Denbury Resources Inc. (DNR)
November 12, 2012 2:00 pm ET
Phil Rykhoek - Chief Executive Officer, President and Director
Charles E. Gibson - Senior Vice President of Planning, Technology and Business Development
Craig J. McPherson - Chief Operating Officer and Senior Vice President
Robert L. Cornelius - Senior Vice President of Co(2) Operations and Assistant Secretary
Mark C. Allen - Chief Financial Officer, Senior Vice President, Treasurer and Assistant Secretary
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. We'll try to keep this on time. We have quite a bit of information to cover.
Welcome to our annual Analyst Meeting. And we're good to go. We have some forward-looking statements, since my securities counsel is in the room. Be sure you read this thoroughly or he's going to clap.
First, the introductions. This is our management team. I am Phil Rykhoek, if you're not familiar with me, I'm the CEO. I've been with the company about 18 years, or will be 18 years this summer. The company was -- I was about the 35th employee here, or something like that and they hired me initially as CFO to take us public, and we went public with about $30 million or $40 million market cap, that was 18 years ago. So it's been quite a ride.
All the people in the top row, you're going to hear from today, they also have speaking parts. Mark Allen is our CFO. He's been with us about 13 years. Craig McPherson, he's actually our newest one. He's been with us about 1.5 years, I believe. Came to us with about nearly 30 years of experience at Conoco. So we recently promoted him to COO last summer. Bob Cornelius, I believe, here about 6. He's over at CO2 supply. And Charlie Gibson who'll also be speaking, he has his 10-year anniversary this year. In fact, we're honoring him on Friday at our quarterly meeting. And so if you have any good stories on Charlie, tell me because we want to have a little roast up there. He comes from planning, technology and business development. We recently promoted him to Senior VP. So you'll hear from all 5 of us.
Also introduce, I believe, we have 2 directors in the room. Laura Sugg, she's on the phone in the back, Laura, wave your arms. And the Chairman of the Board is here, Weiland Wettstein, in the back. So if you haven't met him, stop by and see him and say nice things about management or something like that.
We've also had some good, very nice additions to our staff. We've added -- Jim Matthews, came to us from V&E. Since we met at the last Analyst Meeting, he's our General Counsel. We've also added 2 new VPs of our operating regions. Those are the other ones, the 2 are Matt Elmer. This morning, he heads over the Hastings over the West Region, and Fred [indiscernible] over the East. So both of those came to us from Conoco. So we had some significant additions to our staff. So continuing to upgrade our management team, good group.
So we're a different kind of oil company. What do we do? We drill oil back to life. How do we do that? We buy oilfields, we inject carbon dioxide, and we've shown that we can recover some as much as much 50% more than what's been produced to date. So that in a nutshell is what we do. So why do we like that? Well, low risk. We know the field is there. We know that oil there. This process has been going on for years. It's a very repeatable, sustainable process. We have a competitive advantage. Those are all kind of the highlights of why we like CO2 EOR. Quite honestly, it's become our core strategy because that was our highest profitability of anything we're doing at the company. And so that's why we evolved into making this our core strategy.
And with the Exxon Mobil transaction, it's really our own strategy. So if you look at the classic definition of a strategy, what that say, to have winning strategy, you have to have 2 things: You have to have an advantage position and operational effectiveness. So advantage position, we have that. We control the CO2. We control the pipelines. We control now many, many of the oilfields. So we obviously have a competitive advantage over our peers.
Operational effectiveness, we've made a big push to improve on that, continue to do that, we'll never be happy with that. A lot of that's since Craig came on board, and I think you'll begin to see it in the results and the end targets, doing things -- what we always say on time as we expect them. And so I think those 2 will dramatically improve in our operational effectiveness. So if you get those 2 things, what do you get? Well, the classic, would be the best or a superior risk-weighted return.
So I'm going to give -- you're going to see several slides to them on value. We'll show you we have the highest margins and have the highest capital efficiency we think we're producing the best returns.
So we really believe we have a winning strategy. We think it really works. One of the other things that we put on the slide that we haven't really used before is the eco-friendly, down a the bottom. We've not really touched on that too much because to date, we've been using natural CO2. So we're not really -- it's not a net reduction in CO2 and that we're moving it from Jackson Dome into the Riley Ridge.
In the next 6 months, we will have 2 man-made sources, we will start to using in the Gulf Coast. Bob will go through those in a little bit. But that will be about 75 million a day. So we have found that if you use man-made CO2 for EOR, that it is a net reduction in carbon, even when you take into account the CO2 that's produced in the oil.
So it's extreme to call an oil company eco-friendly, but I think you may be the definition better than most. And I think you'll see CO2 expand over time.
So with that, the numbers in blue are actuals as of the dates listed there. Obviously, we have a high percentage of oil, 92% oil, because we're in EOR play. The ones in the orange are pro forma, adjusted for the Exxon Mobil transaction, which I'll go through in more detail here in just the second.
But you can see heavily weighted for oil, it doesn't change much. Based on this, if we use net of proceeds to reduce that, we'd have quite a bit less debt from the proceeds from the deal.
And our PV-10 is still $10.6 billion, although what really we did there, we took the year end number we added the 2 fields that we booked this year, Hastings and Oyster Bayou. That was about $1.5 billion, $1.6 billion and we took the Bakken off. It was about the same number. So ironically we have the same proved PV-10 pro forma for the deal as of now as we go to year end.
If you do the math, I might just encourage you to look at that, that proved PV-10 implies a net asset value per share of something north of $20. So I think that's something you might want to consider and you say, well, yes, but then why you're trading below proved PV-10? And I think it gets in the lot to how people tend to look at most oil companies. They tend to value them on a cash flow multiple. So our cash flow multiple is quite different relative to the net asset value than most of our peers.
Or put it another way, our net asset value is much higher relative to the current cash flow. So I think if you're just using a cash flow multiple, I think you're probably underestimating the value of Denbury. Obviously, we have significant reserves well beyond this proved PV-10. This is -- I'll show you the barrels we have, it's about 600 million barrels of 3P numbers.
But obviously, it's a disconnect to the net asset value, which is why we are going to be a bit more aggressive in buying our stock back. To be honest, it's very accretive to net asset value, it's very accretive to cash flow, and it's probably one of the best investments we can make. So we'll talk about this a little bit more here in a second.
How does it work? I'm not going to spend any time on this. Charlie is going to have a whole primer on EOR. So we have a section that talks about how EOR works, in summary, we take it from the source send it down to the field through the pipeline, inject it, and that's how we recover additional oil.
So I'll let him take you through that in detail.
We've had a good year. Our first 3 line items, all say we did what we said we were going to do. So I think that's -- I think it goes back to the operational effectiveness. We are on track with production, we are on track with cash flow and capital expenditures and so forth.
So obviously, a good year in meeting expectations. We've also had a good year in adding to our inventory of fields. We purchased Thompson early in the summer. That's a nice add, 18 miles in Hastings. And then of course, with the Exxon Mobil transaction, we've monetized the value of the Bakken, and we picked that 2 big plugs, Webster and Hartzog Draw. So with this inventory we have now, we more than a decade of growth in front of us. So it's
increased our focus on the EOR strategy, added to our inventory and then of course, I think the third thing, a big accomplishment this year, we had our first production from our Texas fields, Hastings and Oyster Bayou. In the third quarter, they produced about 4,300 barrels a day. We booked nearly 60 million barrels on those fields with a value of about $1.5 billion PV-10. So that was about $3.50 to $4 per share that we've added from those 2. So big additions in the EOR crude reserves in 2012.
Lower part, shaping up to be a great year. And Bakken transaction, our Exxon Mobil transaction.
So quite simply, I'm sure you've all seen this. I notice when you do deals with Exxon, you make it in the paper more than when you do deals with other people. So we got quite a bit of press on this. But specifically, it's -- we got $1.6 billion in cash and we get 2 fields, Hartzog and Webster. We'll talk more about those when we go through the field studies.
We are still expected to close on that in November. Obviously, we did this because we were really interested in buying, getting Webster Field. We've actually been working on that for some time. And I think this was about the only way we can get it is to do a trade and use the Bakken as a little bit of a carrot. In addition to the fields and not insignificant, we also are tying up -- basically, the remaining CO2 source that they have from the LaBarge Field out in Southwest Wyoming. So we are still working on that. Maybe it's a little confusing. We're trying to structure as a property interest, which means we would actually own an interest in those CO2 reserves in the ground.
If we do that, then we believe we can trade it as a like kind exchange and avoid some income taxes on the transaction. If we can't, it's a bit more complicated because you have to have some gas. You have to have a processing fee. It's just a bit more -- a few agreements you have to do when you take that sort of transaction and really abort back to more of a traditional purchase contract.
But either way, which have incremental CO2 from Exxon, and the real plus in that is we can use that at both Bell Creek and Hartzog Draw and get it there before we could probably get a lot of rich CO2 in either one of those fields.
That's the plus of taking up the Exxon Mobil CO2. And probably also, defers some of the Riley Ridge expenditures because it's pushing it out a little bit further because we won't need it close fast.
Riley Ridge is the backbone for the CO2 for the Rocky Mountain. The Exxon is a nice 115 million a day Bcf that fits in this intermediate period very nicely. So both parties are working on making that a property interest, and that's -- we're optimistic we can make that happen. But if it falls apart, we'll just normal's purchase contract.
So what we're going to do with the money? Obviously, we may buy some other fields, to the extent we find other properties we can buy and identify those before January 15. We can potentially put them in a tax-free exchange, which will then defer taxes. Now the taxes are estimated to be about $500 million. If we do the property interest on the CO2, I think it goes down to about $75 million for the quarter.I may be rounding off just a little bit. But to the extent that you trade for other properties, it would further reduce the tax.
I might encourage you, though, to look a little bit past the headline of the 4.25 because this is the tax abatement versus a tax deferral. So what happens when you trade and you have almost 0 basis in property you trade for, which means you pay income tax as you produce that oil. And so therefore, you really need to look at the delta or the present value of what you pay as you produce out a field with 0 basis or low basis versus the upfront tax.
But then your tax rate depending on different models, but I would guess is probably something in the range of 1/2 is what the real delta is. So while it appears that 400 million would be the headline number, in net terms, if you look at a net present value, it's probably about half that. And potentially, it could even be less and the change in that depends on our tax rate as we go forward.
In any case, we are talking to a couple of people, hard to predict that that's going to happen or not, but that's something that we obviously firm up probably in the next month or 2.
In any case, we have concluded that regardless of what we buy or regardless of what we look at, that we are going to expand our stock repurchase program. With the lower courts up in the valuable field the purchase of stock will be accretive, it will help both cash flow and net asset value. And so our banks have increased the amendment, they gave us $930 million authorized under bank amendment. To date, our board has authorized $500 million. That's $500 million incremental potential repurchases from today. That is not additive to what was under our repurchase program in the past.
Said another way, I think there is about $245 million and $230 million under the old repurchase deal so if you will, there's an increase of $270 million if you were to look at it that way. But there's $500 million of the Exxon Mobil proceeds that we are authorized by the board to repurchase stock today.
Then of course, anything that's left in the end will go to debt reduction or actually, probably from a real standpoint, probably a go to debt reduction initially and then we'll borrow that. We are very comfortable saying that we can spend $500 million on stock. And of course, that depends on where the stock price goes. That depends on what oil price does. Today, we would be a buyer, but it will vary, of course, depending on the where the stock goes or the oil price goes.
So this is up to our discretion but we do have a significant amount of money now set aside to repurchase stock.
So when you look at the Encore deal, with the monetized on the Bakken, you can see we paid $5.8 billion -- I mean, $3.8 billion, sorry. And now we've got to our total value of $5.7 billion . So most of that profit, if you will, really is the Bakken. If you recall, when we purchased Encore, we thought we purchased it after proved PV-10 and we thought we got the Bakken and the EOR upside is essentially for free. And so ironically, if you look at the delta, what we've made on this thus far as we've alluded and that's what we're getting for the Bakken is the delta, it's the incremental value.
Also, there's just as a footnote, that's one reason we're looking at buying Denbury stock back too. If we can buy Denbury stock for those kind of metrics, if would spend $3 billion or $4 billion for Encore, and PV-10, why won't you do something similar for Denbury? So Encore is turning out to be a very profitable deal, 50% increase in just less than 3 years and we still have the EOR potential up in the Rockies that we have yet to recognize.
As I say, a repeatable, sustainable use in the slide before the DOE reports there's up to 10 billion barrels of oil recoverable in our 2 regions. We have maybe 10% to 15% of that, so this is something we can do for a long, long time.
The changed this map up a little bit, most of the numbers really haven't change. But we kind of -- I know you're highly disappointed but we've got rid of the phase nomenclature. And so we're just going to talk more about the big fields and focus on them, and so we kind of grouped all the older ones in what we call mature area there in East Mississippi. But we still, in the presentation, will go through the key drivers in the key fields that we're working on.
The green dot show you where some of the other potential is based in that DOE reports that shows you kind of collection over the fields are. We also changed -- our blue dots are still floods that are ongoing. The orange dots are new and that they are future EOR floods that we have yet started injection. So you can see where the future potential is.
And there was a question this morning, Hastings, we now book out separately from the Ebbot. And but really, there's always been an Ebbot's field included in that Hastings area. And we now just to break them out separately. So the numbers expected recoveries for Hastings have not changed is the bottom line.
658 million barrels potential there, 200 proved, and we've already produced 64 million to date We'll go through each of these details, so I'm not spending a lot of time on it.
This is the Rocky Mountain. The Gulf Coast is obviously much more developed with the pipeline infrastructure, and we have nearly 800 miles of pipe. So the Gulf Coast is flowing off free cash already.
And in essence, what happened is that the free cash flow from the Gulf Coast is going into the Rocky Mountains as we're building out the infrastructure and starting those floods up there. That will make a little more sense with you when you get back one of these other slides.
In the Rockies, we now have a red line, we're just about to be finished. It will be finished next month, and we'll start drilling Bell Creek in '13 and then CCA is still scheduled for 2017. And the dotted red lines are expected to be done by that time also.
Again, we'll go through each of these floods in detail so I'm going to gloss over them.
If you know the history of the proved reserves, you can see where it was year end, whether it's June 30 and then taken out the Bakken on a pro forma basis. And then of course, with the Bakken going away, we also added the being potential on Webster and Hartzog, the 93 million barrels you see there in Orange. So still over 1 billion barrels of potential.
Talk just a little bit about value. This is the first one, and we have 2 or 3 of these slides on this. But it all starts with operating margin. I think this slide, I particularly like this slide because oftentimes, people say, well, you're a high cost producer because we have some of the highest op costs in the business. And so therefore, why would I want Denbury? Well, we may have one of the higher op costs but we also have one of the highest margins and we define margins here as revenue less operating expenses. So even though we have a little higher op costs, we're obviously getting very good netbacks.
This shows first quarter and the second quarter, we were the highest of our peer group. Third quarter was not completely out as of Friday, although preliminary results show we're still #1. And then in the Orange Square, we did a pro forma adjusting for the Bakken, which is another one that's little bit interesting because you would think the Bakken with a very low op cost would lower our profit margins, operating margin. Actually, you can see it's a slight increase. And the reason here is the oil differentials are much stronger in the Gulf Coast, and that offsets the op costs [indiscernible]. Our net operating margin actually improved post Bakken as shown here.
The numbers in the parentheses are just the change from first quarter to second quarter. Again, we had one of the lowest drops in margin. So why do we have these good margins? Well, part of that is 93% oil, probably one of the highest in the groups. We have very little liquid production. As you know, liquid production prices have dropped off a bit. And that's one reason our margin didn't drop as much as most of our peers. And so this gives us very good results.
So we have high operating margins. If you put that together and probably what is one of the best capital majors of profitability in the industry, and that's capital efficiency. Now this is similar to the Canadian recycle ratio, if you're familiar with that. And what it is, is it's the ratio of cash flow, in this case, we're using EBITDA, but cash flow will give you the same answer, over operating costs. Obviously, if we have highest margins, you can see we have one of the lower funding development costs. That is the reason we have the highest capital efficiency ratio.
Now in this case, we used what we call adjusted finding and development cost only because Wall Street tends to use the shortcut method, which is total expenditures over total reserves. Now if you're in a shale play, as you know, you drill one well and you get to book 4 or 8 or multiple wells off that one. So The Street -- Wall Street F&D can look quite low because you drilled 1 well and in essence, you booked 8. What we did is we went back and added in a future development cost that go with that because to drill 8 big wells, you got to drill -- you got to spend 8x that number. So this takes into account the increase in future development costs and also the change in evaluating costs. Otherwise, it will be so very similar to what you see most of the analysts and so forth that put out.
So you're in that where there's a big different number on F&D when you include what it costs to drill those development wells.
There's about another way, the Wall Street F&D is kind of looking at funding cost that doesn't include the development costs. Ours, ironically, have changed too much, but it was a $16.75, that also includes about $1 per barrel per DD&A on the CO2 properties at the Jackson Dome pipeline.
If you do our pro forma and adjust for the sale, it comes down slightly. I think you'll see it come down even more when you get past 2010, which is when the Encore acquisition was completed. And so that number is quite large and kind of the skews this a little bit. So I think going forward, we'd expect that $16.38 to come down even a little bit more. Adjusted -- obviously, the pro forma number is a question relative to the peer group.
So here's another way to look at the value we're creating. Let's see some -- just using high-level numbers. We've spent nearly $2.7 billion on the EOR, we spent $1.9 billion in the fields. This is as of last year end. So what we did is we took off the money that had spent today on undeveloped properties, in other words, expenditures for which there were no associated proved reserves with it. Plus the green pipeline there for $1 billion is most of that, there's a little bit up there in the Greencore pipeline related to that. And so the investment to date on proved properties as of last year is $3 billion. We already have recovered that money. And we have $5.7 billion of PV-10. So obviously, creating $5.8 billion of value in our EOR program to date.
I'll also show you a slide in the little bit the Gulf Coast is expected -- the Gulf Coast program on most of the EOR is expected to complete pay off as a group by the end of this year, I believe. So again, it's a very value-creating process.
2015, we plan to spend at $1 billion. That doesn't include some of the capital overhead. If you look at the footnote, there's another $125 million . It is not quite self funding, probably take something in the mid-90s, all parts to be completely self funding. So dependent on where that fall back, we will be a dip into our line a little bit. We do, of course, have the floors low at 80, and Mark will cover that. But you can see almost all the spending now is for the tertiary floods. Pipelines are relatively minor in 2013. And the little bit of work at finishing Greencore, a little bit of work expand NEJD and so forth, Bob will go through that.
Than quite a bit on CO2 sources, Riley Ridge and Jackson Dome. Again, Bob will go through that. The big spending on conventional properties is really at CCA. I think about $100 million of that $150 million is at CCA. We expect that will give us between 6% and 14% growth, the 2012 estimate is the midpoint of our range adjusted for property sales.
This does affect tertiary, but of course, that does affect the non-tertiary number. And then we expect to have some growth in non-tertiary. Now part of that is because we acquired a couple of fields midyear. We also expect some production growth at Riley Ridge but that should come on in 2013. We also expect CCA to grow on a conventional basis, as I mentioned.
So total company, we expect the midpoint to be about 11% growth. Do keep in mind, we have purchased back 5% of the company to-date. So that would be additive on a per-share basis, and we plan to acquire more.
So it leaves us with a decade of EOR growth. So one of the big pluses of acquiring these additional properties is we've pushed that peak out. We took those out a decade, but actually the peak in the model is probably 2 or 3 years past that, it's just that the growth rate slows down a bit as you approach the peak.
Spending for 2013 in the peak in 2015 or '16 really hasn't changed. It's still along that $1.3 billion in 2016. And then after 2016, you have had growing with your cash flow. This is soft funding with oils in the mid-90s. If oil is less than that, we would even slow down, dip into our line to fund it some other way. And then, of course, after 2016, it is growing with your cash flow.
The way we really get from point A to point B is the fields are listed there now and in the order that we plan to flood. So Bell Creek is the next one that will be coming on, that's coming on 2013. Webster, we have put ahead of Conroe and we have switched that around. Webster will be expected to come on in 2015. We just need to get a pipeline there. Again, it's just 8 or 9 miles from Hastings. Hartzog Draw is going to come ahead of CCA so we expect that in '16. That is as fast as we estimate we can get the pipeline to Hartzog Draw. It's about 3 miles -- I mean 12 miles, excuse me, and we think it takes about 3 years to get that done, probably about 2 years to get permits and then we can probably put it in actually a pretty short time.
So we are estimating Hartzog in 2016. Conroe, we have pushed back to 2017. What we basically did is we took all these floods the we saw for the best net present value and so that's why we rearranged them. It makes -- if you think about it intuitively, it makes some sense to do the Webster ahead of Conroe because it's not the pipeline expenditure for Webster as it is for Conroe.
CCA is still in 2017 and I think Thompson now is expected to inject in '18 and first production in '19, so that's the order. So just to give you a little color I guess on this slide, the one that is the softest the Cedar Creek Anticline. If Cedar Creek Anticline comes on in 2017, as modeled, we will be -- actually well past that 100,000 barrels a day in 2022. We've kind of hedged a little bit because we have found that there's quite a bit of incremental conventional development work to do at CCA, actually spending quite a bit of money in 2013 on water flood, we're also spending money on some science and not to take all price reports, plan to maybe do a pilot in 2014. This is a field with about 3 billion barrels of potential and so we're still planning with the -- figure out the best way to get that out. And so I think there's a chance that CCA may be pushed back a little bit. That is and that, that means we're getting conventional production out of CCA, and that also means actually some of the cash flow will be pushed out also. So we may even have free cash a little bit sooner, but CCA is the one that's the biggest -- the one in flux the most, at least as far as he schedule.
But in any case, we think we're not that far away from borrowing off significant free cash and if -- just to help illustrate that point, we broke out the Gulf Coast EOR program to show that it's already producing free cash.
As I mentioned before, this is the most superior infrastructure we have in place and so the Gulf Coast is still not free cash. What conceptually has happened as that money is being used in the Rockies, to develop the Rockies. So we expect the Gulf Coast to pay out late this -- late '13. This -- the number here is just a little smaller than it was in the prior slide, that really is mainly because we took the oil price down. I think we are in mid-90s before. And now we're down to $90 oil instead of mid-90s. So that really is the main change. The rearranging of all these floods really didn't do too much, make much difference to the free cash. So Gulf Coast is already there, and that money will be used to fund the Rockies.
We've updated this. The timing changed on just a few of these and, of course, we've added all the new floods that's supported by the first production dates so here's your good point of reference. And then you can see when -- where each one are expected peak. I don't think we would published the Webster, Hartzog and Thompson before but probably no big surprise if you could of compare them to the Hastings some of the other fields. And then you can see the expected peak here. So this is nice, it certainly helps those who are doing models and so forth and a nice reference chart, to see the order of things.
All right. So with that, Charlie is going to come up and he's going to -- we're going to hand you a primer on CO2 EOR.
Charles E. Gibson
Thanks, Phil. Well, good afternoon, everyone. I think my intent today is to educate you on some of the technical techniques we use to analyze our floods. And the real purpose would be to -- maybe have a greater understanding of our profile as company, which we believe is pretty low. So let's get into it.
We talked about this previously, and this is the CO2 EOR process. In the CO2 source, you need a pipeline to transport it. You would be able to put the CO2 in the ground. And then at the end of the line, we think we will capture the CO2 in the geological structure.
A brief history on the EOR CO2 history. Back in early 1900s, people are drilling wells on these big structures and instead of finding hydrocarbon, they found CO2. And obviously, they plug these wells because there was no commercial use for CO2 back in those days. So that was the first indication of CO2.
And then in the mid-1970s, SACROC was started -- was flooded with CO2 and began the industry's introduction into CO2 EOR. And of course, the Permian Basin continues to be a growth and expansion area of CO2.
Back in the mid-'70s, right after SACROC, Shell went up. Shell flooded the Little Creek field, put in phases 1 and 2 in Little Creek field in the mid-'70s, which started the Gulf Coast expansion into EOR operations. And then in the mid-'80s, various operators began to flood the Rocky Mountains.
So this process has been going on for a long time and of course, Denbury was introduced into the CO2 EOR business in late 1990s when we purchased the Little Creek field from J.P. Oil company. And of course, we continue to expand the Gulf Coast region in greater intensity than what was done previously.
This slide has a lot of information about the various operators in the region and so forth. But the thing that struck me was this production curve there in the lower left-hand corner of the slide. And production -- it shows the production history of EOR in the United States. And if you look at the Permian Basin, which is the blue, it's been very stable here over the last 6, 7 years at about 200,000 barrels of oil per day. And I think the primary reason for that is just because the amount of CO2 available to flood fields in Permian Basin has been limited. So additional expansion cannot occur at this point in time.
If you look at the Rocky Mountains, on the other hand, you're seeing some growth in production, primarily due to Anadarko Salt Creek field and that's increased production in the Rockies. And if you look at that the top wedge, that is the Gulf Coast region and of course, that's directly related to the Denbury Resources continued expansion of CO2 in the Gulf Coast.
So as I mentioned, and as Phil mentioned, everything begins with CO2, the source. And we always talk about Jackson Dome as being the backbone of our company or the heartbeat. And it's where everything begins. And of course, Jackson Dome supplies the CO2 to our Gulf Coast operations. As Phil mentioned, we recently acquired the Riley Ridge Field, and we are working on an agreement with Exxon for the LaBarge Field. So both Riley Ridge and LaBarge will be our source for the Rocky Mountain fields.
And we will supplement both Rocky -- Riley Ridge and Jackson Dome with man-made sources as they become available. And we have a couple of contracts that's about to come to reality here in the next few months and we'll be putting man-made CO2 into our system.
This slide shows that -- we've shown this slide numerous times. This shows the entire system of pipe and sources in the United States. Again, if you look at the left-hand corner, you see some interesting facts. In 2010, in the United States, we used 3 billion cubic feet of gas per day of CO2 for enhanced oil recovery. Based on Denbury's expansion, I expect that number to continue to grow and not only Denbury but the additional man-made sources of CO2 becoming available will increase the amount of CO2 going into EOR operations.
Once you have the source, you got to move it. And of course, we have a big pipeline system. We have over 1,100 miles of pipe that we'll be using or moving CO2 from the source to our fields when we get our Greencore pipe operational in December. And of course, the amount of pipe will expand as we connect into Riley Ridge and LaBarge into the future.
These slides shows some of our pipeline operations when we're installing pipe and the thing that's very interesting to me is that we operate in very environmentally sensitive areas. As you can see, the Gulf Coast, the swamps in Louisiana and South Texas and of course, the beautiful Rocky Mountains in Wyoming. And I think we've done a very good job of returning the land back to its native state after we installed the pipe, and we operate in what I would call a very environmentally friendly way where we do very little, if any, damage to the environment. So I think our operations people have done a very, very good job.
So finally, we get to talk about EOR, and we'll get to talk about our reservoirs. And I think there's 4 topics that I really what the focus on today: one, you got to have oil, so I want to talk about how do we determine what's our target for -- target oil volume for CO2. The second topic is I have oil, but how do I know the CO2 is going to mobilize this oil? How do I know the CO2 is going to get the oil out of the ground? The third topic is how would I know the CO2 flood is working? And finally, and Phil touched on this one, the topic is, is this process repeatable? Can we move it to a different basin and to a different type of reservoir? And hopefully, we can try to answer some of those questions.
I think to really understand the oil saturation, we really need to go down to the floor space level and so we're going to look at a microscopic viewpoint of the floor space. And this slide here shows 4 time slices in a life of a reservoir. And let's start on the slide on the left, that's original conditions. So let's assume that Exxon drilled a discovery well and they find hydrocarbons. And in this case, the oil saturation is in approximate 70%. So they're excited. Their facilities really start producing. The second slide shows the saturation after primary recovery and of course, that's one we -- primary recovery is when we use a natural energy of the oil to produce it from miles in the earth to the surface.
And so after primary recovery, the oil saturation is reduced by some amount because water may invade into the reservoir or the pressure depleted to a certain point where such that gas liberate itself out of the oil. So in the floor space, you may have natural gas or water. So after this case, we have 50% saturation.
The Exxon scientist decide, well, it's time to waterflood this reservoir. There's a lot of opportunity to recover additional barrels. So Exxon decides to inject energy to the reservoir by pumping water. So they waterflood the reservoir and recover additional volume of oil.
But again, we reach a life of the waterflood and it's depleted. This is -- at this point in time, this saturation is called a residual oil saturation in water. This is how the Denbury -- this is the time that the Denbury business model begins. We -- when we enter the field, the residual saturation in the water is about the saturation that we are attacking.
So in this case, the oil saturation after waterflooding is 30%. So of course, Denbury comes in and CO2 floods the field and we reach our economic life. We recheck them on the life, there's still oil saturation left in the reservoir. And on the current technology, the saturation remains there. But in the future, additional technology, hopefully, will allow us to go after this additional oil.
So how do we measure this oil saturation? Historically, the industry has used well logs. We log wells both case hold and an open hold to calculate the saturation. We also take cores, and we take both sidewall cores and whole cores. And with these cores, we do special studies. We calculate all types of reservoir properties and characteristics, but we also calculate what the current oil saturation is in the reservoir.
How do we define the size of the reservoir? When we buy a field, we -- our geologists remap the field. And the map on the left side of the slide is a structural map. And the structural map is looking structurally down on to the top of the geologic feature. So it's like a topographic view of the reservoir.
Then if you look at the side of the right, it's a cross-section of this. You you're looking directly into the reservoir. And notice in this case, you can see the layers in the rock is estimated by the geo team. And the important point that I want to make here is that when we buy these oilfields, like at Delhi, Tinsley, Hastings, Conroe there's been hundreds if not thousands of wells drilled. So there's lots and lots of oil data both logs and hopefully core data. So that data is all assimilated, and our geo team remaps the field. And it's very, very -- and very, very, very detailed because we really need to understand the reservoir and geologic characteristics of the reservoir.
So we find the oil target by doing very simple calculations, we know the size of the reservoir and we multiply that times the current saturation, which gives us the remaining oil saturation in the reservoir. Another way to do it is if you know the original oil in play, you subtract how you produce and leaves -- the equation leaves the remaining oil in the reservoir. So we use both methodologies to prove up the target.
But I want to really emphasize that this is a very important step. You really need to know how much oil is remaining in the reservoir. And we have to have a high confidence, a high degree of confidence of this number because we want to minimize the range of outcomes of this number because it can reform the economics of the project.
The next question is why does CO2 recovers additional oil? And the test we run to answer this question is called a separate test. And it's done in the industry. It's -- the outcome is this graph on the right-hand side of the slide. And the key point there is it determines where the minimal miscibility pressure of the oil is. And minimal miscibility pressure, we talk about that all of the time, MMP, that is the pressure where CO2 and oil mix completely together, where the 4 becomes one homogeneous fluid. So in that case, this is the example of that Conroe Field. In the Conroe Field, the crude that exist in the reservoir right now at 2,400 pounds of reservoir pressure will become miscible.
While, not in all cases we can give back to this minimal miscibility pressure. As you recall, we're operating a couple of our reservoirs below minimal miscibility pressure, potentially in the cutter. So say the original pressure at Conroe is 2,100 pounds, if we can get back to the 2,100 pounds, if you look on this graph, you see a recovery factor of 78%. So what that suggests is when the oil contacts -- the CFC contacts the oil, it will mobilize the 78% of the oil. So in the Conroe example, on 2,100 pounds, 2,400 pounds, we are mobilizing somewhere between 78% and 98% of oil we contact. So determining the operating pressure is very important, but what's really important from this slide is that we can mobilize oil. From the test in the lab, we know we can move oil if we -- the CO2 contacts the oil.
So let's move from the microscopic down in the reservoir behavior to the big reservoir from a macro view. And in this is a key to the reservoir. And it shows CO2 moving from the well injector to the producer. And notice the irregular path that's shown on this diagram. CO2 doesn't take a straight path by any means, it takes a very tortuous path. And the reason why it does that is because of a couple of things. The viscosity of CO2 is quite different from the viscosity of the oil and water. That's one reason. The second reason is because of the heterogeneity of the rock. As you can imagine, the rock is not consistent at all. There is some differences in the makeup of the rock.
And one of the measurements we have is called permeability. And notice the vertical layers in this diagram. The flood front, is at various distances away from the injection well. And that's primarily driven by the permeability of the rock. As you recall, our West Heidelberg last year or 18 months ago, we had the similar thing occurring where we had a fast, fast zone. So it had a high permeability. All the CO2 is entering the high permeability zone. And in the target zones we had very, very little CO2 entering. So we see this in the real world. We, obviously, are taking -- we try to take very -- precautions to not allow that to happen again. But the key thing here is the greater the rock you contact with CO2, the more oil you produce.
So how do you -- we determine the recovery factor? So the recovery factor is the volumetric sweep for how much rock you contact times what we call displacement efficiency. And displacement efficiency is the percent of oil displaced by CO2, which is influenced by that minimal miscibility pressure that we saw earlier a couple of slides back and the rock heterogeneity.
So I'd like to try to give you an example here. If you can imagine, if you had a block of Jell-O and you know the consistency of Jell-O, and you try to move that Jell-O with more Jell-O, it's going to move pretty evenly because the consistency of both the displacing and the displaced fluid is very comparable. Now let's look at it from another angle.
If you had that same block of Jell-O and I try to displace it, move it with water, now imagine that. That water is going to channel right through that Jell-O because the characteristics of the fluids are different. So the displacement efficiency is how much Jell-O that water moves with the water as it moves to the reservoir.
That gives you a flavor of how CO2 performs in the real reservoir. The CO2 grabs all molecules and moves to the reservoir, and then the displacing the efficiency is how much oil it grabs when it moves through the rock.
So how do we predict grades? This curve here is called -- what we call the [indiscernible] curve, and we mention this quite extensively. And it plots hydrocarbon core you injected or how much CO2 we inject on the rock of the X axis and works presumed recovery on the Y. The key thing to think about, you've seen the minimal miscibility curve and you've seen the cube with the sweep efficiency, the faster we inject CO2, the greater the speed of oil recovery. So the key thing that we're doing from a technical perspective, we're trying to process our reservoir as fast as we can. It's no different in West Texas than it is in the Gulf Coast. The engineer is trying to get as much CO2 underground in the right places as fast as he can. And you see that on the curve that is as you move to the right and if you go up the axis on the y-axis, you get greater recovery. So we have to try to move as fast as we can.
So I want to move from a theoretical to some actual examples. And this is a bunch of published curves from magazines and technical articles on Fords in West Texas and the Rockies. And a couple of things that came -- I guess grabbed my attention. If you look at the range of recoveries, the range of recoveries in West Texas and the Rockies is somewhere between 10% and 18%.
Then if you look in maybe a little greater detail, you can see the bottom end of the range, you see a grouping of somewhere between 10% and 12% recovery. And then if you look at the upper end, you see something between 15% and 18%. The thing that fascinated me was that the worst field, the worst field with published data still recovered 2% of the oil in place. So I thought, that's quite interesting. How does that compare to Denbury curves? Well, I plotted a slight group of patterns, various patterns in our mature floods because we have enough data on these patterns. And I also have selected enough -- I wanted to get some variability, I didn't want to plot all of the patterns with similar recoveries. And so what's shown here is that from the bottom end, we're seeing about 11% to the high end of 23%, 24%. And I think there's a couple of points that I want to make.
We have this very complex process that requires some chemistry that the oil has to react with the CO2 to get oil out of the ground. And yet despite this complex process, we're still able to get on a minimum 10% recovery. So in my mind, the risk profile is less than what you would think for a complex process. You have to do all of this sophisticated engineering and geology to really understand things yet we're still able to get 10% on a worst-case scenario.
So let me give you a couple of examples of the recovery factors that we're seeing from our floods. West Mallalieu Field, which as you know has been our probably our best flood and maybe our flagship flood, we think we're going to get 22% recovery from that field. We look at Eucutta Field, Eucutta has been outstanding. We think we're going to get 17% recovery. Soso barely stands. We think going to get 18% recovery.
Brookhaven Field, we think we're going to get 15% recovery. I haven't come close to that 10% number. And so we're so far stating that number with the behavior of that field.
The second point that struck me was that our worst performing field, which is, I don't know, I guess worst from a standpoint that it's been the one that we struggled the most with. But the McComb Field, we're going to get somewhere between 12% to 15% of original oil in place. Our worst field is going to generate a positive rate of return in the teens. So our dry holes, so to speak, our technical most challenging project is going to deliver double-digit rate of return.
That makes me excited, and makes me want to invest in more CO2 fluids. So that's what Denbury does.
So how do we determine what our peak oil rate is? Well, we mentioned this morning, one of the things that drives that is the pace of capital development. In the case of Hastings, we have sped up that capital development, and we're going to hopefully increase peak even higher than what we think. In the case here on this Tinsley Field, there's been 8 years of capital investment -- or we haven't spend 8 years of development yet. I think there's been 6, next year will be 7, and '14 will be 8th. And we spend about the same amount of money in each year, about 13%, 14% of the total projected capital. It's spread out very evenly, and you can see the graph. The graph has shown a very gradual, steady increase in production. So I went to compare that with some other Denbury fields.
And I compared the Tinsley, Eucutta, Soso and Delhi, and a couple of things jumped out at me. The first 2 years -- this is monthly production data, by the way. The first 2 years, the 4 fields were sort of grouped together. The production somewhat approaches the same number. And I think what that tells me is that we're developing the same number about the same number of pattern in the first couple of years in each of the fields. But then the third year, you start to see some of the production begin to deviate and to break out. And the bigger fields begin to breakout because you're continuing to add more capital and develop more patterns. And so you can see that with Tinsley. And, of course, Delhi, you're seeing it, too, as well.
Third question, how do we know a flood is working? As you recall, when we had the Heidelberg problem a couple of years ago, we knew it wasn't working because our production had peaked and we started to see some decline in production. But there's also some tools we used to analyze it. We ran what's called profile logs. And of course, the industry has been running these logs forever in both water floods and CO2 floods. And the idea is to look at where your CO2 is going. So in the case of the Heidelberg flood when we ran this log across it, we had the real fast zone. All the CO2 showed to be going into that zone. And the tighter zones, we didn't have any CO2 going into them.
So it became really obvious that we had issues there. In the case of this Hastings profile log here on the right, it shows a very evenly distributed injection profile, which is ideal for what we're trying to accomplish in our injection well.
Another technique we used is what's called net utilization. if you look at -- we plot -- let me define net utilization first. Net utilization is defined by the amount of CO2 we purchase divided by how many barrels of oil we produce. So it's a reflection of the efficiency of your purchase of CO2. And if you look at this graph, it starts high and drops off very rapidly. And in the case of Tinsley, the current net utilization is 10, and the cumulative net utilization is around 20. And both these curves should approach the same number and should -- somewhere end up around 10. Tinsley flood is very, very efficient. And what we do is we compare this net utilization to other floods. And from a relative basis, we can determine if one field is doing better than the other.
We also looked at the produced fluid. From a -- but we don't just necessarily look at the oil. The oil may be an indication, but the gas produced with the oil may be a better indication. So we look at what's called Gas/Oil Ratio. And we plot recovery versus Gas/Oil Ratio. In this instance, the Mallalieu phase 2 over the last 5% recovery has been very, very stable. And so you would -- this would suggest the flood is performing quite nicely. Now if you plotted the West Heidelberg situation on top of this, you would see a change in slope and a dramatic increase in GOR. That would suggest that you may have problems in your reservoir. So this is just another tool we use to help manage our flood and determine how well the CO2 is working.
Is it a repeatable process? Well, as you know, floods have been ongoing in West Texas for 40 years. Floods have been added in the Rockies. Floods have been added on the Gulf Coast. I would suggest to you that as long as you have all oil remaining, and CO2 can mobilize the oil, if you can demonstrate those 2 factors, then CO2 flooding will work. And then it will be matter to determine if it's economic. So I think CO2 flooding will work offshore, in Alaska, in Saudi Arabia. It doesn't matter. CO2 doesn't know where the oil comes from.
And so we have the tools, we know the process, we have the equipment, and I think Denbury's technical knowledge is getting better and better everyday, so I definitely believe the process is repeatable.
So why is CO2 our core focus? I'm sure you've heard this numerous times. But we have a high confidence in our oil target. We spent a great deal of time trying to verify how much oil is remaining in the reservoir.
Denbury has produced 70 million barrels of oil from our CO2 operations that otherwise would never have been recovered. CO2 flooding recovers oil, and I like to use the term CO2 loves crude oil. Denbury is actively flooding reservoir with 11 degree API crude, and that's in the Martinville Field in Mississippi, and we're flooding a reservoir with 40 degree API crude in Delhi, and we've mobilized oil in both instances.
And I'll give you an example about the Martinville crude. That 11 degree API crude, if I put it in a jar and I turned it upside down, the crude wouldn't move. It's like a tar, a tar-like crude. Yet CO2 is able to touch that oil in the reservoir and mobilize it and move it to the surface. CO2 loves oil.
And a prime example of that, we've made 1.5 billion barrels of tertiary oil in the United States. And as I mentioned previously, it's a very repeatable process. I think we can repeat it over and over again provided we can do so economically.
Step 4 of the process is at the end of life of the CO2 flood, when we're done making oil, we leave CO2 in the ground. And it's stored in the geological feature that was able to trap hydrocarbon, so the geological feature should be able to store the CO2.
So my last slide is what we're calling a better mousetrap. And as you can tell, I'm a little bit passionate about what we do. And we -- during my tenure here at Denbury, we have been participants in 3 shale plays. We were in the Barnett, we were in the Haynesville, and most recently, we're in the Bakken. And we've chosen to sell all 3 because we really believe in what we do in EOR.
And you can look at these comparison and think about them at a later date, but there are a couple of them I wanted to point out. Proof of new basin. When we go into a big oilfield, we know the oil is there. But shale plays, like Tuscaloosa Marine Shale, they're trying to figure it out. So you've got to spend lots of money to really get your technology to help you make oil, and eventually make money. So it generally takes a lot of money to get a basin up and running.
Production response timing for us on our CO2 models, we -- it's been difficult, especially in our early 2 -- first 2 or 3 years. We have struggled at times in getting production precisely -- as precise as we would like to. But the same can be said for shale plays. When we first got into the Bakken, our range of outcomes was enormous. But after we drilled more and more wells, 2 or 3 years of drilling wells in the basin, the range of outcomes shrank, and you develop type curves.
Profit to your investment. We think we have a high profit to the dollars invested. You know on a shale play, you're on treadmill: you've got to keep investing to keep production going.
Environmental impact. As Phil said, we think we have a minimal footprint, especially if we can store CO2 in the ground. Environmental impact from shale plays, it's quite large because you have to use chemicals and you have to use freshwater to frac the well.
And finally, total costs. Our finding and development costs is relatively low. Our operating costs are high because we have to recycle. On the shale play, your finding and development costs are high, but your operating costs are relatively low.
At the end of the day, we still believe in our EOR business, and of course, it's our core strategy going forward. Since you've been educated on EOR operations, we're going to take a 5 minute break. Thanks.
Okay, if you could make it to your seat, we'll get on the next part.
Craig J. McPherson
Okay, we're ready to go. I have to be close enough to [indiscernible] Okay, good afternoon. I'm Craig McPherson. As Phil mentioned, we are finishing 2012 strong. 2012 has really been a good year for us as we mentioned in our third quarter conference call. The fourth quarter looks good, as we begin on a real positive trend. So we think we'll end up 2012 in the upper part of the forecasted range. And we believe that will set up a strong and powerful foundation for us to have a very successful 2013.
So what I'd like to do is spend a bit of time with you and talk about our assets and in particular focus on what we're going to be investing in 2013, but also give you sense for our portfolio of assets. That here really provides us, enable not only a strong 2013 but as Phil talked about, a very strong decade of significant growth.
So with that, let's talk about strategy. While our year-to-year operating plans will change, our basic strategy for our tertiary operations will not change. In fact, these are the tenets of what we must be great at to be the world's best at CO2 flooding, and that's our objective. So first and foremost, when we started this morning we talked at the Hastings field visit. First and foremost is safety and environment, and that's easy to measure. You measure by knowing your turf, and you don't make a mess, and you keep your oil, gas, CO2 and water inside the pipes and vessels. And we take that very seriously. It's what our employees expect of us. It's what the communities in which we work expect of us. That's also a hallmark of a well run operation, and so we take that very seriously.
Operational excellence. And I think you heard Phil talk about that a bit. If I'm going to summarize operational excellence in a word or 2 words, it's "never satisfied." We believe you can always get better. And so I've been doing this for 31 years, and it is amazing to me when you look for opportunities, you find them.
And so when you look, you're never contented with where you are. You always believe there's a way to do it better, faster, more and more profitable. And so our focus in operational excellence is to maximize our oil production at optimum cost. And we've got significant focus on that in our day-to-day operations to ensure that we scrub every piece of CO2 production life cycle or to break it down little pieces, and we want to be the best in each one of those pieces.
We don't necessarily want to be the cheapest costs, but we want to scrub every costs to make sure that the optimal value is derived from that. And that's operation excellence. That's what we do everyday. We talk about it all the time.
Third tenet is to maximize oil recovery from the reservoir. Charlie gave you a great perspective on how to calculate oil in place and how you calculate these oil targets. And so we've got to be relatively blunt. It does not do us any good in the ground. We got to get it out of the ground. And so how do we get it out of the ground. Well, Charlie gave you a good perspective on that. The reservoir management is really important, so it's imperative that we're always using the tools that you got a taste of through Charlie's discussion on maximizing oil recovery from the reservoir. We do a lot of computer simulation. We use a lot of analogy from other fields to do the best designs to maximize recovery from the reservoir.
Third point is around project execution. Charlie's last slide talks about a repeatable process. And that's one of the beauties of CO2 flooding is whether the field is small like a small field in Mississippi or decent-sized like fields we visited In Hastings this morning or those very large size like we'll see in Cedar Creek Anticlines, the process is the same. In particular, we use a lot of the same type of equipment, the same approaches to our work. So we want to create a project execution. One of the ways we do that is through standardization and learning from our previous flood. We use it -- we kind of talk about it internally a bit as the Southwest Airlines model, which is they fly one airplane. They fly one airplane for a really good reason. They become incredibly efficient when you're just using one airplane, all right? Well, we use the same -- for those of you who visited the Hastings this morning, remember in particular, the large processing plant. That design that you see at Hastings is the same design that you'll see at virtually all our floods. It's a finely tuned design that applies the learnings over the past decade of our work. In fact, it builds on the works that Shell has done in previous years. And so the way we become more and more efficient is by using a standardized approach in design.
People. We have to have expertise in all phases of the CO2 life cycle. And as Charlie talked about, you get a sense for some of the skill sets that we got to be world class in. We believe we are. But I'll show you the slides in a minute. And as Phil mentioned, Denbury has grown a lot over the past several years, past decade, and we're going to grow a lot more. And so as we grow, were going to need more people. And so we address that really 2 ways. One is to hire some of the industries best to come join us. And also, we also train and train internally.
We've recently started what we called Denbury University, where we have in-house training program. And we also have what we call the Denbury Way, which is applied best practices that we've learned from developing a multitude of floods over many years and then trying to institutionalize that knowledge across Denbury. And so we believe our people are our greatest assets because they're the ones who come up with new ideas for how to make us better.
Last point is to always keep the return on investments. Our objective is to get better and better with our ultimate goal of always giving an approved investment -- return on investment.
And that last point on there is running new ideas and technology. We're never content with how -- with where we are. And so one of the key to success is really growing the company further is to look for new technology and new ideas. One of the things we did this year is to form a technology organization. And part of the assignment of that task, of that group is to do 2 things: one is to train the organization and onboard them with the Denbury away, but also identify some key areas where there might be some breakthrough technologies, some new ideas that might significantly enhance the value of the company. So Charlie runs that group, and we're excited about some of the things that are happening there.
Okay, so this will be my last one in 2012, then we'll we look forward to 2013. But 2012 has been a good year. Let me just highlight a few things that have been significant to us. Hastings and Oyster Bayou, 2 new floods in the Texas Gulf Coast. We've booked over close to 60 million barrels of reserves, and we've been really pleased with the production response this past year. In particular because the other fields that we have in the nearby area are of similar geography but also similar technically. and so it gives us a great confidence, as well as good learnings to build on that success into the future.
I might pause for a moment, and I was asked a question yesterday about what's the significance of booking reserves? Why do you guys make a big deal of being able to book the reserves? Well, it's an important milestone in the life of any field. The book reserves prove you are meeting a very stringent SEC guideline. And one of characteristics of that guideline is that 90% certainty, 90% of higher certainty that those reserves indeed will be economically produced. And so just to give you a sense of the confidence level we have in our reserves when we -- when I go to proved basis.
Moving to Tinsley and Heidelberg, those are 2 fields that we struggled with in 2011. As you heard with Tinsley, we had some old wells that had been improperly plugged by previous operators. And so we have to do a lot of work to resolve that. That was resolved and the field has really taken off in production.
Heidelberg had some conformance challenges, and those were overcome in late 2011 and in 2012, Heidelberg got back on track. And as Phil mentioned as well, we've added nice pieces to our portfolio of assets, in particular that will be future CO2 flood at Thompson in midyear, and then Western Hartzog Draw also will close. So a nice addition to our portfolio to build this into the future.
So let us move to 2013 in particular production. So in Phil's slide, he gave guidance on our 2013 production and he represented that production guidance as a range. So I'd like to spend a little bit of time talking a bit about the factors that will influence where we'd like to end up in that range. To be straight up with you, our objective is to be in the upper end of that range, similar to how we have ended up 2012. So what are the variables that influence that, and let me build on how material that Charlie had, as he proved, I think, the ultimate recovery from all side has a high confidence factor, and he talked about the worst flood we could find had a 10% recovery factor of oil in place.
We can't find the flood, CO2 flood that didn't work, just some basic screening work was done to make sure CO2 actually move oil. And so there's a high confidence factor in the long-term outcome of the CO2 flood, but there's also a bit of uncertainty, especially in the early phase of a flood, when it's first coming on, on what the month-to-month production is going to be. It can be quite lumpy. We'll use the word on a month-to-month basis, but when you look at it on a broader trend, the trend is actually quite predictable. And usually is -- in fact, as you see in our curve, a nice recovery of oil is in place. So with that as preamble, let me talk about 5 fields that we really pay close attention to this year as -- and move forward on as the year progresses.
First off creek, Bell Creek. Bell Creek is going to be our first flood in the Rocky Mountain. I'll show you a map, I will get into some more detail there. But we've made some assumptions and that we will start injecting into the Bell Creek field in the first quarter, and that will have a response in the Bell Creek Field about midyear, a little bit past midyear. Keys to that, all we have to get about 50 million a day of CO2 from ConocoPhillips plant in Lost Cabin. And so that work is all on track to be finished by year end. But there are some uncertainty about that because we don't operate that. Also, this is going to be our first flood in this area. And so just how well Bell Creek responds to the CO2 flooding, and particularly the timing of the response, there's some uncertainty there. It could be faster than what we forecasted and it could be significantly faster than we are forecasting, but it could be a bit delayed as well. And then when you're just talking a couple of months, it has a sizable impact on 2013 production, and yet not have a big impact on the ultimate value from the Bell Creek.
And we'll watch that pretty closely. Heidelberg, I'll talk a bit more. But we've got at East Heidelberg a slide, it's called the Christmas zone. We've just started 2 wells in that flood this year. So they've only got 2 wells. It's early production, numbers look good. But we kind of need to see that play out, so there's actually quite a bit of upside at East Heidelberg, but there's also some downside to our base case assumption on how that will respond, or the pace at which it will respond.
Moving to Hastings. Matt talked about we're going to be injecting in some down-dip patterns and Fault Block A this year. We'll see what the response there is. But there is some uncertainty, once again, as we move into some new patterns that are being developed. The good news there is Hastings has outperformed expectations for the past 12 months. We think we're positioned quite well there for continued good news at Hastings.
And really I could say anything about Oyster Bayou. We've assumed that the production growth rate will stay basically constant, so it'll continue to grow at the rate it's been growing over the past 12 months. But there are some scenarios where an oil bank will hit the producers. And that would be good, that would be a significant uplift to our production.
And lastly, but not the least, well certainly is Delhi, again we've got some new patterns that will be responding, so some uncertainty there. Also as you probably know, when we acquired the Delhi field, part of the agreement in the acquisition was at a certain threshold of operating profit, our net revenue interest would drop, and there's a part of that working interest and net rev interest that would go back to the original owner. We forecasted that will happen very late in 2013, but it's a function of how much oil we produce and what the price of oil is. And so if indeed the price of oil, however, that we’ve assumed and the pace of response from Delhi is faster, that date of revisionary interest moves up and our net production moves up a bit. So those are some of the variables -- in fact, those are the key variables that are going to influence, we believe, how we end up in that range. We're optimistic about 2013. We are positioned well for another successful year there.
So with that, let me start walking through some of the details of our assets. This is a slide of our Gulf Coast active floods. We've got 14 floods in the Gulf Coast region. You can see on the bar graph on the upper left corner, the reserves position over the course of -- over the past 14 years, a lovely story of growth, particularly in the reserves. You'll note, the 2012 addition of Hastings and Oyster Bayou that gets us up over 200 million barrels out of our -- the proved reserves out of our active floods.
Similar to the story of growing reserves is the story of growing production. So it's a beautiful story of growth. So this is a Gulf Coast tertiary oil production, 5,000 barrels a day in 2003 and see we're over 35,000 barrels a day at the -- end up in the latter part of 2012. So a great story of growth, which we believe sets a great foundation to continue that growth profile over the next decade.
So I'm going to give some detail on about 5 fields which will represent the bulk of where we're going to be investing in the Gulf Coast. I'll just give you a sense for what's driving the production growth, but also where we'll be spending our money. Now clear this slide, because you'll see this slide format several times. So far-left corner is the locator map, Hastings, for most of you who went to the filed trip this morning, it's just south of the Hobby Airport. So it's in actually -- just outside out of Houston and basically the greater Houston area. The production profile is in the upper right-hand corner. You can see the -- in the green, the conventional oil production, and we still have some conventional oil production in Hastings. But that lovely highly inclining purple curve is our tertiary oil production. So we would anticipated that, that production profile will continue to grow as we progress the flood. I'll show you a little bit more detail in a bit.
At the bottom right table is our treasury reserve and investment for the Hastings Field. So first column is reserves produced to date. We produce less than 1 million barrels of oil equivalent. We've got another 46 million barrels of proved reserves yet to produce, so we're early in the life cycle of the field. Cumulative investment we recovered. That's basically taking the total investment to date and then subtracting from that the revenue stream or operating profit from that. And so we've got about $334 million yet to recover before we break even. So if you see a positive number, that means we've paid off all of our cumulative investments, and down -- recognized a profit of that amount to date.
Then you see the PV-10 number, and so Hastings on -- just reaching the prove reserves has a PV or present value of over $1 billion. And on top of the proved reserve, we've got, we call, 2p and 3P here, probably and possible reserves of additional 24 million barrels.
In 2013, Matt described this just this morning, we're going to spend about $90 million, continuing the development of -- so we'll finish up the development of Fault Block A, and we'll also start some work in Fault Block B.
You can see our forecast for production profile that is where we will continue to grow. As I mentioned there's some upside related to if those lower patterns respond faster. We're trying to accelerate that with some increasing our CO2 recycle and our CO2 injection rates. And we're optimistic and pleased with how much Hastings is growing. That's been a great investment for us, we're going to continue that. As you can see and through 2019, so we'll be investing in Hastings for a good while.
Moving about 70 miles to the east of Houston is Oyster Bayou. So we just go across Galveston Bay, it’s close to the town of Cadillac is Oyster Bayou. It's been on production since December of last year. You can see the production profile in the top right corner. That's just a lovely production profile of growth. We expect that growth profile to continue. In fact, there is a reasonable scenario where that profile growth [ph] increases as an oil bank hit. We've not built that into our forecast assumption. It was in basically a relatively steady growth on -- growth rate, as you see there, but there's some upside, which impacts Oyster Bayou. 14 million barrels of proved reserves yet to come, $172 million of investment yet to be recovered before breakeven and you see $0.5 billion at present value.
Not much money is going to be spent in Oyster Bayou, it's fully developed. Our focus really is on ensuring that we keep CO2 flowing to the reservoir. We're looking at ways to increase the amount in a rate at which we can inject CO2. We do that through water disposal as well. But we really like what's going on in Oyster Bayou, optimistic about that in the future.
Moving to Delhi, maybe this is a geographic locator, that purple squiggly line by Delhi is Mississippi River. So this Delhi is located in North Louisiana, it's across the Mississippi River. It's source is Jackson Dome. You can see in the upper right the production profile for the Delhi Field.
And what you notice in particular is as we talked about in the third quarter conference call, is the Delhi production plateaued and wobbled a bit, kind of a bit lumpy in the middle of 2012. And that was due to a couple of things. One is we had some well work and some flood work that had to be done so there was some downtime. But also we were in some -- we were injecting in some new patterns in it, it just took a bit longer for those patterns to process the CO2. As we talked about in the third quarter conference call, we're seeing now a nice response at Delhi to move into the fourth quarter. And it appears to be once again back on the upper trend as we develop those areas.
You can see proved reserves of 26 million barrels; cumulative investment, $177 million yet to recover to break even; $1 billion net present value asset. So an important part of our portfolio. Just looking at the map view on the bottom right. What you can see in that blue circle is our area of focus and investment at Delhi. That's been about $40 million, and really what we're going to work on there is pattern optimization. We are going to invest in areas that have already been -- had one phase of development done, but they're stack paced within Delhi. And so when we spread Delhi and look for opportunities, the best opportunities came out where we found intervals of high oil saturation that were not being technically effectively flooded and swept. And so we're going to optimize those patterns this year. It's about $40 million investment. So we really like what we see here. As Charlie talked about, it's a high oil saturation target. We know how Delhi responds to CO2, we expect a really nice response from Delhi this year. So you see our production growth is anticipated to be relatively steady in its growth rate throughout the year, and then there's some commentary -- a little bit more commentary on the revisionary interest, going from roughly 76% to 57% at the latter part of 2013. We guesstimate that, that impact will be between 1,000 to 1,500 barrels a day net when that change occurs.
Okay, we'll keep it moving. East in the Mississippi, Heidelberg, it's an important field to us. You can see the production profile shown in the upper right-hand corner. That kind of bobble in 2011 is what we were struggling with some conformance issues. Those issues have been resolved. But also while we were looking at Heidelberg, we also look -- found more opportunities for development. And I'll talk about that in just a minute.
You can see the cumulative investment of Heidelberg, it's paid out all of its investment to date and has recovered $54 million more profit over and above what it cost. Almost $1 billion of net present value, $930 million.
Looking in Heidelberg for our investment program, we are going to spend $120 million in Heidelberg, the bulk of that being in the East Heidelberg. In particular, we're going to spend about 50-50 between the Eutaw and the Christmas zone. The Eutaw is a zone that we've been producing in for a good while. You see the maps on the right-hand side, you should envision that those 2 horizons sit atop each other. But the Christmas zone is one that we've focused on this year and really like the potential of the Christmas. And so you can see the activity we'll have there. We've got 2 wells producing in the Christmas now in East Heidelberg. We like what the initial response there is. And one of the uncertainties that I mentioned earlier was just how fast it will process, there's upside there on -- based on what those wells could get.
Moving to Tinsley. So this is a Mississippi, just northeast -- Northwest of Jackson. Again looking at the production profile of Tinsley, you can see a lovely curve of events in late 2011, that drop in production. That represent the trouble we had when we found some wells that had been improperly plugged by our previous operators. We had to shut in part of our CO2 injection in the field, while we got that fixed. We got it fixed. You can see it had a corresponding production impact in 2011. It also delayed our 2012 program and investment, and so you see that's why the production has plateaued there. We've -- Well, I'll talk about that in a second. You see the reserves produced today, the 7 million barrels, 30 million barrels proved yet to be recovered. We've recovered all of our investment absolutely, and it's $91 million profit above that. Significant net present value is shown.
Our investment program in Tinsley is about $33 million. We're going to continue the development of the North Fault Block. Modest decline, actually that's really more likely through the midyear as opposed to Q3, and then it will start growing midyear forward. But this is just continuing this very successful development of the Tinsley Field.
So I've covered 5 fields. There's another 9 fields that are relatively mature. So I'm not going to give much detail on that, but this just gives you just a sense of the production profile from those 9 fields.
Amongst those fields, we'll spend about $90 million in 2012. You can see the distribution of that money in the various fields. It is primarily to compete the development in some of those fields and also to do some maintenance or remedial work to optimize those floods.
The real focus of our activity in this area, in particular, is around operational excellence. It's over and above the capital investment. This is an area we believe that there is a hidden treasure, and that hidden treasure is around operating uptime, operational efficiency. And so this is our heritage older fields that we no longer have a aggressive capital program in. But we now want to have a very aggressive operational excellence program. And so we've got key performance indicators that we've established. We've got proven initiatives underway, and I'm really excited about what that means for the production profile in the out years.
Well that's -- we'll move from the active floods to the future floods. Starting in the Gulf Coast, Thompson, Conroe and Webster are our future floods there. As we've talked about a bit, those will build upon the success -- the proven success of Hastings and Oyster Bayou. They're close geographically, and they're close technically. They all produce from the free oil reservoir and so the -- some learnings we've had and that we're having from Hastings and Oyster Bayou, we get to immediately apply those learnings and those efficiencies to Webster, Conroe and Thompson., and they're very large targets.
So a little bit of detail about those. And from a timing standpoint, this year we'll spend about $50 million in those 3 fields, starting with Webster. Of course it's not ours yet, but we think it will be shortly. We're just closing it shortly. Conventional production will decline modestly. We'll spend about $20 million on conventional and recompletions. The next thing we'll be doing is actually assemble a technical team to get ready for CO2 injections in 2015.
Conroe Field, conventional production, we think, is on modest decline. We'll spend about $15 million there for some infill. But in particular, we've got a technical team working to optimize the development plan for -- with a view that by 2017 we'll be injecting CO2. Conroe will be at that point, the largest CO2 flood that we've got. It's over 1 billion barrels of oil in place. This is a phenomenal target. We're actually excited to get kind of going.
In the Thompson Field. Target midyear, production will be relative flat with some of the work we've done and are planning to do. And prepare for CO2 injection in 2018. It is not unitized. And so it's going to take a bit of time to get that unitized, which is one of the reasons it's sequenced in the program as it is.
A little bit more detail about Webster, it's not actually far from where we were this morning. Just to highlight a few things, produces from the same zone as Hastings. Large oil in place, 0.5 billion barrels of oil in place, with a 60 million to 75 million barrel EOR target. So it's very attractive
fill for us,just really build upon our expertise and learning curve. Not far off from Green pipeline, Bob will talk to you in a minute about that. And you see the reserves target we'll be pursuing.
With that, let's move north into the Rockies. Here is the slide, just a geographic locator. That main state you see, what you can see is Wyoming. We're basically going to replicate a very successful strategy that's been employed in the Gulf Coast to the Rocky Mountain. So what do you need? As we talked about, you need a large supply of CO2 -- a large secure supply of CO2. We have that with our Riley Ridge Field. It's just atop the 100 Bcf LaBarge Field. We'll connect then via a pipeline to large anchor EOR potential flood oil field. So we've got a small field, named Grieve. That's 6 million barrels filled with small field there. We've got -- we have the Hartzog Draw Field, which is a very nice field that stretches a few miles off the pipeline. We've got the Bell Creek Field, which is just across the Wyoming border into Montana and then the Cedar Creek Anticline, which is a huge target. To put it in context, Cedar Creek Anticline, it has an EOR target conservatively of 200 million barrels.
Just at a few slides back, our current crude reserve base is 70 million barrels, so massive amount of oil and massive EOR target for Cedar Creek Anticline.
So excited about the Rockies, where that's going to be as successful, if not more so, than our Gulf Coast. So with that, talking about Bell Creek. We're excited about the Bell Creek. This is going to be the inaugural year of EOR productions. You can see the stage of development in the right-hand map -- right-hand corner map. There is a typo. Phase 2 should be 2014 as opposed to 2013. But as you see, we'll be developing Bell Creek for [indiscernible] into 2019. Really, what drives the pace of development at Bell Creek is availability of CO2. It has conventional oil production, so you can see that production currently -- when we hear extra, we're going to show you a nice purple curve of increasing production. Because we expect Bell Creek production to be on about mid-year. You can see that in the bottom right-hand corner. We'll decline slightly in production through the first half and then grow when the production as EOR response. We'll spend about $100 million this year in Bell Creek, as we continue to develop that field.
So with that, we'll move to see the Cedar Creek Anticline. What's the objective of the Cedar Creek Anticline? And that's to improve the waterflood as well as to prepare for CO2 injection in 2017. So Phil mentioned as well, but let me just reinforce how big this is. You can see the dimensions on the map. It's 80 miles long, 3 miles wide. And you should -- while it's a collection of 10 fields, it's basically contiguous. 1 billion to 3 billion barrels of oil in place. And so as we worked on Cedar Creek Anticline, in particular, this year, what we've noticed is that the waterflood has been long ignored. And there'd been a significant opportunity to improve that waterflood response. And so, we're going to spend, of that $115 million, about $90 million of that on improving our waterflood. So what does that mean? We're going to clean up the water. We're going to clean up injection wells. We're going to inject more water into some zones. We're going to drill some infill wells so that our patterns are better balanced. We have a high degree of confidence that, that's going to be very successful and even open up more opportunities for us in the waterflood. What we like about that as well is all the work that we do in the waterflood is complementary and applicable to the future -- CO2 flooding as well. And so they're very synergistic.
On top of that waterflood work, we're going to spend probably about $25 million on some work to really better understand how CCA will respond to the waterflood, and in particular, help us to design the optimal flood for CCA. One of the things that really intrigued us is it has a massive column of oil. We've only looked at a small portion of it. When we talk about 200 million barrels of oil, we've actually only looked at a small portion of that column of oil. And so if we can figure out ways to mobilize more elements or sections within that column of oil, the opportunity for us goes up significantly. So we want to do that wisely. And so we'll do a bit of science for how best to optimize the design of our future flood. There is a -- we're looking into the opportunity to do a pilot -- a CO2 pilot in 2014. So there's some pre-work that we'll do this year to figure out if that's wise. And if so, how best to design that. So we'd like -- we like CCA -- it's going to be one of the catalysts for a significant growth through the decade.
Last slide is around Hartzog Draw, just to give you a little more insight into what's going to be part of our portfolio. You can see a large oil in place at 370 million, nice working interest at 83%, close to the Greencore pipeline. Bob will talk about that in a minute. It's only 12 miles away. We're going to spend about $13 million of CapEx this year, not much just to get that filled with a few recompletions. And you can see we anticipate starting that flood in 2016. What really drives that is just as soon as we can get a pipeline built there. So we really like the addition to our portfolio.
So with that, that concludes my comments. So let me just mention that we're finishing up 2012 on a strong note. We're really optimistic about 2013. We've got the assets, the people and the plan to deliver not only our 2013 program and our objectives. It should also set up the achievement of growth over the next decade.
So with that, let's turn it over to Bob.
Robert L. Cornelius
[indiscernible]. So let's -- well, that's too loud. So -- okay, now you got it. All right. What separates Denbury from a Kinder Morgan and from [indiscernible] Petroleum? And really what it is, it's a supply of CO2. Denbury controls the CO2 supply both in the Rocky Mountains and in the Gulf Coast area. And so, the story with Denbury has to start off with our Jackson Dome. And so, be patient for you people who have been here for awhile and know our story, because there's some people out here that don't. Jackson Dome is not really a dome. It's really about 10 fields, and we've shown those in a cartoon form here. And it's about a 40-square-mile area, just northwest or northeast of the City of Jackson, Mississippi. The reservoir is about 3 miles deep, and the sand is about 300-feet deep. And the pressures down there are wonderful to produce, and the CO2 is about 98% pure CO2. It is a industrial, pharmaceutical-grade CO2. You can use this CO2 for soda pop or you can use it for dry ice. You can use it for pharmaceuticals. So the dry ice is very -- the CO2 is very good. The other thing we have is a distribution system that, like Phil said, we have over 800 miles of distribution system from the port. So we can move it wherever we need it. And you can see Denbury acquired the Jackson Dome area in 2001, and we've been ramping up production ever since. So our production now is about 1.1 Bcf a day. So it's a race always between Denbury and Kinder -- I think right now, it's -- we're at 1.1. We'll probably produce as much CO2 as anybody in the country.
We drilled 4 wells in 2012. And as we said in our call, we didn't add any reserves. We were -- these were rate-based wells. We were trying to make sure that we have enough CO2 as we ramped up Oyster Bayou and as we move forward, with Hastings and other places.
Our well work or work next year is mostly going to be 5 wells. We're going to drill 5 wells next year in the Jackson Dome area. The other thing we're going to do is we're going to have a seismic program. We're going to shoot some seismic over part of this area, so we can better define the reservoirs and look at them. One thing we're going to do is we're going to do an enhanced seismic process. What we've seen, is when we look at some of the reservoirs, that we have places where the sands are better quality and the concentration of CO2 are higher. So this enhanced program is going to allow us to better define the waves, the fractures and so forth. And it's also going to better define what parts of the reservoir can be more productive. And then we're going to acquire some additional acreage, and then we're going to build out our facilities with some pipelines and some compressions.
Let me just take a second here and talk about -- this is the Gulf Coast area, obviously, from New Orleans area all the way to Houston area. You've -- Craig has already pointed out the fields that produce. Enhanced oil recovery are in blue. The other ones we own are in white. And the green pipeline is in green. So the other green pipeline and green pipeline is Texas. And that pipeline was routed back in 2007. And it was routed, and it starts out in around the Baton Rouge area. And we actually took the pipe and we put it in a northwesterly direction along the Mississippi River. And that was done so that we could capture the industrial complex that works along the Mississippi River, just north -- just in that part of Louisiana. So once we got it far enough north of the Mississippi River, we brought it over near Lake Charles, Louisiana. So if you've never been there, again, an industrial complex. We've been routing the pipeline through Beaumont, Port Arthur and Orange. Again, the chemical complex ended up crossing under Houston Ship Channel and then over -- and to -- up through [indiscernible] city and Texas City, again, industrial complex. So what we've done is we value this pipeline, where we think there's going to be a lot of anthropogenic CO2.
Since 2008, we have not had the kind of response that we thought. But recently, we have been able to get a lot of anthropogenic or manmade sources. Those are along the top line and the shaded area are all those that have contracts. These are already either in existence producing CO2 or will be constructed or under construction. Their products is about 50 million cubic feet a day, PCS nitrogen. Just at the end of our green line is 25. And then Mississippi Power up in Kemper County, it's going to be the first coal gasification project in United States, that's really going to produce CO2 for us along the Gulf Coast. And that's going to be completed in 2014. So we have about 190 million cubic feet a day that we're going to be able to add to our system in the near future. The 3 plants -- the 3 on the bottom line are ones that we have an agreement with that are not under construction. If you keep up with Leucadia, Lake Charles, that particular plant, we have an off-take agreement. They have an off-take agreement for all the products they're going to produce. They're just in the final stage of financing. Once that financing is done, then we'll be able to -- they'll start construction. And we hope that the capture date is before 2018.
In fact, let me give you a qualifier. When you read Leucadia's press releases, they think it's going to be end of 2016 or early '17. We want to be a little more conservative. We have to have the CO2 supplied in place for our timing. So what we've done is we've kind of put a little conservatism into that start date, the 2018. We also have an ammonia plant. It's 85. And a chemical plant, possibly above or 200 million cubic feet a day. So you add those up, that's 675 million cubic feet a day that we could get along the Gulf Coast area. Recall our productions was 1.1 Bcf a day. So we have a pretty good supply of CO2 in the near future to help us with Jackson Dome.
So let me build where we are on our CO2 supply and where we're going to go. So this chart is the CO2 volume in Mcf a day versus time. So you can see in 2000, we're about 775 million cubic feet a day. Today, we're a little over 1 Bcf a day. And our demand next year is going to be right at 1 Bcf a day. So from the bottom up, Jackson Dome proved reserves will give us a certain volume of gas. And then we put in the anthropogenic sources I just talked about. And these sources are the ones that were already under construction. So we feel like these sources are pretty secure and then we put the Jackson Dome risk. These are probable reserves. These are reserves that we've looked at with seismic. These are reserves that may be in a fault plain, but these are probable reserves which we are pretty confident with. And so we've kind of even risked those on top of that. So you can see that we have those -- and then we have the anthropogenic supply that's going to come on in the near future and yield enough CO2.
Also, I want to point out on the top part of the page, we also have probable and possible reserves at 3 Tcf. This would include the Smackover, the Buckner and some other northerly horizon that we know are there. There's 3 Tcfs there. We also can go in there, and we can do improved recovery of our reserves. And what we're going to do there is we can drop a flowing TB pressure. We can perforate additional intervals. We can look at the hydraulics within a well bore, and we think there's at least 0.82 of Bcf of reserve potential there.
And then finally, we have doing -- as Charlie pointed out in all this field, we're taking CO2 from a field that's been depleted. So once the field is completely depleted production-wise, let's take the Little Creek and other fields, we can begin to recycle, pull the CO2 out of the reservoir as required. And there's 3 Tcf there. So we have a potential of about 7 Tcf additional potential, the size that we show on this curve.
Real quick on the pipelines. The Webster lateral, we're already started looking at right of way. And we're already starting to scope that line. It's going to be a 12- to 14-mile piece of pipe. It's going to connect our Greencore, Texas pipeline, up to our Webster field. And we're going to invest about $11 million to start looking at right of way, start doing some regulatory work.
Conroe line. It's about 9 miles, and we've also started to do some work there. We've already got a bunch of the right-of-way acquired. We're already doing some regulatory work, and we're going to invest about $9.5 million to $10 million to continue that right-of-way work and the regulatory work required. So if need be, we could even accelerate that program if we needed to.
Then we continue to Rocky Mountains. As we've talked about, we have the Greencore pipeline, which is -- it's about finished. And then we've talked about the other pipelines we're going to put in. The one -- the things that -- the one you need toe see here, which you'll hear more about, is our planned interconnect, which is an interconnection line between the Greencore pipeline and Anadarko pipeline. So as we've talked about getting CO2 from Exxon, from their plant at Shute Creek, we'll bring that up their pipeline and into Anadarko's pipeline. We'll transport over to our Greencore pipeline and will be put it either in Hartzdog Draw or up to Bell Creek. So it's going to give us an opportunity to accelerate our plans at Hartzog Draw or put additional CO2 into Bell Creek Field. And there would be about another 700 miles of pipe in the Rocky Mountain over the next 5 years.
Shifting to the supply side in the Rocky Mountains. We have LaBarge Field that Craig talked about. LaBarge Field is just a wonderful field. It is 750 square miles in size. It has over 100 Tcf of CO2. And so Denbury was fortunate enough to be on the Riley Ridge unit, which we have about 100%. And it's 9,700-acre unit. And we're going to start production at about 135 million cubic feet of CO2 once we get up and running. We also have the adjoining units. We have the horseshoe unit, or we call that Rams Butted or Miami ditch. Both of these are -- or after that, we could possibly go ahead and get into production later in life.
ExxonMobil Shute Creek. We plan to sell or -- our plan is for them to sell us about 33% of the CO2 reserves. And then we also have, if that doesn't work, under our volume production time that we have with other deals, we can -- they will sell us the volumes that required up to 115 million cubic feet a day.
This is the same-type curve when we look at CO2 demand, and the Rocky Mountain's in red. And then -- and versus time. So you can see amidst this particular curve, we have Lost Cabin. It's going to come in about 50 million cubic feet a day that slowly -- that reservoir will slowly decline. But then we have the ExxonMobil CO2. It's going to come on again. We feel a pretty conservative forecast. It'll peak out at about 115 million cubic feet a day, and it will stay there for a long time.
And the Riley Ridge unit, as I mentioned, we'll ramp it up. We'll have about 135 million cubic feet a day of CO2. We'll do an expansion. We're going to try to do an expansion. Later in the life, we can double that volume.
And then the final one is DKRW Medicine Bow. It is a coal-to-liquids. And that plant also has plans to expand. So we put that into 2016 and ramped it up slowly. So you can see that we have -- definitely have enough CO2 supply in the Rocky Mountains. And in fact, if we needed to, like I said, we could expand the Rams Butte or the horseshoe area and have enough of CO2 to produce, with CCA Hartzog Draw and Bell Creek.
Finally, the Rocky Mountain activity. We expect to invest about $77 million up in the Rocky Mountains. We have Riley Ridge facilities. I think we've talked about it. The Riley Ridge is a plant that has a separate -- the H2S, the methane, the carbon dioxide and the helium. When we acquired that from the prior owner, we found that some of the metallurgy wasn't quite right. So when we did our review to start up, we had to reflect on that. We had to go back. We had to change some of that. That process is in place. We plan to have it in spring of next year. We'll start our pre-safety start-up. And as we point out here, by the second quarter, we should be in the operation of producing methane and helium.
We also proposed 2 wells. Our current development up here is to go ahead and expand. Normally, we have 2 producers. We ultimately will have 4 producers in injection wells to produce an input volume of about 200 million cubic feet a day of raw gas.
And then there are things we're doing up there. We've got a lot of work to do to start our initial right-of-way work up in the DKRW. We have to do our interconnect, and we have to do some things at Hartzog Draw. So all those things are going on next year.
Then finally, the Greencore pipeline. The Greencore pipeline is the first pipeline we put up there. It's a 232-mile pipe from Wyoming to Bell Creek. It's on time and on budget. Our total cost is probably going to be around right under $300 million. We expect to have it completed by mid-December. As Craig pointed out, we'll start loading it with gas from Lost Cabin plant. And we'll start that operation. It's going to take us a while. We've kind of spoiled. When you have Jackson Dome facility that has a Bcf capacity, you can boil some gas to that too, purge the line in these shaded lines. The pipeline is a pretty large pipeline from Lost Cabin. So it's going to take us a while. But as Craig pointed out, by the end of the first quarter, we'll be injecting at the Bell Creek.
So with that, I'll turn it over to Mark.
Mark C. Allen
All right. We'll round up the afternoon with -- a little bit of financial information and some great technical overview and overview of our assets and our plans for next year. So this first slide here is just -- is actually we stole from KeyBanc, I was talking to [indiscernible] earlier. [Indiscernible] see that we ask their permission to use it, but. We wanted to kind of display -- show you what different rates of return are anticipated, what indiscernible] had a 20% before-tax rate of return. And the green one there are customers placed on KeyBanc study. You can see we have the Bakken. There's 3 different cases. There's 600,000 locations -- 400,000 locations. And so if you take $72 oil price to get a 20% rate of return in the Bakken -- or 20% rate of return in the Bakken and at $87, that's $400,000 [indiscernible]. We also layered in our CO2 EOR space. This is a larger case out of our Gulf Coast region and have some historical evidence. There are historical results. But we're right in that model, and that would show the $50 NYMEX price to get to the equivalent 20% before-tax rate of return. And there's -- we did assume in there or looking at the details, it is our assumptions regarding differentials in oil price received versus NYMEX. I think the Eagle Ford has a $10 positive differential, and we received something similar, in our case, which is very reasonable, and I think, based on the premium were getting. Today, I also think that there's been some recent information on the Mississippian that would indicate that it may be not quite as good as what this case may show. But anyway, that's just for reference purposes and just for the support slide, we really believe what we're doing on the Gulf Coast and actually taking up the Rockies can yield us a great return over time.
This slide we've had in our deck for quite some time. For those of you who followed us, you will have seen it. But what we're doing here is basically just comparing and contrasting our EOR flood in the Gulf Coast versus our Bakken. And so this is actually based on our Gulf Coast model and layers in future expectations. And then typical Bakken well for us were actually one we kind of picked one of our Cherry Wells, which is a pretty good well for us, 575,000 BOE well price, $9.6 million investment and 20% royalty. So still at that $90 oil price in those scenarios. And as you heard our discussion earlier, [indiscernible] one of the primary differences is the EOR, our planning development cost is lower. Operating cost is higher. In the Bakken or the shale plays, the planning development cost is higher and the operating cost is lower. So you can see the numbers rate out there. We also [indiscernible] 2 scenarios to the tune of $10 [indiscernible] for the Bakken and $1.25 for Gulf Coast EOR. Today, these are more, I guess, historical differential. Today, our EOR model is significant premium that we have over $10 premium in the third quarter. So there are some differences today versus what we are showing. But we try to do this in somewhat of an average or normalized basis. So you can see the estimated gross margin is very similar under the two basis. But the EOR model yields a higher-rate return and a higher return on our investment. And the reason why that is, what we did here is we've took the same model and layered in the capital spending profile. And the green line represents the Bakken production curve and that basically shows us we invest, starting at $83 million a year. You can see the amounts listed there how much our capital investment is in here and what the production profile would yield. That is the same capital spending profile that is used for the EOR floods. And you can see that's the green line. And so that ramps up. If there is a delay, we assume the 3-year delay between the 2. So there's time to get the injection, get the facility and get the response to the EOR and to the injected CO2. But once the production ramps up in a more prolific manner, it stays higher for a longer period of time, therefore, generating that extra free cash flow and higher rate of return.
And our financial position. We feel very good about where we sit today. At the end of the third quarter, we have $625 million drawn on our $1.6 billion bank line. So we're 37% debt-to-cap ratio. I mentioned on the call a week ago, we can go that assuming the Bakken transaction does not occur, we'll have somewhere between $700 million to $800 million probably drawn on our bank line at the end of the year. And if you go back, I guess, to a year ago, when we kind of walked through this, we estimated cash flow at that time for 2012 was about $1.2 billion to $1.4 billion. We showed you our capital and [indiscernible] in how we are going to pay for it. [indiscernible] that we're trying to be very neutral between capital and cash flow. So this year, we baked that in. We started the year around just under $400 million of bank debt. And if you take that out, basically, the increase in our bank debt from last year and this year would basically represented by the Thompson acquisition. So we effectively done what we said, we covered our capital with cash flow and other sales. So we sit here today, I think, in very good financial position and if the Bakken deal closes as we anticipate, we'll discuss the -- we'll look our alternatives there for paying down debt [indiscernible]. We would project to pay down our bank line with the proceeds that we do have.
Our financial or our debt position has various components. So I guess some people, you got some higher-rate notes there. Yes, we're aware of that. So they become callable early next year. So there's an opportunity there for us to make those a little bit more attractive or such that it fits very nicely. We continue to watch that market. If you look at our annualized Q3 adjusted cash flow, this is about $1.4 billion. Kind of what we're projecting for annualized basis -- or projected basis for the year and like we said last year. And then also our Q3 annualized EBITDA, you can see there with our rates are about 1.85x, 1.9x and 2x for cash flow. So our debt metrics are well in check. We feel good about where we sit today.
Phil and Craig now will walk through our capital budget. So you can see him out there at $1 billion. The $1 billion does not include about $125 million that we estimate for capitalized interest, which kind of a round number of, say, about $40 million. Of that capitalize expiration, about $50 million of that and the rest of would be made up of what we call pre-production kind of tertiary costs, which is primarily related to Bell Creek and the period where we're injecting CO2 and before production commences next year and that would make up about, round out the balance there.
You can see here, we've estimated our cash flow 2013. We're showing here $850 million to $1,050,000,000. Now this is not necessarily meant to be exact or precise but to show you a couple of things. One is that for the $10 difference in oil price if you can see, assuming of an average between $85 and $95. There's about a $200 million difference in cash flow for a $10 adjustment in oil price. It also assumes somewhat of an average differential, so we're not taking it to the positive extreme or negative extreme. We also are not necessarily assuming the highest pace on production. So there is upside to what we're showing here and there's also potentially some downside. The downside, I think, is relatively relative because if you look at our hedging position for next year, we have floors at $80, so we're pretty well hedged. Anyway, that gives you a snapshot of how we look at 2013 and where we're kind of shaking out. So this would show anywhere from maybe slightly outstanding cash flow, if you include capitalized interest and other things to -- and maybe a little bit higher number. But based on what we see, our financial position, we see it as very doable.
Back in May, we had some discussions. We're looking at a little bit lower oil price environment, and so we kind of started to talk more about how our models can play out very well in an lower oil price environment. We do have a lot of flexibility. I think sometimes people look at our financial model or our projections. And they look at knowing that our capital commitments out into the future. Yes, we do have some dollars that we need spend. But the commitments today are not necessarily locked in. Unlike Bakken, where you have rates locked in for years potentially, our capital spending can be moved around and instantly have a pipeline under construction. And such, maybe that becomes a little bit more difficult. But -- or where you have a pipeline order. So in general, we have the ability to slide our capital programs around quite a bit. And especially, as we look into the Rockies, that's something that we are toying with, so if you see us roll out from changes to our model because of recent acquisitions. And such, we still have a good amount of flexibility to those projects. In contrast to shale plays, we could reduce our capital spending and we want to see that immediate drop in production. A lot of our -- so far, our production today is relatively new plays but are still ramping up and require very little capital to be spent in the near term. We also -- unlike a shale play we're not dealing with lease expiration issues. So we don't have to spend that money. If you think past the 2008, 2009, we're in the midst of building the Green Pipeline. And we didn't shut it down, but we slowed it down and stretch out another year. We were able to manage our capital and cash flow quite well. It's something recently -- with every channels we're taking, we look at our profile over the next several years and see what would it take for this kind of old our production flat in terms of the capital spending. And pretty interesting, what came back, and if you look at 2013 and beyond for the next couple of years, 50% and trending down quite a bit lower would be reasonable for us to look at holding revenue flat. It gives us a great deal of confidence when we look out into the future and a flexibility that we have the ability to adjust through varying all types of environment.
Phil walked through the direction growth year-over-year, kind of a big way. We'll show you the results for more detail is broken out on this slide. You can see the details regarding the Texas non-tertiary and other Gulf Coast non-tertiary, Cedar Creek Anticline and other Rockies. Most of the increases in those from year-to-year are related to a recent acquisition we've done this year or we'll be completing with the Bakken transaction. So is -- that's why the production will be increasing in those areas. Cedar Creek Anticline, we are spending some money, so we expect that have a little bit positive impact there. And then the Gulf coast, there are non-tertiary, discontinued declining in there and them some of those fields over to EOR. Overall production profile would remain relatively consistent at 93% where we are today.
This shows the financial results for the last quarter and then the first 9 months of the year. I'm not going to go through this in some great detail, but you can see there we can start with net income and then we can get down to what we reported, our adjusted net income. We typically have a fair value adjustment for derivatives every quarter. And then you can see there throughout the rest of the year, we've had some other adjustments of either kind of more onetime in nature or unusual or things that you may not be anticipating in your models. And so we've walked through those in this quarter as they occurred.
At the bottom, you can see our cash flow from operations, which we call our adjusted cash flow, which is before working capital changes. And you can see there we're on a trend to hit the higher end of our targeted range for the year.
This year shows some pro forma effects for the Bakken transactions. I'll walk through some of those for Q3 on the call. This takes more of the year-to-date approach. This would not assume Hartzog or Webster being added into the number. So it's nearly just backing up the Bakken assets from the year-to-date numbers. And so you could see the impact on production. The oil production mix was up slightly, but we would expect that to remain about 93%. Once you factor in Webster and Hartzog, differential actually improves. Obviously, moving the higher negative differential Bakken production out of our profile helps us. The LOE per BOE, this one jumps up at about $24 but gets back to more of our long-term model for EOR and more of where we currently are from the EOR standpoint. Also, I would say that Webster and Hartzog in constant can either similar or higher LOE per BOE cost, so this number will likely drive up looking into the future.
Operating margin overall, from differential, we picked up a positive differential pickup versus the higher LOE. It still results in a net positive operating margin for us as we look forward. And our DD&A per BOE, with the Bakken transaction, the 1.6 billion or whatever it ends up being, coming back in and upsetting our pool, we'll have the impact of reducing our DD&A on a per BOE basis going forward. That number will move around next year. It's a little bit imprecise at this time because it will be determined based on the fair values used on the closing of the transaction. But today, I would estimate that probably to end up in the $17 to $19 per BOE range kind of going forward after the Bakken transaction and depending on other potential transactions.
From an operating cash flow standpoint, for the first 9 months, we generated about $250 million for the Bakken assets to be sold, and we had capital expenditures around $340 million. So net free cash flow -- negative free cash flow of $90 million. Anyway, I hope that helps you a little bit to get sense of some of the impacts from the Bakken transaction and as you look forward into 2013.
NYMEX differential, you can see here, throughout 2011 and 2012, we've enjoyed a very nice premium in our Gulf Coast tertiary operations. Most of that production received the LLS pricing component, which has been a significant premium. So you can see how that has trended throughout 2011, 2012. We see here recently it's actually probably improving a little bit from where we were in Q3.
The Bakken, yes, I pointed out the positive move from the Bakken transaction on our differential overall. You can see there the impact of the Bakken assets each quarter that were a negative drag. The other things have remained relatively stable, but you can see some movement. So that will help you in your modeling efforts going forward. This just kind of shows the correlation between NYMEX and LLS and we also threw in Brent in there. Now Brent gets a little bit more recognition than LLS, but you can see over to last year here, the 2 moved very much in tandem, at times, one of the other kind of breaking out in front of the other. But that is kind of what we're talking about as we look at LLS and what we're getting through our Gulf Coast tertiary operations.
In the Rockies region, there's a little bit more distortion going on at various times. We see that small disruptions in take-away capacity at certain areas can cause big movement in the differential we see. So through a lot of the end of the first quarter and second quarter, even third, we've seen pretty high negative differentials up there. We've actually seen those narrow quite a bit recently. I think a lot of our production teams use Clearbrook or Guernsey, and those have actually been close to NYMEX or even positive to NYMEX. However, there is a transportation fee that needs to be taken off of it. So when you see those things kind of turning positive, that doesn't mean that's what we're getting because there is a transportation deduction if we can get it there. But anyway, you can see here that the -- why some of the differentials have occurred earlier in the year.
From a hedging position, we feel very good about where we are. In the third quarter, we restructured most of our hedges in the first 3 quarters of 2013 to put on an $80 floor. It could give us some of our cap on that, but as you can see, our remaining cap is still very good and averaging kind of around the upper $108, $109 range for a good part of the year and $119 in Q4. And then we also hedged out through the first half of 2014 with $80 floors and slightly over $100 in cap. So we feel really good about where we are today on a hedging profile.
Financial data per BOE. A lot of this in our quarterly reviews. But I'll use this just to kind of reinforce a couple of points in 2013. If you're looking at your models, LOE, as you see here for Q3 was about $19.50 on a corporate-wide basis. And as I showed you on the pro forma information for the Bakken, you'll see that coming up quite a bit once you take the Bakken out of that. So somewhere in the mid-25s or more. We're still declining our LOE forecast for next year, but we do expect that to be upward trend on the BOE -- LOE per BOE.
G&A. We do not anticipate big changes in our G&A or reduction as a result of the Bakken transaction. We continue to grow. We continue to expand our business. And so we talk about our G&A in terms of more of a dollar amount. We kind of been in mid- to upper $30 million range. I would expect to see that continue in probably the upper $30 million to even lower $40 million range as we look at next year. And also, recall that our G&A tends to be a little bit higher in the first quarter than it does throughout the rest of the year.
Interest, cash interest. I do see our capitalized interest is going down a little bit next year. I mentioned somewhere maybe around $40 million, and I see that kind of trending down throughout the year. Our Greencore pipeline should come in the end of the year, which we will see capitalization on that. Also around midyear, we expect to see capitalization on Bell Creek and Riley Ridge. So those are the 2 -- or 3 big items next year. So we'll start off higher in the year and trend down more towards the end of the year.
Taxes. We expect our rates to continue to be between 38%, 39%, with current taxes access maybe around 5% to 10% of our total taxes, just kind of where they have been running. So not too much of a change there.
Just a little bit more detail on our tertiary operating cost. You could see that between power and fuel and CO2 costs, they make almost 50% of our total operating costs there. The other items, not a whole lot are moving in. I will mention, if you recall in the second quarter, we did make some changes as to how we report our leases. And so removed that from an operating expense, and we now have our leases in our books instead of it comes through more as payment and interest. But overall, you can see the trend there and have an understanding what the drivers are around that. And obviously, oil prices have an impact on our cost of CO2.
And this slide demonstrates that over the last few years, you can see how the NYMEX price movement has impacted our overall cost of CO2 coming out of Jackson Dome. The green bar there represents what we pay in royalties to owners of the CO2. The blue bar represents underlying LOE cost, production cost, of the CO2. And then we have some taxes. So you can see in Q3, our cost of CO2 coming out of Jackson Dome average around $0.25 per Mcf. And you can see the lines there shows you what the NYMEX prices are. So you can see when that moves up. And usually, the impact there will be on the royalties we pay.
And lastly, this is just more production detail for you, also available on our 10-Q. I'll just lay it out here for you. And as we did mention recently in our conference call, we have seen our tertiary production pick up. For October, we think they are probably around 36,000 or so barrels per day, and Tinsley Field -- or Delhi Field has been a good contributor to that recent uptick. So we're encouraged about what we're seeing. So hopefully, that gives you a little bit of understanding of what we're looking at in 2013 and for our financial projection. Phil?
Thank you guys. Just to reiterate a couple of points, kind of going backwards our remarks. I think one of the cool things is, I don't know if you got it, but if we adjust our capital budget, we can cut our budget about in half for the next several years and keep production flat. I think that's actually a fairly important thing. So if you get concerned about downturns and drops in prices and that sort of thing, we actually do quite well. You also saw that we have breakeven at one of the lowest in the industry.
Secondly, selling the Bakken, while it was creating value and production growth, it was a user of cash. Even though we had slowed down the rig program, we still were spending more than we make there. If we buy something, it will likely be PDP, and it will be strategic. It will an ultimate EOR flood, but it would be a provider of cash. So it would be quite a difference between the 2. So if we're fortunate enough to get an acquisition or 2, I think it will be very accretive to cash flow and also very helpful for free cash.
Bob, the key think there was we've looked at Jackson Dome really hard. That slide, we actually spent a lot of time on. So we have worked out our program. We have a risk drilling program. Those were risk numbers in that one red in that wedge. So we have taken the accounting potential failures. And in addition, as you can see, we had the curve pretty well covered there. That box on the top left, by the way, is addition over and above what's in that curve. It was one analyst report that came out right away, and there was confusion there. They thought that, that was our total upside potential. Now we have the potential in the curve and the different slices, and then there's about another 7 Tcf on top of that.
So we feel like we have a couple of different alternative plans. If those NYMEX forces don't develop, we will do just more drilling, and we have a way to cover it. So we work very hard to make sure we have enough CO2 to do the Gulf Coast program. Craig showed all the different things we have to do, and he went through that very well. The part I liked about Craig is he talked about operational effectiveness. And basically, that means we're not happy with where we're at, and we're going to get better. So that really is the theme at Denbury. And that's something he's worked very hard on, and I know the rest of us all have that same attitude.
Charlie, I know Charlie's dry hole. It means we're getting low teens recovery rate and the upper teens rate of return. So not a bad business, if that's your dry hole. Compare that to some of our peers. I think it should give you a lot of assurance that the EOR process is something that's been going on for years, and it works very well.
The summary slide here. We've talked about all these different things. What -- I guess we're creating lots of value. I think that's the theme we definitely want you to get. We have this substantial cash flow, as illustrated by this slide, coming up in the future. We're going to take the ExxonMobil proceeds, we're going to be very aggressive in buying our stock, up to $500 million. Basically, we see it is undervalued, and so we see that as a very accretive both to cash flow and NAV. So something we're going to pursue starting very soon.
So with that, we have a little bit of time. If any of you have questions for any of the presentations, we would be happy to do that. We have our slide. That was magic. I didn't even do that. We'll bring you a microphone. And if I can't answer it, I have 4 guys smarter than I am who can.
So just following up on the Jackson Dome, Slide 83, you just were illustrating that anthropogenic is not the top. You still got this additional CO2 potential that you illustrated in the box. I was just curious, what happened between last month's presentation where I think you showed about 4.5 Tcf or so of probable and proved reserves at Jackson Dome and now it's 3 Tcf? Is it just the risk that's occurring?
Craig J. McPherson
Yes, this is Craig. I'm not going to flip back because this takes a while. But this, the risk drilling program there, that's at least 3 Tcf. And that's on a risk basis. Plus you have 3 Tcf in addition to that. Those are additive. So if you will, the number didn't shrink. It actually expanded just a little bit. Does that make sense?
That does make sense. And then on Slide 88, on Rocky Mount CO2 supply, I don't mean to be pessimistic, but DKRW has been trying to get their project done for a long, long time. And a coal -- some sort of coal gasification might be challenging in the Obama administration second term. And it looks like if you don't have DKRW come online, that you might be a little bit short on CO2 in, say, 2017 and 2018.
Craig J. McPherson
Well, the backbone to that one is we have put what's in our current capital expenditure model for Riley Ridge, and so that's what's factored in there. However, Riley Ridge is a very large resource that's producing from the same one Exxon is producing volume, and so we can expand that really to almost any volume that you need. It's just how many wells do we drill, how big a facility do you build. So Riley Ridge is the backbone of the whole North EOR play, and the nice part of it is too, it gives us -- there's other Exxon talk about maybe expanding there. I mean, there's other sources that may or may not happen that we have -- we can control our investment with Riley Ridge and we can follow that up to whatever extent we need to. So what we showed there is just what we have currently planned in the capital program. It could be expanded, and it could go faster.
I just have one more quick question, if that's all right. On Slide 78 where you're talking about the Hartzog Draw Field, earlier you were talking about recovery factors kind of being at 10% at the low end and potentially up to the high teens. I was just doing the math there, and it looks like the recovery factor is only about 7%. I was just wondering why that would be lower than the ranges you were kind of giving earlier.
Craig J. McPherson
I'm going to guess, correct me if I'm wrong, it's one less floodable area. And one, it is taken out in net revenue interest versus gross working interest.
Chris Robertson with Mackenzie. On Slide 59, you gave guidance of how many wells you'll be drilling at Hastings. I was wondering, out of those 16, how many are injector wells versus how many are production wells and if you gave guidance on the cost per well?
Craig J. McPherson
I'm going to beg -- I want to get out of this question. Cost, $1.2 million, I'll just repeat it, per well.
Charles E. Gibson
I think the well count is about 50-50. As we move off structure and get away from the top of the reservoir, most of those wells have been closed. So everything has to be redrilled. But we can get those numbers, Matt can get those numbers, for sure.
Phil, we saw the key drivers of the variability and the enhanced recovery growth rate for next year. Moving beyond that, are you going to see that variability start to contract some? I was thinking when you have more fields online that you'd start to take some of that variability out of it. How do you see it going forward?
Yes, we use -- for the guidance, we use -- it's actually the same range, I think, as we did last year. I think it's very much the same. I mean, I think a lot of this is just we're trying to give ourselves a little room just in case. I mean, we're actually optimistic. And in fact, there's some significant upside. In the initial flood zone, these new ones, they are ones that's the most variable. And its -- Oyster Bayou, as example, is not growing as fast as we originally said. And that's actually a factor in 2013. However, Hastings, we're ahead. So you have 2 fields. You're right, you're starting to get the portfolio, and it does help kind of make it more in the center of the forecast. That's why we're going to be slightly above midpoint this year, a little bit above. But we're still -- if they all go the wrong way or if Oyster Bayou and Hastings both have gone the same direction, it would have been a tough year for 2012. So we're just trying to illustrate that it's a little hard to forecast on these new floods. But we think we're doing to better job of managing that. We'll exceed expectations in '12 and hopefully as well in 2013.
Phil, can you just remind us the kind of generic booking process for an EOR? And how does -- what's the timing of 2P and 3P becoming 1P?
Usually, we, as illustrated by, I guess, probably the Hastings or Oyster Bayou, normally we book about somewhere in the 70%, 75% range of the 3P number on initial bookings. I don't know that I have any science as to why we do that except it's just kind of become our conservative nature. As you know, our reserves are done by an independent engineer. It's the most conservative method to do in proved reserves because they prepare the numbers. It's not an audited number, which potentially you could, at least in theory, get a little stronger number. And then usually after the initial booking, we would hope to see the initial -- get up to that 3P number over, probably, a series of several years. And it comes in usually 1 million barrels here and 1 million barrels there. It's usually not a big chunk.
And so what recovery factors do you guys use in your 3P? And at what point if you're higher or lower, do you make adjustments?
Well, the recovery factor varies by field in the 3P. So Charlie gave you a few of those of what we expect at Mallalieu et cetera, and they were all slightly different. So sometimes we're settle on that 17%, which was a Little Creek history. And that probably is a fairly common 3P number, but it does vary. It varies from low to mid-20s down to, what, probably about 12% from the bottom in. Hastings is booked at 12% now.
15% 2Ps. So that's one of the lower ends. So the ranges that we give in those Gulf Coast fields is to represent that range because we're still not really sure what will come out of that.
If I can point to Slide 69, can you just give us a sense, maybe, Craig, of the decline that we should be modeling in for the mature fields. And I guess secondarily, if you think there's an opportunity, I guess, CO2 injection will slow in this field and you might, I guess, stop it over time as these are getting more mature. And then I guess if you go that route then, since you called them mature, you will have a shelf life in Denbury?
Craig J. McPherson
First question, what's the decline rate? So decline rate is field dependent, but in general, around 10% to 12% if we do the incremental investment, what we've modeled in. And that's the [indiscernible]. Second question was -- sorry?
In the earlier slides, 3 or 4 years ago had talked about getting to a point in the fields life where you, I guess, stop injecting in the fields and kind of move on. Is that in the near future for these fields?
Craig J. McPherson
It is not in the near future. And so we look economics of these fields when that occurs. So we don't see that occurring in the near term. We do look at that regularly. What we're looking at, at the moment though is optimum distribution of CO2. And so what we have not done historically that we're going to start doing is to be in that collection of 9 mature fields. We may shift that CO2 distribution. We believe there's some upside there with optimization. And I think that's more likely the case because there's question around the shelf life [indiscernible] this is the last phase of development. So we will produce this until end of the life and don't all get fields seem to never die. And so likely, history says we're like a conservative on that outlook -- on a long-term basis.
Some of these fields, we've been able to really slow down the rate of decline. So Little Creek is not included there, but if you really look at Little Creek, it's really flattened out. And we've actually, in some cases, have brought it back up and had a slight increase and back down again. So some of these curves, to your point, they never die. Some of these, we actually get quite flat. So obviously, there was another one that's expected to be flat or so because we're expanding that flood. There's still a little bit of work, and so we were doing the daily one side of the field historically, and now we're going to the other side of the field. And so that's going to get a little bit bumpy uptick in production, too. So while the orange curve looks a little steep, I think if you kind of look at the individual curves, you'll see a lot of times we can kind of flatten those out or get a little bit of initial steep decline, and that then kind of starts to slow down, the curve, and flatten.
On Page 98, you mentioned that you can hold your production flat over the next several years with about half of current CapEx. First question, just a clarification, is that mainly for tertiary production and also tertiary CapEx? Or is that the company as a whole? And a second question is, can you just kind of help us think more about that, like what kind of math do you guys use to get to that number just given that? Because I think if we say of the whole company, about $0.5 billion of CapEx this year is for future production, and that is the nature of tertiary, which we all understand, but it's hard to kind of get a grasp around those numbers.
Yes, it is tertiary only. It's actually what that is, although total company was not that much different either, to be honest. We actually ran models. We developed kind of a more sophisticated model we can play with timing of things, and we actually schedule them out. So we could show you the schedule. The reason it happens is you take out a lot of the spending on new floods, new infrastructure and so forth and you just cut that off. And so you're spending money to finish floods of fields that have already started, and those -- that's quite accretive. And so you don't spend a lot of money to keep the flood going and keep the production growing in some of those. And you postpone CCA, for example, or you postpone maybe even Conroe. I think in one of them, we postponed Conroe, didn't we?
Craig J. McPherson
Yes. So if you -- the EOR floods are a little capital intensive at the beginning and you spend money and don't get anything for a little while, so conceptually, what you're doing is you take all that out and you can go for several years with actually very little spending to keep production flat.
No, because the timing of our expenditure is so different. A lot of those statistics get a little bit meaningless for us because in most cases, the money we spend in a given year benefits future years. And so it's just -- I'll give you an example. The year we went down -- we cut spending way back when we put the Green pipeline in. I think we cut it back to -- there was about 2/3 of our spending for the pipeline, about the 1/3 for EOR. And we actually still had, I think, 20% growth that year or something in EOR. The point being is the money spent in that year really for next year, and the next year, we have a little bit light growth because it was kind of a delayed impact.
Can you give us some idea what assets you've identified potentially for like kind of exchange, however generically you want to talk about it?
It will be very generically. There will be fields that, as I mentioned, would be future EOR fields. So it would an oilfield in one of our 2 core areas that we would plan to flood the CO2? And they're probably crude producing properties when they get to the floods for several years, but they obviously give PDP cash flow. However, to give you color, we've had discussions with several people, but some have already said no, or wanted a very exorbitant price. That was just down to a small handful. And we will -- we may even know by the time we flood or by the time we close. We'll probably know what deals are still alive by the time we close. But we'll have to make some of that decision at closing because it depends on how much money we put into the trust.
So small handful means you're in negotiations on 1 to 5?
I guess that meets that definition, yes.
And if you have 100% success, can you talk about what that would mean in terms of the ultimate kind of post-Bakken price adjustment? That's my last question.
Yes, I think that's tough to answer. There are varying sizes, and it's almost certain we will won't have 100% success. If we do well, we'll lower a lot of the tax leakage and end up with some very accretive properties. If it doesn't go so well, then we'll pay down debt and we'll buy some stock and we'll do all that. So do keep in mind that tax number is -- the headline number is probably half or less than that, that you actually save because of the present value of taxes you pay.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
My question is on that as well. Ryan Oatman of SunTrust. Can you just walk us through how the tax implication would flow through cash flow statement, income statement, if the company decided not to pursue EOR properties?
If we don't buy anything? You want to know how the tax works if you buy something? If you don't? I don't know where it goes in the income statement.
Mark C. Allen
That cash tax will impact in the period that we determine that we don't have any identified properties by the end of the year. It will get turned tax. So that would distort the numbers from a cash flow standpoint. So that's where the numbers would show up. It wouldn't change them, it would just change from deferred to current.
I do remember seeing Shute Creek before. In fact, there was a CO2 search. Is that just another field that's on the LaBarge structure?
Just another name for it, yes. It's an Exxon plant. It's single, same source. Exxon is the only one that's producing from that formation today. We'll be the second one to produce. But it's a very, very large area, somewhere around 700 square miles.
Where is that CO2 going now?
Well, they're denting part of that, I believe. A big bulk of their CO2 is going to Anadarko up that pipeline to Salt Creek. So Anadarko is by far the biggest user of that. There's a small amount going to a couple of other floods that are kind of very mature. Devin had one -- Merit had one. Those are all on their last stages of life. But Anadarko is the big user. And we are, in essence, getting the balance of what's left based on the current plant size.
Craig J. McPherson
Phil, I'm not going to ask you a question, but I will just respond to the question on Hastings a little more specifically. The 16 wells drilled at Hastings, 4 producers, 9 injectors, 3 water supply wells. In addition, we plan to reactivate 24 existing wells, 14 of them producers, 10 injectors. So if you add all that up, Charlie, was almost spot-on with about 50-50 producers to injectors.
Charlie used to oversee the -- until last -- just a few months ago. Charlie oversaw the West region. So he did have Hastings until just recently. So he's a good guy to ask those questions. Matt has only been with us for 4 months. And Charlie now is overseeing our planning and our technology group. So he's looking at some interesting things, new technologies. He's really helped develop this new planning model we have. And we're putting a lot of emphasis on that. That's one of our initiatives going forward.
Phil, do you have any capital requirements for the Tuscaloosa in 2013?
We do not have any in the budget, no.
What are you hearing from EnCana on what they're thinking about the flood?
I don't know that we've heard much, to be honest. So you probably know as much as we do. What you see in the public whatever they put out. But we have not participated in any of those since we got past what they -- the part they paid for.
Okay. We will -- the management group is going to do a lot of one-on-ones the next few days. Craig and I are going down to the Bank of America conference. We're flying down there tonight. We'll be there tomorrow and presenting one-on-ones. We will repeat this conference. Craig and I will go to -- Wednesday morning in New York at a little faster pace. And in New York. And then I'm going to Chicago. And Mark and Charlie, I believe, are going West and going to hit the West Coast. So if you want to sort of be in one-on-ones in the next few days or whatever, it's probably already pretty full, but check with our Investor Relations group. Jack is here. He's in the back. Wave your hand, Jack. He's the head of IR. Ernesto's in the background, on the computers, making everything work. Ernesto put all of these slides together. That is impressive. If he looks at you cross-eyed, that's why. And then we have Doug and Cynthia supporting us. So obviously, those are the ones behind the scenes and did all this work for the team. We appreciate all the help. So thank you very much for attending. We'll be around for a few minutes. We do actually have to catch a flight. So we won't be here for very long. But thank you for coming.
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