement, have huge value. And when you extrapolate that across the acreage position, I think you'll see its true value, eye-opening. I mean, it's just a tremendous value opportunity for us.

So this is a big deal. It's a big deal, not just for our onshore business, but our offshore business as well. When you look at the ability to take advantage of existing infrastructure in place, you'll see tremendous value from something like our Dantzler discovery in the Gulf of Mexico, the expansion of Tamar and using existing facilities in Israel, the next set of projects in West Africa, projects such as Diega, all tremendous opportunities. So this holistic approach to how we develop our assets goes hand-in-hand with our fundamental belief in integrating all aspects of our business from exploration through operations early and often.

When you see this integrated approach here on our project execution, the top bullet specifically talks about the integrated approach. We constantly get asked, how do you repeat the success on project execution? Chuck mentioned we got 6 more projects and it won't be long until Dantzler will be seventh coming up. So the repeatability is important, the delivery of this execution is important. When you look at these top 3 bullets, these are the things that kind of stand out to us. And it's all common sense items if you look at it, but it all focuses on aligning all phases of the project and everybody touching the project early and often. Examples shown here today include everything from our first integrated development plan which you'll hear a lot more about at Wells Ranch. I mean, this kind of [indiscernible] major project list and I think you'll see today why these integrated development plans are truly major project. This is just the first of many more that you'll hear about today.

The -- going around clockwise, from left to right and down to the bottom, in West Africa, now 2 remarkable projects for that part of the world, on early and on budget with Aseng and Alen. And then you go around to Tamar. In 2.5 years, from project sanction to delivery and now running at essentially 100% runtime, truly remarkable.

Here was a little slide that we put together to really depicting it. It touches on what I alluded to earlier on the asset quality. I would say, and we've shown examples here, we have a phenomenal set of assets that fit nicely together to create Noble Energy. Our strategy blends high-growth development with material exploration. When you look at it, the connection between our areas is important and it goes back to what we talked about with aligning our businesses and taking advantage of synergy, whether it's sharing the learnings from the DJ Basin with the Marcellus, and you'll see how we're reaping rewards from that already, while there's leveraging technology in the offshore arena from Gulf of Mexico to other parts of the world in new areas that we're breaking out. All of this is creating tremendous value. And it goes beyond just those pieces. When you look at the exploration fit, we create value not just in finding new areas, but the exploration process creates tremendous value in getting more value out of our existing core areas and core assets.

So let's look at 2014. Chuck mentioned part of it already, but we released our detailed 2014 guidance this morning. Our growth -- underlying growth is up 18% on volume driven by the large growth from the DJ Basin, here showing up close to 28%, and the Marcellus, which will come close to doubling from this year to next year. Also we'll get the benefit of a full year of Tamar.

Our capital programs, really set up for 2 main pieces: accelerating our onshore development and developing this next wave of major projects that we mentioned. At the same time, Keith will walk you through some of the increased optionality and what we're doing about that and preparing for that and taking advantage of that in the Eastern Med. And Mike will talk about our material exploration program, both on the aspect of the seismic program and drilling, not just over the next year, but over the next few years.

Here's our capital as its allocated out, the $4.8 billion, which we put out this morning. If you look at it, on the lower left pie chart, the combined spend on our 2 core onshore areas is about 2/3 of the program. You see a nice mix between the other -- between the offshore areas and about $150 million that will go towards new ventures. We've also broke out on the right the onshore allocation. The key point there is the increasing facilities' cost as we start to take this longer-term approach and to fulfill development on some of these big Integrated Development Plans.

So it results in a significant volume growth for 2014. I'll first step back and say -- and mention and I think it was mentioned already this morning, as part of the guidance we put out, that we increased our fourth quarter 2013 volumes by about 5,000 barrels oil of equivalent per day. What was extremely encouraging to me was that this increase in volumes was driven from better performance in each of the 3 operating regions, not just relying on 1. So we're seeing it across-the-board. We've mentioned the adjustment for sales this year, that's about 7,000 barrels of oil equivalent per day in red, with the underlying growth rate then of the 18% to go into the midpoint of our guidance -- in the guidance range of 302,000 to 322,000 barrels of oil equivalent per day.

On the right, you can see the breakout on production by area -- by core area, the DJ Basin being the largest with a little over 35% and Marcellus in second with about 15%.

Just wanted to briefly highlight how our crude oil volume growth is pretty much keeping up with our underlying company production growth. If you look at where we expect to be in 2014 and then step back to where we were in 2011, you can see we have about doubled our crude oil volume over that period of time to, whereby, 2014 we expect will be around 115,000 barrels of oil per day.

Risked resources. Chuck mentioned the discovered and discovered unbooked. Here, you can see on our risk resource pie chart on the left, about 62% of our risked resources are coming from our discovered unbooked. In other words, found but not yet moved into proved reserves. I'll say that what's not reflected on here is an acquisition -- a bolt-on acquisition, which Donnie will mention here in a little bit in the Marcellus, which will actually add about 300 million barrels equivalent to this plot. So if you look at the bar chart on the right, you can see how the discovered unbooked is growing about sevenfold up to now about 6.4 billion barrels of oil equivalent over the last 5 years. You can also see, if you look closely between 2012 and 2013, a significant increase both in the onshore areas and in the offshore areas. Again, this underpins our confidence in delivery, and I'll come back to that point in the closing.

The cash capital outlook over in the 5 years, you can see here, we mentioned the high point there being down somewhat from what it looked like a year ago. You can see another key attribute is, in 2014, is actually the first step in that improvement in capital efficiency. If you look at the pie charts on the right, we show a breakdown by area for that 5-year period and a breakdown by type. At top, on the area, you can see the DJ Basin and the Marcellus have about 2/3 of the funding over that period of time, very consistent with what the 2014 program that I talked about earlier. When you look down below, you can see a large portion of that obviously is from the horizontal drilling, about 60%, and about 17% tied to the exploration programs, about 17% tied to exploration.

So what's the result? And here's the production outlook. Again, this is one of our continuous favorite slides, and it's especially because we continue to hit it each and every year. Again, it's got the underlying growth -- and what's important is we've actually added a percent to our compounded growth rate compared to last year and we've added a year. Both of those are significant items when you think about the size and base that we're starting from.

On the right side of the plot, we show that about 60% of this growth will come from the continued investment in our onshore horizontal programs. And as Chuck mentioned, 96% of this is underpinned by discovered resources, not something that we're looking for in the future.

So results in the discretionary cash flow profile that we show here. A key point is that we're growing cash flow annually by about $1 billion per year starting in 2015. And when you look at just the breakout, the proportion on the pie charts on the left, comparing 2014 to 2018, you can see one of the key increasing contributors is the onshore program as you would expect, moving from about 55% of the cash flow in '14 to about 68% by 2018. Again, essentially, all this activity driving this cash flow growth comes from ongoing development.

So in summary, I'm excited about the company we're creating. There's always -- as Chuck mentioned, there's always challenges along the way. But with the diversified portfolio of high quality assets, with the running room that we have in each and every area, I'm very confident that we'll continue to deliver what we say and essentially what we plan for. I believe what you'll see today outlines the future that is truly unique. It's an outlook that continues to improve, with growth rate -- large growth rates extending further and costs that continue to improve and really underpinned by a long-term integrated approach that creates a tremendous value. Our expanding inventory of undiscovered or discovered unbooked resources provides the path to not just our 5-year growth. But when you really look beneath our plan, it underpins double-digit growth for the next decade.

And as Chuck mentioned, we're not done discovering new resources. The exploration program, that's focused on delivering a new core area. And as you listen to the operations and explorations review, I think what you will see is a tremendous amount of new information but what obviously you should hear and be able to see is a company leading in a number of ways, in many ways in each area.

So I want to thank you for attending today, as we have the opportunity to share with you what the future we're creating here at Noble Energy. And with that, I will turn it over to Ken to talk about the financial review.

Kenneth M. Fisher

And we appreciate everybody being here today. It's a pleasure to be with you today. Unique by design, and as I think about it, you've seen, from Chuck and Dave, a history and a future of sustained and consistent double-digit growth. So as we think about it from a financial prospective, what we're trying to do is ensure that sustainability and consistency with our financial framework. So that starts with a very strong balance sheet and a liquidity level that supports us through any time of uncertainty to it's really driven by, as Chuck mentioned, the culture of capital and portfolio discipline and to ensure that we're not only driving growth but also really focused on returns. And I think you'll see that through the plan. It's commitment to our investment-grade credit rating and a competitive dividend for shareholders, and it's also underpinned by a lot of focus on risk management throughout the organization, whether you're talking about the offshore operators using the safety environmental management system or safety on a drilling rig or within the financial world, working on the insurance program or addressing above-ground risk with our government and community relations teams, focusing on bettering people's lives for a purpose. It's really a big drive on risk management and managing the uncertainty.

Financial position remains very strong. We finished third quarter in very good position, $4.1 billion of liquidity, of which $900 million of that was cash on hand. Our debt-to-capital ratio was 34%, but taking account the cash, it's 29%, very much in line with our investment-grade peers. And we have a very manageable maturity profile. The first major maturity is not until 2019. So good shape as of the end of the third quarter, and we've been very focused on continuing to improve that as we work through fourth quarter.

So in November, we visited with the rating agencies, both Moody's and S&P, and have both our rating and our outlook affirmed. We shared with them essentially the 5-year plan you're seeing today. And we also extended our $4 million credit facility for another 2 years to a maturity in October of 2018, so we have essentially a full 5 years available on what's a very large facility. And then we had a successful bond offering as well, $1 billion funding, a 30-year bond at a very attractive rate. So we're in very strong position. Today, we stand at about a $5 billion liquidity level.

Chuck and Dave mentioned portfolio management. It's probably worth looking back over the last few years and just see what we've done. Through this program, we've generated about $2.1 billion of divestment proceeds, which have strengthened the balance sheet and allowed us to strengthen and expand the DJ Basin core area with a timely transaction in 2010 and then also, with a timely and well-structured transaction in the Marcellus as core area in 2011. So this has been a key element, and it's really been about focusing our returns, our capital investment in high-returning areas. So the program is ongoing. We do expect to have some additional non-core divestment proceeds during the course of 2013 and through '14. And additionally then, we hold a number of high-interest positions in both core areas and in exploration assets where we can, in a sense, leverage those for additional monetization opportunities. So I would expect us to continue to aggressively focus there.

Returns, critically important and you can see a big focus for us as we look through the 5-year plan. We expect from today's -- a roughly 10% return level of the corporate total to move to the high double digits, at high-teens by 2018. This is, again, consistent with what we showed last year in the plan. What's driving that? The 65% or so of capital that's being deployed in the low-risk, high-return onshore business, and Gary will talk with his team in a minute in the onshore business about how we're leveraging -- improve the EURs, lower drilling and completion costs and the infrastructure efficiencies of the Integrated Development Plans that drive improving returns in those plays. Additionally then, the Eastern Med is also contributing. Keith will share with you the fact that we're being able to leverage the Tamar expansions in a cost-effective manner to support the growing domestic demand in Israel in a very capital-efficient way. And then, we're also staging the development of Leviathan so, again, in a capital-efficient manner. And then, the West Africa and the deepwater Gulf of Mexico continue to be not only a high-returning set of assets but also strong cash generators for the company. So we feel good about these and are continuing to remain focused on returns.

From a shareholder standpoint, we're also focused there, commitment to continue to grow our dividend and ensure competitive returns. If you look over the last decade, we have been the leader in our peer group in terms of dividend growth, with a 29% compound annual growth rate. And also, our payout ratio compares very favorably to peers. So, again, something that we continue to remain very much alert to and focused on.

Risk. As I said, we're trying to continue to have the entire organization focused on thinking about uncertainty and thinking about risk and managing it, not only from the board down through the organization, the executive team, but also at the asset level up. So we face, in our business, a number of risks and also an evolving public policy environment, so we spend a lot of time thinking about this. There are a number of things that we consider foreseeable but potentially low likelihood events, but they could be potentially impactful for the company, and we refer to those as Grey Swans. So I'll talk about how we're using the tools on the right to address these things and, in a sense, Swan-proof the company from various risk factors

One thing I've talked about in the past few years is cash flow at risk modeling, we continue to use this tool and, in fact, expand the use of it. Here, you have the green line representing a Monte Carlo outcome of over 5,000 commodity price results over a period of 3 years, 2014 to 2016. You can see we have the plan set just about at the 50 percentile outcome, which will generate about $13.4 billion of cash flow over 3 years. And you can see, at the 95% worst case or the fifth percentile outcome, that would yield significantly less, about $2.5 billion of cash flow. And you can see in the table then essentially what yields that price, which would be sustained prices over those 3-year period. The message being here is, is we're thinking about it, too. With our liquidity level, we can manage this. And then, obviously, in a lower price environment, we'd be proving and adjust accordingly. But -- and then, thirdly, we have very minimal likelihood of breaching any debt metrics or exposing ourselves to any kind of downgrade actions. So it's been a very effective tool to help us think through.

Another effective tool has been our commodity hedging program. This is our corporate program which is the annual program where we look at the current year plus 2 future calendar years, and this is distinct. We have had some special programs for Patina and USX in years past, but you can see this program has delivered net hedge settlements of about $475 million over the course of '08, the third quarter of '13. And, more importantly, it really address and cut off the tail risk of the financial crisis. So it's been a very effective program in managing the downside and, at the same time, not really surrendering much upside as we move through time.

So we remain well hedged. If you look forward for '14 and '15, the oil side, we're about 60% hedged next year, with the floor at our plan premise rate and 35% hedged for '15, again, at the planned premise rate.

On the gas side, U.S. natural gas side, we're a little over 50% hedged for next year, with the floor at $3.83 and -- or $3.85 and upside to $4.83. And then, again, '15 is roughly 30% hedged, with the planned -- floor at the planned premise rate. So we feel good about this program, not only in the past, but moving forward.

Grey Swans, I talked about. These are low likelihood but potentially impactful events, and so we've spent a lot of time thinking and planning about how you would address these. This chart picks a few of the scenarios. And what we've shown here then is the -- both the pre-mitigation exposure over a 3-year time period, and then the post-mitigation exposure at which being the red is insurance, our current insurance program; and the green being commodity hedging. And so if you look at these and you compare them then to our liquidity level balance sheet and our financial position, we see these as things that we can manage and deal with effectively. And this is -- this program has helped us then to structure our recent insurance program renewal. As we grow in the business, particularly bringing on major projects at Western Africa and Eastern Med, we've continued to work with insurance markets, both OIL, the industry mutual and the commercial markets, to continue to grow our ability to cover various risks. So you can see this in the 2013 renewal. We've stepped up coverages for property and casualty, well control, liability and also, political violence and business interruption. We also moved in our business interruption waiting period from 90 days to 60 days. So we feel very good and -- that we can manage these, again, low likelihood but potentially significant events as we move forward.

Additionally, from a -- as we grow in our business in each of the core areas, customer concentration risk has been something we've been thinking about. And so this year, we access receivables portfolio credit coverage as well at a very low-cost basis. So we'll continue to think how do we use the risk thinking to mitigate and reduce or eliminate uncertainties in delivering the business plan.

Corporate structure is also an area where we've continue to evolve. As we grow in the business internationally, we tried to build in more funding flexibility. For example, our credit facility that was recently extended includes international subsidiary borrowing capabilities. And we have an efficient way to fund new ventures from a tax efficient basis and also, facilitate intercompany lending.

So these things give us more flexibility and efficiency in the use of our cash resource. We're also thinking about how do we leverage bilateral investment treaties as we plan new venture activity. So again, feel good about the ability to meet the future needs.

So as Dave mentioned, cash flows are growing substantially. And that's really what supports the plan here. Third quarter year-to-date, our cash flow this year is up versus 2012 at 16%. The third quarter in the street was up 33%. And that was a record, and it was essentially just under $1 billion. So you can see that cash generation coming through next year. We will be up again to almost $4 million of cash flow. That's up 10%. If you take that, that's at the planned premise rates. If you take it back to this year's price realizations, it would be a 15% growth in Bcf next year. And then 2015 beyond, we grow $1 billion a year. So we'll be $8 billion of cash flow by the 2018 timeframe. And again, the point being here, this is from the existing resource base just as we develop these resources.

So from a financial metric standpoint, we feel very comfortable. We're well within our rating agency balance. As I mentioned, we had the rating and outlook affirmed in November from showing this plan. And you can see also that as we move through time, we're actually improving our position starting in '15 and throughout this period. So we feel very confident we can deliver this plan and maintain our strong financial position.

In closing, I'd like to acknowledge my colleagues in the finance and IT teams who are also focused on living our purpose. So we've had active program, both in Houston and Ardmore and Denver, working with Habitat for Humanity, a couple of house builds this year, a partnership with the Aldine Community Transformation Center up in Northeast Houston, and then also active with the -- in the flooding response with the Well County Food Bank. So it's -- this is an example of how the people throughout the organization are living this purpose.

So in closing, like Dave and Chuck, I'm excited by the ability to continue to deliver what is a unique outlook on growth. And I'm very excited, as a financial professional, from going from where we were a few years ago, $2 billion of cash flow in 2010 to essentially $3.5 billion of cash flow this year, and $8 billion of cash flow plus by 2018.

So with that, I'd like to turn you over to Gary Willingham, who will take you through the onshore business.

Gary W. Willingham

Thanks, Ken. Good morning, everybody. It's my pleasure to be here today to present to you the U.S. onshore region, give you some insights and all the exciting things that we have going on. The region actually incorporates 2 of our core areas, as well as an exciting new venture opportunity that we're playing. So the U.S. onshore is really a region where we've had significant growth in both production and resources over the last several years in our 2 core areas, both the DJ Basin and the Marcellus. We've also been focusing the portfolio by divesting certain non-core assets. This leaves us with a vast majority of our production coming from these 2 core areas, which are 2 of the highest quality, highest value resource plays in the country.

In addition to the core areas, we also have a very large position and an exciting new play in Nevada that we're currently testing. Mike Putnam will give you some insights into that later this morning in his presentation. Overall, in the region, we have 5.5 billion barrels of oil equivalent of net risk resources, which is equivalent to over 100 years of production at our current production rate in this region. This is an increase in resources of 20% from last year and 70% over the last 2 years. Currently, 85% of these resources are concentrated in our 2 plays in the DJ Basin and the Marcellus. As Dave mentioned previously, both these resource and acreage numbers do not include the acquisition that was announced last week in the Marcellus. We'll show you some more information on that here in a little bit.

The economics of these programs are very strong. And we're currently operating 15 rigs, drilling wells that generate from $4 million to $8 million of net present value per well, with returns ranging from over 30 -- from 30% to over 100%. And current net production's a little over 140,000 barrels a day equivalent. And we expect production to grow at 27% a year, compounded annual growth rate over the next 5 years, which is actually very consistent with the 27% we've seen over the last 2 years, and is also an increase from what we told you last year. Our 5-year forward growth rate last year was 24%.

But having great asset is only part of the equation. Chuck mentioned that it's all about delivering. So you have to be able to execute. You have to be able to deliver outstanding results as well. And when we realigned our operations in April, the one U.S. onshore region, our focus was to ensure that we leveraged all of our learnings and efficiencies across the entire region, so that we're able to take advantage of new ideas and successes in one area and rapidly deploy them to others. At this time last year, the DJ Basin operations were jointly led by Dan Kelly and Donnie Moore. And since April, Dan has taken over the lead of the entire DJ Basin, while we've moved Donnie and all his experience and expertise gained in the DJ Basin over to the Marcellus. And he's running the Marcellus today.

And the results of that have been pretty impressive. And you'll see that shortly when we review how much the Marcellus performance has improved since last year. We believe we've developed a really unique set of expertise and many competitive advantages in the onshore, a number of which are shown on this slide. One of the most exciting things you're going to hear about today, you've already heard about it a little bit, is the integrated development planning concept. And this is an example of how we're combining our major projects practices that were developed across the country -- I'm sorry, across the company and our ability to really accurately forecast our development activities far into the future. And as a result of being able to do this, that's really caused us to rethink how we go about developing these plays long-term. And so now, we're creating these IDPs that are a very holistic view. They go way beyond just drilling individual wells. And it creates significant incremental value, significant, it's in the billions of dollars, while also lessening our impact on the environment and the communities in which we operate. You'll be hearing a lot more about our IDP plans in both the DJ and the Marcellus as we go through the presentation.

I've already mentioned that our net risk resources are 5.5 million Boe, and that over 85% of them are in the DJ and the Marcellus. You can see from the bottom chart that over 80% of them are also currently either proved or discovered unbooked. So there's very little, if any, risk to these numbers.

The chart on the right, something else we've stolen shamelessly. This is from Credit Suisse. It's their review of basin economics. And you'll note that our 2 core areas compare very nicely to everything else out there. I will also point out that these are industry economics. So they would not include the significant incremental value that we are realizing through our IDP concept, which you'll see in a minute.

So I think the tag line of this slide really does tell the story. We really are in the early days of a tremendous growth in the onshore. We've almost doubled production over the last 3 years, and yet we expect to more than triple it over the next 5 years. And we'll be close to 450,000 barrels of oil equivalent per day by 2018. As I mentioned earlier, that's a 27% compound annual growth rate on top of a pretty big base to start with. And the 2 core areas, as you can see on the chart, contribute essentially all of this growth, which means that any success in Nevada or other areas would only add to these numbers.

Here, you can see the cash flow is growing right along with production. We generated about $1.6 billion more of operating cash over the next 5 years. And we invest in capital. And we expect cash flow to start exceeding capital in 2016.

So to summarize our strategy in the U.S. onshore, we're taking full advantage of our learnings and synergies across the region as we continue to accelerate the development and the value creation of our core areas in the DJ and the Marcellus. We've been successful in unlocking tremendous value by doing that, as you'll see later this morning. We're also continuing to grow and optimize the portfolio by looking for that next core area and continuing to divest our remaining non-core assets.

And finally, as Dave's earlier slide showed, we're building the first LNG plant in Colorado. And he also have mentioned our -- highlighted our role to develop new air emission standards in the State of Colorado. We believe those 2 things, along with the benefits that we're seeing from our IDP concepts, demonstrate that Noble Energy truly is leading in environmental stewardship. And I'm personally very proud to say that. And everyday, everybody in our company is living our corporate purpose of energizing the world and bettering people's lives.

So turning to the DJ Basin, I'll start off and then give you an overview and a sense of the strategy for this area. And then Dan Kelly, who leads this core area from our Denver office, will provide more detail on some of our operations. So for the last several years to these conferences, we've shared with you increasing resource estimates, increasing production growth rates and some insights into some of the truly unique and innovative things that we're doing in this basin to unlock even more value. And this basin is our largest core area as a company. Well, I'm excited to stand here today and tell you that, that trend is not going to end this year. We're going to continue to highlight the growth in this area.

We've built what we believe is one of the largest, most contiguous acreage positions in any of the onshore resource plays. And we'll show you how we've improved on that again this year. We've increased our view of net risk resources in the DJ Basin once again, this time up 24% to 2.6 billion barrels of oil equivalent. We've increased our 5-year production forecast again. We're at 23% now. Last year, when we're here, our 5-year forward production forecast was 20% a year. And that was actually over the 2012 to '17 timeframe. When you look at it on the same equivalent timeframe we're showing today, 2013 to '18, the 23% we're showing this year would have only been 18% last year. So it's a huge acceleration in both production and value from this area.

We're now projecting that our drilling activity will double over the next 5 years to almost 700 equivalent wells per year. And more of those wells will be extended reach wells, which provide almost 3.5x the net present value of a normal-linked lateral well.

And finally, as promised earlier, we'll be focusing the vast majority of our development activity in these areas where we're utilizing our integrated development plans. And as a result, we will deliver 30% to 50% more net present value than a conventional development.

I mentioned the large contiguous acreage position that we've got. And we've improved on that again this year with an acreage trade that we announced with Anadarko in October. We now have over 600,000 net acres in the basin, majority of which is located in the rural areas of Wells County. Much of that is on large ranches. 87% of it is in the oil window. And roughly 2/3 of it is in areas where we are, today, planning these integrated development plans. And I'm actually confident that, that percentage will increase over time.

Looking at the map, you can clearly see how this contiguous position lends itself nicely to an integrated development concept in the drilling of even more extended reach lateral wells. Not a lot of companies have an acreage position of this magnitude, in an oil play with these strong economics that can be developed as efficiently as this one. And we truly believe that this play is competitive with anything else out there.

Our net risked resources I mentioned in the DJ are now 2.6 billion barrels, up almost 25% from last year and double what it was just 2 years ago. And liquids are 61% of it. This increase is due to continuing strong well performance across the basin and a confidence in 16 wells per section across our acreage position. And as important to note, these resources still equate to a recovery of less than 10% of original oil in place. And that original oil in place has gone up again this year, as Dan will show you here in a little bit.

And so we're not resting. We continue to test new ideas, including downspacing tests this year, in which we will drill the equivalent of up to 32 wells per section. And we fully expect our resources to continue to grow in the future. I mentioned earlier, production's expected to grow 23% over the next 5 years on average. And that's up from 18% over the same time period last year. You can really see the results of that on this slide. Our 2018 production is forecasted to be over 250,000 barrels a day equivalent from the DJ. That's 20% higher than what we showed you last year for 2018. Our focus is on the oilier parts of the field and also -- which leads to increased liquids contribution over time as well. And we expect to invest $12 billion over the next 5 years, but we expect our operating cash flow to be almost $17 billion. So we can deliver excess cash flow of almost $5 billion over the next 5 years that can be invested in other growth projects around the company.

So with that $12 billion of capital over the next 5 years, we'll be drilling over 11 million lateral feet of reservoir. 11 million lateral feet of reservoir, I don't know if you can wrap your head around that number. I had a hard time. I converted it to miles. It's about 2,100 miles of laterals in the reservoir over the next 5 years. That's roughly the distance from New York City to Salt Lake City. It's also a 15% more footage than we told you last year.

As important to note that this footage estimate comes from our planning models, which currently assume only about 30% of our footage comes from extended reach lateral wells. But with our contiguous acreage position and our focus on IDPs, we'll be pushing those numbers higher. And we ultimately expect it to be north of 50% of the footage coming from extended reach wells. As an example, you see on the slide, our East Pony IDP, which was sanctioned this year, has roughly 64% of the footage being developed through extended-reach laterals. So drilling more extended-reach laterals will also only increase the total lateral footage that we're drilling each year, above and beyond what's shown on this chart.

So if we're going to be drilling that many extended-reach laterals, we better be confident that they perform. And we are. You can see from the map that we've now drilled ERLs in 5 of our first 7 IDP areas. Our longest lateral drilled to-date is 9,972 feet long, only 28 feet short of 10,000 feet. And we believe that it's the longest lateral ever drilled in the State of Colorado. And the wells continue to perform as expected. The 9,000-foot laterals are producing between a 750,000 Boe and a 1 million Boe type curve, with the best wells tracking the million-barrel curve. And from the economics in the table, you can see that the long laterals have much higher capital efficiency, delivering a 188% rate of return, which is double that of a normal linked lateral, and as I mentioned earlier, almost 3.5x the net present value per well of a normal linked lateral. That's why we're excited about our plans to drill a higher percentage of ERLs. That's why we're excited about IDP concept.

So we continue to be very confident in 16 wells per section, and we -- but we suspect that the optimal spacing is actually going to be more dense than that, at least in some areas. So in late 2013 and on into 2014, we're testing multiple downspacing tests in 4 of our IDP areas, testing the equivalent of both 24 and 32 wells per section. And note that depending on the area, these wells may be Niobrara A, B, or C, or they could be Codell wells. And we're taking a very methodical approach to these tests. It's really taking full advantage of our experience in the basin and from the previous tests that we've done and all of the knowledge that we've gained from our underground laboratory that we told you about last year. And Dan will be updating you on that again this year. The optimal spacing in each area will ultimately be determined by a number of things, including the zones targeted, how many legacy vertical wells there are in the area and surface constraints. But we're focusing a significant technical resources on determining the right spacing for each area to ensure that we maximize both value and the recovery of the resources.

So we've talked a lot about IDPs. What is an IDP? Here is a graphic that shows what all it entails. And it basically starts with our ability to accurately plan and predict our activity levels in the field over a number of years. Dave mentioned earlier the importance of really taking a long-term view in all of our developments. And that's a very large portion of the IDP concept. That, coupled with our subsurface expertise, results in a greatly reduced uncertainty over time, which gives us a lot better ability to plan our wells, maximize the number of extended reach lateral wells, plan the placement, understand better which zones we're targeting, build out our gathering systems, plan those better, construct centralized processing facilities and really just take full advantage of all of the economies of scale that a development of this type offers. All of that, of course, leads to increasing production and the capture of incremental value.

The final piece shown on the upper left shows the benefits to the landowners, the communities, the environment and the areas that we operate in because we're able to greatly reduce truck traffic, better control our emissions, more efficiently manage our water resources and minimize our footprint.

And so this IDP concept is really a change in our thinking in the DJ Basin. And it takes advantage of our ability to plan long-term and our major project skills that we've developed across the country. And it's a concept that you see we're already taking to the Marcellus. You'll see that here in a little bit.

So again, you can see the positive impacts of it. It allows us to accelerate development, drill more high-value ERL wells, reduce our environmental impact, all the while significantly increasing the value. The map at the right shows our first 7 identified IDPs, 2 of which are under development right now, Wells Ranch and East Pony, Dan will give you more details on those; 3 more that are currently in the planning phase right behind them; and then 2 more behind those that we're starting to think about.

So let's look at an example and see how much value the IDP concept creates. This is an economic analysis of our East Pony IDP, which was sanctioned earlier this year. And we've already identified $800 million of incremental value associated with this IDP plan versus a more conventional development plan. You can see the bullets on the slide that essentially comes from cost savings across-the-board, whether it's drilling and completing efficiencies, lower lease operating expense, more efficiently sized and consolidated facilities, reduced trucking. I'll give you an example of the magnitude of it. If you look at our -- what our water -- building on our water infrastructure is going to do for us, it's going to save us almost $4 a barrel or 80% of our frac water costs.

They also create additional value by allowing us to capture more flash gas at the facilities, and again, allowing us to drill more extended-reach lateral wells. So that $800 million is identified. That's in the plan today. There's also another almost $300 million that we're continuing to work off potential efficiencies. If that all comes to fruition, that will be more than $1 billion of value, incremental value created in just this one IDP. And we expect other IDPs of similar size to have similar impact on value. And as I mentioned, we're working 7 today.

To put that $1 billion of additional value in perspective, on the right size of the slide, we've highlighted the economic impact on an individual well. We're creating more than $1 million of incremental NPV per well, above and beyond what the value would be under a conventional development scenario. That's a significant increase in both value and rate of return.

So as I turn it over to Dan, I'm going to leave you with some data that you can use to model these IDPs. I'll tell you that this is more granularity than we've provided in the past. In the past, we've used basin-wide averages, we've used tier averages. And as averages are, some are higher and some are lower. That's how you get to the average. So some of these numbers may appear quite a bit higher than what we've shown before. Some may be a little bit lower. Overall, I can tell you, our position on the entire basin has not changed. Our average across the entire basin remains what we've shown in the past. We're just giving you more details to work with this time as you may want to try and model some of these IDPs yourself.

So for the purposes of the economics, we've allocated the centralized facilities and gathering investments back to the individual wells. And you can see that the economics are very strong across-the-board, individual well net present values of between $4 million and $7 million, with rates of return from 75% to over 150%. And I'll also point out, in the next to last column, that we've assumed 40-acre spacing or 16 wells per section on all these IDPs for now. So further downspacing, which again we're testing now, would only improve the economics even further. So hopefully, you can see why we're excited about these plans. With that, I'm going to turn it over to Dan Kelly, who's our Vice President of the DJ Basin. And he'll walk you through some additional details.

Dan Kelly

Well, thank you, Gary, and good morning, everyone. So I'd like to just pick up where Gary left off and add some more substance around the integrated development plan model that we've created. My intentions are certainly to illustrate just how much our knowledge and our technical abilities have increased over this past year. And I'll do that by pointing out what's exactly going on in our Wells Ranch area and now in our burgeoning East Pony area, really exciting stuff. And there's a tremendous amount of momentum around this is in the DJ Basin. And I really hope to make sure you guys understand how successful this really looks to us in the field.

So at the map, included, you'll notice Noble's dominant land position in the northeast portion of what I call the legacy Wattenberg Field. This is where we're operating approximately 61,000 net acres, which is roughly 10% of our acreage position in the DJ Basin. In this area, we're producing about 25,000 barrels per day, with the majority of it now flowing through our new central processing facility, or you'll hear a lot, CPF. This facility came online in late October. And as Gary stated earlier, the economic, environmental and operational efficiencies of this development model are becoming very clear to us on a day-to-day basis.

Back in the map, you'll see the infrastructure that's laid out, which includes liquid and gas pipelines that connect each development area in this overall integrated development plan back to what we consider our central processing facility. And you'll also notice that our planning teams methodically lay out drilling locations section by section, taking into account the most updated spacing scenarios to optimally develop the area. The inlay is an example of the detailed look taken to properly locate wells and introduce extended-reach laterals wherever possible.

Our plans throughout this area in 2014 include keeping 4 rigs busy, drilling on average 16 wells per section where feasible. We predict that we will peak at production sometime in 2019 at 115,000 barrels a day. And that's equivalent. This is really an amazing opportunity. As we see the ramping activity over the next 5 years, we're generating right now a before tax net present value of somewhere over $3 billion, again, on only 10% of our acreage position in the basin.

So I've just included a picture of kind of where we've been and where we're headed. In the bottom right hand corner is the new CPF, which has about a 60-acre overall footprint. This facility, with 2 production trains in service, will handle approximately 45,000 barrels oil per day and about 45 million cubic feet of gas per day. Our intention is to continue to drill at a pace in this area that will keep this facility full in the near term. And potentially, we'll build a second facility similar to this, maybe even a little bit larger, to handle additional growth. That's just in this single IDP.

Now if you look at the upper left-hand corner, you can see the size and scale of our generation I EcoNode, which is completely self-sufficient. It does not need a central production facility. But I'll point out, you can see the number of tanks that sit individually on that facility. And you can imagine that 3,000 to 4,000 barrels oil per day flowing through that facility, what truck traffic might look like to try to haul fluids from this individual tank battery.

So go now to the middle where you see the Gen III EcoNode. The Gen III has a much smaller footprint. It's about 1/3 of size of the generation I EcoNode and works in conjunction with the CPF. The significance here is that by utilizing the CPF, we can begin to reduce our overall footprint by a factor of 10, if you were going to develop this area on individual basis, and at least and a 1/3 -- or if it's 1/3 if you're going to continue to build the generation I EcoNodes. Just an amazing difference. And again, at the CPF, we can ship all of our oil via pipelines to much different outlets. We can monetize our flash gas from tanks and we can centralize water recycling. This also allows us to utilize our automation and manpower much more efficiently because this is a very active location on a 24/7 basis. There are just numerous advantages that are becoming more clear everyday.

So we'll catch you up on the underground laboratory that Gary referred to in section 25 in our Wells Ranch area to tell you what's kind of happened in subsurface. It's really pretty amazing. Last year, we had unveiled 9 wells that we drilled in section 25. And they were drilled under 3 different spacing scenarios. 2 of these wells, as depicted in the blue, were drilled and -- at about 80-acre spacing and were equipped with fiber-optic cable running down the exterior portion of the horizontal leg of the well.

Over this last year, we've been able to capture about 30 terabytes of digital temperature history from these 2 producing wells, as well as a significant amount of pressure data from each well -- one of the well's downhole. Our technical experts continue to extract information that supports not only 16-well spacing, but is really pushing this to a tighter density in that 24 to 32 wells per section. The need for increased oil density is also confirmed with over 1 year of production history from these wells that you can see, the 9 wells that you can see on the graph. Our 40-acre space wells in this section and our 80-acre space wells are performing very similarly even after 500 days of production. As these wells are obviously not competing or interfering with one another, we have proposed 2 more spacing tests that will include a 24-well pattern and a 32-well equivalent pattern in 640-acre section. As we said a year ago, and as we were saying today, we will continue to tighten well spacing within the Wells Ranch area to ensure that we are optimally developing this area.

We've also increased our original oil in place in this portion of the field from 74 million barrels oil equivalent to now 82 million barrels equivalent on a per section basis. This is an 11% increase. We cut another quarter this year to confirm our residual oil saturation. This was a state-of-the-art core acquisition utilizing proprietary oil and water treasures. This methodology confirmed lower-than-estimated irreducible water saturations which resulted in a higher hydrocarbon core volume. This, again, provides more confidence in that 24 and potentially 32-well spacing tests that we've got slotted for next year. The drilling pattern in the middle of the page provides an illustration of our intention to spread these wells out throughout the entire 300-foot section of the Niobrara in the A, B, and C benches. The lower graph helps visualize the value created with downspacing. The graph measures our current confidence levels and it provides a range of improvements of our net present value and recovery factors as our optimum spacing is established.

I want to wrap up the Wells Ranch IDP portion of the story, which is one piece of the puzzle, one last piece of the puzzle. The black dash line depicts our 305 MBoe type curve. And then this is what we're utilizing on all the economics we've provided today. We have overlaid the average normalized production history of 175 horizontally drilled wells in this area. Now keep in mind that 70% of this is liquid. Production results over 1-year timeframe, with 175 wells show that well performance is consistent and certainly repeatable. So the byline on this slide reads great project continues to demonstrate upside. This is so true. During the past year, we've confirmed 40-acre spacing in this area. And we continue to look for optimum well density as we go forward. Future drilling plans will maximize the utilization of extended-reach laterals with our intensive planning process. Cost continue to decrease, which we'll show more of that later, but this is all due to the infrastructure in place. And we continue to minimize our footprint more closely with the community to lessen our impact in this area. This truly is our model for true -- for future development in our 600,000-plus acres in the DJ Basin.

We're going to jump to East Pony, and things are just going very well in this area also. From previous match, you may remember that this is in the furthest northeast portion of our acreage position in what we call our Northern Colorado area. We're extremely excited about it, as it is designated as our second integrated development plan area. In East Pony, economics are even more robust, as we are using a 345 MBoe type curve, with about 80% of that being oil. We're running 2 rigs here already, with the expectation that we continue to build out our infrastructure, so more rigs can come as soon as possible.

Another key component is our push to increase the inventory of extended-reach laterals in this area to roughly 45% of our well count. Or as Gary stated earlier, 64% of our lateral footage drilled will be in extended-reach laterals. Our current model predicts a peak production rate in 2019 of 150,000 barrels of oil equivalent a day coming from these 3 townships. Again, with 80% of that being oil. We operate 44,000 net acres in this area, which equates to about 7% of our entire acreage position throughout the entire basin. Our current production model generates a before tax net present value in East Pony between $3 billion and $4 billion.

Going ahead and including the same well performance slides that we did in Wells Ranch. The type curve represents a normalized average performance of 46 wells drilled in the East Pony area, with about one year production history. The wells continue to follow a 345 MBOE curve with the no concerns or interference. We have continued to perform increased density tests in this area. Our spacing preference at this time is 16 wells per section. But similar to Wells Ranch, we will be performing downspacing test in this area in 2014, again targeting that 24 and 32 wells per section model. We are also seeing great results from the one extended-reach lateral well we have in this area. Again, very similar techniques and leverage learnings from Wells Ranch area provide a tremendous amount of confidence in this East Pony area.

I couldn't go very far without talking a little bit about the amazement of our drilling and our completion groups. They never sit back. They continue to optimize as we throw more and more at them. It's amazing the expectations we have upon these folks. Truly, their passion to improve is always present. In 2010, we averaged 16 days per well from spud to rig release to drill a typical 4,000-foot horizontal well. Today, we are spending, on average, the same amount of time to drill an extended-reach lateral well. And recently, we drilled a 4,000-foot, what I'll call, typical lateral horizontal well, in less than 6 days. This is truly an amazing and it really makes we wonder where we're going to be 3 years from now. Our well cost continue to come down also.

We are certainly benefiting from pad drilling. Rig moves, construction costs, our leverage across [ph] multiple wells with completion optimization -- operations optimize. We've included a graph of the actual well cost in Wells Ranch just to show how systematically these efficiencies are being realized. And in Wells Ranch, we have recently reported 6 wells on a single pad that were drilled and completed sub $4 million. This is a step change from the almost $5 million that we were spending about 1.5 years to 2 years ago.

On the stimulation side, we continue to contract 2 full-time 24/7 crews with Halliburton. We're delivering water to our jobs via pipelines, significantly reducing transportation costs. We are optimizing stage volumes and stage lengths based on historical performance. And we are working different and -- with different and less expensive gel fluid systems, constantly tweaking rheology for optimum performance.

Our job capabilities continue to grow, and in 2014, we plan to frac almost 10,000 stages. There are 8,760 hours in a year. We will average at least fracking 1 stage per hour in 2014. Our operation teams continue to rise through all of the challenges we put them through and continue to perform at best-in-class levels.

Relative to oil transportation, we have recently participated in the startup of the new Plains rail facility in the southern portion of the fields. We will seek capacity increase on the White Cliffs pipeline in mid-2014, which this, if you remember correctly, connects the DJ Basin to Cushing, Oklahoma. That pipeline is expanding and will nearly double its capacity with a 12-inch loop line later this year and in the middle of next year. In short, Noble's oil takeaway capacity almost doubles in the next 12 months.

And in the greater Wattenberg area, Noble works very closely with its midstream partners. An example of this is DCP. DCP started up their 110 million cubic feet a day O'Connor plant this past fall, and will be expanding that plant by another 50 million cubic feet a day to further increase their existing capacity in 2014. They're also performing other meaningful changes in their system in 2014, which will benefit Noble's throughput potential. So from June of this year to the end of next year, we'll have increased our gas takeaway capacity somewhere close to 30%. And the production in Northern Colorado is primarily oil. But certainly, our gas and NGLs also make an important part of the value there. We operate our own gas gathering and processing facilities, and we'll be bringing on our new 30 million a day Kyoto plant in mid-2014. I will say that we're even looking at further expansion into 2015 already at this time.

So to provide just a little bit more clarity, we've gone ahead and included a map that details the location of these expansion projects, and we're very confident that these projects will secure takeaway capacity for our production for several years to come.

So you've heard it quite a few times already this morning, but I'll talk about it again. A significant driver for us at Noble is to live our purpose: energizing the world and bettering people's lives. Our new IDP concept and centralized facilities really help us fulfill that purpose. With the integrated pipelines, we're taking trucks off the road, significantly reducing emissions and dust. We are leading the discussion in Colorado around air rules, where these new facilities will provide more efficiencies around flash gas capture and monetization. We're recycling up to 90% of our water in these IDPs and sourcing our water from non-tributary resources that don't compete with municipalities, ranches or farmers. We've discussed a reduction in surface impact and our ability to develop large, contiguous acreage blocks with less footprint. And to me, what's important, fewer oil and water storage tanks.

We have committed to a first-of-its-kind LNG facility in Northern Colorado that will supply the drilling rigs, frac spreads and other operational horsepower with clean-burning natural gas.

We now have 500 employees in our Greeley operation center in Northern Colorado. We work closely with approximately 1,200 contractors on a day-to-day basis. I remind folks constantly that we're a very large part of this community, so when Noble stepped up to donate manpower and resources after the floods in September, we did it because we remain driven by our company's purpose. I, along with the entire DJ Basin team, are proud of our accomplishments but continue to address growth and increased pace, with the commitment to our environment and the communities we live within.

So in closing, last year, I talked about my tenure in the DJ Basin since 2006, and it just keeps going on. This really is an area of limitless possibilities. In 2018, our production is forecasted to be over 250,000 barrels of oil equivalent a day. That's the size of Noble Energy in mid-2013. This is after a 23% Compounded Annual Growth Rate that we're projecting over the next 5 years, truly significant.

And then the resource itself, the more we learn about the Niobrara, the bigger it becomes. Our original oil in place indicates over 80 million barrels equivalent per section. And as we look closely at the Wells Ranch and East Pony areas, only 2 of our potential 7 IDPs, we see that this includes about 17% of our leased acreage. And both of them, combined, have a before tax net present value of $6 billion to $7 billion. And that's including 40-acre spacing. That's not including any downspacing potential. This truly is an area of unlimited possibilities. Thank you very much for your time. I'll hand it back to Gary who will cover the Marcellus.

Gary W. Willingham

We'll move back to the Marcellus. And similar to DJ, I'm going to give you an overview and then I'm going to turn it over to Donnie Moore, who runs this core area, and he's going to come up and lead you through some of the details.

So much like in the DJ Basin, we've seen a significant increase in our resources in the Marcellus over the last year. We now estimate net risk resources of 13 Tcf equivalent, which is up 30% from what we showed last year. And that growth comes a variety of sources that we'll look at here in a few minutes. But I'll once again point out, you're probably tired of hearing it, but that 13 Tcf does not include the acquisition that was announced last week. If you did include that, it will take that number to almost 15 Tcf equivalent net. We're now forecasting that production will grow to compound annual growth rate of 46% over the next 5 years. That's an increase of 4% from what we've showed over the same period time last year. And last year, we told you we were targeting a 20% reduction in our well costs over time, and we're well on our way to achieving that goal.

Learnings that we've transferred from other areas, efficiencies that we've already realized that resulted in a 10% reduction this year, and we're on pace to achieve the full 20%. And while we're driving those costs down, we're also improving the well performance. We're seeing higher IPs, flatter declines, higher EURs, and of course, all of these leads to significantly higher value per well, which we'll show you on a later slide. So we're not stopping here.

We're also testing new -- multiple new concepts and looking for additional ways to accelerate value in this field. And Donnie will be telling you more about some of those ideas when he comes up. And finally, just wanted to mention that with our position in Southwest Pennsylvania and Northern West Virginia, we continue to receive premium pricing relative to other parts of the play, and we have plenty of capacity to move our production.

So just a reminder that we've got 50% interest in over 600,000 gross acres in our joint venture with CONSOL Energy. Again, this doesn't include the recent acquisition. Adding that would take you close to 700,000 gross acres. And we operate the wet gas side of the acreage, and CONSOL Energy operates the dry gas side. And this acreage position really has many benefits. There's a very high percentage of HDP, so we don't spend a lot of time moving rigs around trying to chase lease expirations. It also has a very high NRI, which obviously makes great economics even better. And we've seen quite a rapid growth in production since last year, and we're currently producing 200 million a day. As of this week, we're up to about 210 million cubic feet per day net, which is up over 65% from last year.

So I mentioned, net risk resources were 30% -- were up 30% to 13 Tcf equivalent. You can see on the chart, that's almost double what they were just 2 years ago. And the exciting thing about that growth is it's coming from multiple sources. Our well performance continues to improve, and we've increased the average EUR in the areas that we're currently developing by 15%. We've also assumed some downspacing in the field from 750 feet between wells to 500 feet, but that's only in a portion of the field. And the overall average for the field, we're still assuming between 650 and 700 feet, so still more potential there.

And finally, we've included a small amount, if I can call 0.7 Tcf a small amount, but we've included a small amount for stack to pay potential in the Burkett. And this really is only a small portion of the unrisked potential that we see on our acreage, and Donnie will give you some more details on that.

Not included in this 13 Tcf is obviously, again, the acquisition, but also some new concepts that we're currently testing, which we're very excited about, which will also provide some more color on.

So production is expected to grow an average of 46% per year over the next 5 years. 2014 alone is going to grow 90% from 2013. We're going to be investing $7 billion in the Marcellus over the next 5 years, increasing our activity levels until the JV is running 16 rigs in 2018. And at that point, we'll be drilling up to about 2 million lateral feet of reservoir per year. On the left side, you see the strong growth in cash flow that, that results in. It reaches $1.4 billion in 2018. On the capital chart to the right, you can see that we're showing the drilling carry there in the yellow, we're showing that as starting in 2015, while all of you know that that's dependent on gas price and that won't kick in until Henry Hub averages $4 or more for 3 consecutive months. But it's in there, it's $1.4 billion is what it adds up to over the 4 years that we've got it in there, and that is included in that $7 billion in the bullets.

On the midstream side, we continue to actively manage our gas processing capacity. All of you know, the industry's rapidly building out infrastructure in these areas. We currently have about 370 million cubic feet a day of our own firm gas processing capacity net to Noble, as well as another 40 million a day of interruptible capacity that we can use. Altogether, that ensures that we can continue to move and process our gas. And we're also maintaining our optionality for ethane. We've supported the building of a new ethane cracker, but we also currently have blending capacity for ethane, given the amount of dry gas that our partner operates, which is just one of the many benefits of our strategic partnership.

The chart on the right shows the gas differential versus Henry Hub since early 2012, for the Southwest Pennsylvania part of the play, where our properties are, versus the Northeast Pennsylvania area. And our pricing remains favorable. We have over -- we have 255 million BTU per day net of firm transport. And as you can see from the map, that extensive network of pipelines in the area allows us to reach multiple markets with our gas.

So I mentioned earlier how rapidly our production is growing, and the chart on the upper right clearly shows this. We've more than doubled or right at doubled our production in the last 6 months, multiple things are really driving that growth from significantly more lateral feet being brought online this year to accelerating the first production on wells by conducting safe, simultaneous operations on pads to improving our completions. In fact, our IPs are up 15% in just one year, in part, due to the many of the learnings that we've transferred from the DJ Basin. Along with the growing production and improved completion designs, we're also driving costs down. As I mentioned earlier, we've already achieved a 10% reduction in well cost on a standard 5,000-foot lateral, so that's on equivalent 5,000-foot lateral basis, we're not taking credit for drilling cheaper just because we're drilling longer laterals, it's on an equivalent basis. And that, in turn, results in an increased NPV of about 10% on each well. These reductions are coming in from both the drilling and the completion side. And you can see in the bottom chart that we've realized even more savings then by drilling those longer laterals.

As I mentioned earlier, we're on track to realize the full 20% cost reduction that we mentioned last year. And you can see on the bottom right of the slide, some of the things that we're pursuing to achieve that.

So just as we've done in the DJ, we're now drilling longer laterals in the Marcellus. Our acreage position, which is largely HDP, allows us to drill more wells per pad and longer lateral wells than we probably be able to if we were moving rigs around chasing acreage. And as you can see in the upper right, our average lateral length has increased from 5,000 feet to 7,000 feet in just one year, which places us well ahead of the average of our local peers based on their public disclosures. And we will continue to extend laterally even further where possible. And in fact, the bottom chart shows the benefit of that. A 10,000-foot lateral well has more than triple the net present value of a 5,000-foot lateral with the development cost that's about 30% less. Given the significant increase in value and capital efficiency, as well as the performance that we've seen from these wells, we'll continue to push more and more of these and drilling them even longer. In fact, we recently brought on a pad where we have 5 laterals that are all greater than 10,000 feet.

So how does this all this add up? Higher EURs, reductions in drilling and completion cost, increased value for longer laterals, the graph and the data quantify the increase in value that we've from all this. The starting point for both is what we've called the historical view. And you'll see in the footnote that the historical view is based on the EUR assumptions that we have had at the time entered the JV and the cost assumptions that we've showed last year. So fast forward to today, we're drilling longer laterals for about 20% less cost, less cost per lateral foot and we've improved our completions at the same time. So while a historical well would have had a net present value of about $1.5 million per well, a typical well we're drilling today has a net present value of $7.4 million, almost a fivefold increase. And that's cost have of dropped by 50%. I don't think in my career I've ever seen the economics of a play improve that quickly. But it doesn't end there. As the future column showed, we intend to drill even longer laterals, drive the cost down even further, test tighter lateral spacing and test multiple zones. I'm really looking for to come back next year and telling you about the additional increase in value that we've seen as a result of all of those things. So with that, I'm now going to turn it over to Donnie Moore, he's our Vice President of the Marcellus and he's going to get a bit deeper into the details and show you how we've created all this incremental value. Donnie?

Donnie Moore

Okay, thank you, Gary. Good morning, everyone. I'm really, really excited to be here this morning to share some of the details of the great work that Noble's doing in the Marcellus. As this U.S. onshore story has been unfolding this morning, you've seen a lot of common themes between the DJ and the Marcellus, tremendous resource growth and production growth, accelerating activity, multiple targets, tighter lateral spacing, completion optimization, continuous improvement and then kind of rolling all that up in the integrated development plans to maximize value. You heard that in the DJ, you're hearing it in the Marcellus. As Gary mentioned earlier, this isn't by accident, this the way we designed it.

Dan and I worked together in the DJ Basin for the last 3 to 4 years, with our teams creating the process or the model that Noble uses in developing these resource plays. This is -- it's a proven model, you've seen it in the resource and the value numbers you're seeing in the DJ, and you're going to see it in the Marcellus as well. And now, our teams in the Marcellus are applying that model, and that's allowed us to really accelerate our program to deliver the value by plan the best practices today. Currently, we have 2 integrated plans in the Marcellus that are in execution phase, Majorsville and Southwest PA Drive. And we have 1 IDP that is sanctioned and in the planning phase for our airport acreage. These areas only account for about 20% of our total acreage in the play. As you can see, there is a tremendous amount of upset value that will continue to deliver as we continue appraising, taking those learnings and applying them with a very integrated process and plan for our future integrated development plans.

So first, let's take a look at Majorsville. This is a core operated area for Noble and a core integrated development plan for us. Strong liquids rich area, sub $0.90 FNDs, and where we have experienced tremendous growth in really a short amount of time, this is only been in development for about 1.5 years. We're currently producing about 150 million cubic feet a day. And I want to point out, we're still early in this program. We still have over 80% of our acreage to develop here, so much more to come.

One thing I want to highlight on the slide is the increased per well reserves and the new type curve that we're using here. As has been -- as we've been optimizing our completion technique and modifying our frac designs, we're seeing our well performance really make a step change. We originally increased our type curve because our wells this year are producing about 15% more in the first 30 days than our wells that were completed in 2012. But rather than just focusing on the 24-hour IP or a 30-day rate, we like to look at the well's performance over the first 2-, 3- or 4-month period. So when you look at that for our wells, we've seen, we're producing about 20% more in the first 4 months compared to our wells last year. And we're really seeing [indiscernible] as you can tell on the plot produced a lot flatter decline than our type curve. And that's what's exciting, that's setting a lot of value today. Majorsville will continue to be a strong growth area for Noble for years to come, as we continue optimizing our drilling and completion techniques. In addition, in Majorsville, we'll also be testing 500-foot lateral spacing, which could really unlock even more potential here. About 1/2 of our program, 2 to 3 rigs next year that we operate will be in Majorsville.

So I'd like to add a little more color to the Marcellus model of an integrated development plan. We're very proud of Majorsville, as it was designed from the very beginning to maximize value through our efficient development model, with centralized separation, dehydration and compression facilities, common gathering lines for gas and liquid transports, a shared water infrastructure with 100% recycling and reuse, and a major processing plant located ideally in the center of the field to receive our products. This plan not only provides a reduced footprint with multi-well pads and long laterals, but maximizes value through the most efficient development process.

In Majorsville alone, we estimate the IDP is delivering an incremental $150 million of value to the company. And if you look at it, Majorsville is less than 10% of our position. We have a tremendous amount of additional value we'll be delivering as we continue to apply this model across our entire position.

Our next integrated development plan that's in execution phase is in Southwest Pennsylvania. It's a large acreage position in the dry gas window. It's operated by our partner CONSOL Energy. This is one of the most prolific areas within the basin with returns nearly 35% and a per well valuation of around $8 million. We have a lot of history here with over 130 wells producing, and the production is doubled in just the last 2 years. This area will continue to add tremendous value with strong economics as we further consolidate our acreage, drill longer laterals and apply our new completions and techniques and optimized designs. Dry gas or not, this area provides tremendous value to our Marcellus position.

So I'm going to jump over to the airport acreage, the Pittsburgh International Airport. This was the first strategic acquisition the joint venture made in the basin and rounds out our currently sanctioned integrated development plans. Again, this is another ideal area for IDPs with all the right characteristics we're looking for, has a contiguous acreage position with great rock properties, thick Marcellus, high liquids content, great analog wells nearby. And some interpretations even put this in the superrich window, though we're kind on a wait-and-see approach on that one. This acreage has a very perspective Upper Devonian with the Burkett, and we'll be testing that early in the program as well. We're eager to get this plan underway. We should start drilling here in mid-2014 with production in early 2015.

Finally, to our appraisal and delineation areas. The Oxford/Pennsboro/Shirley area is, I believe it is, the most active area in this basin. We have 2 rigs aiding the area for us, gathering the right technical information to create our next IDP. I'm really excited about the technologies we're applying here and the testing that we'll be doing in these rich gas areas. We're in the process right now of building our underground laboratory. You heard a lot about the one in DJ Basin, so we're building one here as well with realtime downhole monitoring for pressure, temperature, stress and fracture mechanics, so we'll really understand how these wells and completions are performing to optimize our development in this area. We'll also be doing a significant number of lateral spacing and multiple target tests in this area, and I'll talk about that a little more in a moment. It's really exciting area for us, a lot of running room and we're ready to get this IDP defined, sanctioned and into development mode very soon.

So we've got only 20% of our acreage in an IDP currently. So we have a tremendous amount of running room. In fact, we have over 450,000 acres of running room. Due to our position being largely held by production, we can take a deliberate and measured approach to development in order to maximize the value of these assets. As we fine-tune our learnings from our downhole labs, we can really apply those learnings to unlock the full value of this large relatively an appraised acreage position. So let's shift gears just for a moment and talk about a couple of key activities that we believe will be game changing in this basin. First, I want to reiterate something, and I mentioned it just a slide or 2 ago, because our acreage position is held by production, we're able to do several things that frankly others just don't have the opportunity to do, such as prioritizing our development areas and applying integrated development plans to maximize value. It also allows us the opportunity to test things like downspacing in multiple targets, and that's what I'll touch on now.

As most shale plays have evolved, lateral spacing tends to get tighter and tighter over time. And the Marcellus is no different. We originally started out at about 1,000-foot spacing for our laterals. We're currently developing at 750-foot spacing, which is roughly 100 acres per well on a normal lateral. And our scientists telling us we have a long ways to go. We're not seeing any interference between 750-foot spaced wells. Right now, we're testing 500-foot spacing, which is still only 65 acres per well. We're feeling really good about what our models are telling us, but as it stands right, and as Gary mentioned, we're assuming 20% of our acreage can be downspaced to 500 feet. This leaves a tremendous amount of upside value as we prove this up over the next year or so and apply this across our entire acreage position.

So I've mentioned the Burkett potential several times already. This is a tremendous untapped opportunity. And I believe will be the next big breakthrough in this basin.

Just as in the DJ, we look at the entire interval of resources from the base of the Marcellus through the Upper Devonian and optimize our development patterns to maximize recovery and value for the total resource. We have seen areas where the Burkett exhibits similar rock properties as the Marcellus. In fact, there are areas where the Burkett is as thick or thicker than the Marcellus. With our partner CONSOL, we've already drilled and completed one horizontal Burkett well that's exhibited some really strong and encouraging results. At this point, as you in the earlier slide, we're carrying a very small number of resources from the Burkett are less than 10% of our acreage. And yet, the Burkett is very perspective across more than 50% of our position. We'll have a half a dozen to a dozen Burkett tests this next year, and we'll test those with multiple development patterns with the Marcellus. And by applying our new completion learnings and techniques, we will unlock this huge potential in the basin. I believe the Burkett and Upper Devonian host tremendous upside and will drive growth for many years to come.

So if the base plan to continuous improvement downspacing tests and Burkett potential were not enough, we're also working on several other big things that will really increase our well performance and ultimate recovery across our position. And again, we keep repeating this, but none of these are included in the plan that you're seeing today. As we continue to reduce our stage and cluster spacing, which at one point, was about 500 feet per stage, we've seen tremendous improvements in our well performance or recoveries. Right now, we're testing 150-foot stage spacing with 30-foot cluster spacing, and seeing great results, as demonstrated by the plot on your slide there that has increased production rates by over 40%. We have a number of these designs planned in all of our areas in the coming year, so we're excited to see how that continues to progress. We're also applying the learnings from the DJ Basin around controlled flowbacks in production. This technique really maintains our fracture network over the long term and minimizes the irreversible damage to the stages in our lateral from excessive drawdown. Still early, but we're seeing even flatter declines on these wells, and even an increased condensate recovery with potential to increase EUR to another 10% or so. We also think there's a tremendous amount of refrac potential in the older vintage horizontal wells that did not have benefit of our new completion designs with our partner we've recently conducted a refrac on one of our older wells in Green Hill and Southwest PA. Well increased performance fivefolds and is basically back to its original production rates when it was completed. We have several of these already in the queue being planned to execute very soon. So a lot of very promising upside that we're executing on now and they all have tremendous potential to continue to add value across our entire play.

Okay. Gary has mentioned previously our second strategic bolt-on acquisition. This is yet another example of how to structure a deal to maximize value. Almost 90,000 contiguous acres with 1.8 Tcfe of net risked resources, and average gross price of about $2,000 per acre and only half of that is due upfront and the rest of it is due in the next several years.

Again, I'll remind you, this is not in our plan, so a tremendous upside opportunity here. This large position bolts right onto our existing acreage in that area of about 150,000 acres. So is that deal for large IDPs, for efficient deployment infrastructure, multi-well pads and long laterals. And this is an area where the Burkett is up to 50 feet thick, so significant potential there as well.

Another thing that's exciting about this acquisition is the ability for us to continue to leverage our improved concepts and deliver results, especially the application of our drilling and completion learnings and technologies. We have a 6-well pad directly offsetting this acreage that we recently completed with our new completion designs. The wells are just now coming on, but the first well has come on strong with the initial production exceeding our expectations by 40%, with an IP of nearly 14 million cubic feet a day. So we're feeling pretty good about being in the right area. This -- the plan is to start drilling this area mid-2015 with first production expected in early 2016.

As I've talked about the value, our IDP concepts delivered to the business, I also want to talk about the value, the plans delivered to the communities where we work and where we live. We've designed our operations to lower the overall impact of our footprint we have in the community through taking trucks off roads, reducing nuisance dust and noise and minimizing our impact to the land and lowering emissions. We're also taking that further by continuing to increase the use of locally developed clean-burning LNG and CNG on our rigs and on our field vehicles. So our goal is to not only be the leader in developing the Marcellus the right way, but we always strive to leave the areas where we work better than we found them.

Finally, and closing, and just one year, we've increased production over 60% and we have really laid the foundation for dramatic growth that will take us through 1 Bcf a day by 2018. Our resources had nearly doubled since the acquisition. Our technical and operational teams are testing numerous concepts that could substantially increase that number by the end of next year, which will really redefine this play. We have continued to see tremendous improvement in our well performance. We have delivered significant cost savings. And it all adds up to improved results, increased production and a very efficient, well-run operation that delivers tremendous value in a responsible and prudent manner. We're positioned in the Marcellus to deliver significant value to Noble for years to come. So with that, I'll take us to a break, 15 minutes, and we'll see you back here. Thank you.


Brad Whitmarsh

Hey, let me ask everybody to go ahead and take their seats so that we can restart the rest of the presentation. We'll start in about 1 minute.

All right. Thank you for coming back for the second half of this presentation. I appreciate all the attendants so far. I wanted to transition us now from review of our Onshore business to the Global Deepwater and Exploration portions of the presentation.

Before handing it over, I'd like to mention that we will be having a formal question-and-answer session after the presentation, and management will also be hanging around for some additional discussion at the end of the meeting.

With that, I'd like to turn over to Susan, who leads our Global Deepwater, Gulf of Mexico, West Africa and Frontier business as well. Susan?

Susan M. Cunningham

Thank you, Brad. As you can see, this year, we've organized our portfolio more by project type and less by geographic location. And so, as Brad mentioned, we are leaving the land and diving offshore.

I'll start the section focusing on the Gulf of Mexico and West Africa, and it will be followed up by Keith, who will update you on all about the Eastern Mediterranean.

We're focused on leveraging similarities and learnings in deepwater exploration and developments throughout the world. The interchange of ideas and thinking will continue to support and grow our effectiveness in innovation and finding, developing and producing deepwater offshore resources. I'll highlight our performance and latest thinking in the Gulf of Mexico, our expanding efforts in West Africa, including new venture opportunities in Sierra Leone and Gabon.

We have a track record of creating value through exploration, rapid development and efficient reliable production in our core businesses of the Deepwater Gulf of Mexico and West Africa. We are producing over 100,000 barrels of oil equivalent per day, and before tax, generating operating cash flow of approximately $1.5 billion per year. We have 6 discoveries to be developed and about 1.3 billion barrels of oil equivalent of net unrisked resources, a number of exploration prospects on our near-term drill schedule.

Over the last several years, we've demonstrated our competitive advantage in major project execution through our offshore activities, bringing discoveries to production efficiently. Now I put this slide together just to illustrate the breadth of our activities in these 2 areas. The Aseng FPSO, on the lower left, in West Africa brought online ahead of schedule, continues to perform extremely well. By reinjecting gas, we've lowered emissions and improved recovery of high-value oil. We're dramatically increasing condensate recovery in the Alen Field millwright by recycling gas at this offshore gas plant. It is integrated with dual product-type offloading at the Aseng FPSO.

And then on the Gulf of Mexico, the Galapagos project, in the lower middle, is performing well and has more upside potential. We recently completed the acquisition of the Neptune Spar for Swordfish production, marking our entry as the Gulf of Mexico floating deepwater facility operator.

And Alba in Equatorial Guinea continues to deliver.

Our growth offshore is through the drill bit, and we continue to grow our abilities in offshore exploration. This is the competitive advantage and will continue to be so in the coming years.

We effectively utilize technology and apply it to our exploration processes globally. Our exploration efforts have delivered an inventory of major projects, which we have and will continue to develop through innovative development solutions. We work well with regulators and have proven ourselves as a safe and efficient operator. Our record-setting drilling performance in the Gulf of Mexico sets us apart. As we've expanded our reach into new global areas, we are seeing opportunities to apply our new ventures mindset back to our existing position.

The value of our global offshore business is evident. Production growth in the Gulf of Mexico was expected to offset minor declines in Equatorial Guinea through 2018. And before tax, the operating cash flow contribution will be over $8 billion over the next 5 years.

Please note that Ken's chart, illustrating a decrease ROCE in 2018 does not include Dantzler as it is such a recent success, a really high-return project as you'll see. This allows us to deploy capital efficiently to the best projects, supporting explorations for the future and funding other opportunities and programs in our corporate portfolio.

We have 4 major projects on the path to production. Big Bend and Gunflint were sanctioned a few months ago, and we expect to sanction Dantzler and Diega next year, with initial production beginning in 2015 for Big Bend, and 2016 for the other 3 projects. Our sanction-to-production time is expected to average 27 months, just over a year -- just over 2 years, a number that we believe represents efficient and effective project management. A focus on getting the right project done right, quickly and on-time.

And we are preparing for our next core business now. As Dave mentioned, we believe it is important to have the public's trust anywhere in the world. We are global explorers, and we continue to evaluate opportunities for areas that can be material for us and which are running room to grow. And there are 3 opportunities offshore that currently made that criteria. We are focused not only on exploration as he mentioned, but on living our purpose, bettering peoples' lives, gaining and keeping the public trust no matter where we operate.

Nicaragua, where we drilled a well earlier this year, is being evaluated for future prospectivity. We have a large acreage position there and with multiple prospects. In the Falkland Islands, we're actively shooting 3D seismic over this enormous acreage, with the intent of spotting an exploration well in 2015, and Mike will talk more about those. And in Sierra Leone, we're participating in a 2D seismic program, which will be used to direct 3D efforts, if they're warranted.

And now, let's look specifically at the Gulf of Mexico. We've been active in the Deepwater Gulf of Mexico since 2001. This core area has consistently contributed good cash flow and is now poised to more than double that contribution over the next 5 years. You could see our producing properties here in red, as well as the discoveries it will bring to production over the next few years. These 4 discoveries are expected to add up at least $1.3 billion of before tax net present value to our portfolio. Approximately 80% of the 5-year production will be oil.

Our acreage position, shown in yellow, represents another 3.8 billion barrel of oil equivalent resources on unrisked basis. We will continue to mature our prospect inventory and expect to drill 4 to 5 exploration wells in the next 2 years in the Gulf of Mexico.

Before I show you the specifics of our discoveries and our resulting growth, I want to briefly discuss the factors that have driven our success in the Gulf of Mexico.

We like the Gulf of Mexico. It has great geology, all the right ingredients, combined with the relatively stable commercial and regulatory environment, significant existing infrastructure and a mature support industry. The Gulf of Mexico continues to be an incubator of technology and innovation, a great place to explore, invest and produce. In short, geology, technology and innovation, coupled with great commercial terms and infrastructure, results in great returns to Noble and brings value everywhere we work offshore.

We're postured to take advantage of these characteristics to double our production in the next 5 years, as I mentioned, consistent with Noble's overall growth. Our base portfolio, led by our Galapagos and Swordfish fields, continues to provide nearly 20,000 barrels per day of high-value production.

Our sanctioned projects at Big Bend and Gunflint will add production in 2015 and 2016. And we find the sanctioned Dantzler, the Dantzler discovery next year, expecting it to come online in 2016 and elevating these high-value areas to new record production and ramping up to a peak in 2017, again, doubling production in the next 5 years. Of course, this assumes we do not have any new discoveries and, of course, we plan to have more.

Our recent Dantzler discovery shown here will leverage infrastructure and be a very significant contributor to value.

The Gulf of Mexico program has been cash flow positive and will return to significant cash flow generation by 2015, the cash flow approaching $1 billion in 2018.

Our current production is led by the Galapagos project area and Swordfish, a legacy asset that is now expected to be more than double the original resource estimates. As I mentioned, we recently completed the acquisition of the Neptune Spar that processes Swordfish production, where we have significant remaining resources. Galapagos production continues to exceed original expectations. It was brought online in June of 2012, and we currently produce from 3 integrated subsea fields: Isabella, Santiago and Santa Cruz. We see further potential with the second development well at Isabella, as well as a well at Genovesa. And we expect an additional $1.2 billion of before tax net present value from this area.

Next, we'll take a quick look at our 2 sanctioned projects underway.

First, Gunflint. We and our partners discovered over 150 million barrel of oil equivalent in -- of resources in 9 sandstones of varying composition, gas and oil. We hydrated the most currently economic oil reservoirs for initial development, utilizing a 35 to 90 million barrel of oil equivalent range for these 2 oil reservoirs. We plan to initially develop this resource as a 2-well subsea tie-back that will start production in 2016. Using a 15 million barrel of oil case, we expect payout to be reached within 2 years of startup, with initial production of 37,000 barrels -- of approximately 37,000 barrels of oil equivalent per day.

My experience that once production starts and new information is gained, such as reservoir performance, and with developed infrastructure and innovative thinking, more of the discovered resources become economic. So there is significant upside production that could show up here in the future.

Our second sanctioned project is Big Bend, located in an integrated project area we call Rio Grande. Picking up on the scene from this morning, so far, at Onshore, we look the same way at all of our projects to maximize value. In this area, we have discovered a mean of about 150 million barrels of oil equivalent with 77% oil and significant upside. We intend to drill another prospect in the area called Hagerman in 2015, and the proximity of these fields will allow us to develop and with common infrastructure, another integrated project, enhancing overall returns. The developments will be via subsea tie-backs to our nearby processing facility.

Our Big Bend development underway consists of an 18-mile subsea tie-backs. Although the initial development is a single well, we expect upside resource potential will warrant additional wells and water injection for secondary recovery. What we learned at Troubador almost doubled our resource range at Big Bend versus what we had last year. Payout of this initial project is expected within 2 years of startup and has a 42% rate of return.

Early this month, we announced the Dantzler discovery. It has over 85% oil and 2 really high-quality subsalt Miocene reservoirs. Dantzler continues our string of referrals in the Rio Grande area, where our proprietary seismic reprocessing paves the way for the success. We're formulating our Reservoir Development Plan and incorporating Dantzler into the Big Bend development as we speak.

Since Dantzler is located between Big Bend and the potential host facilities, we'll be able to leverage the Big Bend infrastructure very quickly. We currently see this developed discovery as a 2-well development, with the first well coming online in 2016 and the second in 2018. Utilizing the Big Bend infrastructure enhances overall economics by reducing development costs and shortening the time to first production. You can see the impact of this project on the economics -- the rate -- the impact of this integrated approach in the economics where the rate of return is, basically, 100%, and payout is less than 1 year from startup in this initial phase. Note there's a lot of cases for our P75 cases or our minimum case and will only improve on a larger scale.

Now we'll take a look at our near-term exploration plan. We're currently focused on the Miocene trend in areas where we can, again, leverage common infrastructure. And this map shows our near -- our 2 near-term areas -- focus areas. First is in East Mississippi Canyon where our Rio Grande area is located. We're maturing 4 key prospects of about 365 million barrels of oil equivalent, with Madison planned in 2014. We expect to start exploring in the Aleutian's area next year, where we're maturing 3 prospects there with a combined gross mean resources of about 420 million barrels of oil equivalent. And we plan to drill Katmai first testing our concept. These 2 areas have running room, and as we saw in both the Galapagos and Rio Grande areas, exploration success will help to de-risk other nearby prospects.

As in the Onshore arena, we're leveraging ideas across the Offshore worldwide. Historically, we've leveraged our experience and activities in the Gulf of Mexico to enhance our global programs. In essence, we exported technology in place to support our efforts throughout the world. Currently, as you've seen, our program in Gulf of Mexico is delivering discoveries, which are turning into high-value development projects. And we're confident in our ability to meet and exceed safety and regulatory requirements. We're confident in our ability to drill safely and efficiently. We're confident in the ability of our exploration program to deliver. And we're confident in our ability to bring these resources to development quickly.

We see a bright future with a higher level of integration of worldwide place and innovative development, where we bring our global new ventures thinking back into the Gulf of Mexico, where we bring our innovative approach to development back into the Gulf of Mexico.

We believe that there are new venture-type opportunities in the Gulf of Mexico, and we believe that we have the expertise to find them. We know that successful exploration has a possibility of generating superior returns when done well. So we will continue to apply our disciplined exploration processes, testing only the best place and prospects.

Recapping, we have exceptional sustained exploration success in the Gulf of Mexico, greater than a 50% success rate since Noble entered the deepwater in 2001. And recently, we've had 3 successive discoveries. Double-digit production growth is expected over the next 5 years, consistent with Noble's overall growth. Our focus exploration strategy is expected to create over $1.3 billion value from our 4 most recent discoveries on a mean basis. And each of them having upside. And we have 3.8 billion barrels of oil equivalent of net unrisked resource potential on our current inventory, with 4 to 5 exploration wells expected to be drilled in the next 2 years.

Now to West Africa. West Africa is a story of long-term performance, exploration success, the company's first major project, sanctity of contract and strong returns, leveraged into a broadening regional approach. We've performed well since 1998, contributing relatively stable production to Noble through the whole time.

In Equatorial Guinea, our longest running international business. Noble is the only oil company that has maintained a continuous presence for over 20 years, making significant investments over this time period. In a country that honors its contracts, Noble has provided a growing base of value for Equatorial Guinea over those 25 years. And in turn, Equatorial Guinea has provided a growing base of production for Noble and has been a substantial part of our business. This had an exploration-driven program that has delivered exceptional returns.

Ken, again, talked about our returns by area. This is a capital-efficient area, providing some of the highest returns in the company. We like it. Over the past 8 years, Noble has taken 2 major projects from discovery to first production in record-breaking time. We had the foresight to build flexibility into the Aseng infrastructure, to accommodate future developments such as the land in Diega, significantly reducing capital costs by leveraging our facilities in an integrated manner.

We're holding conversations with stakeholders, governments, midstream companies and end users to investigate opportunities to accelerate delivery of natural gas into local petrochemical industries, including methanol, LNG, and ammonia urea.

In the Cameroon Tilapia license, we're looking at 2 alternatives for our 2014 obligation well: The Cheetah [ph] prospect, a slow-fan deposit in a large 4-way closure; and the Racia [ph] prospect, a Paleocene appraisal well to an earlier oil discovery with less upside and lower risk.

Over the years, we've created value by finding solutions to technical challenges. The first hydrocarbon production in EG was achieved by stripping condensate from the Alba field, a world-class discovery. Noble and our partners repeatedly found ways to create value from Alba natural gas by successfully implementing LPG, LNG and methanol recovery plant. Alba is the sole source for natural gas supply to power generation facilities to provide all public electricity on the island of Malabo.

We've expanded our legacy as uniquely creating value with the Aseng FPSO and the Alen liquids recovery project. This is where we prove our major project execution, as I mentioned, taking it around the globe. And we're positioned to capitalize on our expertise and experience and expand it into other highly attractive countries.

It is known that our purpose is to better peoples' lives and local communities by conducting our business in a safe and environmental-friendly manner. Not only do we better peoples' lives by expanding local economies through oil and gas investment, we're also committed to bettering their way of life through investments in education and health. You'll see more on this in Equatorial Guinea.

West Africa has been a solid and stable source of production, providing us of over $1 billion of annual before tax operating cash flow. Work is underway to ensure this cash flow remains for many years through the development of Diega and other nearby projects. Please note that the production rates for Diega are relatively conservative and may increase.

With the challenge of developing a world-class discovery in a basin with no existing infrastructure, again, we rose to the occasion and installed that first FPSO Aseng in the area. It was designed and built for success and has achieved over 99% average runtime, while producing 44 million barrels since production in late 2011. This achievement is only possible with real-time flexibility to change operating conditions and to maximize performance. The Aseng FPSO was built, again, with that future in mind, available to service storage facilities for land condensate. The availability of Aseng for storage and offloading Alen condensate has resulted in significant cost savings, which may be repeated as we develop other projects in the area such as Diega.

Storage and offloading crude and condensate on the same vessel is complex and challenging. However, we have operated in this challenging environment with only 1 lost-time accident over 1 million man hours worked.

Through world-class project management, Alen's first production was achieved in 30 months from sanction on budget. The project is returning significant value, with 3.5 million barrels of oil produced so far this year. The Alen condensate stripping facilities are massive, even by onshore standards, at over 25,000 tons. These 25,000-horsepower compressors provide, basically, 0.5 billion -- 0.5 Bcf per day of injection capacity, with over 24 megawatts of power generated on the facility.

And again, reinjecting has had a huge impact on our recovery in Alen and expected to in the future. Production has stabilized at about 28 million -- 28,000 barrels and is expected to increase to 30,000 by 2014, as we work at enhancing well performance, amongst other things, to keep continue to grow production. This success is accomplished with only 1 lost-time incident due to an equipment failure during construction. And there have been no safety incidents since first production.

In 2013, Diega appraisal work has been very positive this year and includes a Diega pile deposit, yielded 45% WI of net pay, with 23% average porosity and 37% water saturation. The subsequent lateral encountered net pay with a continuing nice numbers. And the net sand at 86% to 89%. The long-term DST confirmed the lateral continuity in the reservoir with no compartmentalization. We expect to sanction it reasonably quickly in 2014, with first oil production expected in 2016. And we are continuing to evaluate other resources and opportunities in the area to tie in.

As others have mentioned, one of the things that inspires and fulfills everyone at Noble is how we better peoples' lives, beyond developing hydrocarbons. And here are some examples from Equatorial Guinea where we have spent over $16 million in social projects over the last 5 years. These projects have included providing safe, clean water to people in villages; repair or construction of high school buildings, including supplies, desks and computer equipment -- of school buildings, regardless of high school, library buildings and books and children's park.

The malaria project has significantly reduced the incidence of malaria in Bioko island and includes support of a highly promising malaria vaccine. The maternal and child health care is focused on providing training for workers who will provide health care to pregnant women and their newborn children, which is a significant issue in Sub-Saharan Africa.

And the economic development project is assisting individuals to sustainably manage fishing and farming along the coast of the mainland.

Continuing on, we've looked for way to leverage our successes in Equatorial Guinea and Cameroon and to similarly situated countries elsewhere in West Africa. Of course, there are common geoscience trends across the region that allow us to extrapolate learnings from current areas, as well as from the Gulf of Mexico. And we believe that there are further underexplored opportunities for large discoveries.

Beyond the technical considerations, Equatorial Guinea and Cameroon experiences have taught us a lot about the character and cultures of the region and how business is best conducted in that setting. We're confident we have a team in place that can partner with countries like Sierra Leone, Gabon, and any other countries toward the accomplishment of mutual objective.

We're choosing new countries in the region that give us the commercial incentives and stability of contract that we need to take on the technical and operational challenges involved.

As I covered in the prior slide, we will continue to place high importance on making a positive difference to local communities, wherever we are in the region. And we're expanding our footprint in the area, in the Sierra Leone and hopefully, in the Gabon, where we were announced as the winner in the first phase of a recent bid round.

Noble is participating in a block operated by Chevron in Sierra Leone and in a geologically attractive area, supported by government, ranked as one of the most stable in the region. 2D seismic has been shot, and we're anxiously looking at the results.

So in summarize -- in summary, a new growth generally builds on past success. In the West Africa, we have a unique blend of experience, competency and accomplishments. We've demonstrated an ability to commercialize new basins. We built an infrastructure base in Equatorial Guinea that facilitates future bolt-on projects. And we developed expertise that when combined with strong partner-government relationship gives us the competitive advantage in this region that we consider to be underexplored.

Next, on to Keith.

J. Keith Elliott

Thank you, Susan. Good morning. It's my pleasure to be here with you this morning and having a few minutes to be able to share with you some of what's been accomplished in the Eastern Mediterranean in the last year since we met and to give you a few insights into what we have coming forward.

First of all -- we've got to control the slides. So we've discovered approximately 40 Tcf of gas. Our resources have grown in the past year. We'll talk a bit more about that. Also, Gary mentioned earlier in his talk that we're about delivery, and we've delivered Tamar. Flawless execution in project management has followed on with flawless operational performance. We'll talk some about that. And thus led to record gas sales in Israel in 2013. Tamar has averaged 750 million cubic feet a day since startup. We are continuing to see growth in both the Israeli domestic market, but more interestingly and more excitingly, we've seen new growth beginning to emerge in the region for regional exports. And we'll talk more about that.

The exploration program in the Eastern Mediterranean region continues to be robust and continues to evolve, and most interestingly, it begins to have much more of a proportion of oil as part of that resource base that we're prospecting for.

Finally, our -- we've generated strong cash flows. Our cash flows from Tamar happens to support the next wave of exploration and development projects in the region.

Okay. So a little bit about the resource progression there. We've had a continuing good year of exploration and appraisal activities. Appraisal activities at Leviathan have resulted in growth and resource in the Leviathan field to just at 19 Tcf, really a world-class resource by any measure.

We've had additional discoveries. Earlier in the year, we announced a discovery at Karish, prospect north of Leviathan. Almost 2 Tcf of discovered resource, but most interestingly about Karish, we found a different environment in terms of condensate yield and liquid properties, which really gave us more insight into the deep exploration potential for oil. And that, combined with some work that Mike will talk about later on, lead us to become more confident of the oil prospectivity in this basin.

Following on from Karish, we drilled an appraisal well in Cyprus that appraised our initial discovery there in Block 12. We refined the resource range through the activity there and most significantly, we verified the quality of reservoirs that are similar in productive capacity to what we see in the Israeli licenses. And we've extended the western extent of those reservoirs in that productive capacity into the Block 12 EEZ.

And finally, most recently, we've announced the Tamar Southwest discovery, where we've discovered a mean resources on the order of 700 Bcf. Tamar Southwest is about 8 miles south of the Tamar field. It's very similar in reservoir quality to what we see in Tamar. At 700 Bcf, it's about 90% the size of the Mari-B field, to put it in a bit of perspective there. Its location makes it an ideal tie-back to the Tamar field infrastructure, and we see it as a key resource that supports the expansion of Tamar and the continued supply of the Israeli domestic market from Tamar resources.

The Noble, as a company, have internally sanctioned the project, and we're now working with our partners and with our regulators to solidify final approvals to move forward with this project, with the anticipated first production in 2015 in conjunction with our Tamar expansion program.

Speaking of Tamar, this is nothing short of a fantastic story. Tamar, as you've heard, came on production 2.5 years after sanction, but that was really kind of just the beginning of the story. Since it's easy to stand here and say, we've had nearly 100% uptime, and you've seen that in the number in the presentation today. To put it in a little more context, since we started production in the end of March, Tamar has had a total of 6 hours of downtime. 3 of those hours came in the first month of production while we were still commissioning the plant. The longest single period of downtime we've had has been 45 minutes. That's what we call the definition of reliability. And what that reliability has allowed us to do is to achieve this record performance. In the month of December, Tamar has been able to supply the Israeli domestic power generation market, as we displaced coal plants during their annual maintenance period. In the month of December to date, we've averaged 700 -- or 893 million cubic feet a day of production. In the past, we -- Tamar has set a production record of 930 million cubic feet a day, with a single-day record of 985 million cubic feet a day, that equates to over 1 billion BTUs of gas we sold in 1 day.

That's the definition of operating performance. We're now moving on beyond that to expand Tamar, to take Tamar to the first phase of expansion, which is a 200 million cubic feet a day expansion in the form of onshore compression or Ashdod Onshore Terminal. That project is underway. It's on schedule, on budget. We expect it to start up in mid-2015 and supply the growing demand that's emerging as part of the Israeli domestic demand. And we see further projects coming that we're working with our partners and our regulators to approve, to take Tamar toward an ultimate expanded capacity of about 1.5 Bcf a day.

With respect to the Israeli domestic demand, we see that gas demand continuing to grow as natural gas continues to become the fuel of choice for the Israeli domestic market. Our number of customers have doubled in the -- since last year when we were here. A lot of that expansion is coming in the form of new independent power producers coming onto the markets, as well as the growth of local distribution companies. Gas in Israel is becoming much more of a retail commodity. And you're seeing that taking shape in the form of these local distribution companies.

Finally, coal plant conversions are underway. The first conversion is underway now. They're going to be online in the end of 2016, and we expect additional conversions to be following.

When you take all that in aggregate, you'll see that the next 5 years, we expect Israeli domestic demand to grow at a compound annual rate of 17%. That doesn't take into account some of the additional smaller scale opportunities that we see forthcoming, that you see where gas is becoming more of a -- an application for -- as a motor transport fuel, as well as petrochemical uses in desalination activities. Toward the end of this decade and into the next decade, we see further coal plant conversions leading Israeli domestic demand toward 2 Bcf a day.

So that talks about the domestic demand. I think we'll move on next to look a bit at what the export market looks like. But one of the key elements of the export market that everyone's seeing in the press for the past year has been how much gas was going to be approved and when is export going to be approved for Israeli gas.

In mid-2013, the Israeli Cabinet approved an export policy that authorized the gas exports. That policy was upheld by the Israeli Supreme Court, following legal challenge. That upholding took place in October. And basically, what it means is that roughly 40% of the Israel's discovered resources are now exportable to regional and extra-regional markets. The bulk of that, of course, comes from Leviathan at about 9.5 Tcf. The table you see on the chart shows what the allocation resources is for each individual field by field size. I think that the key takeaway for -- from this is when you combine the authorized Israeli domestic volumes for export, along with what we have discovered in Cyprus, there's approximately 19 Tcf of gas in the Levant Basin discovered to date that's available for export to both regional and extra-regional markets.

As I said, the bulk of that supply for export markets comes from Leviathan. Leviathan has continued to grow in size. Big fields get bigger. This one's no exception. Leviathan now stands at 19 Tcf. We expect Leviathan will be developed in multiple phases to service both the domestic and export markets. And we're currently working with our regulators and with our sales customers to refine the market demand, to solidify export and domestic sales contracts and then to secure the regulatory approvals necessary to proceed with Leviathan development.

For us, we see Leviathan as the key linchpin in providing a source of enhanced reliability and security of supply for the Israeli domestic market and underpinning a very robust export market, both regionally and beyond.

As I say, we expect to see Leviathan develop in multiple phases. First and foremost, to supply Israeli domestic demand, but also with multiple phases of regional export, we expect the initial phase of Leviathan to be an 800 million a day facility that will provide that Israeli domestic demand and pipeline export to nearby regional markets. We expect that it will be followed on by an LNG phase. Our current view is that of a floating LNG project, and we'll talk a little bit more about the work that we've been doing around floating LNG developments over the past couple of years. And we expect to follow phase of a 1.6 Bcf a day FPSO aimed at supplying the -- that growth in the domestic Israeli market that I mentioned earlier, as well as expanding regional markets. And we'll talk a bit more about that. Expect initial production from Leviathan to come on in the second half of 2017. I think it's important to point out though that the sequence in these phases is really driven by growth in market and market security. So for example, if we see the acceleration of contracts for regional supply to sufficient scale, that FPSO could come ahead of any LNG development, and regional exports could take an earlier role in Leviathan monetization.

So let's talk a little bit about the regional markets that we see. In aggregate, we see the opportunity for regional pipeline exports for Levant gas to be on the order of 2.5 Bcf a day. That comes in a variety of markets. Jordan, we see industrial power and industrial demand on the order of 300 million to 400 million a day. As most people know well, there are LNG plants in Egypt that are well undersupplied now, about 2.5 or little over 2 Bcf a day of LNG liquefaction capacity sitting in Egypt of which 25% is currently utilized.

Within the Cyprus domestic market -- and we'll come and talk more about Cyprus in a bit, but in the Cyprus domestic market, we see a demand on the order of 60 million to 100 million a day.

And of course, Turkey sits out there as a very large potential market that we see existing now with up to 1 Bcf a day of upside by 2020.

Several of these markets are accessible now by existing pipe; notably, the existing pipe connections between Israel, Egypt and Jordan. Our opportunities are easily and relatively, quickly able to be brought online, followed on by expansion of pipe lay, both in that region and more broadly, in the region between Cyprus, Turkey and Egypt.

Initially, these projects and these demands could be supplied by Tamar interruptible capacities, followed on by Tamar expansion and ultimately, by Leviathan and other fields development. Some of the markets that require pipe lay will take a bit longer. The interesting thing about those markets is we've actually been approached by a number of our -- a number of potential customers to engage in either laying pipe to us or to engage in joint investment in infrastructure to take volumes outside the existing fields into those markets.

For us, this is a really exciting and really unique opportunity for bringing together a world-class resource in a part of the world where there's a regional demand that genuinely could energize the world and better peoples' lives. So this is actually a place where I'm personally very excited about what might be possible here.

If you look beyond the regional export opportunities and look at the extra regional, what I call extra regional are global LNG opportunities, Levant Basin reserves and resources are well placed to compete on the global LNG market.

This chart shows the balance of supply and demand expected out through the end of this decade and into the next. And the table on the -- the graph on the right shows the cost of LNG supply. That's cost of liquefaction and cost of transport from a variety of competing LNG sources of supply. This table excludes the upstream development cost. As you can see, the Levant Basin LNG cost of supply is competitive on a world-scale. And when you include upstream development cost, it becomes more competitive.

I mentioned floating LNG. At Noble, we've been working on floating LNG developments for a couple of years in earnest now. We've gone through a number of pre-FEED activities. We've participated in quite a significant engineering design effort. And we've become comfortable with the application of floating LNG in this market. Through the work that we've done, we have much better understanding of the technical challenges. We've had the opportunity to work with a number of key contractors who have and will play a big role in any FLNG development in the future, and we've become comfortable with their abilities to design, construct and deliver these kinds of facilities. A number of those suppliers have expressed a strong interest in working with us and have formed consortia to work with us on several of these projects where FLNG would be applicable.

And finally, there's some interesting commercial frameworks for the rest of the supply that are developing. And we continue to develop that structure of commerciality of these kinds of projects. We've begun marketing some of the LNG opportunities and we continue to be working this going forward.

Moving beyond Israel and moving beyond Leviathan, I'll talk briefly about Cyprus. In Cyprus, we have been working primarily toward the development of an onshore LNG plant at what we've identified as a world-class site at Basilicas on the south coast of Cyprus. We've completed a pre-FEED study over the first course of this year, which has confirmed the validity of that site. We believe that additional resources are going to be required to make that site go forward. That's part of our ongoing exploration program, we'll talk about later. We also see that there's opportunities for that additional resource to come from other companies exploration in the Cyprus EEZ or from the movement of Leviathan gas into Cypriot waters.

However, we also see that Cyprus is a candidate for floating LNG development now. We believe that the resources that exist are well placed to support a floating LNG development. We also see existing opportunities for Cypriot gas to be monetized through that same set of Egyptian LNG plants that I mentioned earlier. So we'll see multiple opportunities for Cypriot gas to be monetized, and we continue to work with the Cyprian government with our partners in bringing those opportunities forward. Our exploration programs are a key part of that.

So what does all these add up to? It adds up to a continuing stream of development projects playing out over the next 8 to 9 years of -- starting with Tamar, and Tamar expansion, followed on by Leviathan and the multiple phases of Leviathan as we meet market demand, and then following on from that with Cyprus. As I said, the phasing of these projects may shift a bit, but you can see that there's a continual stream of project activity that is really underpinning our growth agenda. And that growth agenda looks like what you seeing at the bottom left panel there, where we have continual year-on-year growth of production from Cyprus and from Israel over the next decade. That looks like a compound annual growth rate of 21% over that 10-year timeframe, which is accelerated when exports come online in 2018 and then begin to really ramp up in the 2020 timeframe.

Again, it's important to point out that regional pipe export opportunities could accelerate this export profile from what you see here.

What does that look like then in terms of net impact to Noble? Over the next 5-year timeframe, we see a 23% compound annual growth rate in our net production, driven largely by Tamar's annual growth and then following on with the start of export at the end of that time period.

That then results in strong cash flows coming off Tamar and then supports reinvestment at a significant level within this basin, while yielding free cash flow beginning in 2015.

So that's what we're doing in the world of developments. We'll talk a little bit about exploration, and I won't steal Mike's thunder, but just a little bit from my perspective. We continue to be very excited about the exploration potential in Levant Basin. I think the thing that's probably new for this year is we see a growing likelihood of exploration potential being oil versus what we've seen in the past. We've seen multiple opportunities both in Israel and Cyprus.

A couple of the other thing that's new this year is we see the Cypriot Block 12 is having a much higher proportion of the exploration potential than what we've attributed to it in the past. As most of you know, we recently acquired a 3D survey over the bulk of Block 12 over the course of the summer. We're just now beginning to get that data in and processing it, and our exploration plans will be refined as that processing continues on.

And we have further Miocene gas to prospect for, primarily in Cyprus. Again, that's part of the evaluation of that ongoing 3D survey. But Mike will say a lot more about this. I will just leave it to say that Levant Basin really continues to be a great ZIP code for explorers.

So as we're pursuing the development and next phases of exploration and next phases of development, we continue to pursue strategic partnerships that can help bring value to our resource base. We continue to work with our existing partners, in particular in Leviathan to -- and with the Woodside, to bring this Leviathan format agreement that we announced last year to a close. All parties are actively and sincerely engaged in negotiations and are targeting a structure that allows us to recognize the increased value that we see coming forth from Leviathan.

As everywhere we operate, it's important for us at Noble to do more than just produce oil and gas. It's important for us to live our purpose. In the Eastern Mediterranean, that means growing our local workforce. 80% of our workforce in both Israel and Cyprus are Israeli or Cypriot nationals. We are engaged in projects in both countries that promote education, that promote the growth of technology and really underpin what we expect our long-term presence there to be.

In the very near-term though, we see ourselves -- we see gas as being the fuel of choice, having very positive societal and environmental impacts in Israel.

We're contributing over $145 billion over the life of Tamar in energy savings and revenue to the state of Israel and its people.

In addition to that, gas is displacing imports of coal, imports of fuel oils, and most significantly, gas is really helping to reduce emissions in the region to the tune of 215 million metric tons of CO2 over the life of Tamar, which is the equivalent of taking all the cars in Israel off the road for 16 years.

So for us, it's important to do something beyond just being a hydrocarbon company. It's important to leave something that's a positive impact on the societies where we operate.

So in closing, we're working to monetize a world-class resource for domestic and worldwide demand. We have seen the Israeli domestic demand grow and it continues to grow, and we expect it to grow to the point where it exceeds 1.5 Bcf a day by 2015 -- by 2018. We continue to work the planning and preparing for execution of Leviathan development. We've seen multiple options for Leviathan monetization emerge, led in large part by the realization of regional export markets and how those real -- those regional export markets are coming to fruition. We have a tremendous base to work from. We've discovered nearly 40 Tcf of gas, and we have roughly 19 Tcf of that gas that's available for export to both regional and extra-regional markets. We see exports reaching 2 Bcf a day in capacity in the next decade. And we continue to explore. We continue to be very excited about the potential of this basin. And all that adds up to a decade of growth coming forward, where we grow year-on-year from net production of 200 million a day in 2013 to 600 million a day in 2018 to over 1 Bcf a day by 2023. So fantastic place to be working and the tremendous opportunity we're all very excited about.

So with that, I'll hand over to Mike, who will talk to you more about exploration and where we go with that. Thank you.

Michael W. Putnam

Well, thank you, Keith, and good morning, everyone. I'm Mike Putnam. Turning to exploration, last but not least, I'd like to begin by characterizing Noble's program with these key attributes. A great track record of success over the last decade in both proven and frontier basins. A program that is deliberately designed with an eye on sustained growth, and underpinning that is a highly confident and subsurface organization that has strong ownership in the company outcomes, and they're fully accountable for the full life cycle of the asset.

Looking forward, there is a robust inventory of prospects with a multiyear plan of execution and currently, that inventory is about 2.8 billion barrels of net risked resources. And later, I'll give you a view of the activity we have planned for the next 24 months.

And lastly, a key component behind our ability to deliver new core areas is a dedicated global new ventures team with a focus on both conventional and unconventional opportunities. Those are 2 teams.

Thank you. There we go. So looking at the track record, year-over-year, the program continues to be a material driver to resource and production growth. Almost a decade ago, we shifted this exploration strategy to focus more on material prospects and plays with running room, you've heard Susan talk about that over the years. And we're seeing the benefit of that now.

We discovered over 3 billion net barrels since 2005, and the key discoveries in that timeframe are expected to contribute about 170,000 barrels per day by 2018. You can get a sense of the cycle time there from the middle of that red graph to the beginning of the blue, relatively rapid discovery to production.

And the successes in this timeframe has created approximately $16 billion in before tax net present value.

So this is impact that continues to lay our own support for the company's double-digit growth.

And Noble stands out when benchmarked against other leading explorers. And here, I want to share with you a recent external view published by Wood Mackenzie in August of this year. This is a 10-year look back at exploration performance among 33 leading explorers, both large and small. We are ranked in the top 10 in the 6 key metrics we're showing you here. And I think this is indicative of our consistent exploration performance over a long period of time, and with a well-balanced portfolio -- a diverse and well-balanced portfolio. Clearly, 2 key differentiators here that I'm proud of. Number one, the discovery cost. I think that speaks to both the technical and the financial discipline, again, the focus on more material prospects with running room, as well as low entry cost and funding cost. And our success rate, number two, whether it's overall or commercial, it stands out above industry average. The Wood Mackenzie numbers from that study are shown there on the right side of that graph, and I'll refer you to that report for more detail.

I mentioned the subsurface organization earlier. It's made up of integrated teams, both engineering and geoscience professionals, and they're mostly embedded in all the various business units across the company. We really focus on building bench strength to deliver scale and scope for the future.

And here, I'd like to talk a little bit more about the geoscience part of that. Nearly half of our geos have at least 20 years experience. And we have a good split, as you can see there, between early or mid-career professionals and young professionals. And the latter, mostly, are recruited off-campus and trained by Noble. And on the right, you see half of the total resources are focused on exploration and new ventures. I think what stands out there, too, is a third, and I'm talking about the red part of the pie chart, a third, our focus on post-exploration phase, delivering our major projects. So there's a lot of effort going on in subsurface and geoscience on these major projects, and back to the integrated approach that Dave talked about earlier.

We also have a core team of technical specialists with critical expertise in areas such as petroleum systems, petrophysics, geochemistry, geomodeling and petroleum systems. And the list goes on. These specialists are global in their scope and they are top-tier in the industry.

So a little bit about the process. You have heard us talk about this before, but I'd like to reemphasize it. We are consistent and disciplined in the technical process for all assets, no exceptions. We started a decade ago with exploration excellence, which is that XX in the second box there. It now covers all phases, from pre-capture through appraisal and subsurface development. And again, an integrated approach over the life cycle of these assets, with everyone accountable for that. The processes are interdependent and leverage diverse thinking and the best experience in the company. We've really become -- the process has really become a resource for the project [indiscernible] value. And I'll say that we're relentless about tracking our predictions, and there is follow-up so that we can constantly learn from our performance.

So let's take a look at a global snapshot of what we've accomplished in 2013, and you've already heard pieces of these. Overall, it's been another successful year. We made 4 new discoveries between the Gulf of Mexico and the Eastern Med. We also have successful appraisal wells in each of those areas.

In other activity, we started drilling the Northeast Nevada play, and I'll share some preliminary results with you on that in just a moment. We drilled the first deepwater well offshore Nicaragua, and I'll give you an update on where we stand there. And in the Falklands, the play is maturing and we've got a third 3D survey underway as we speak.

And finally, we're building our position offshore West Africa with a new project, as Susan alluded to earlier.

And so what to expect from exploration the next 24 months? Here's an updated schedule over what we've shared with you in the past. These are most likely the drill options being planned through 2015 and overall. As you can see, it's an active schedule, both core area and new play exploration. And the maturation level there on the right is driven primarily by how advanced the technical work is, as well as how confident we are that we have risks and resource prediction properly filed in. So that's new on the schedule over what you see. Obviously, this could be fluid, so you'll see updates from us on this from time to time throughout the year.

So let me take you through a little more detail on some of the key projects.

Starting with the Deepwater Gulf of Mexico, as Susan mentioned earlier, the Miocene trend, and talked about why we're excited about it. Over the years, we've acquired a number of these prospects and lease sales at a 100% working interest and then progressed them through maturation. And as you saw from some of our recent drills, Dantzler and Troubadour, we've brought in partners to help reduce capital and risk, and that's what we'll do here with Madison. So it's likely the next Miocene prospect you'll see us drill in the first half of next year. It's located not far from Galapagos fields and our Big Bend discovery, so possibly, some future synergy there. The trap is a 3-way closure against salts and it's actually under a salt overhang that's been imaged with proprietary depth reprocessing of 3D. The primary objective here is the proven reservoir at our Galapagos field, which is the M55 [ph] sands. So we're excited about that. It's got a nice upside of 135 million barrels gross un-risked, and it's drill-ready for early next year, and I'll say there's more coming behind that one.

So another drill-ready candidate for next year is the Katmai prospect in Northern Green Canyon. Here, the target of the lower Miocene, as opposed to the middle Miocene on that prior one. And this is a new target for this area of the Gulf of Mexico. The prospect is a well-imaged, 4-way closure under salt, with some upside in the 3-way closures around it. And we have put a lot of technical effort into this imaging project up here. It's very complex. And this one -- and if this one is successful, this prospect opens up some additional possibilities on our acreage in the area.

So turning back to the Eastern Mediterranean. Keith said, we've continued to put a lot of technical work in understanding the deeper basin and the potential for a Mesozoic oil system here. So building on what Keith mentioned earlier, we're now recognizing multiple opportunities, both Israel and Cyprus, and we see the trend potential on the order of 3 billion barrels. We're really encouraged by the observations that we've seen that hint at the presence of a deeper thermogenic petroleum system, so a liquid system. And this comes from extensive geochemical analysis of gas and condensate samples on all the wells -- in all the Noble wells in the basin, every one. The success of the structure beneath the Leviathan gas field, which is shown here on the slide, remains our top pick of the first test of this play. And success here, obviously, would significantly de-risk additional prospects and I think create a step change in the basin.

The prospect is a large closure against a basement feature and it does have a material resource range. And just a note on the resource range shown here. It does reflect an updated analysis where we removed the gas from the model and saw an uplift on the liquid side. So this is a revision over what you've seen previously. And I'll also note that the resources in your book are probably still showing as equivalent. I just want to remind you that we expect this to be 100% oil.

So our current plan is to bring a rig back into the Eastern Med in late 2014, and right now, the timing on this prospect is early 2015, as we've said.

Keith mentioned exploration possibilities for Block 12 in Cyprus. And this is an example of some of the additional opportunities we're working on there. We do expect to see multiple prospects come out of the new 3D we just acquired there, and that's still in the processing phase going to depth imaging into early '14. But we expect to see both Miocene gas and deeper well possibilities.

So turning to Nicaragua. As you're aware, we drilled the first deepwater well there. Earlier this year, testing a new frontier play concept. Clearly, we're disappointed by the outcome of the Paraiso well. We did not find oil. We did find the carbonate reservoir we predicted, and we did observe some shale as well, drilling the well.

In short, we learned a great deal from the data collected in the well, and we will use that to assess the potential of the additional opportunities that we see on the acreage position there. Again, a quite large acreage position. And these include a very large and older feature located southeast of Paraiso that we call Gordisimo. And you can see it there on the southern part of the acreage block. So stay tuned on that one.

What's happening in the Falklands play? We continue the technical maturation on our 10 million-acre position there. And just as a reminder, this is a vast area we're dealing with. For reference, the distance across that acreage from end-to-end is about 400 miles. And the 10 million acres is equivalent to over 1,700 Gulf of Mexico leased waters, which I continue to find impressive, having spent a lot of my career in the Gulf.

We've acquired a large amount of 3D already, and we're currently shooting in that northern area, as shown on the map. We're focused on 2 play types. The main one is the Cretaceous submarine sand play, and these are both -- this is going to be both basin floor fan and slope fan types. And these are ramping up to be quite large. These will be similar to those seen along the Atlantic margin, for example, off West Africa, and that's one of the reasons we're excited about this play. There is also a tilted fault block concept with a proven petroleum system in that very southern area there, as shown on the map. And I should also mention that operationally, we have established a presence there in the Falklands and have begun work on support facilities, and we're also working on a plan to secure rig resources for 2015.

So on this slide, I'm zooming down a bit into that Fitzroy Sub-Basin in the middle area on the last map. And this is a large area in itself. That 3D outline there in blue, the box, covers over 2,000 square miles. And we need to complete the detail work on our new 3D to mature these leads. But the team is excited about what they're seeing so far. And this is likely the first drill candidate shown, we call it the Diomedia B-1 prospect, and it's that orange area outlined there with the label on it.

And the resource side shown is just for that orange area shown. In keeping with our strategy, our success here can de-risk a number of additional prospects on the acreage. And so spud date there is estimated in the first half of 2015.

Okay, finally turning back to the onshore and our new unconventional play that we've been working on in Northeast Nevada. It's a large acreage position we've put together starting in 2011. The map on the right shows the 3 sub-basin areas outlined in blue that we're focused on and where we have acquired proprietary 3D, those are the red boxes there. And the resource potential shown is for the entire position. We're just finishing our second vertical well in that middle area we call Humboldt, where the green flag is. And at this point, we can share some additional drilling results and say that we are encouraged by what we're learning so far.

So in the first well, we encountered about 700 feet of the primary target that we're exploring for here. And that's the tertiary Elko formation, we call it. And within the lower portion of the Elko, we have a potential sweet spot. It is about 400 feet thick, so a nice thickness, and it's dominated by organic-rich mudstones and shales. These are dark shales.

We have strong oil shows during drilling through this interval, including live oil in samples and from early sample work, and this includes sidewalk course cuttings and fluids. We're seeing some good oil saturation up to 70%, a source rock that is thermally mature and the peak oil generating window in very good total organic content, or TOC, averaging so far around 7%, but up -- we've seen it up to 24% in that first well. And as a reference, you can see there that the Niobrara generally ranges between 2% and 6%. So good TOC. Initial oil quality estimates are as we expected, but it's early. Further tests are going to be needed there. We call -- we expect this to be a Uinta-type crude.

We are close to finishing the second vertical well a couple of miles away from the first one. And it was placed there just to confirm presence of the aforementioned and to cut a conventional core. And as we speak today, we're just beginning to cut that core. So again, we're encouraged by these early results. And looking forward, we have a significant amount of data, obviously, to analyze from these 2 wells. Success here is really going to be contingent on additional drilling and testing. And so delivery, obviously, the key unknown at this point. So we'll be conducting some flow test in the second quarter of next year. And then we plan to do more exploration pilot wells in the second half of 2014 to address those other areas.

[indiscernible] transition there. So I'd like to leave you with these final comments. I'm excited to be on this team and I'm excited about Noble's future. And exploration is going to be a key contributor to that future. We have a track record and we have -- of discovery success, and we -- and turning that value into production impact quickly. We plan to test about 850 million barrels over the next couple of years, and that's net-risked resources. We have about 2 billion barrels in inventory behind that. We are uniquely designed for both conventional and unconventional success, and I think, well-positioned to deliver on our strategy of creating growth opportunities over the long haul.

So thank you, and I'll now turn it back over to Chuck.

Charles D. Davidson

Well, that was a lot to cover, I know. You've been very patient as we went through our plans this year. It's a -- I would say that through all the years and going through a number of these conferences, that it never really soaks in until you see it, that final time when everybody has got the words put together and everything comes together and it's just an amazing, amazing story. And so congratulation to, again, everyone who worked so hard as part of the Noble Energy to put this together and our speakers this morning. One thing I just wanted to mention, because it's -- not all of you may be aware of it, but earlier this year, we went through a significant change in our leadership. This was really part of building depth in our organization, broadening some of our senior leaders and management. And so if you look at the team of presenters here, the first 3 of us, obviously, our jobs didn't change, but the next 6, all of them have taken on either expanded leadership or completely different roles since roughly about April of this year. So when you think about Gary Willingham who've moved from Strategic Planning to heading up our U.S. Onshore Business; Dan Kelly who expanded his role to the full DJ Basin; Donnie Moore who moved from the DJ Basin to the Marcellus; Susan, more than a decade, Global Leadership of Exploration, taking on Global Deepwater Operation; Keith Elliott, who is major -- heading up our major projects, Drilling, Supply Chain, now heading up Mediterranean; and Mike Putnam, stepping up to Head of Exploration. So this would've been a year we could have said, well, we need to take a timeout so we can get our -- catch our breath and let everybody get up to speed. But you know what, that would've been a failure. And so what I take away from this is the depth of our management, the depth of our leadership that we can put together, continue the momentum, the growth, the acceleration, the programs in Noble Energy, and do it with a team that has changed roles, but at the same time, has one thing in mind, and that is the success of Noble Energy to make sure that we succeed as a team. And so it's been a fabulous success story and, again, it's all about delivering results and doing it in the right way.

And you saw this all the way through our presentation as you talked about living our purpose. And as I said at the beginning, it's you can't just do with, you got to do it right. And in today's world, corporations have to do it right. They have to do it in a transparent way because in many places, that is your license to operate. Many places in the world, it's license to operate. And we know that by doing it right with performance we've had in both -- in certainly in living and delivering our purpose, it's open the doors to opportunities in many's places. And that's what's created some of these opportunities that we're showing you today.

I've commented in the past, really, this is something I've not experienced before in my career. And that is a situation and an opportunity in a business that, first of all, over the past 10 years, has grown tenfold in value. In 10 years, Noble Energy has grown tenfold in value. That's about delivering value to all of you, our shareholders, those who support us. But it's also now, a company that even after that 10-year, that decade period, has this fabulous decade in front of it of double-digit production growth over the next 5 years, 18%. And a company that now has 75 years of discovered, unbooked or proven resources in an inventory. So that's what makes us unique. That's what gets me so excited. That's what I think creates a lot of opportunity and potential. And I'll tell you, sometimes, it's a bit overwhelming because that's a lot of change, it's a lot of moving pieces. As you can see, our business has grown and expanded, but we got it -- we've got the team that can deliver. We really have the team that deliver and it's one that continues to grow and move forward. So I'm really excited. I've got a couple of slides here at the end and, of course, I never stick to my script when we wrap these things up, but I will just say that we started with our vision, we live it everyday. It's not just a statement. There's a lot of companies that have vision statements and they stick them up on the wall and say, that's our vision, and then they forget them the day after they create them. To me, the real key is to move from a company that has a vision to a company that's visionary. And visionary companies are the ones who constantly embed their vision, their purpose and their values in everything they do, everyday, and that's what we're doing at Noble Energy. And I believe that visionary companies are the ones who become not only successful companies, but enduring companies. And that have the ability to accomplish amazing things, but, again, as I said at the beginning, also have the ability, at any point in time, have an amazing future in front of them. And that's what we're all about. All about creating the future. All about creating an amazing future for all of us. So it is about being unique. And again, no accidents here. Hopefully, you saw these things pop out as we went through the presentations. And, of course, they're all intended to create and deliver a very unique feature for all of us that's associated with Noble Energy.

It's an exciting future. It's one that not only includes dramatic growth, but many accomplishments all -- along the lines of delivering our purpose. Nobody's crystal ball is perfect. We've shown in the past, we have to be flexible. We have to adjust. We can't predict the world perfectly. But I think with the portfolio we have, with the diversity we've had, with the skills we have, with the financial resources we have, with the technical staffs and human resources we have, we have the ability to adapt, change, and as I noted in the beginning, deliver on the plan. It's what it's all about, delivering on the plan. Whether it was the 2010 plan that we've now delivered a large portion of it or delivering this plan, which we'll continue work to deliver every year from now through 2018.

So I think we've got what it takes to deliver.

Also, I just want to say for everyone here, thanks for your support. We have shareholders. We have those who are working on the sell side that work night and day to help make sure that they get the story right and really help to communicate Noble's story to shareholders throughout. And I really appreciate it because we will learn a lot from all of you. I greatly enjoy going out on the road and visiting with shareholders, visiting with the research side on it to really understand things that are going on, areas that we need to improve on because whether you realize it or not, it's your feedback that helps us continue to improve and grow as a company. We're not silly enough to think we just create all these things on our own. We learn from others. The key on -- in any business is to absorb all that, assimilate it, put it together, make sure it's in a sound strategy, good package and then deliver. So again, thanks for your support.

With that, we are straight up at noon, and I think we're set up for some Q&A. And again, we're not running out of here. So I know some of you are good at working the brakes. Like I told somebody earlier, I said, I think I just -- after they started the show, before we started 8 o'clock, I think I just went through half of the Q&A as everybody looked at the books. But we'd love to answer some questions here while everybody's together. Also, we'll be staying and there'll be a lunch that will be available out there, and a number of us will be out there to answer any individual questions you don't want to cover as part of the group. But we've got microphones and I'd love to take some questions or redirect them to the experts over on that side of the room. We'll go there and then we'll go here.

Question-and-Answer Session

Unknown Analyst

Just a quick question about your 2.6 billion Boe of potential you brought on the Niobrara DJ there. I was hoping you can kind of help us just frame up some of the big picture assumptions around that regarding average spacing, what you guys are assuming on the various zones, whether it's A, B, C in Codell?

Charles D. Davidson

Great. I'm going to let Gary talk a little bit about that because it's evolved a little bit since last year, and you can steal some things on it.

You'll probably recall in the pack, there's a data table. It was the last slide that I presented on the DJ that gives you details on 5 of our IDPs and it shows the assumptions for each one. So it showed the average EUR for each area. It shows how many normal linked wells we have remaining in a normal well and Wattenberg is between 4,000, 4,500 feet. And then it shows the capital metrics and so forth. All of those are shown at 40-acre spacing, and as we talked about, we're testing 24 and 32 wells per section across the field, so it could likely go up from there. But if you can work through those IDPs, then you should get close to the 2.6 billion barrels. As far as what zone it goes to, our 16 wells per section is really 16 wells. It could be B and C in some areas, it could A and B in other areas. It could be a mix of A and B and Codell and in other areas still. So all parts of the field are a little bit different. We feel like with the patterns -- various patterns we've been testing though, that we can access and produce from, really, that entire 300-foot section wherever we are in the field. So hopefully, that helps.

Unknown Analyst

Chuck, it's [indiscernible] from Bank of America. Chuck, my question's on the production profile. You've obviously given us 2018. I just wanted to be clear, is Leviathan and Dantzler are 2 of the big slugs that step you up in 2018. Is Leviathan already included in that or is that an add-on given the project status? And I guess, if I could double up here, the front end of the curve doesn't really change too much despite the step-up in capital, so I'm just curious as why not a faster pace in the Wattenberg given the depth of the resource you own [ph] today?

Charles D. Davidson

Yes, on the production curve, yes, when you get to 2018, you get contributions from Leviathan. It is only domestic and regional export that's part of that, so you don't have any LNG in 2018. In fact, there's no -- through 2018, we don't have any LNG for West Africa or for Mediterranean. So that's the piece there. Dantzler is a little bit of late breaking news, so we've kind of got it in some of the numbers there but it probably would've been risked before and maybe it's unrisked now, so there's a little bit of derisking in that, but it's kind of more blended in with everything else, so it's not going to be a significant thing. When you look at the near-term production profile, what we have to be very careful, especially in the Niobrara, is not getting ahead of infrastructure. And that, to me, I think the area that we have been very cautious about, especially in 2014, and that is that we've got -- I think, we've got now a good plan. Dan, Gary, talked about the infrastructure and growing infrastructure there, but it takes a couple of years, especially in gas processing, so it all has to be sequenced together. So that's been the area that we've had to be very careful on. So you're exactly right. When you look at the DJ Basin, it's in the later years where we've pushed the well counts up and pushed some of our investment levels up because we believe we're in good sync at that time with the infrastructure. So that's just part of the plan. And if we could turn gas processing plants on overnight, we would do something different because you obviously saw what the cash flow looks like coming out of the DJ Basin. There's a lot of cash flow there. But it doesn't do any good to sink money in the ground that you can't produce. So that's what it's all about, making sure you got a good integrated plan. Also, part of it is, and certainly, I'm going to go out a little bit on here. So I'm watching over here to I make sure I don't get -- but we're -- as we invest in some of the facilities for these integrated development plans, we need to make sure we've got those in place as well before we start doing a lot of mass factory drilling in there. So it's a lot -- it's all part of a strategic plan, but it's closely integrated with infrastructure, making sure we've got the ability -- takeaway ability for the gas NGLs and oil associated with it. Let's see. Let's -- right down -- yes, we'll go there and we'll jump around a bit. Yes.

Unknown Analyst

In the case of map of marketing Eastern Mediterranean gas, we get into a lot of political questions. But one of those dashed lines was the dry gas pipeline to Turkey -- Eastern Turkey. It looked like maybe near Jehan. Would I not be right that might cross Syrian waters and is that realistic under current political outlook?

Charles D. Davidson

Well, that's probably an area where we're probably having conversations with customers about whether or not someone may want to lay to us rather than we lay to them. And I think Turkey is going to take a lot more work in -- as we look at regional opportunities. One, because of the distance involved and the uniqueness of the market. It is a big market. Turkey is a large gas market, so you don't want to ignore it. But as we're all aware, in that part of the world, it's not just as simple as building facilities and laying pipe. It's that we have to work through government and politics as well. So that's just another one of those examples where it's going to take some work because of -- as you point out, it's a challenging route and you've got several countries that would be involved as you pass through on the way to Turkey. Let's see. So right back there.

Unknown Analyst

Some quick ones. The Gabon, what is the concept there, for the play concept for that Gabon acreage?

Charles D. Davidson

I want to just talk about, generally, and now I'll tell you, we are in the -- we're still in the negotiation for a license. And so generally, we don't talk a lot about what our proprietary thinking is on something until we've secured it. So with that lead-in, if there's anything left to say, I will -- Mike? He's going to get in the [indiscernible].

Michael W. Putnam

Chuck, I'll just say this, subsalt general fan complexes, very similar to the rest of the margin.

Charles D. Davidson

Thank you. Any others before -- and we got 1. Okay, we got 1 over -- yes, go, yes.

Unknown Analyst

Two questions. The first on the Marcellus. What are your needs and plan for infrastructure and facility spending to execute on your growth? And you mentioned flat realizations relative to Henry Hub. What's your outlook for those realizations going forward based on your spending? And then second on oil. You talked about $90 barrel number that you've kind of run through for the next 20 years. How would those plans change if the current strip scenario plays out in terms of your capital and growth?

Charles D. Davidson

Well, I think when we look at our -- I'm going to take the last one and then I'm going to let Gary and Donnie talk about Marcellus realizations and infrastructure. But when we look at our oil price forecast, we kind of have it as a flat. It actually steps down a little bit in the future, and then we just basically hold it flat. And clearly, that can move around some, but right now, we don't see huge changes in our program with, I would say, some fairly significant movements in that price curve. One is the things that Ken talked about in terms of our balance sheet and our ability to handle changes in pricing. The other thing is the robustness of the returns of the projects even if you -- nobody worries about if oil prices go up. I actually worry about it if they go up because I'm worried about what's happening in the world. But if you're looking at the downside and oil prices drop, we see that these are very robust projects, and yes, we wouldn't throw off as much cash flow and you want to look to see what the duration would be of a drop in oil prices. But right now, on a near-term basis, we don't see that as really impacting our plan to any significant degree. If something systematically -- if something moved dramatically through global markets that completely change our thinking, the equivalent would be as our thinking on domestic gas. Everybody's thinking on domestic gas change 2 years ago. If something like that happened in oil, then sure, we would shift our thinking. But it's great to have a diversified portfolio. It means that opportunities such as the Mediterranean, that is -- that's in a market by itself, and those types of opportunities will just keep moving on. So maybe just a little bit about the Marcellus realizations and also some of the investments in infrastructure that we see going forward.

Donnie Moore

Yes, Chuck. I'll add on the infrastructure. I mean, part of it is our joint venture on midstream company, CONE. I mean, those guys are working with us daily, staying up, keeping our midstream going. And the other is kind of a strategic partnership that we have with folks like MarkWest. As Chuck mentioned earlier, it's a -- it's not an overnight deal but a processing train-in. So we're 18-plus months to do that. So staying in front of that, one thing that really helps us with these integrated plans. We know where we're going, we know what's out in front of us. We have to plan out that infrastructure well in advance, so we're not waiting on it. I mean, that's kind of where we're at. There's actually a slide that shows a little bit on our infrastructure build-out. What we're -- what our cost are over the next 5 years, in your deck there, and you can see that it's, relative to anything else we're spending, is very small.

Charles D. Davidson

Yes, good. Thanks.

Unknown Analyst


Charles D. Davidson

Hang on. Yes. That way, they can hear it on the web, too.

Unknown Analyst

You took about $1 billion out of your 5-year plan in terms of CapEx. Can you comment where that CapEx came out of?

Charles D. Davidson

[indiscernible] it -- where the CapEx come out of? Of every nook and cranny we could find. Everybody contributed. But I think that we have a number of things. Our timing on some of the Mediterranean is adjusted a little bit. We've noted that because of the delay in getting the export policy in Leviathan, some of the timing on there changed a little bit. Some of it is efficiency. So I mean, we're just -- we're seeing that we're having better cost, and so we squeeze a little bit out of there. We talked some about the Niobrara, about making sure we pace that program along with the infrastructure, but we're actually -- there is an area where we're trying to push as much in as possible. So it is contribution from a lot of areas. It is efficiencies, as well as thinking on the timing of projects. But also, it's just the recognition that if we can deliver more from spending less, that is a winning solution every time. That -- it just -- because we all see it, somebody comes in who's got -- I can deliver x more growth, so it's going to take 2x as much the capital. And so we're just really focused on being very efficient with the capital. I'm going to ask Dave, who's been really driving a lot of that, to comment on maybe some of the other areas he's seen where we've been able to squeeze some out.

David L. Stover

A lot of it goes back to what we talked about on the integration of the way we look at our facilities and so forth. For example, next year, a big portion of what's come out is some of our offshore costs, especially as we continue to look at both the timing of how we lay out facilities, but really, the use of facilities. Now, you're not having to look at each of project on a standalone basis. You're actually able to integrate some things and capture, like we saw Susan highlighted down at Dantzler, for example. So there's big value, and a lot of that big value is driven by this integration of facilities, both onshore and offshore, and much more efficient use of facility spend, if you will, as we lay out these programs. And look at it on a long life, long-term basis, really enables us to lay that out very sequentially on a way to really capture this benefit.

Charles D. Davidson

Maybe take 2 more? Is that -- I'm looking at David back there. Okay. Okay. So I want to point this direction. Who? John [ph]. [indiscernible]

Unknown Analyst

Yes, I've got a couple. For East Pony, you had infrastructure development cost of about $0.5 billion. Is it going to be partially more for wells? What are you spending kind of annually on your infrastructure?

Charles D. Davidson

On East Pony, about $0.5 billion for infrastructure is a proportionally...

Unknown Analyst

We'll you've got more acreage than wells, [indiscernible].

Charles D. Davidson

Yes. Is It more acreage, more wells? I think it's -- really, the question is how the allocation of that goes. I think they're trying to sort out how to match their answer to your question.

Gary W. Willingham

Yes, I mean I think it's -- it will be slightly more. In the slideshow, we've got more acreage in Wells Ranch than we do in East Pony, so to some degree, you can ratio it up. But the thing you have to remember too is that we're not going to pour 10 rigs into 1 IDP all at the same time. The drilling's going to be phased out over time. So there is more acreage. You do get those benefits of the economy of scale and some of those wells that will be drilled on -- drilled later on, we'll be able to utilize facilities that were built earlier for other wells that were drilled. So it's not a direct ratio. It will be higher, but it won't be a direct ratio.

Charles D. Davidson

Okay. You had a follow on there?

Unknown Analyst

Yes, I do. Regarding Deepwater, your RORs in the Gulf of Mexico were kind of Marcellus-like in terms of returns. Obviously, you have different cycle times there but your returns are better internationally. So how do you balance the portfolio and why no Paleogene?

Charles D. Davidson

Well, I think when you refer to the ROR, you're talking about the -- yes, well, I guess what I'm thinking is, there was 1 return number that was a cradle to grave that was more of the overall program, but the individual project IRRs are very high. I mean, Dantzler is almost 100% rate of return. So I think what we have seen, as we go through there is that depending on the nature of the project they can move around at how much infrastructure is available there. So I think when we look at it historically, we've had very good returns. I would say that the Marcellus has gotten -- as we pointed out, has gotten better. I mean, in some instances, it's doubled because of some of the efficiencies that we've gone through there. So I think that, again, as Susan pointed out, we really like all the aspects of the Deepwater Gulf of Mexico, especially the add-on things that come with huge incremental rates of return. There was a question about -- we kind of focus a lot on the Miocene and why not going into the Paleogene?

Susan M. Cunningham

Can I just comment first on the rate of returns, because one of the things is that in general, what I showed you were smaller-type initial projects because we're really doing a phasing approach to make sure we really know what we have. So in most cases, I expect those to improve.

Charles D. Davidson

Yes. I think...

Susan M. Cunningham

It's really quite conservative.

Charles D. Davidson

I think in the case of Gunflint, you use actually the minimum resources rather than the full, so it's -- we probably undersold our case a little bit. But it's better to -- you know how it goes, is over-deliver, under-promise. And well, we like the Miocene. I mean, the Miocene has been very good to us, whether it's upper or lower, and I'll let the experts comment on the portfolio and going into some other target.

Susan M. Cunningham

Yes, this is the -- we do like the Miocene. It's got the best reservoir characteristics for the value that we've seen for their prospectivity, and the Paleogene is just -- continues to be a challenge.

Charles D. Davidson

One more question.

Gary W. Willingham

[indiscernible] add to the earlier answer on East Pony. The slide that show $500 million of infrastructure capital, Dan reminded me that in Northern Colorado where the East Pony IDP is, we gather and process our own gas. So that does include somewhere between $50 million and $100 million of gas infrastructure that we would not be spending ourselves in Wells Ranch. So I backed that out of the $500 million and then, again, not fully ratio it up, but you can increase it from there for Wells Ranch.

Charles D. Davidson

Great. Great, thanks. One more. How about way over there, we'll get -- so we get full end of the room.

Michael Kelly - Global Hunter Securities, LLC, Research Division

It's Mike Kelly, Global Hunter. The question is that first, the added detail on the DJ that really splits the acreage into the 7 IDP is very helpful. And on that front, I was just hoping you could speak to your confidence that the consistency that you could see the Wells Ranch and East Pony than more the developed field so far will be reputable in some of these new areas in the Greeley Crescent, Mustang and Core specifically.

Charles D. Davidson

Okay, great. Thanks. Yes, I'm sorry we gave you a challenge in all your modeling with all that data, but we just thought it would be helpful. But maybe just a comment, either Dan or Gary, on the confidence of carrying on into some of these newer IDP areas?

Dan Kelly

So Mike Kelly from Dan Kelly. How does that sound? I think that we've always said that these wells results are going to be area-dependent, and we know that the reservoir is different throughout. We've certainly built that in. But fairly confident that -- no. I'm very confident that we've underestimated maybe in some areas and we may have predicted higher than others, but I really believe that what we've given you is very fair and balanced throughout the entire DJ Basin. I believe that it's all going to work itself out. But this is a -- in the most part, this is may be a conservative look at where we're headed going forward.

Charles D. Davidson

Okay, thanks. All right. Well, again, thanks, for all your support. Thanks for participating today. We're really excited about the program we have in place. We'll be around. Hopefully, you're going to stay for a little bit of lunch and we can chat some more. But then again, thanks a lot.

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