QEP Resources, Inc. (NYSE:QEP)
November 14, 2011 9:00 am ET
Richard J. Doleshek - Chief Financial Officer, Executive Vice President and Treasurer
Jay B. Neese - Executive Vice President
Vincent Rigatti -
Perry H. Richards - Senior Vice President of Field Services
Paul Matheny -
Linden Bailey -
Unknown Executive -
Charles B. Stanley - Chief Executive Officer, President and Director
Scott Gutberlet - Director of Investor Relations
Jeffrey Thompson -
Andrew Coleman - Raymond James & Associates, Inc., Research Division
William B. D. Butler - Stephens Inc., Research Division
All right, let's go ahead and get started. I want to welcome everybody to the QEP Resources Analyst Day. This is our first Analyst Day as a public company. My name is Scott Gutberlet. I'm the Director of Investor Relations for QEP. I'm going to be handling the day here, trying to keep us on time and keep us rolling along.
Some logistics before we get started. We actually have 2 rooms here. We've got this room and then we've got the Reed Salon across the hall here. If you have phone calls, stuff you need to take care of, you can go across the hall. There's tables and whatnot to do some things and there's wireless service over in the Reed Salon as well.
Secondly, I want to welcome those that are on the webcast. This is a live webcast, and I want to welcome everybody that is tuning in via the Web. It's great to see so many existing shareowners here, and hopefully, we'll convince a few of the others to become shareholders as well at the end of the day.
A couple of things. Two people I want to introduce. Robert Ferguson and Laura Clayman. I think they're still out at the check-in desk. If you have any need throughout the day, please find one of them.
We put out a press release this morning, a guidance press release, CapEx, production and EBITDA. It hit the market at 7:45 this morning, so I encourage everyone to take a look at that.
There's QEP personnel scattered throughout the room here. We've got 14 of us total. There should be one at almost every table here. You all are used to hearing Chuck Stanley and Richard Doleshek speak, but we've got a great group of other QEP personnel here to help you out.
With that, let's get rolling. Of course, we're going to be making quite a few forward-looking statements here. This is our cautionary statement. I encourage everybody to review it and understand it.
The Analyst Day agenda. We're going to start off with Chuck. He's going to give us an introduction to the company, then we'll roll right into Richard Doleshek, who's going to go over some of the financial stuff and then we're going to dive very deeply into our plays in both our Northern Region and Southern Region. Jay Neese, who runs our E&P division, will be leading that effort here this morning. We are going to feed you. We're not going to have any presentations or any converse -- or anything going on during the lunch hour. We'll just allow you guys to sit and relax and eat and hopefully speak to some QEP folks. So we will be feeding you. And then, we'll come back from lunch and do the Field Services. Perry Richards will lead the Midstream conversation. And then finally, Chuck Stanley will get up at the end of the day and with some concluding remarks.
So we got 5 hours. It's going to be a long day, and hopefully, a very useful day for everybody. And we've got a lot of new information here, a lot of plays that we haven't talked about before and some data here that I hope you'll find useful and that will cause you all to have to change your models and improve your QEP evaluation.
So Q&A. You see the microphones in the middle there. We're not going to have Q&A during the individual discussions. At the end of each section, we'll ask for Q&A. And then if you wouldn't please mind going up to the microphones and asking your questions, as I said, we are being webcast, so we want to make sure everybody's able to hear the Q&A. So no Q&A during the actual talks themselves. Each person will stop at the end and ask for questions. And yours truly gets to be the time manager here to keep us rolling along.
So with that, I'll turn it over to Chuck Stanley.
Charles B. Stanley
Thanks, Scott. Good morning, everybody. It's great to be here, and we look forward to spending the day with you or most of the day with you, telling you some things, hopefully, that you don't know about QEP.
A quick corporate profile for those who are new to the stock. We're actually an 83-year-old company. Obviously, we've been public for about 1 3/4 years now or 1.5 years, but the company goes back to the 1920s in Western Wyoming where gas was discovered near Rock Springs, Wyoming and ultimately piped into Salt Lake valley. And we've been in the E&P business and the midstream business since that time. Last July, we were spun off as a separate publicly traded entity from our parent, Questar Corporation, in a tax-free spinoff to existing shareholders.
Important note. We sometimes get questions about any residual ownership of QEP by Questar. There is none. We also get questions about tax-related issues and if there are any impediments for any kind of transaction, corporate transaction, either buy or sell, and the answer is no. There is none. We have no obligation or no prohibition against any transactions.
On the 11th, our enterprise value was $8.1 billion. Our year-end 2010 reserves, 3 trillion cubic feet equivalent, of which 86% is natural gas, about a little over half is proved developed. Our third quarter production, as we reported a couple of weeks ago, 768 million cubic feet equivalent a day, comprised of a little over 15% liquids.
In addition to our Upstream business, we have a very profitable and complementary gathering and processing business, and Perry will tell you all about that this afternoon. But our business primarily focused on our own upstream activity that we then levered our presence to build a substantial third-party business. About half of our revenues today come from third parties in Field Services.
You've all seen this slide, just a breakdown on the contribution of EBITDA for trailing 12 months. You can see $1.3 billion of total QEP Resources EBITDA, 77% from our upstream business, 22% from Field Services, then we have a small Marketing shop that basically markets QEP Energy's production, manages our pipeline and transportation capacity. And QEP Marketing also owns a small gas storage field in Western Wyoming that we use for our own use. So we trade around that asset to put gas in, usually in the summer, and then pull it out in the winter and take advantage of the seasonal variation in prices.
Every year, we go through a 5-year planning process. We look at the growth of this company over the next 5 years, and what we see is a tie that roughly doubles in size, but the proportionality of the business is the relative contributions of the businesses over that 5-year plan remain pretty much the same. About 80% from our upstream business and about 20% from our midstream business and then a small contribution from Marketing.
Some stats you may not know. When we were putting together this book, we decided to go out and look at how we rank. We are a #18 gas producer and #19 in reserves as of the end of last year. This was an interesting slide to me as well. We are the #9 most -- #9 most active driller in North America through the first 3 quarters of this year on a footage basis. And you can see a little over 4 million feet drilled. And I think when I reflect on some of our core competencies, one that I would hope that you would agree with, is that we've been very successful in driving down well costs in our core areas. And this, I think, speaks to one of the reasons why we've been able to do it. We are a large volume driller and we have been able to lever that activity into substantial efficiency gains and substantial cost savings.
We're also a cost producer. Our cost structure, we believe, is a competitive advantage even in the challenge of current natural gas price environment. We are able to make industry-leading EBITDA margins, and one of the reasons for that is our extremely low cost of operations. This shows our 2010 average production cash cost versus 44 peers. And as you can see, we compare quite favorably to the universe.
We've been able to grow production and reserves while maintaining a high return on capital. And this slide shows one measure of return on capital. This is an average return on capital employed, which is basic cash flow from operations over gross PP&E. We were looking for a way to adjust for the impairment of assets that some companies have reported, so we add back in those impaired asset values to come up with a gross PP&E number and then we've normalized debt-adjusted per share growth in production along the x-axis and you can see we compare quite favorably to the universe of producers in debt gross -- adjusted per share growth versus return on capital employed.
Another new slide that we added is to look at our capital efficiency. And as you can see, we also compare quite favorably in terms of production growth versus cash flow. And this is, I think, an important message because we believe that over the next 5 years we can deliver profitable growth in the sort of midteens range over that 5-year period and do so while living within cash flow. And as you can see from this slide, 2010-2011 production growth a little under 20%. We were one of very few companies that's funding that growth within our own cash flow from operations, so it's also an important takeaway.
Turning to Field Services. Another interesting stat. This is a stat where we took some data from Hart's from the June, July issue. And just looking back a year at 2010, we added in the new Blacks Fork II processing plant. And you can see that with the 2010 volumes, we would be the 10th largest gas processor in the U.S. A very important part of our business and one that we'll talk about in more detail.
So what's the macro environment like? Well, obviously, I don't need to tell you guys. We're looking at record gas production. You can see the rapid ramp in dry gas production from the EIA data. Starting in '05 through the nadir there and moving up today a little under 64 Bcf a day of dry gas production in the U.S., driven primarily by a number of shale plays. The Haynesville being one of the largest drivers of this growth in production, followed now by the Marcellus and some other plays.
The next slide shows this. We took all of these different plays as a reservoir engineer thinking about T 0, Time 0 plus we normalized them all along the x-axis for months since the inception of the play, so you can see the relative growth or trajectory of growth of the various plays. You can see the 2 Rockies plays in the lower part of the graph, Jonah and Pinedale, and then you can see the growth in the Barnett, the first real shale play that took off. And you can see how long it took before the Barnett really started to ramp, almost 72 months. Contrast that with Haynesville, where we've seen production go from nothing to over 6 Bcf a day in less than 3 years. And you can also see on there the trajectory of the Marcellus. The Marcellus data has lagged a bit because the Pennsylvania reports are about 6 months old. We dashed the line and we know it's above 3 Bcf, but we're not sure exactly where it is as of today. But you can see the dramatic trajectory, and of course that is one of the current contributors to the supply-demand imbalance.
In spite of the growing gas production, we've seen no significant response to the lower gas prices. On this graph, you can see in red, NYMEX gas prices, prompt prices, and then in blue, you can see the Baker Hughes rig count. Obviously, you can see the collapse in drilling activity in 2008. But since that time, with roughly a $4 gas price, we've actually seen the rig count recover and bounce around between 900 and 1,000 rigs. And, of course, most of those rigs are horizontally directed drilling activity, and we've seen the supply response from that activity at $4 gas.
So what is our strategy? And how do we plan on executing our 5-year business plan and beyond 5 years? Obviously, you've seen this management team, many of you many times before, and we talk about capital discipline and return on invested capital.
We are very focused on capital allocation, moving capital to the highest return portions of our portfolio and either slowing down or getting rid of our return projects that are in our portfolio. We pride ourselves on being able to drive down drilling completion costs and production costs in our core areas. And we've been able to do that and we have a track record of doing that and we believe we can apply that expertise to other plays.
We've driven growth primarily with the drill bit in the past, and we believe we have a portfolio that we'll continue to be able to do that. We've managed our assets, our investment portfolio, if you will, to drive returns across all of our businesses, including our midstream business. Richard will tell you we have a strong balance sheet, and he'll get into the details on that in a minute, but a substantial amount of available liquidity and the ability to raise more if we need it.
We're focused on organic growth here. Although we're not adverse to opportunistic acquisitions, we're not announcing an acquisition today. But we are constantly evaluating our portfolio, the quality of our portfolio versus opportunities that we may be able to acquire in bolt-on or add a new area within North America.
And then we have a culture of learning from each other, of aligning strategy across our company and a sense of urgency. And if you talk to these guys, you'll get a sense of urgency that we all feel as part of QEP.
As I said earlier, our goal is to double the size of our company in the next 5 years. We think we've got a great inventory, and we hope we can convince you today of a very low-risk, high-quality development locations allow us to basically grow production and EBITDA over the period without the need for M&A. We can fund that growth from cash flow and we've already got the assets captured that will allow us to do this. So there's no execution risk other than the drilling and completion risk that we think we can manage quite effectively.
We've got what we believe is a track record of generating good returns on invested capital in our portfolio, and we believe we can continue to do that going forward, given the current commodity and price. And if you look at our EBITDA margins, we have some of the strongest EBITDA margins in the business. We've got a track record. I've talked to a lot of investors in the past year as we became a stand-alone company. Most folks say, "oh, you're a brand-new company. We need to see you perform for a while." Well, this management team that's here today have managed these assets, well, some of them were managing them when I showed up in 2002 at Questar, and they've continued to manage them through the past 10 years. So we have a track record inside Questar. We realize we don't get credit for that in all circles, but we have continued to put up good numbers since the spinoff and I'm confident we can continue to do so in the future. And we're focused on building and maintaining a very strong organization that's competent and is capable of delivering these results in the future.
So what about that development inventory? I thought of different ways of showing this to you and one way is to just look at gross locations and then years of development opportunity at our forecasted pace of development in 2012. Just to give you an idea of the depth of inventory. And what you can see is that our shortest-lived asset has 9-years-plus of development drilling at the current pace of development that we forecast in 2012. The longest-lived asset, in part a reflection of early stage development, is the Red Wash Mesaverde. But if you look at the Haynesville, the Bakken, Powder River Basin, the Oil, you can see a large inventory of development opportunities, repeatable development opportunities, and an opportunity set that spans over, on average, over 10 years into the future. So we feel like we've got a very large asset base. And then outside of this identified asset base, we have additional projects that haven't yet fallen into this inventory that we're reporting to you today. If we look at the inventory, it's over 10,000 gross wells and net capital investment opportunity of close to $25 billion and an average remaining life of 20 years as we go forward. So a deep inventory, very high-quality inventory. We know the well results that we will deliver from these assets going forward.
So by the end of the day, I hope you will have collected a few key messages here. I'm just going to tell you what they are and then we'll let you hear the message over and over again and then I'll come back and tell you what I had hoped that you had garnered at the end.
We think we can grow and thrive in today's commodity price environment and generate competitive returns. We've got a portfolio of assets that will allow us to allocate capital and adjust our capital allocation in response, not only to commodity prices, but also operating conditions. As we discussed in the third quarter call, we have the flexibility to move capital in and out of some of these plays as well cost and service availability ebb and flow, and we think that's unique. Some people ding us on being too diversified. But when it comes right down to it, we have the flexibility to continue to deliver good growth and good returns because of that portfolio diversity. We've got a strong balance sheet, and we believe we can drive growth in this company. And we think we are unique, and that graph that I showed you earlier would support that while living in and around cash flow.
So with that, I'm going to ask Richard Doleshek to come up and go over our financials.
Richard J. Doleshek
Thank you. Well, good morning, folks. I want to add my welcome to Chuck's. I'm excited to be here today because generally when I'm in front of you guys, I don't get a chance to talk about our financial condition. We just jump right into the plays and how many rigs we've got running in Haynesville and what our capital allocation strategy is and things like that. So today, I get to spend a little bit of time talking about what I think is one of the best assets at QEP, and that's our balance sheet and our financial condition.
Our balance sheet is very simple. It consists of debt, income and equity. We don't have any joint ventures. We don't have any hidden liabilities. What you see is pretty much what you get. In terms of assets, $7.3 billion of assets, $1.6 billion of debt. That debt is composed of about $500 million drawn under the revolving credit and $1.1 billion of senior notes outstanding, and equity at the end of the third quarter is $3.3 billion.
If you look at our balance sheet and compare it to our peer group, we think we're pretty conservatively levered. Our debt multiple of EBITDA is about 1.1x. When you annualize the third quarter EBITDA, our debt-to-cap is about 32% and our debt ratings are Ba1 and BB+. Both the agencies came out with notes at the end of August. We put our new revolver in place and reaffirmed our ratings. And in terms of, well, it's not important today, in terms of debt maturities, we don't have any debt coming due until the second half of 2016. So no refinancing pressure at all.
In terms of our debt position, we put a new $1.5 billion revolving credit in place at the end of August. We thought it was a good time to take advantage of improving conditions in the bank market and raised a $1.5 billion facility. We had $2.4 billion of commitments for that facility from 19 financial institutions. And a couple of interesting features about that. It's $1.5 billion face today, but we can take it to $2 billion. And it's also a 5-year deal that's got two 1-year extensions to it. One of the unique features and maybe one of the downsides of having foreign bankers, CFOs, we've got a leveraged base spread as opposed to a ratings base spread. So it really gives us the chance to drive down interest cost if we improve our leverage position. So the grid where we are today is at LIBOR plus 175. It saves us about 75 basis points versus the old facility and that cuts about $4 million a year of interest expense out of our spending. We had $510 million drawn at the end of the third quarter, and we're basically living sort of around that $500 million to $600 million outstanding as we go through our monthly cycle.
And finally, we dropped one of our financial covenants. We've only got 2 covenants in the revolver. We've got a 60% debt-to-cap and a 3.5x debt multiple EBITDA as a leverage cap. We dropped our PV9 coverage estimates in this new facility. So we think this is a good time to be in the market. We got basically everything we asked for in terms of a new facility and, again, great -- it provides great flexibility and about $1 billion of liquidity.
In terms of more commentary about our financial profile. These assets generate just excellent cash flow. The E&P business, over the last 12 months, has generated $1 billion of EBITDA, midstream almost $300 million and the total company about $1.3 billion. So with these assets, even in the low commodity price environment we find ourselves in today, generate tons of cash.
In terms of our capital program, it's designed to be at or around EBITDA. We're announcing a $1.5 billion program for 2012. Even with the reduced commodity price environment, we find ourselves in today that capital spending still drives midteens production, EBITDA growth from identified in-house projects, all organic growth. And to get the capital allocation, the projects had to generate at least a 50% after-tax rate of return and we had way more projects that generated that than we had that capital to allocate to them.
As Chuck noted, you'll see in some of the earlier slides we've got what we believe is a low-cost structure, both on the drilling and completion side in our core plays. We believe we're the leading driller both in Pinedale and Haynesville, and our operating cost structure is among the lowest in the industry.
And finally, hedging is an important part of our strategy. Our target is to be about 50% hedged for forecasted production. Currently, the E&P side is about 44% hedged for 2012. We're right at 50% for gas, but low percentage on our oil and NGL. And also as NGLs are becoming a bigger piece of our revenue equation, we're also beginning to hedge NGLs both at the midstream side and on the E&P side.
In terms of the balance sheet, a little bit different presentation than you're probably used to seeing. The first line is our gross PP&E. And why do we care about gross PP&E? Because this is the denominator in our calculation for return on invested capital. So you can see almost $2.4 billion of investments from year-end '09 through -- into the third quarter leads to $9.6 billion gross PP&E number. Total assets came to $7.3 billion and debt about $1.6 billion and equity $3.3 billion.
And if you jump down to the credit stats at the bottom of the page, our interest expense is right at $23 million. We're covering at 15.5x with our EBITDA and 32% debt-to-cap, I mentioned earlier, the 1.1x debt multiple of EBITDA.
In terms of our debt structure, again, no real maturities until the second half of 2016. In '16, both revolver is due. And again, we're showing the $1.5 billion revolver with $1 billion unfunded and $0.5 billion drawn. And then the red bars are indicative of the senior notes maturities. And you'll notice that in '16, '18 and '20, we've got some unusual-looking debt amounts that mature. As you recall, when we spun, we had a change to control the bond, a ratings downgrade. So we tendered for that $1.15 billion of senior notes that was outstanding at the time and we got pieces of each of those issues back. So the $177 million, the $139 million, the $138 million due '16, '18, '20 are all the stub pieces of what we didn't bring in-house through that tender offer. And then we refinanced that purchase with a $625 million notes offering due 2021. So you put all that together, the senior notes portfolio is $1,078,000,000 face value, bonded coupon is 6.72% and the average duration is just over 8 years. So we got no real refinancing needs until 2016.
In terms of just the quarterly EBITDA numbers and where the contribution comes from, we're showing you from the first quarter of 2010, which we generated under $270 million of EBITDA to the third quarter of '11, $354 million. Back in the first quarter, about 80% of that EBITDA stream was generated by the E&P business. And with their drilling contribution from the midstream company, in the third quarter, the E&P side was 76%, the midstream side was 24%. It just shows it is for a continuous growth on a quarter-to-quarter basis.
In terms of the income statement, lots of numbers. I won't talk about all of them. But a couple I wanted to -- couple of things I want to point out. This is -- we're going to show you a couple of things here. First of all, highlighted in the green bars is our net hedging revenue. And then there's realized loss on basis-only swaps. You need to put those 2 together to get the total impact of our derivative portfolio. So back in 2009, we generated about $575 million from our derivatives portfolio. When you come all the way through to the 9 months 2011, we generated about $125 million. So the derivative portfolio was making a big contribution in 2009 as prices were falling away. As prices have been roughly stable for the last -- decline to stable the last 12 months, the derivative portfolio hasn't contributed quite as much.
A couple other things. If you look at the lease operating expense, the operating expense line which is a combination of LOE, G&A and taxes, it's been a relatively stable through 2011. $113 million going to $120 million quarter-to-quarter-to-quarter. If you think about what we're doing in the liquid side, you think about where production factors are, et cetera, it's pretty remarkable. And if you look at it on a per Mcf basis, basically costs have been flat this year in spite of growing production and a growing percentage of liquids production.
And just a couple of other things on the income statement. DD&A, if you look at the 3 quarters in 2011, has been covering about around $190 million. Again if you think about that on a per Mcf basis, as production has grown, as we brought on the 2 big facilities in the midstream business, flat DD&A is, I think, a pretty good accomplishment.
And then finally, if you come all the way down to this other income, we got a lot of stuff buried in here. But basically, the biggest component of what's in there is the offset to that realized loss on basis-only swaps. Before we redesignated those swaps as "hedges," we would mark it as the market run through the income statement every quarter, and this is the reversal of that and this will be the last year we talk about that. Fourth quarter will be the roll-off of the basis-only swaps.
So that's a different look at the income statement.
In terms of CapEx, as you've heard both Chuck and I say our stated objective is to live at or about EBITDA. And if you look at the last 5 years, we've had a couple of departures from that. First of all, in 2008, we outspent EBITDA by about $800 million. That was the year that we made the big acquisition in Northwest Louisiana of what is now our Haynesville play. Had about $750 million of acquisitions that year, so that sort of leapfrogged us out. And then in 2010, we overspent by about $340 million and that was to really jump start what was going on in the midstream business. And in retrospect, we wish we had pushed that spending back in 2009, so those plans were full on in '09 -- in '10 and '11. But basically, the strategy and the history has been to live in and around our EBITDA stream.
And finally, this is our return on capital employed slide. When we look at -- this is a little bit different. This is EBITDA divided by gross PP&E. And the reason we look at gross PP&E is it ignores the impact of any impairment or anything like that. And really if you look at what the bars tell you, the blue bars are the E&P company, the red bars are the Field Services and the green is the blended QEP Resources return. And you we can see the midstream business has just been generating great return, and in the third quarter generated 21% return on invested capital, as all the investments, the plants were generating cash flow. And you can also see the impact of the lower commodity prices on the E&P business where that return has gone from almost 23% in the first quarter of '09 with higher commodity prices to down about around 13% in the third quarter of '11. You put those all together and that blended portfolio generated about a 14.5% return on invested capital in the third quarter.
So interesting business, very complementary. When natural gas prices are low, the midstream business does pretty well. And when natural gas prices are high, the E&P company picks it up.
Finally, this is our first glimpse of 2012 guidance that we're putting out there. Couple of things to talk about: $1.45 billion to $1.55 billion of EBITDA forecasted for 2012; 305 to 310 Bcfe of production, midpoint of that is about 840 million cubic feet equivalent per day and that's about 20% oil NGLs versus 80% gas. As I mentioned, capital budget of about $1.5 billion and about -- we're about 44% hedged on a blended basis, but about 50% of that is natural gas. If you look at our price assumptions, $3.75 to $4.25 NYMEX, $90 to $100 oil and $0.15 to $0.20 basis, both at the Rockies and at the Midcontinent. I think one of the -- for the first time in a couple of years, we've seen basis about the same in both of our producing locations.
So again, our first look at guidance for 2012. I'm happy to answer any questions or we'll go ahead and jump into the regions. Okay. I'll turn it over to Jay Neese and he'll introduce his guys and give you over to the E&P business.
Jay B. Neese
Thank you, Richard. As Scott mentioned, I'm Jay Neese. I'm head of our QEP. And I've been with the company for 34 years. So basically going back before child labor laws were enforced. And I'm going to introduce just a really quick overview of QEP Energy and then turn it over to a couple of my fellow old guys, Paul Matheny and Vincent Rigatti. And then we'll let a couple of our younger guys, I define that as the under-30 crowd, Jeff Thompson and Linden Bailey, talk about our plays in the Southern Region.
Before I do that, I'd like to introduce some other QEP Energy officers that are here today that won't be speaking, but you might want to try to catch with them at break or at lunch and mingle with them: Austin Murr over here in the middle, VP of Land and Business Development; Jeff Tommerup over here. Jeff is -- heads up our Eastern Midcontinent division located in Tulsa, Oklahoma; and then Michael Penner, VP of our Western Midcontinent division, at the back of the room, located in our Oklahoma City office.
QEP Energy is the E&P subsidiary of QEP Resources, and we're divided into 2 regions, the Northern and Southern Region. Vinnie Rigatti, who you're going to hear from next, is the manager of all of our Northern regions headquartered in Denver. And within that, we've got 3 divisions: our Pinedale division; our Uinta Basin division; and then our legacy division, which covers everything not within the Uinta Basin or the Pinedale Anticline.
And then our Southern Region, we have the Tulsa office headquartered in Tulsa, run by Jeff. Their focus is primarily Haynesville and the legacy Cotton Valley assets that we've got. Everything else in the Midcontinent is run by Michael Penner's group, located in Oklahoma City.
So you've heard us talk a lot about our major plays in the past, the Bakken/Three Forks, Pinedale, Woodford, Cana and Haynesville, but today, we're also going to talk about some new plays that are going to receive an allocation of our drilling budget in 2012. Two liquids-rich gas plays in the Rockies, the first being targeted to the lower Mesaverde formation in the Uinta Basin within our Red Wash unit, the second being in Almond Formation liquids-rich gas play in the Vermillion Basin located in Southwest Wyoming. We're also going to touch on some oil plays that we're pursuing in 2012 in the Powder River Basin of Northwest Wyoming -- Northeast Wyoming, excuse me, Western Oklahoma, and then while we talk about the Mesaverde liquids-rich gas play, we're also going to show you the Green River formation oil play that lies above that and that we will get some free looks at.
On this map, we're depicting the location of our plays that we're targeting for 2012. And of note...
Jay B. Neese
They'll come up on a flip. What I want you to take away from this on the headline is over 75% of our capital budget directed for drilling and completion of wells next year will be targeted to liquids-rich gas plays and oil plays. The only "dry gas" play we have in our portfolio for next year is the Haynesville play. And our 2012 budget is not targeted at chasing explorations. QEP Energy has about 2 million net acres under leasehold or mineral ownership and about 2/3 of that is in the Northern Region in the Rockies. Some of that dating back to the 1920s history of the company, as Chuck mentioned. A lot of it also was generated in the '60s and '70s. We have a lot of legacy acreage that's held by production or held by units in the Rockies. And then 1/3 of our total net acreage is in the Southern Region. Only 34,000 representing about 1.8% of our net acres will expire in 2012 in the absence of drilling or production. So while we will be drilling on those expiring leases, hopefully to save most of them, it's not the major driver for our capital allocation.
As Chuck mentioned earlier, we've doubled the size of the company in the last 5 years relative to our net production, growing at a 16% compound annual growth rate. We're forecasting about 13% growth from our midpoint guidance of '11 to our midpoint guidance for '12, and we believe we have the assets in-house to continue that same compound annual growth rate for the next 5 years.
This slide shows you the efforts we've made to try to direct more of our drilling capital towards our liquids-rich plays. This year, $1.5 billion budget, 11% of that, about $170 million going to our midstream business. The balance distributed across our E&P plays is noted on the chart. I'll point out that our Haynesville play is going from 30% allocation in 2011, down to under 20% this year, and that represents a drop in the rig count from about 6 to 2. And you'll note on there, we're significantly increasing allocation to our liquids-rich gas plays and oil plays like the Bakken play.
This slide shows you our pretax rate of return, assuming a $4.50 gas and $85 oil NYMEX prices. And you see our lowest is 20% at Haynesville play, all the way up to 95% for our Western Oklahoma Oil plays. Also indicated on here is our 2012 planned operated rig count, and we can get into those in more detail as the guys go through each play.
We go back to the 1920s, as Chuck mentioned, that history of the company was a geologic mistake finding gas. And the company was focused on continuing to find gas for most of its 83-year history. So we're not going to go from being a gas company into an oil company overnight. As you can see from this chart, only 11% of our production in 2010 came from liquids. This year, we're forecasting 14%. And with the continued allocation that we have planned for our 2012 budget, we're forecasting that 20% of our production for next year will come from liquids.
Every few years, we do a inventory of our existing asset base. In addition to our proved reserves of 3 Tcf, we estimate that we've got 3.7 Tcfe of probable reserve, 5.9 Tcfe of possible reserves and over 18 Tcf of resource potential on our asset base distributed across the areas shown on the slide.
Today, we're going to talk about plays that represent about 80% of those probable and possible reserves, but only 11% of the resource potential. So we're just scratching the surface of the potential on our existing asset base.
And then a recap of the slide that Chuck showed earlier, just to drive that back home, that the plays we're going to talk about today, while they represent 80% of our probable and possible inventory, we have a long, long life of inventory left yet to drill that will drive our production growth for many years.
With that, I'm going to turn it over to Vinnie Rigatti to talk about our Northern Region plays. I'll ask Vinnie and the guys that follow him to give us a short bio of themselves. Keep it under an hour.
Good morning. It's glad to be here this morning. Yes, my name is Vinnie Rigatti. Just a short bio. I've been in the -- I'm sorry, Scott? I've been in the industry since 1981. Got my degree in Geology and Geophysics just up the road at the University of Connecticut, so it's glad to be back in the homeland for this presentation. Most of my industry -- or most of my experience has been work in U.S. basins. Did spend about 10 years international, both in Southeast Asia and South America. I've been with QEP for almost 9 years, working in the Denver office, the Rockies assets. And let's get started on the presentation.
Before we get into specifics on individual plays, this slide demonstrates the wide variety of play types that we have within the company, and we broken those play types into 4 basic categories. Type A, which I like to call classic shale, are horizontal wells targeting shale resource rocks. And examples of those plays that we'll talk about today are the Haynesville of Northwest Louisiana and the Woodford play of Western Oklahoma in the Anadarko Basin. Play type B are horizontal wells targeting tight sands. And examples of those plays that we'll talk about today are the Sussex and Shannon sand stones of the Powder River Basin and the Tonkawa of the Anadarko Basin. Play type C are horizontal wells targeting tight carbonates. And examples of those plays that we'll talk about are the Bakken and Three Forks of the Williston Basin, the Marmaton of the Anadarko Basin and the Niobrara of the Powder River Basin. And finally, play type D are vertical or directional wells targeting tight sands. And examples of those plays that we'll discuss are Pinedale Anticline and the Almond of the Green River Basin, and in the Uinta Basin, the Lower Mesaverde and the Green River Formations in our Red Wash unit.
So with that, let's look at the planned activity in the Northern Region in 2012, and we're going to start off talking about the Williston Basin in the Bakken and Three Forks. We'll then move south into Northeastern Wyoming, then talk about the stack potential of the Sussex, Shannon, Niobrara and Frontier formations. We're then going to move west into the Green River Basin, and I'll talk about the Vermillion Basin, Almond Formation. I'll then hand off the presentation to Paul Matheny, and he's going to talk about Pinedale Anticline and the Lance and then wrap it up for the Northern Region in the Uinta Basin and talk about our emerging gas play with the Lower Mesaverde and the Green River Formation, which is just above it.
So let's kind of dive into the Williston Basin. These are a couple of photos taken on the west side of Lake Sakakawea. We have acreage on either side, and this is one of our unit rigs that was operating over the summer in the Badlands area, again on the west side of the lake. It's a pretty scenic area, a nice place to be in the summertime.
This is a map of the geographic setting of the Williston Basin. It's showing the oil fields in green and QEP acreage in yellow. And throughout the presentation, you'll see the QEP acreage is always depicted in yellow, except for one slide and I'll point that out when we get to it. This shows that production of the Williston is coming from both North Dakota and Eastern Montana, going up into Canada. Note on the slide, the Fort Berthold Indian Reservation, where we have the majority of our acreage, is outlined in blue. Also note that the Parshall and Sanish Fields, which are to the north of the reservation, and the Bailey Fields to the south, are connected by a green dashed line. We fully expect that both of these fields will be connected over time as further delineation drilling continues on the reservation.
This next slide now zooms into our acreage, and our acreage is divided into 2 primary blocks, again shown in yellow. Fat Cat area, we have around 5,000 net acres. We have 3 operated wells out there, and that's in Williams County. As we go further to the east, you cross over to the Nesson Anticline -- let's just see if this pointer is working. I'm not sure how that works. Anyways, the Nesson Anticline, which is in the center of the map, north-south trending geologic feature, separates our Fat Cat area from Fort Berthold. Fort Berthold, we have around 72,000 net acres. The remainder of our 90,000 net acres in the Bakken is 13,000 of acres -- net acres scattered lease and mineral interest throughout the productive area of the Williston Basin. On this map, also notice that the Bakken wells are shown in black and the Three Forks wells are shown in red.
The objectives on the Fort Berthold reservation are both the Middle Bakken and the Three Forks. And on the type log, the objective limestone and dolomites of the Middle Bakken are shown in blue and then the shales are shown in gray. So from the Middle Bakken, we're drilling horizontal laterals, typical length are 10,000-foot laterals, giving us a 20,000-foot measured depth. These wells are typically completed in 25 to 30 stages and have EURs in the range of 400,000 barrels to 1 million barrels of oil equivalent per well.
The secondary object is the Three Forks formation. The Three Forks lies directly underneath the lower Bakken shale, and it's also a dolomite. The EURs are slightly lower than the Middle Bakken, on the range of 350,000 to 600,000 barrels of oil equivalent per well. And they complete very similar to the Bakken in 25 to 30 stages per long lateral well.
I want to go through a time progression of the activity and the development of the Bakken because it really has exploded from near nothing 5 years ago to over 200 rigs in the play currently. And this map shows the activity in the Bakken and the Three Forks prior to 2007. The discovery of the Parshall Field, which really kicked everything off, occurred in the summer of 2006. So there was activity to the north on the Nesson Anticline and to the southwest of Montana around Elm Coulee Field, prior to the discovery of Parshall just to the north of the Fort Berthold Reservation. This really kicked the play off. If we go into 2007, on this map now, all the wells that were drilled in 2007 are shown in red and prior wells are shown in black, and you'll see that same theme as we go through the presentation. In 2007, we saw additional activity around Parshall and then QEP participated in our first nonoperated Bakken well through prior mineral interest in that area, and that really kicked off our interest. And at that time, we began negotiating an acreage block on the Fort Berthold Reservation. You can also see some activity to the southeast, and that's around the present or current Bailey Field.
As we go into 2008, you saw activity expand to the north and the west from Parshall. In March of that year, we signed our large leasehold on the reservation and key was we signed early before acreage prices really took off in the play.
2009, activity continued to expand. A lot of activity around Parshall and Sanish. We started seeing more wells being drilled on the reservation. In 2009, we drilled our first operated well in the basin, the MHA 1-18H, which at that time was about 10 miles south of known production in the Parshall Field and about 25 miles to the north of known production in Bailey Field.
2010, the map is really starting to fill up, and this is where we stand currently. You can see that there's a lot of activity up at Parshall/Sanish, a lot of activity down in Bailey. Just look at the stats. Currently, the State of North Dakota is producing over 450,000 barrels of oil per day. 5 years ago, it was under 100,000. So the field has really exploded.
If we look where we sit geologically, this map on the left is an evaluation from the USGS of the Bakken Petroleum System. We've posted our acreage on there. And if we zoom in to the majority of our holdings on the Fort Berthold Reservation, this lies within what's referred to as the eastern expulsion trend. It's a large north-south trend. Put the green dash on there, that's the approximate eastern margin of the field, which needs further delineation, particularly on the Fort Berthold Reservation.
Let's look at it in a little more detail, and this is a regional Bakken EUR map or estimated ultimate recovery map. It's color-coded by EUR. So the cooler colors represent lower EURs. The warmer colors represent higher EURs, particularly key on the oranges and red, which are wells greater than 500,000 barrels. You can see Parshall and Sanish is quite the sweet spot up to the north. But this recent drilling on the Fort Berthold Reservation shows that, that sweet spot potentially extends across the whole western 2/3 of the Fort Berthold Reservation. Down south in the Bailey Field, you see smaller EURs. This is largely driven by the fact that the major operator down there originally was completing wells in a single-stage open hole completions rather than multi-stage fracs that we see up in Parshall and Sanish and across our holdings.
I want to point out the eastern field boundary, which needs further delineation across our acreage. And a couple of key wells that we've completed in the last few months, our MHA 1-5-08, which was completed in July, at 2,650 barrels of oil per day, and the well we just completed at the end of October, the 1-32-29, which has completed near 2,800 barrels of oil per day, 2 very strong wells, again showing that the sweet spot from Parshall/Sanish is extending across the reservation and across our acreage.
If we look at some specific well results from QEP activity, we're going to refer to the 4 wells that had stars on the index map. Again our acreage is shown in yellow and Bakken producers are shown in green. This graph on the left is a cumulative oil plot. So cumulative oil on the y-axis and days on the x-axis, and we're showing the first 90 days of production. So the first well in green was our first long lateral, filled underneath the lake on the eastern shore of the lake. It was a 10,000-foot lateral, and the first 90 days have produced around 50,000 barrels of oil. We have an EUR of that well assigned at around 750,000 barrels, so it's a very strong well. The second well, which is drilled on the extreme western portion of our acreage, our MHA 6-31, is one of our strongest wells to date, producing over 60,000 barrels of oil in the first 90 days. We have an EUR in excess of 900,000 barrels assigned to that well, so it's a very significant well.
This next well was the well we completed in July of this year, and that well came at around 65,000 barrels of oil in the first 90 days. And to date, is our strongest and best performing Bakken well after 90 days production. We haven't assigned an EUR to that well yet because we don't really have enough history of it, but to date, it's very strong.
The importance of this is that we're seeing very good results across the breadth of our acreage going from north to south, as well as from east to west.
And here's the well that we just completed at the end of October, flowing nearly 2,800 barrels of oil per day from the Bakken. So very encouraged by that well result. We have a planned well in 2012, a delineation well. That's going to be on the southeastern portion of our acreage, and this will help us evaluate that portion of our acreage, as well as the eastern boundary to the field, which you can see is presently mapped about 5 miles to the east of that well.
So if you look at the upside potential on our lands for the Bakken, the red stars on the map show our current Bakken producers and we have 18 Bakken producers on the reservation.
If we consider these wells to be developed on 160-acre spacing, that would be 4 wells per section, with an EUR range of 400,000 to 650,000 barrels of oil equivalent per well. And keep in mind, I just showed you some wells that were well in excess of 650,000. We have 240 gross locations, representing upside potential between 73 million and 120 million barrels net to QEP from the Middle Bakken formation.
Let's move on now to the Three Forks, which again lies directly below the lower Bakken Shale. We look at a similar plot. The map on the right shows the 4 Three Forks producers that we have on the reservation and the green line is the eastern field margin for the Three Forks. You'll notice that it's a few miles to the west of the Bakken boundary.
The first well that we drilled targeting Three Forks was completed in September, 2010, our MHA 2-6-31 and IP-ed at 1,300 barrels a day. And over the first 90 days, it produced around 35,000 barrels of oil. We're assigning an EUR between 300,000 and 400,000 barrels to that well. However, we did have some mechanical issues, so we hope that improves over time. Also notice on the chart that I've dashed the wells that were completed from the Bakken that we showed on the prior slide as a comparator.
The next well was the second well that we drilled from that southern twin pad. This well is kind of a twin to that outstanding Bakken well that we completed in late July. That well IP-ed for nearly 1,500 barrels per day. And on the ray [ph] cum plot has made nearly 60,000 barrels of oil in the first 90 days. So this well is our third-best performing well to date, and it's comparable to some of our best Bakken wells. So we're seeing a very good result there. And just recently, within the last 2 weeks, we completed 2 more Three Forks wells from our clod path of Independence Point, the 3-32 IP-ed for over 1,000 barrels per day and the 3-4-3 IP-ed for 1,662 barrels of oil per day. So similar to the Bakken, we're seeing very strong results from the Three Forks across the breadth of our acreage, going from north to south and east to west. Also notice there's a well that's called out here just offsetting our acreage to the west, a recent completion by another operator on the reservation, that IP-ed for over 3,000 barrels per day from the Three Forks, which helps us feel very confident about the Three Forks over that portion of our acreage.
So if we look at the Three Forks potential similar to what we did for the Bakken on a 160-acre spacing and looking at a range of reserves between 350,000 and 600,000 barrels of oil equivalent per well, we have a 180 gross potential locations in the Three Forks, representing 48 million to 82 million barrels of oil net potential to QEP for the Three Forks.
So if we lump the Bakken and the Three Forks together, you can see that we have 420 gross locations on the Fort Berthold Reservation. Again, this is considering a 160-acre spacing with a reserve potential between 120 million and 200 million barrels of oil net to QEP. So we've got, presently, 22 wells producing on the reservation and we're going to have 3 rigs active out there in 2012.
In terms of drilling days, our efficiency has improved. 2009, we're averaging 40 days per long lateral. So that's about 20,000 feet measured depth. In 2011, we drilled that down to under 30 days with a recorded well in under 20 days. However, while the drilling times have come down, the well cost has gone up. I think everyone that follows the Bakken play, it's a common theme. Our long laterals now cost around $9.5 million to drill and complete.
If we look at some economics, and you'll see the same economic sensitivity run for all the plays that we're going to look at today. There's a production type curve in the upper left. This is a type curve for a well with an EUR of 550,000 barrels. This is our type well, completed cost at $9.5 million. Using those metrics and the $85 West Texas Intermediate price, we get a before tax rate of return for a typical Bakken well of 26.4%. If we look at higher EURs, on a 650,000 barrel well, delivers around a 38% rate of return. When you go up to $90, then you're in the mid-40s. So with these Bakken wells at $9.5 million, still deliver very strong results.
So before I move into the Powder River basin, I'll open up the floor for any questions.
No questions? Yes, sir?
Okay. If you didn't hear the question, the question was could I comment on some of the results across the basin and the type of oil prices that are needed for an economic return? We feel that we're located in the eastern expulsion trend and some of the higher EURs in the basin in excess of 500,000 barrels per well. With those type of metrics, with our type well, we need about a $75 West Texas Intermediate price for a 15% before tax rate of return. When you go over into the areas, kind of west of the Nesson Anticline, the EURs drop slightly into that 400,000 to 600,000 range. So that they're a little more challenged as we push these well costs in excess of $9 million. And we have seen some AFVs exceeding $10 million in the trend. Yes, sir?
Can you talk about what you expect for 2012 in the trend of your well cost? The $9.5 million, do you still feel pretty good about that? Is there upward kind of [indiscernible]? Can you remind us what -- how many frac crews do you have in place and how many of them are left [ph] ?
Okay. The question was, can I comment on how we feel about our $9.5 million well cost? We do think that's a pretty solid cost. The big drivers on the cost are at the completion side, particularly water costs and sand and frac crews. Frac crews are strained to the maximum up there right now. But we really feel we've got a good model in place to drive our water cost down, so we hope that we can actually drive our cost down as we start drilling some of our own water wells up there and reduce some of the trucking cost. Another big cost out there is completions in trucking oil. So if we can get the wells hooked up at the pipeline quicker, then we can reduce some of our costs there. Let me think. What was the other part of your question?
Frac crews. We do not have a dedicated frac crew up there. We do rely on a frac schedule. The frac crews are very strained, but we were able to get these wells frac-ed within 1 to 2 months of TD-ing the run of completions. And that's pretty typical out here. Just with so many rigs and so many operators, you just have to get in line for the frac crew. Let's go to the back of the room.
The Bakken, Middle and the [indiscernible] you drilled so far, you just have [indiscernible] 160-acre spacing.
Well, let me go back to a map here. The question revolves around 160-acre spacing. And to answer that, I think I'll go back to this map. It is Slide #13, but that's on the individual slide deck here. Man, if I could figure out how this laser pointer worked. Scott, do you know which button is the laser?
The button in the middle.
The button in the middle, very good. There's been quite a few wells drilled off the reservation to the north, in this area I'm pointing to on the right slide, on a 160-acre spacing. We happen to have some mineral interests up there and we've seen that there's really no degradation in the results on a 160-acre spacing. And then recently -- and is it the hedge [ph] here -- we just drilled our first infill pilot, offsetting the strong well here, the 13-14. We just drilled 2 wells to the north, testing the 160-acre spacing, and we'll be completing those wells later in November. So the modeling that we've done and the infill that's taken place off the reservation suggests that a 160-acre spacing will be adequate to capture the Bakken and the Three Forks reserves. Other questions? Doing good on time, Scott? Okay.
So with that, I'm going to move onto a relatively new play and talk about the Powder River Basin, just to the south of the Williston in Northeastern Wyoming. This is the geographic setting of the Powder River Basin. It is located in Northeastern Wyoming. On this map, the gas fields are shown in red and most of the gas production in the Powder is from coal-bed methane. The oil fields are a little bit more historic, long-term production out there. And those are shown in green, and again QEP's acreage in yellow. And I'm going to be talking about our Spearhead Ranch area, which is highlighted there by the blue-dashed circle. In the Spearhead Ranch area, we're targeting stacked oil and liquid reservoirs in the generative kitchen. And from top to bottom, the 4 reservoirs we're targeting are the Sussex formation, which is the sandstone, which trends southwest or northwest to southeast across our acreage. We have around 40,000 net acres in the Spearhead Ranch area. Underneath the Sussex is a look-alike formation called the Shannon. The Shannon runs 1,000 feet below and it trends north to south across our acreage, and the Shannon Fairway is shown on the map in that burnt orange color. Well, the Shannon lies on Niobrara. I'm sure you've heard a lot about the Niobrara potential, both in the DJ and the Powder. And that fairway is shown here, encompassing all of QEP's acreage within the Powder or within Spearhead Ranch. And then the final formation is the Frontier. I did not highlight the Frontier Fairway on this map, but it's roughly the same size as the Niobrara Fairway, encompassing most of our acreage.
So the next series of slides, I'll just go through each one of these formations, and we'll start off with the Sussex. On the left is a tight block. The Sussex is a sandstone reservoir. It's deposited in the offshore of our environment. We're going to target it with short laterals, average 5,000-foot length, total measured depth of around 15,000 feet, completing in 10 to 15 stages per lateral. The fairway is shown on the map to the right in that purple-dashed line going from northwest to southeast. Within the fairway, QEP is 17,000 net acres. And originally, this was a vertical play, targeting areas of high perm and porosity and there were 2 fields in our area that we're targeting here, the Spearhead Ranch to the north, which is keen 2.5 million barrels of oil from the old vertical wells, and the Hornbuckle Field to the south. About 2 years ago, operators started drilling some horizontal wells around the uneconomic vertical limit of the Hornbuckle Field. And they started hitting some pretty big wells. This is an average well of around 1,500 barrels per day from a short lateral. The EURs of these wells range between 300,000 and 400,000 -- 450,000 barrels of oil equivalent per well. 3 years ago, we did a one-section farm-out just to the west of our acreage in Spearhead Ranch. That well had an IP near 1,000 barrels per day. This is a strong well, has an estimated ultimate recovery of 450,000 barrels of oil.
We participated in an important well between the 2 fields, shown right here and I'm highlighting it, the GH Federal. We participated with a 27% working interest as a nonoperator. That well IP-ed near 1,000 barrels per day and we think it's going to have an EUR of around 450,000. So it's a very strong well and it shows that you can find commercial Sussex production between the old vertical wells.
Another well has been drilled to the northwest of Spearhead Ranch. That's drilled horizontally in Sussex, but the results of that well have not been released yet. We're planning 4 to 5 operated Sussex wells in 2012 around our Spearhead Ranch area. If you look at the potential in the Sussex, and we're looking at 2 options here, a 320- or 160-acre spacing, we're trying to figure out what the optimum is. By considering an EUR range between 300,000 and 450,000 barrels per well, we have between 100 and 200 gross locations representing potential between 16 million and 48 million barrels net QEP for the Sussex formation.
We'll now go down around 1,000 feet vertically and look at the Shannon formation. You can see in the type log, the Shannon is very similar to the Sussex. It's an offshore bar in sand. This type log is taken from the middle of the trends, as you can see shown on the map, with a dashed orange line. Within the Shannon Fairway, we have 37,000 net acres. Similar to the Sussex, at prior days, the Shannon was targeted with vertical completions in the higher perm and pross [ph] and porous portions of the field -- of the trend. The Pine Tree Field is keened [ph] around 6 million barrels from the older Shannon wells. We think this can be exploited similarly to the Sussex, and we're planning a horizontal well offsetting an old Shannon well to the south that keened [ph] 20,000 barrels of oil from a prior test that was drilled in the late 1990s. So this is a really good show well to drill a horizontal well offsetting it, similar to the progression that we saw in the Sussex. So the Shannon is a really exciting play. However, it's probably a couple years behind where the Sussex was, say, 2 years ago. We're planning one Shannon well in 2012 in the southern portion of our acreage. And if you look at the upside potential on our 37,000 net acres, using a similar EUR range to the Sussex, we have between 212 and 424 gross locations, representing reserve potential of 35 million to 104 million barrels net QEP for the Shannon.
Let's go further down now and talk about the Niobrara. For the Niobrara, we're targeting a chalk interval, which is highlighted by blue on the type log. The measured depth is around 12,000 feet. So these will be horizontal wells, short laterals, measured depth around 16,500 feet. We're looking at EURs in 350,000 to 450,000 barrels of oil equivalent range. There'd been some activity in the Powder targeting the Niobrara to the south at Spillman Draw. You see wells that are averaging between 300,000 and 400,000 barrels of oil equivalent from the Niobrara and a recent completion that IP-ed for close to 1,400 barrels of oil per day on the Niobrara. So some very good results. The fairway here is pretty wide because the Niobrara is deposited over a large regional area, and it's mature within the deepest part of the basin, across our acreage to the north.
If you look at the potential again on 320 and 160 acres basin and using an EUR range between 350,000 and 450,000 barrels of oil equivalent per well, we have potentially 280 to 560 gross locations, representing potential between 44 million and 112 million barrels of oil equivalent to QEP.
And then the final formation is the deepest, is the Frontier formation. This one's a bit more complex. The Frontier has 4 or 5 different sandstone benches. We're showing a couple here on the type log. This will be targeted again with horizontal wells. Prior to drilling in the Frontier, we're targeting highly porous and permeable sandstone benches through vertical development. Now it's moving into more of a horizontal play through then a recent well completed just in the south that IP-ed nearly -- near 800 barrels of oil per day and 1.2 million cubic feet of gas. We haven't put any numbers to the potential because we need to go in and map these individual sand bodies. But we feel this could have similar potential to what you saw prior to Niobrara and the other formations. This is quite deeper, though. We're looking at measured depths around 17,000 feet for the Frontier, again targeting the short laterals by 10 to 15 stages per lateral.
So if we look at the economics for each one of these plays on the Sussex, the type curve is a 350,000 barrel of oil equivalent at a well cost of $6.1 million. An $85 West Texas price yields a before-tax rate of return of 42%. At $90, we're pushing 50%.
For the Shannon formation, similar EUR, similar well cost, West Texas $85, we have nearly a 50% before-tax rate of return. At $90, we're pushing 60% rate of return. So really good economics for both the Sussex and the Shannon.
The Niobrara is a bit deeper. And I'm going to point out a typo that's in your books. The measured depth should read 17,000 feet, and I think in the books it says 13,000. Using a type curve at 300,000 barrels, we're seeing a rate of return of near 20% at $85, and at $90 nearly 25%.
So if we stack it all up, no pun intended, these stacked reservoirs in the Powder River Basin have outstanding potential to QEP. By tallying up the Sussex, Shannon and the Niobrara, we have the potential for 95 million to 264 million barrels of oil net to QEP on 320 to 160 acres basin, and we really haven't put in any numbers to the Frontier yet.
So it's an exciting play. It's -- we're kind of early on in it. We plan 4 to 6 wells in 2012 targeting both Sussex and Shannon. And then the out-years, we'll be targeting some of the deeper formations as the play matures.
And with that, I'll open up the floor to any questions, that there might be.Yes, sir?
Yes, that's a good -- the question was, "This is a play that's kind of early on. And how do we assign probabilities?" Well, if I start with the Sussex, we've got wells that produce out of the Sussex. We have a very good handle on what's driving the productivity there. So we feel that the Sussex play is very low risk. And right now, it's just a matter of execution, getting the permits and getting the wells drilled. The Shannon, even though there hasn't been a horizontal well drilled in it yet, it's very much a look-alike to the Sussex. There are old vertical wells that produced noncommercial amounts of oil, 10,000 to 20,000 barrels, which are fantastic indicators for a horizontal play. If you look at the Bakken early on, any kind of vertical well that has perforated in that Bakken formation might produce 1,000 or 2,000 barrels total before modern techniques moved to it. So we feel very good about the Shannon as well. The Niobrara is a bit deeper. We know there's oil in the system. The question for the Niobrara is going to be: Can we frac it? Can we get commercial quantities out of it? If you follow the Niobrara play and the DJ, you see that frac-ing has been a challenge. Counter to the DJ, we do feel that the maturation of the Niobrara is pretty well understood in the Powder, and it's very well behaved, very similar to the Bakken petroleum system. And then the deeper, the Frontier is an established play. There it can be a matter of mapping those sands out and targeting them. But the Niobrara is oil -- I'm sorry, the Frontier is oil charged throughout the deeper parts of the basin. So yes, it is early. It's a good question. But we feel -- knowing our experience in these resource plays, we feel very strongly about the potential in the Powder and very excited about it.
[Indiscernible]. Can you talk about how your [Indiscernible]?
Those -- the Sussex wells were completed kind of similar to what we've seen in the Bakken. Multi-stage frac-ing in the horizontal leg, 10 to 15 stages slickwater fracs. So a pretty similar model. These sands treat pretty well. Yes?
And this -- can you drill 5,000-foot to 10,000-foot well laterally? [Indiscernible]?
Initially shorter because it's a little bit lower risk, and no one has drilled a long lateral here yet. But I think it'll progress very similarly to what we saw in the Bakken. If we can get the play to work, it'll -- we'll much rather drill 10,000-foot laterals than 15,000-foot laterals. But we want to get a few under our belt first then we'll move on to the longer laterals.
Sure. Most of our lands up here are federal lands. So the permitting process is kind of drawn out. The office that handles this out of Casper in Wyoming hasn't seen much activity up until about 1.5 year ago, and now activity is exploding. So they're at their straining point. We're looking at about a year to get a permit. Okay, Scott, any other questions before I move on?
Gosh, in process, I want to say we have probably close to about 20 permits in process, in some stage of a process. If there's no other questions. I'll move into the Vermillion Almond play.On the -- and so I have a few pictures here. Upper left Hiawatha Camp, circa 1968. And we've been active in the Vermillion Basin for a lot of years and drilled our first well in 1927. So it's been an historic area, and we're still finding new reserves out there, which is pretty amazing. Below that picture is a 3D seismic crew in 2003. And this was our rig in the upper right active out here in the summer of 2011.
Geographic setting. The Vermillion Basin is located in Southwestern Wyoming on the border with Colorado, you can see called out here by the blue box. On this map, the gas fields of the Green River Basin are showing in red and QEP's acreages in yellow. And we pretty much have a stranglehold on the acreage in the Vermillion Basin. You can see our acreage out there at Pinedale controlling the Northern 1/3 of the Pinedale Field as well.
This is a type log for the Almond play. And here,,, we're targeting individual sandstone benches within the upper portions of the Almond. Typically, we complete these wells in 3 to 4 frac stages. They're vertical wells, average depth of around 6,250 feet. So they're pretty shallow. They drill relatively quickly.
The next slide is going to be a seismic profile going across the Canyon Creek dome and the Canyon Creek Anticline, which is our primary focus. The seismic line is extracted from our 3D seismic volume. It trends from northwest, which is on the left, to southeast. And in Canyon Creek, we have production from the shallowest, Fort Union zones all the way down to the Dakota. So it produces from multiple-stack reservoirs. But on that structure, and as that structure trends from southwest to northeast, we're focused on the Almond formation, and we're going to be drilling wells along the crest and the planks of that Anticline at depths around 6,250 feet.
This is a map. It kind of zooms into the Wyoming portion of the play. QEP acreage shown in yellow. And on the Wyoming portion, we have around 50,000 net acres. So we have a large, pretty solid acreage holding here. The prior Almond producers are shown by the blue circles. And 2 wells are called out, our 2 wells that we drilled 2 to 3 years ago, the Whiskey Canyon 3, which has a EUR from the Almond only of 2.2 Bcfe, and the Alkali Gulch 5, which has an EUR of 2.5 Bcfe. So very strong wells from relatively shallow depths.
Just this past summer, late summer, we drilled 5 delineation wells targeting the Almond with a relatively small rig. We're just in the process of completing those wells. And if I go from the back limb [ph], the Canyon Creek 13-31 is flowing back around 700,000 cubic feet a day, the 6-29 at 1.2 million, the 9-23 at 1.5 million. We're still flowing back on this one. We have a sustained rate on the 9-29 [ph]. And then the 5-32 [ph], 600,000 cubic feet of gas per day.
So we're testing the gas from these recent Almond completions. Our 2012 plan will include 9 additional Almond wells. So we'll have additional delineation along the flanks and down-dip on the structural, going deeper structurally. We're also going to drill a 40-acre pilot around our Alkali Gulch 5 Well. So the objectives of 2012 are the gradual down-dip delineation, determine the upper Almond's water context as well as the productivity across the structure because it's a very large structure, covering 15, 20 miles from southwest to northeast and about 8 to 10 miles north to south.
This is diagrammatic seismic line going from northwest to southeast with northwest on the right. And it shows the productive wells that we've seen on the [indiscernible] of the structure with the gas symbols at the Almond interval, as well as the 2 recently tested gas wells as we're moving down the flank. We have tested gas 600 feet below the structural spill point in our Alkali Gulch 3 well. however, it was in noncommercial quantities. So the objective of this year is to gradually move towards that Alkali 3 and see where the commercial limit is for the Almond.
This is an early play, but we're pretty excited about it because of the metrics on it. We also hope that using our 3D seismic volume, we'll be able to identify the individual sand bodies of the Almond. This is an example taken from the Vermillion area showing a deep channel sand, which trends from northwest to southeast in the Frontier Formation. We drilled a well here then encountered some very nice sands at around 13,000 feet. So seeing this kind of data from the 3D seismic volume at deep depths gives us confidence that we'll be able to map the Almond sands at much shallower depths, around 6,000 feet.
Our drilling programs was pretty successful. We started out with this new rig, and our first well took 7 days over the about a month's period.
We were able to drill wells and case them in under 4 days, which is pretty remarkable for a target of 6,000 feet. So this will really drive our costs down. Average depths of around 6,400 feet for the Almond.
If we look at the economics, this is a production type curve for a 1.9 Bcfe-type well, considering cryogenic processing. These are pretty liquids-rich gas in cryo processing. A typical Almond well will produce around 90,000 barrels of NGLs, which means our economics are pretty strong. Using a $4.50 NYMEX price and a $1.8 million completed well cost and this 1.9 Bcfe type curve, we've got rates of return of 45%. We've seen wells in excess of 2 Bcf that will give us rates of return with cryo processing of around 80%. So pretty strong. But again, this is early in the phase for the Almond. We have some delineation work to do in 2012.
With that, I'll open up the floor to questions.
What's the status of the EIS?
EIS. What's the status of the EIS? Good question. We started the EIS, gosh, I think this is almost an anniversary, November -- 7 years ago. Typical to a handful of EISs that were started around the same time in Western Wyoming, they're still in the -- I'll try to be kind -- in bureaucratic limbo. They're moving forward, but they're moving forward slowly. They're kind of in their evaluation stage. We hope to have a record of decision within the next 2 years. But we're able to drill out here. We have an MOU, and we are able to drill these delineation wells. We're not impacted by that. Other questions? Yes, sir?
That's going to be an ongoing project, and I believe Perry is going to talk about that later this afternoon. If there's no other questions, I'll turn it over to Paul Matheny, who is going to talk about Pinedale and the Uinta Basin. Thank you for your time. I appreciate it.
Well, good morning. I'm Paul Matheny. I'm Vice President and Chief of Staff at QEP. I started with the company in 1982. I worked in almost all of the aspects of the company since then. Before that, I worked for Gulf Oil [ph] in the Permian Basin. I also worked in China, in Mexico and Australia. And I want to say hello to those of you I've seen before up in Pinedale. We've taken them beyond on tour up there. If you haven't been there, here's a couple of pictures of what it looks like. And again, as Vinnie said for North Dakota, a nice place to be in the summertime.
The next map, I think, is almost identical to what Vinnie showed you. For Vermillion, you see Vermillion down to southeast and our acreage position on the northern end of the Pinedale Anticline. The gas fields are shown in red, and the green represents oilfields.
The statistics first. We have proved reserves of 1.35 Te to Pinedale. As of the end of the year, we will turn in 432 PUD locations that are a combined density of 5, 10 or 20 acres. We have about 1,200 remaining locations to drill, and our completed well costs are now below $3.8 million.
The map on the right shows our acreage in yellow. The red dots are producing gas wells. The gash line around the outside is our current economic limit, and the dash blue polygon near the bottom represents the 2012 position of the CDA, or concentrated development area, which -- where our development activity will be in 2012.
The star in the southeast part shows the location of the type log shown on the left side of the slide. You know that at Pinedale, we produce from about a 5,000-foot interval of stacked pay sands. So that's what you see on the very left. That's the mile-thick stack of pay sands. We expand about 150 feet of that into the larger log section where sand is shown in yellow, where the shales between the sands are in gray and the red symbol show you the gas-producing intervals. These wells have a fairly uniform 2D of about 14,300-foot measured depth.
So the upper left here, you see the pretty predictable trajectory of our net production from 2004 to present. The peaks represent the times of the year when we are able to do the completions, which starts in March and goes through mid-November. And then the declines on those [indiscernible] go from mid-November or December into March when we again begin completions. But overall, the trajectory is pretty constant and predictable.
The map on the right-hand side shows you again our acreage in yellow, and it has the position of the CDAs historically, 2009 through 2011. And it shows you where we'll be as it marches from south to north over the course of our projected development so that in 2019, we will finish up on the north end when we finish with the remaining 1,200-or-so wells that we have left to drill.
I put some more pictures in here to show you one of the unique things we do at Pinedale. Anywhere in our operations, and I think we're at the only operator at Pinedale that does this, we show you how we construct a well pod. So on the upper left, we'll start to see well casings sticking up out of the ground. We drill and set conductor, and then inside the conductor, we drill and set surface casing on 4, 6 or 8 well pods at a time. Once that's done, we go and excavate around and between those casings down to a depth of about 15 feet. In the upper right, you can see that we go in and set precast concrete walls down in that excavation. And in the lower left is what it looks like when the walls are set, the floor, concrete floor is poured. We've cut off those casings and installed the lower section of a wellhead. In the bottom [indiscernible], when all that's done, you can see the bottom section, the wellhead's there along with the mouseholes and ratholes to facilitate the drilling rig when it moves on to drill the majority of the depth of the well. And then finally in the bottom right, you can see what a pod looks like after the wells are drilled and completed down in that cellar with a grade over it [ph]. There will be 6 flowing Pinedale gas wells. We do that so that we're able to drill and frac and produce on the same pad all at once. You can get the wellheads down below the ground, you eliminate that risk of having somebody back into one or something, fall over and damage a wellhead and have a big problem.
One of the reasons our costs continue to decline at Pinedale is because we've continued to become more efficient at drilling. You can see in 2003 it took us 61 to drill on these Pinedale wells. This year, our average is down to 14 days with the fastest at 10.6. That dash curve shows you how many wells our rig has been able to drill in a year. Back in 2003, we could maybe knock out 5 of them. And this year, we're getting about 22 wells per rig per year. So those efficiencies are the reason that we're able to continually to drive down our well costs even though the commodity and component costs aren't decreasing.
Similarly, on the completions, you can see that we're frac-ing more stages in fewer days. Back in 2003, it took us 14 days to pump. Our completion were at 13, 14 stages. And by 2011, we're pumping north of 20 stages in just 3 days. Again, one of the ways we drive those prices down and keep them down is through efficiencies.
This is an interesting slide. This shows the effect our the start-up of Blacks Fork II has had on our net production. Our net gas production is shown in red. The condensate production is stacked on top of it in green. And you can see that August 2011 we started up Blacks Fork II and instantly added about 8,400 barrels, net barrels of NGL per day. That has a tremendous effect on our revenues. We projected in November the NGLs will be responsible for 32% of Pinedale's revenue.
Again, our standard type curve slide for a Pinedale well with an IP of about 6 million barrels -- I'm sorry, 6 million cubic feet of gas a day, EUR of 4.6 Bcfe, which includes the NGLs, $3.8 million well cost at $4.50 NYMEX and $85 WTI. This will generate about a 38% rate of return. And a $3.8 million well has a BTAX PV10 of $2 million. You can see that we're good for a 20% rate of return all the way down to $3 on our 4.6 Bcfe curve. And it just gets better at prices above that.
So I'll be happy to answer any questions about Pinedale before we move on.Sir?
Based on the current [indiscernible]?
Well, we anticipate our volume of wells that we drill per year will slowly but consistently increase as we become more efficient. We're going to add 2 rigs toward the end of this year so that we can generate the volumes to keep Blacks Forks II full. And the best remaining wells that we have to drill are up on the north end. That'll be in the probably 2015, 2016 time frame as we march on that predictable progression, south to north.
I'll -- traditionally, you repeat the question before you answer it. But for the benefit of the folks on the webcast. I'll tell you that, that question was about when will we get to our best remaining wells on the Anticline, what year and how do we anticipate the progress to go forward. Anything else about Pinedale? Okay, we'll keep going and talk about the Uinta Basin.So we haven't taken anything out of the Uinta Basin, but we did include a picture here of the only trees on any of our leaseholds. So that's also the rig that will be doing the drilling that we're going to talk about.
Again, here's our standard location map. Gas fields in red, oil fields in green, our acreage is yellow. You can see in the upper right, the Northeast is Vermillion, to kind of get you registered to where we were talking about Pinedale and Vermillion. Red Wash is located in the northeast part of Utah. And I want to bring your attention to the little bit of green that's peeking out from under our yellow acreage there at Red Wash. That's the -- what we expect to be about another 100 million barrels of oil peeking out underneath that acreage in addition to the gas play we're going to talk about.
So besides our project, there are a couple of other Lower Mesaverde development projects going on. Our acreage is yellow here. Our Red Wash unit is outlined in red in the upper right. The blue shows you an active development program with 1 rig producing about 144 million a day, and it's being developed on a 10-acre density. That's EOG's GW Wells [ph] project.
To the west of it, again in pink is Anadarko's Natural Buttes where they run 7 rigs. They're making north of 500 million a day, about 2,200 barrels of condensate and 9,000 barrels of NGLs by virtue of cryogenic processing. And that's also being done on a 10-acre bottom hole density.
So we're going to zoom in on our acreage a little bit here. We outline Red Wash in the black solid line. Again, our acreage is yellow. You can see our 19 producing gas wells by their red gas symbols there. And the pink area is the Lower Mesaverde productive fairway as we currently interpret it. These Lower Mesaverde wells are 11,500 to 12,000 feet measured depth. And they produce from -- again, from a series stacked sandstone objectives. Today, our wells have EURs of about 0.6 of a B all the way up to 5 Bcfes.
The location of the type log is shown by the red star in the lower right part of our acreage. That type log is on the left-hand side of the slide. And it shows you the stacked sandstone objectives, excuse me, in yellow. They occur over about 1,000-foot interval of the Lower Mesaverde. And the gas-productive sands are shown by the red symbols.
So this is -- we just looked at Pinedale. This is very similar to what Pinedale looks like and how Pinedale behaves. It's not as thick a section, but the area is much greater.
This is an interesting slide here. It's Lower Mesaverde production data normalized to time 0 on the left-hand side. So our type curve is the heavy dashed red. And then the other colored curves show each of our wells normalized back to time 0 start date. So you can see that we have 1 well that's been producing for about 3 years. We have several that have been online between 1 and 2 years, and quite a number that are have been producing for almost a year now.
And you can see the IPs of those wells range from about 800 Mcf a day on the bottom end up to about 3.5 million a day on the best ones.
The plot in the upper right is a probit [ph] plot where you plot gross EUR along the x axis on a log scale against our well results on the vertical scale and a probability on the vertical axis on a probability scale. So you can see that's a pretty well-behaved population of wells for the 19 that we've drilled so far. You can see the range of EURs from 0.6 on the bottom end up to 5 Bs for the best one. And what you should really take away from this is that you can see 90% of our wells, 90% of these wells, which is a pretty representative population, have an EUR of 1.4 Bs or better.
So zooming even farther on our acreage, even closer, and one maybe analogy to Pinedale. Just to give you a sense of scale, Pinedale is 8 miles from south to north on our acreage. If you laid those down horizontally, you could put 2 Pinedales side by side in here and stack 3 of them on top of each other. So there's room for 6 Pinedale areas within the area of our pink area of anticipated Lower Mesaverde development.
So the pink area is what we expect to be productive. Our 19 producing wells are shown there. Red Wash unit is outlined in black, and our Kilimanjaro Unit outlined in turquoise. As Jay said, all this acreage is HBP, so we don't have any expirations to chase. So we can go about a rational, orderly development of this project in whatever way makes the most sense.
To give you an idea of what this would mean in terms of locations and reserves, if we're to develop this area on 20-acre spacing, it represents 1,670 gross locations. QEP reserves would be 1.95 Tcf net with 24 million barrels of condensate and 110 million barrels of NGLs.
If we're to develop on 10-acre density, like the other projects that are just to the south of us, that would be 3,200 locations, 3.3 Ts, 42 million barrels net condensates and 200 million barrels net NGLs. So that number is the size of the existing company.
So this shows you where we plan to do our development drilling in the remainder of this year and in 2012. The green diamonds are the wells that we'll drill in the remainder of 2011, the blue squares are our 2012 locations. And the purpose -- I have 2 objectives for these 2 years' drilling campaigns. One is to get some more spatial delineation of the areas that we haven't tested yet up to the north and out to the east and west. And we also want to do some density pilots so that we can determine the appropriate well density going forward. This is exactly the same process that we went though at Pinedale about 7 or 8 years ago. So we know how to do is. We've been very effective and efficient doing it at Pinedale. We anticipate the same type of process here, so -- which might give us a pointer.
The southeast part of the project, you can see we have lots of blue squares concentrated. We're going to drill 10- and 20-acre offsets to a couple of our producing wells here to look for both pressure depletion and continuity of sands between all those wells. We have another pilot down here in the south central part where we're going to offset an existing producer on 2 sides. And then finally, out here in the west, we're going to do the same thing around this existing gas well, again to see if we can detect any pressure depletion from the existing production as well as get an idea for the extent of the sands that we're producing from.
So here's our type curve for the Lower Mesaverde play. Again, the IP is 2.4 million a day. Our 2.1 Bcfe EUR, that includes the 70-plus thousand barrels of NGLs per well. The $2.1 million well cost at $4.50 NYMEX and $85 WTI allowed us to make a 42% BTAX rate of return. A $2.1 million well is worth $1.5 million in BTAX PV10. And you can see on the sensitivity on the right that given the amount of liquids that we're going to produce, we're still at a 20% rate of return all the way down to $3 NYMEX gas.
So this is a trick. Usually, I ask for questions, but we're not done. So this is a schematic cross-section that shows at the bottom in red the stacked sandstones we've been talking about in the Lower Mesaverde. And above that, shallower in green are the stacked sandstones in the Lower Green River Formation. Now those sandstones have been producing since the 1950s. That was the original objective of the field. And it was developed on 40-acre spacing between the late 50s and the 1990s.
So what we're talking about doing is going in and drilling in between those wells on the 40-acre spacing through the Lower Green River and down to the Mesaverde. And why that's significant is that we believe even though Red Wash has produced almost a 100 million barrels of oil from the Green River already, there's a significant amount of oil that's been bypassed, and we're going to get a free look at it as we drill through on the way to the Lower Mesaverde. So the next slide kind of talks about how we'll do that.
Again, Red Wash is outlined in red. On this slide, the green circles are existing oil wells that are still producing. The blue squares here are water injectors in the existing waterflood, and the red diamonds are gas wells that produce from the Green River.
Now the Green River, again, is a stacked interval of sandstones, spans about 3,000 feet top to bottom. There have been 78 individual producing reservoirs identified within that 3,000-foot section. These oil wells historically have had EURs between 30,000 and 1.3 million barrels per well, so they can make a lot of oil.
And there's a waterflood in place that was initiated in the 1960s by Gulf Oil [ph], and it's been very inefficient. And the reason is -- as you can see on the type log, the location type log is the red star out in the eastern part of the oil field. Now we take that 3,000 feet of the total pay interval and expand it to about a 300-foot section where again, you can see the sands in yellow. The oil-productive symbols show you that most of those sands are oil productive. And the reason that the waterflood has been so inefficient is that water was pumping these wells, and it just went in all the sands. So there's no ability to control the conformance of the flood. The water went where it wanted to go. And there's a lot of oil, but it has never been touched by water. So we feel there's hundreds of millions of barrels that should have been produced that hasn't been yet.
So last slide, the green area is the outline of Red Wash oil field. Again, the green circles are Green River oil producers. The red diamonds are Green River gas wells. And the blue squares on this map are where we're going to drill those 40 wells in 2012 and 10 wells the remainder of this year.
So what's significant about the field is this low recovery of oil. We have another waterflood that we operate called Glen Bench, which is outlined in blue down in the southwest portion of the map. We know that Glen Bench from 1 sand, so is a flooded 1 sand. So it's very efficient. It had 5.4 million barrels in place originally. To date, we recovered 2.3 million for an efficiency of 43%. We project an EUR of 2.6 million barrels from that project. That would probably about 48% recovery of the original oil in place. Now to contrast that with Red Wash where 78 sands produced, and we've calculated 747 million barrels of oil originally in place but only recovered 88 million barrels to date. That's 11.8%. Any reservoir engineering textbook or reservoir engineering course would tell you that an average recovery on primary from a conventional reservoir is about 15%. But you waterflood, you should be able to easily recover about 30% of the original oil in place. So our expectation is that as we drill the Lower Mesaverde gas wells and go to the Green River, we're going to find a bunch of that oil that should have been produced already but it hasn't. If we could come close to what you'd expect from a conventional reservoir, secondary recovery of about 30%, we could come up with as much as 100 million to 112 million net barrels incremental from the oil field part of Red Wash. And again, I'll remind you this is HBP 100% working interest, 87% in our acreage.
So, I'll be happy to answer any questions about Red Wash.
[Indiscernible] Red Wash [indiscernible] Red Wash [indiscernible]?
Yes, sure. The question is about the depth of Red Wash going from east to west. The drill depth is about 10,000 feet on the east side, and it goes down to about 13,000 feet as it dips west by the time you get to the far west side of the acreage, with an average of 11,500 to 12,000 feet for the Lower Mesaverde there in the central part.
The well cost?
Right now, we're looking at $2.1 million well cost for these Lower Mesaverde combinations of deepenings and new drills.
Yes. But we've -- so far, we've drilled 19 of these things. We expect the same sort of hammering of well costs that we've done at Pinedale as we drill 1,600 or 3,000 of them going forward. So we're going tell you we're going to start off that 2.1 average, but we fully expect it to be better.
Again, with Pinedale as the analogy, we are planning and expect to do the development here on pads like we do at Pinedale. So we'll have a number of large multi-well pads and drill 40 or 50 wells directionally from each pads so that we can minimize our surface disturbance and also minimize the amount of surface facilities that we have to build and construct. Yes, sir?
[Indiscernible] operating expense [Indiscernible]?
The primary -- now the question is about operating expenses. At $0.76 per million on Red Wash project versus Pinedale, which is about $0.18. The main difference is that we produce quite a bit more water from these Mesaverde sands. So the water lifting, water transportation and water disposal costs make up the bulk of the difference. Yes, sir?
[Indiscernible] several years out, what's the ramp of [indiscernible]?
Sure. The question was about rate of development once we get out a few years and get going on our program. We'll be doing this, this development, with the same rig that Vinnie showed you that we used in Vermillion, where they started out with about 7 days to drill the well and, after a month, they were down to 4 days. We're going to use the same rig, same kind of rig. In fact, the exact same rig as drilling force in the Uinta Basin now. So once we determine what the appropriate well density is and the appropriate pad layout and facilities, we can knock out a bunch of these wells. Jay, I think showed you we had 60-year development life on this project with the 2 rigs that we have scheduled for next year. But I think when we began our plan, finally finished and decide to go forward and have gas processing in place, we go pretty fast and knock out hundreds of these wells per year. So a little premature to be specific beyond that at this point, but it could get really big really fast.
When will you have the gas processing in place to [Indiscernible]?
Yes, the question was about when we'd have the gas processing in place. And yes, it would be correct to assume that we'll plan to have the gas production and the ability to process that gas to arrive at the same time. So given that it takes a year, 1.5 years to get it together and build one of these things, we probably wouldn't accelerate things much faster than that. But depending on the well density and the ultimate development scenario, it could be a lot of drilling and a lot of processing. Construction also. Other questions? All right. Thanks.
We're running about 15 minutes ahead of schedule. So we're going to take a break, take a 15-minute break. It is 11:00 or close to 11:00, Eastern Time, right now. We're going to come back in 15 minutes, 11:15. So those of the webcast, hang with us. We'll be back -- start it back up here in about 15 minutes. Thank you.
Can I have your attention? If you could take your seats. We'd like to get started again. All right, well, we're going to go ahead and move to our Southern Region. And first, I'll have Jeff Thompson come up and talk about the projects within his area followed by Linden Bailey. When these guys are done, we'll give you a just ask questions about all of the QEP projects that you have heard about today or anything that slips on your mind relative to Q2. I believe it's lunch break and then we get into the midstream, field services after lunch. So Jeff?
Thank you. My name is Jeff Thompson. I'm a division reservoir engineer in our Oklahoma City division. Myself and Linden Bailey will be up here in a little bit. We're going to talk a little bit about the Southern Region and the plays we got going on now. In case you're wondering if I'm an engineer, I did bring my ginormous calculator in case any of you have any real detailed questions.
So anyway, let's go ahead and move on. And these are some of the plays we're going to talk about today. So I'm going to discuss the Anadarko Basin. And for our 2012 activity, that's going to primarily include the Cana Woodford, the Marmaton and Tonkawa plays. And then shortly after that, Linden is going to come up and discuss the Haynesville Shale in Northwest Louisiana.
Okay, here’s a picture of the infill pilot that was -- we had a non-op working interest in that pilot, just to give you an idea that there is development going on here and will be in the coming future, especially in 2012.
All right, so here's a map of our acreage throughout the Anadarko Basin. And there's really 2 things I'd like to point out on this slide. First, you can see the yellow, obviously the QEP acreage, and it's scattered all across the Anadarko Basin. And then we have kind of an outline of the 3 plays we're going to discuss today. The Woodford in the red. That's a liquids-rich gas play. And then our 2 oil plays are the Tonkawa that kind of straddles the -- right up against Oklahoma-Texas border, and the Marmaton play up in the Oklahoma Panhandle.
One thing that I think is interesting about this slide is you could see our acreage scattered all over the Anadarko Basin, but you see a much higher density of acreage located in the Woodford play. And one important thing to point out about that is that wasn't always the case. We had -- inside that red bubble, our acreage is very similar to what it is outside the red bubble prior to the take-off of Woodford play. And since we did have so much acreage located in and around where all the activity was, we were able to be on the forefront of acquiring leases and really able to build a very nice acreage position within the play because we are kind of located all over. So we're very familiar with the Anadarko Basin. We've worked it for years and years, and we just keep finding new projects to work on. So without further ado, let's get into the Woodford.
Okay, here's the Strat. Column and, again, a general map. And this is just a structure map on the Arbuckle so you can get an idea of the depths of the Arbuckle relative throughout Anadarko Basin. And the Woodford Cana Shale is a Devonian shale, and then you move up to the Pennsylvanian-aged sands and carbonates. And you've got the Marmaton, which is a carbonate reservoir. And as I said, it's an oil producer. And the Tonkawa is a sandstone reservoir that also produces oil.
So okay, here's a map of our Cana Woodford Shale acreage position. You see we have lines outlining the Tier 2 and the Tier I acreage, and the yellow is our Woodford acreage in the area. And I think all total we have about 77,000 net acres of Woodford Shale. And you can see our Tier 1 boundary is defined by being 150-foot-or-greater thickness for the Woodford Shale. And you can also see that there's a lot more density of drilling inside the Tier 1 area as opposed to the Tier 2 area. And a lot of that is just the Tier 1 is where the play was kicked off. That's where the first wells were drilled. And slowly but surely, it's kind of moved out outside the Tier 1 up into the Tier 2 both to the northwest and the southeast. The primary difference that we see between these 2 areas is the Tier 1 has very -- obviously, with the density of drilling that's happened there, we have a lot of wells drilled to delineate the acreage, and we see very consistently repeatable results in this area. All very economic, and we'll talk a little bit about the liquids in that portion of the play in here in a little bit.
But once you move outside the Tier 1 area, we've seen some very good well results outside that area. But we simply don't have nearly the amount of wells drilled to define the acreage fully. We see a little bit of a wider range of results in the Tier 2 area, but still some very promising results. Most of our activity in 2012 is going to be focused on the Tier 1 area, and we're going to start working on some increased-density projects and I'll talk to you about that here in a minute.
All right, so here's a type log of the Woodford Shale. And you can see this type log is -- the location of it, so start here in the middle of the core. It's about a 300-foot pay zone in the type log. And we land our laterals in kind of the upper portion of the middle member of the Woodford, and we -- the -- they're roughly about 13,000 feet deep TVD, so 18,000-foot with a 5,000 lateral and -- 5,000-foot lateral. And we cement all these wells, and we frac them in about 13 or 14 stages with 3 million tons of prop. And then let's see.
Okay, next we're going to talk a little bit about the liquids in this play. All right. So this will give you an idea of kind of where the thermal maturity and how it changes from the northeast down to the southwest. So up in the northeast parts of the Cana Woodford play, it's shallower, it's less thermally mature. And so although it's still gas in the reservoir, as we produce it to surface, there's a lot more heavy molecules located in the gas stream, and that falls out both into the separator tank as well as we process it and get NGLs out of the gas stream.
For the kind of the light green band in the middle, that's kind of the transition zone as we move from the dryer gas area to the very condensate-rich area. And then that kind of red-banded cells, it's more thermally mature, it's deeper. And so we're seeing -- we don't see hardly any condensate in that area, but we are able to process the gas and get some NGLs extracted out of that.
Total reserves as of year-end 2010, we're looking at about 200 Bcfe with 103 PUD locations. And we estimate about 3,450 total locations to be drilled in the entire Woodford. And that's on the combination of both 80- and 160-acre spacing. Completed well cost range from $7.5 million to $9.5 million, and that's primarily just due to the differences in depths throughout the play, so.
Okay, for the infill pilot program, that's one of the main projects that we're going to be working on in 2012. And we plan to spud in the middle of the year and drill 8 wells in 1 -- 8 additional wells in 1 section. And the location of that pilot, as you can see, is basically right in the center of the slide where you have those pink well locations. And it's in 13 10 -- I'm sorry 13 north, 10 west, so right in the heart of the Cana Woodford play.
And as you could see, just due north of where our planned pilot is located, there is a section where another operated -- we have a nonoperated working interest in the section, drilled a 4-well infill pilot mid-2010. So we've got a long life of production history to analyze those wells. And from what we've seen, we predict EURs to be in the 5.5 to 8.6 Bcf range. So very good wells, and they don't appear to display an enormous amount of interference with each other that we feel would be any kind of drawback in terms of drilling these on 80-acre density. But anyway, that's essentially the only data point that we and, I believe, most of the operators have in the play. So we're going to go ahead and drill our own 8-well pilot that we feel very strongly about and we think is going to be a big uptick in production for our division as well as the company. And we hope to report more results on that towards the end of next year.
Okay, here's the economics on the Woodford Cana Shale for Oklahoma. This is our type log. This type log is for 5.5 Bcfe well, which essentially ties to the blue sensitivity curve over on the right. These 3 sensitivity curves, just kind of so you know as you're looking at his, are tied to the 3 different areas of thermal maturity. Remember we had the red and the light green and the dark green bands? So the red sensitivity curve, obviously, is the red line. The blue is kind of the transition to wet gas zone. And then the dark green is the high-condensate area. Anyways, so we got a 5.5 Bcfe type curve with initial IP of right around 5.5 million a day. We have the type curves at about $8.3 million, which is kind of just our average for the heart of the play. So in terms of rate of return, this -- the wet gas zone, we're at about a 23.4% rate of return with $3.3 million BTAX PV10 and a net finding cost of $1.64.
As you look at the other 2 plays or other 2 areas of the play, the 5.5 Bcf type curve for the dry gas window is about -- at $4.50 and $85 pricing is right around 11% rate of return. And the heavy condensate NGL window is upwards of 40% rate of return at our flat pricing scenario here. So we are going to focus most of our drilling on the wet gas and the high-condensate areas of the play. And since most of our dry gas acreage is HBP, we don't -- we intend to wait and see where we can get some gas prices and then develop that at a later date. So I believe that's the last slide I have on the Woodford. I'll be happy to take any questions on the Woodford before I move on to the other 2 plays. Any questions? So here's one.
[Indiscernible] condensate [indiscernible]?
Condensate and wet gas.
Btu? I'm sorry, okay. The question was what is the -- for the capital return sensitivity curves, she was referring to the EURs that are listed on the chart there. And what that's showing is the condensate and the wet gas. So on the 5.3 and the 26 MBo, which represents kind of the light green portion of the play, that's about 1,180 to 1,200 Btu gas. And for the, the 3.7 Bcf and 86 MBo, that's more in the 1,250 to 1,300 Btu tight gas. Any other questions? Okay, we'll jump into the Tonkawa quick.
As I said before, Tonkawa is a sand play, the Pennsylvanian sand. And we have a type curve here, and it shows that we land our laterals in that thick sand package towards the bottom of the Tonkawa interval. And when we cement our casing here and complete them with 10 stages and about 2.5 million pounds of prop. We have a total of 6,600 net acres in the Tonkawa fairway. And you can see on the slide we've got our acreage in yellow and then our planned 2012 locations in blue. So just to point out some of the recent results, we've got an IP of 1,029 barrels of oil equivalent per day, a 1,343 barrel of oil equivalent per day and a 767 barrels of oil equivalent per day. The lowest 1 that we're showing on the slide is right around 500 barrels of oil equivalent per day. So very strong results in the early life of these wells, and I think you'll see from the economics that we feel really good about the upside of this play. Let's see, the -- and just to point out, you can see our 2012 locations are all kind of surrounded by the very high IPs that we're seeing on this slide.
Okay, just briefly discussing the potential of the Tonkawa play. We assume the EUR to be about 140 to 290 MBoe. And we think this will be developed on either 320- or 160-acre spacing. So just kind of doing the math for you, that's either 21 net locations on 320-acre spacing or 41 net locations on 160-acre spacing. And so that's gives us the range of reserve potential from 3 to 8 -- or 3 on the low end, 3 million barrels of oil equivalent on the low end up to 16 million barrels of oil equivalent on the high end. So it's very early in this play's life, and I believe we only have one operating well that's been drilled and not completed yet. So we're just now kicking off our operating acreage in this play. So there'll be a lot more to come on the Tonkawa in the future.
Just to give you an idea of the economics of the Tonkawa, we have our type curve off the list. That's with 100 barrels of oil equivalent per day IP, and total type curve EUR is 310 barrels of oil equivalent with $5.6 million completed well cost. These wells are a little bit shallower and don't take as much capital to complete, obviously. Then the Woodford number I'm referring to.
The total BTAX rate of return run on the $4.50 and $85 flat pricing is 39.4% with a PV10 from that $5.6 million investment of $3.3 million. And net finding cost of $20.40 per Boe.
That sensitivity curve there and up to $95 oil, we're up over 50% rate of return. So very economic play. That's all we have on Tonkawa right now. Do you have any questions there real quick before we move on to Marmaton? No? Okay, very good.
Okay, here's the Marmaton. And we have our type log here on the Marmaton as well as our acreage map. And one important thing to point out on the Marmaton is it doesn't look very good on logs. It's a fractured carbonate reservoir. And if all we did was look at log characteristics, then you would think that this play wouldn't be able to take off. But there's so much oil stored in all these fractures that we can't identify from the logs. Our geologic and geophysics teams worked really hard to identify the location of where these fracture systems are and the best places to drill our laterals so that we get the -- so we connect up the most fractures and get the most complex fracture network together so we can produce all that oil. So anyway, the map that we have that we're not showing today is primarily a map that identifies where these fractures are. And that's the thing that drives this play.
The -- a few IPs to point out on there is the QEP-operated Bobbit 3-13H. It had one of the best IPs this play has seen so far with 1,063 barrels of oil per day. That just came online a few weeks ago. We also -- we've also drilled and completed or are completing the Law 4-19H. So we should be getting results on that one in the not-too-distant future. And we are currently drilling the Patzkowsky 1-20H The only other IP that we have on this map is the 641 barrels of oil per day that's located just off of our acreage lot there.
Let's see. These yellow -- or, I'm sorry, these -- the yellow is our acreage, obviously, and then these blue squares identify where we have locations planned for 2012. And as you can see, a lot of those locations are in and around that Bobbit 3-13H well. So we have a lot of high confidence that those are going to be some good locations and good wells as we drill them next year.
Okay, just give you an idea of kind of the range of results we can expect from this play. On 320-acre spacing, that gives an estimated 97 net locations. On 160, that will be 194 net locations. We've put EUR range on this play at between 100 and 165 barrels of oil equivalent. So that puts our reserve potential, depending well results and spacing, anywhere from 10 million barrels of oil equivalent up to 32 million barrels of oil equivalent. So again, so very early in the stage, but we really feel strongly about this play especially with the result of that Bobbit 3-13H coming online a few weeks ago.
So all right, here's the Marmaton horizontal type curve. And you can see that on the left. This is for a 135 MBoe well. So basically right in the middle of that range that we discussed on the last slide. And 760 barrels of oil equivalent IP. And the well cost on these is what's -- one of the huge upsides of this play is only $3.5 million. And that gives us a BTAX rate of return of 106.7% and a net PV10 of $1.7 million. Finding costs on these wells is 36.18 per barrel of oil equivalent. But the biggest thing about this, as you can see from the type curve, you get so much oil back so quickly. And these wells have short lives they it really accelerates the present value of these wells.
And looking at the capital return price sensitivity curve, we really couldn't go much above $85 without going above 100%. So that basically goes off the charts. Then on the low end, down to $75, we still have a 60% rate of return. So a very economic play, and the Oklahoma City bunch will be working really hard to exploit that throughout the year and beyond.
That's all I have for that Marmaton. And any other questions before we move on to the Haynesville?
Well, we have 2 rigs running in the Woodford play. And then we'll have 1 rig running Tonkawa and 1 rig running Marmaton. So total of 4 rigs for the division. Any other questions? Okay, fantastic. Well, we'll move on to Haynesville. Oop.
A quick question.
Knock it in there.
Okay, the question was what we think about the Hogshooter. And kind of going forward, where we see that play going. Is that correct? Okay. The Hogshooter is still very early in the development. We see a lot of really high IPs, and we're still trying to ascertain what we think the EURs are going to be on that acreage position. We haven't drilled any operated wells for the Hogshooter, but we do have a lot of non-op wells that will be coming online. We're very encouraged about the high oil IPs. Obviously, oil is kind of what we're all looking for these days. But in terms of us putting a huge operated program there, I don't know that we have the acreage to do that. And we're still kind of evaluating where we see that play going. So all of our operated rigs are going to be focused on these 3 plays that we listed here. So any another questions? Okay, very good. With that, I'll turn it over to Linden who is going to talk about North Louisiana Haynesville.
Hi. My name is Linden. Excuse me. My name is Linden Bailey. I'm an engineer out of Tulsa office, working the Cotton Valley Haynesville division. It had the distinction of being the only dry gas play in our portfolio right now, but we're actively drilling. So I'll try to move quickly through these slides, if we can.
Okay, this is a geographic setting of the Haynesville. And here we see that it's in the Northwest Louisiana area, extending into East Texas. Our acreage is towards the northeast portion of this play.
The next slide shows roughly where our acreage is relative to the developments. You can see that our 50,000 acres are very much in the core of the play. They're concentrated in the areas of highest development and the best well results.
Here we have type log. The type location is here in the center of our operated position. True vertical depth is in the 12,000- to 13,000-foot range. EUR is in the 6 to 8 Bcf on average. We do have wells that are better than that average. We think we have a number of wells that may approach 10 Bcf in ultimate recovery.
As of year-end 2010, we have a 0.6 of a Tcf in proved reserves, 219 PUD locations. And that's 1,300 remaining locations on 80-acre spacing.
I'd like to draw your attention to the different fields. We have the Elm Grove field in the northwest portion of the acreage. That's where we started developing Cotton Valley/Hosston. We also have the Thorn Lake field in the southern area and Woodardville [indiscernible] to the East. The next area that I'll be talking about is Thorn Lake on the southern edge of where we operate.
Okay. In the Thorn Lake field, you have the yellow operated units and the green units which are operated by other operators. The initial well was done in the 7-well pilot section here with -- that initial well was drilled by another operator back in 2009. Then last year, both us and that other operator drilled and completed 3 wells in that unit, bringing a total of 7 locations in that unit, roughly 90-acre spacing. The Thorn Lake well EURs are in the 6.5 to 7.5 Bcf range, we believe. I'll get a little bit more in the detail on those.
And finally, a second unit just recently put online with 8 wells in there drilled by yet another operator. Way too early to start assigning EURs there, but we are encouraged by the initial rates and pressures.
Okay, this is a slide on the 40-acre spacing pilot concept. This is not anything that we have planned in 2012, but it is something that we might get into in a higher gas price environment. Basically, the idea is to stagger laterals low and then high in an upper and lower target within the Haynesville, thereby optimizing the recovery within the unit. It's not anything, like I said, that we have planned immediately. But in a higher gas and price environment, we think there may be some technical merit to the concept.
This next slide shows just how important the operator actually is to the development in the Haynesville. Three different operators, all at wells in the same general area, towards the eastern portion of our acreage. And you see different well results based off of different completion practices and flow-back procedures.
I'll actually start with operator B, the operator in black. The top graph is the gas rate versus cumulative gas production. The bottom curve is formed bottom hole pressure against cumulative gas production. You could see the wells, I believe nicely 15 million a day, good pressure on the bottom graph, but very quickly declined. We think that's due to a couple of different things. One, on the stimulation side, a lot of cross-linked gel pumped in their treatment and then they compounded that problem with opening the chokes and being very aggressive in how they draw the pressure down. And the recoveries kind of speak for themselves. We're projecting them only at a 3.3 Bcf EUR for their 4 wells.
Next operator did a lot better job stimulating the rock but also fell into the trap of opening the chokes and trying to get that recovery up in that first year. And you see even at 2 Bcf, the rate cum plot crosses over and then from that point on, not even within the first year they're trailing behind and will continue to trail behind over the life of these wells. We're projecting those EURs in the 6 Bcf range. Finally, the QEP wells did an effective job on the stimulation. Got tighter chokes to manage pressure and drawdown, and we're projecting those wells at about 9 Bcf. You can see clearly that we're producing more gas at higher pressures within about the first year of the life of these wells, and everything from here looks like -- will be much more profitable.
Next slide shows how drill times have come down over time. You see we've cut our time in half from 2009 into 2011 with a record of 20 days. That's a TD.
The next slide is average days to complete. Once again, we're giving -- contractors offer a location and writing smaller checks to the drilling and completions guys, while still maintaining a good completion with 14 stages per well.
Last slide I'll get into on the technical side of things, discusses the results of that Thorn Lake, 7-well pilots. This is an average infill well from that Thorn Lake pilot. And you see historically, we've got about 12 months of production data here while IP-ing about 7 million a day and then declining from there. There's a wide range of potential EURs that you could assign to the location here, just depending on the hyperbolic [indiscernible] of things. Any of these curves are somewhat valid, at least according to the production data. So where we have this well booked is at 6.1 Bcf, that's the red curve that you see there. We take a very conservative approach when it comes to booking reserves and I think that's paid dividends. And if you look at the wells that we completed in 2009, we see that per well EUR, those wells that we brought online in 2009 was 6.7 Bcf, those same exact wells in the last quarterly update we had booked at now at 7.2 Bcf. So generally speaking, our wells meet or exceed expectations and we have been able to positively revise our reserves upward with time.
Now speaking to what I would call the reasonable curves here in the middle between 6 Bcf and perhaps 9 Bcf here. The midpoint of those would be 7.4 Bcf. To kind of substantiate that a bit, we did have a third party do a reservoir stimulation study and their per well EUR is in the 7.5 Bcf to 8 Bcf range, just to kind of give you a handle on what we think these well might produce. But when the engineering data is there to support a stronger booking, that's when we will move the reserves up on this.
Last slide is on the economics. You see the details there. 8 million a day IP, b factor of only a 0.3, 50% initial decline. At $4.50 gas and 6 Bcf, we're generating about a 20% BTAX rate of return. And for those wells, should the EURs be more in the 7 Bcf to 8 Bcf range, we'd be looking at a rate of return of closer to 30%. Any questions at this time?
What is the rig cap you have next year?
We will be going to 2 operated rigs next year.
Right. So the question is about the upper and lower targets and where they lie. They're actually both within the Haynesville. Our Haynesville section is as thin as 150 feet, in places can be more than 200 feet thick. So no, it is not the mid-Bossier. These would be staggered laterals within the Haynesville itself.
Right. So the reason behind why we think that we might need 2 separate locations to land our laterals, basically the structures are all very similar within the Haynesville, if you look at the overburden versus the stresses horizontally. So we think that we get a lot of pancake fracturing, which is not just straight up and down --extending up over the -- All of the Haynesville -- it's possible that we also get a lot of pancake fracturing so we get a lot of lateral fractures moving out. And so it could be that the upper portion or the lower portion, depending on where you land your lateral, may not be effectively drained as the interval unless you actually do land your lateral. It's a concept that other operators are starting to maybe realize that we might be testing in 2013 or something like that.
Based on the [indiscernible] we're ultimately heading to an 8.9 to 9 [indiscernible].
Yes, okay. As far as how many of our locations are operating versus non-operated, it's about half and half. But we have, of course a lot higher working interest in the operated. As far as the per well EURs, when we have the engineering data to justify it, we will increase the per well assignments. We're basically trying to take a single curve to describe a 5 parish or county region. And so we recognize that the results from the Thorn Lake pilot still carry a little bit of risk, applying them to other areas. Now the other areas have things going for them too. Some have better thickness. But at this time, it's just too early to try to revise that curve upwards.
Are you seeing completion cost coming down?
Question was, if we're seeing completion cost come down. I don't think that we are at this time. We're kind of stabilizing that $8.5 million to $9.5 million range, and maybe the average is right around $9 million at this point. You don't want to cut your sand and water too much. We've tried that and the results were not as good.
Okay. With that, I guess I'll pass this back on to Jeff's.
I hate to hear Linden apologize for working the only dry gas area within our inventory, but the Haynesville is a great play and I'll add my 2 cents about why you won't see us really increasing our tight curve and our materials, and that's we plan on going to increase density full development. And we do expect to see some degradations from the interference between wells. And so on average, while we'll see the first well per section EURs creep upwards, we don't want to put false expectations out there for what the average EUR is going to be under a full 80-acre development scenario.
This last slide I've got here is just kind of wrapping up a summary of the plays you heard the fellows talk about today that are in addition to our Pinedale, Woodford and Haynesville plays, which you heard a lot about in the past. These newer projects that we've talked about today have the potential to add significant liquids and gas beyond our current crude reserves. You can see the range for oil potential between the individual plays we talked about on the low end of 254 million barrels to 626 million. For condensate and NGLs, 134 million to 242 million and additional gas from 2 to 3.3 Tcfe. So a lot of potential on our legacy acreage. As I mentioned, the majority of our acreage by far is held by production, were not driven by explorations. We don't have any explorations remaining in the Haynesville play. That's all HBP. And the 2 rigs that we plan on running there next year are really focused on trying to maintain that cost leadership role that we currently have in the Haynesville play. We believe we are the lowest cost operator in our depth portion of the play. Well, either we talked way too fast or you didn't ask enough questions, so I'm going to open it back up for questions on anything you've heard about the QEP plays, QEP Energy plays. You'll get another shot at the end, but before we break for lunch, just give you one more chance to ask questions.
The last thing I will mention to end up the QEP Energy portion though is that as Chuck mentioned, we have a sense of urgency and no room for complacency within our company. And I can tell you, I feel that and I think all of our managers here feel that. And while you've seen all of the plays that we plan on allocating dollars to in our 2012 budget today, the exact rig count will change based upon the commodity prices that we see and information and new data we see. We set a budget in advance, but things change and we're always flexible in our rig contracts that we have allow us to have flexibility to move. We, out of our entire rig portfolio next year, there's only 4 contracts that extend beyond 2012.
Okay, with that, we'll go to lunch.
All right. So what we're going to do here for lunch is the food is outside in a buffet style and just grab your food, come back in here and eat at the table or you can eat over in the Reed Salon, wherever you choose. We're going to try to get out of here a little early today to get you guys back to work. So we're going to stick to the original time frame, which was 45 minutes for lunch. So we'll try to get started back up here again at 12:45 p.m. For those on the webcast, please come back in about 45 minutes and we'll get kicked off with the Field Services. Thank you.
All right. I think it's time to get going again. I hope everybody enjoyed their meal. Those on the webcast, I hope you were able to grab a bite to eat as well. We're going to get kicked off here with our Midstream business. And I'm going to introduce Perry Richards, who runs that operation for us. So Perry?
Perry H. Richards
Thanks, Scott. As Scott mentioned, I'm Perry Richards, Senior Vice President of the Midstream business. I've been with QEP now about 28 years. Actually, I started out in college, excuse me, working as a meter reader for the local utility there in Salt Lake City, and I just kind of stayed with the company ever since. Kind of, you've heard a lot about from engineers and geologists today, my background is more on accounting and on the financial side of the business. What I hope to do today is kind of reprogram your thinking just a little bit. You've been hearing a lot about frac-ing and type curves, type logs and horizontal drilling and things like that. I want to kind of spend some time talking about some real exciting stuff: compression, gathering, processing, keep-whole margins, those types of things. So that's what I hope to present to you today.
Well, the picture up there of our Blacks Fork complex, as you can see on left-hand side looking east, on the right-hand side looking west, to give you a perspective of the size of that facility going from east to west. It's just about 3/4 of a mile long, so a very large facility. Here's our areas of operation. As you can see, we overlay where a lot of our E&P company assets are up in the Williston Basin. Of course, our Blacks Fork hub that's in southwest Wyoming that gathers and processes a lot of our Pinedale gas. We're also in the Vermillion area and our Uinta hub, as well as where our Haynesville production is in northwest Louisiana. That's the strategic initiative that we follow within QEP on our Midstream business is we have pretty well stayed in the basins where our E&P assets are for a couple of reasons. First of all, our primary objective is to ensure the best marketability and optionality for our E&P production, as well as being in those areas gives us a baseboard to capture third-party gathering and processing within the area.
As Chuck had mentioned earlier, we -- about 50% of our business is third-party business, and about 50% is our own equity production. What this is trying to show you is that -- put together this slide to demonstrate that there are lots of different areas of capturing value as the gas comes out of the ground. There's the gathering portion of the gas. There's low pressure gathering, where we usually take the gas from the wellhead down to the compression facilities. And a lot of your large gas fields will have compression on it to allow the gas field itself to operate under low pressure, so it doesn't have to fight high pressures of the main interstate pipelines or the pressure that's needed at the processing plants. And so they'll have compression there to lower it in the gas field, but raise the pressure up to get it to the processing plant.
Of course the processing plant is where we separate the NGLs out of the gas stream, as well as other components, such as CO2 and H2S. There's really kind of 2 different main areas when you think about Midstream business. There's the area that's upstream of the processing or treating plant and then the areas that's downstream of the processing or treating plant, but the plant is usually the dividing area of those 2 different processes.
Moving on then, looking at the downstream market from the processing plant when the gas goes through the processing plant, the residue gas, which is commonly referred to as the methane, will then be transported in the interstate pipelines where the gas could go to all parts of the country. Anywhere throughout the country, there's the interstate pipe grid. The NGLs or natural gas liquids, some processing plants will have fractionation. We actually have a small fractionator at Blacks Fork. It's about a 5,000 barrel a day fractionator, where we're able to capture the local pricing on those NGLs. We have rail facilities and truck facilities there at Blacks Fork as well as the ability to pipe those NGLs down to a fractionator. The 2 main hubs for fractionation are either at Conway or at Mont Belvieu down in the South Texas area. You can see the picture there of the fractionator, a lot of towers where the liquids are separated. I'll kind of go in to that here in a little bit. Eventually, all these products end up down at the end-user market, where they're used for lots of different -- have lots of different uses.
There's a little bit and kind of gives you a summary of our assets that you can go through. The main thing I kind of point out there is that in every step of this natural gas chain or value chain, we do have in place long-term contracts that enable us to capture this value not only in gathering or processing or dealing with the products downstream at Mont Belvieu or Conway, we're able to do that and we have the ability to capture that value for a lot of years to come.
So you might ask yourself, well why do we need processing? There's a couple of reasons. Number one right now, you want to process because of the value of the NGLs. But gas, when it comes out of the wellhead, the temperature of the gas, we commonly refer as the hydrocarbon dew point of the gas stream is too high for being able to be transported in the interstate pipeline system. If the gas comes out of the ground in the Rocky Mountain areas, it's usually about 80 degrees to 90 degrees hydrocarbon dew point and it needs to be about 15 degrees to enter into the interstate pipeline system.
And so that's why we have to process the gas just to remove enough of the liquids to allow that gas to enter the pipeline system. There's about, there's 3 different types of processing methods that we have within our portfolio of processing. There's a very simple process that's referred to as the Joule-Thomson or a J-T process. It's a simple process where you achieve auto refrigeration across a control valve that as the gas flows across the valve, the pressure drops on the gas and that cools the gas and as the gas cools, the NGLs fall out of the gas stream. It's usually it's your more heavier NGLs that are falling out of the stream. That's the lowest cost and lowest NGL recovery method.
Another method is called the refrigeration method and that's an actual external process. It's like -- think of a giant refrigerator on the gas as it goes through the processing plant. It just cools the gas as it goes through. It doesn't reduce pressure or have anything to do with the pressure of the gas as it goes through the processing plant. It just cools it and as it cools it again, those NGLs fall out of the gas stream. That's about your mid-level or mid-range cost of processing and gives you about your mid-level NGL recovery.
The highest level of processing is called cryogenic processing. Again, it's a combination of pressure and cooling through a turbo expander that reduces both of your gas temperature as it goes through the facility. And that process is your highest recovery and highest cost. So you can see there the J-T process reduces your temperature down to about 5 degrees, your refrigeration process to a minus 30 and your cryogenic process really cools down to a minus 120 degrees Fahrenheit.
The picture there is of our Stagecoach/Iron Horse complex. On the left-hand side there, it kind of gives you a feel of what a refrigeration plant looks like. Out there, that's our Stagecoach refrigeration plant and on the right-hand side is a picture of a cryogenic processing plant, our 150 million a day Iron Horse plant that came on earlier this year.
So we have the NGLs that come out of the gas stream. You have to be able to fractionate those products so that you can use them in all the different uses that they have there, and that's kind of what that is slide is trying to portray here. Most of your cryogenic processing plants will have just kind of a Step 1 in that process. They will have a demethanizer. The gas would come in and it will go through the demeth tower and it will separate out the methane from the rest of your NGL products. And the rest of your products; ethane, propane, the butanes and natural gasoline, we often refer to that as your Y-grade product, for most processing, that's done across the country. That product will then be piped again either down to Conway where it will be fractionated or down to Mont Belvieu where that product will be fractionated. Once it gets there, then you have different towers that separate those liquids.
And basically, the way that it works is within each of these towers, we have the ability to control the temperature and the pressure of the product so that it allows each of these products to fall out in a vapor stream as it's going through the tower. And then once the vapor stream comes out of the tower, we cool it down into the individual products. You can see there what each of these individual products, the primary use of each of these products is.
So how does it work? Looking at the 3 different processes, if you assumed about 150 million a day gas stream coming through each of these different processes, and what I've done here is kind of taken the makeup, the gas makeup of our Pinedale gas, to kind of give you a perspective on that. If you think about the natural gas as it comes out of the ground about in the Rockies, in particular, which is where we do it, it's about 80% to 90% methane. The rest of it is NGLs. And so and in the Rockies, the primary component of the NGLs is ethane. So each of these gas streams will have what they call gallons per million or per million Btu of product in them. And each, again, of these gas processing plants has the ability to recover certain amounts of those products.
For example, looking at ethane, the cryogenic process will recover about 82% of the ethane within that gas stream. Refrigeration process is about 6% and your J-T down to 1%. So you can kind of start to get a perspective of the recoverability of each of these processes and the value right now with liquid prices the way they are at the cryogenic processing plants, looking there almost 3x or 4x more gallons recovered. If you think about one point to make here is in the Midstream business, you think about in gallons, not necessarily barrels. We deal in gallons. This is just kind of the way we did it. The product is priced and dealt with. And then down there at the bottom there, you can see the makeup of our different processing plants within each of these options.
So pricing. Looking back historically, the liquid prices, NGL prices and their comparison to NYMEX oil, you can see going clear back to 2000, the various curves of the different products and the relationship that they've had with oil over that time period. In the table there, on the middle column there kind of shows you what that average comparison. Again, for example, ethane, has been 44% of the price of oil on average over the last 10 or 11 years. And the Mont Belvieu, this is Mont Belvieu pricing, I should point that out, this is not Conway, which is where most of all of our liquids end up, propane and the different components. And then on the right-hand side of that table there, it shows you what the 2011 comparison has been for pricing relative to oil.
It's kind of interesting to point out that gasoline is actually, the value at Mont Belvieu is actually higher than NYMEX oil. It has been for most of 2011. You can see on that curve there, following that orange graph versus the green on oil. What's interesting even in September there, which was the last month this was done, your iso-butane was actually been priced a little bit higher than oil. So that's the NGLs. So think about how that has kind of curved up over the last 2 or 3 years, trended up and then compare that with gas prices over that same time period. This graph here shows you the relative value of your NYMEX gas pricing versus the Rockies gas point, which we use as a northwest pipeline price at Opal. But your gas pricing over that last same 2- or 3-year time period has been relatively flat during that time period. Also, kind of interesting thing to point out that the pricing in the Rockies, the basis differential has flattened out. I think even recently here over the last month, again just as of September, your basis has actually switched so the basis in the Rockies is actually higher than to your Henry Hub/NYMEX pricing point. So again, flat gas pricing, rising NGL prices, what does that equate to? Obviously, higher margins, rising margins within the value of these products. This one that I'm showing here is ethane. If you think about the margin, if you think about the value of the product by itself, fractionating it out, and that the value it receives in the marketplace versus the value that it would receive if you left that product within the gas stream, that's the margin we're thinking about. And then in this case, we've actually taken it back to the processing plant so we reduced that value by the transportation cost to get it to market, as well as the cost to fractionate that product once it gets there.
Couple of interesting points on this graph. You go back for the first 5 or 6 years of that, the value is relatively low compared to where it is today. Back in those days, we used to be glad to get $0.03 or $0.04 ethane margins and it felt really good about it and today, we're look at in 2011 a $0.30 margin on ethane alone, which is the lowest priced natural gas liquid.
Just kind of marching through now each of these different products, propane being next. You see that same rising curve here over the last 2 or 3 years. One thing to note here if you look back -- if you looked at 2011, it's the highest margin we've ever seen in the last 10 or 11 years of this NGL product, $0.96 per gallon margin. It's incredible. Same with -- you see the same curves on normal butane. Again the highest margin by far that we're seeing begin to see that bringing on our Blacks Fork plan and complex was very well timed. Same with the iso-butane and then gasoline.
So what does all this mean? Going back to our example of 150 million a day of gas coming into a processing plant, each of these -- again each of these different options and plugging in each of those current 2011 margins, for example, ethane of $0.31 all the way down to the different products, you can begin to see what the value of processing and fractionating those liquids and capturing the value is to either the processor or the producer, for that matter, whichever way you have contracted for that business. Again, $175,000 a day equates on cryogenic processing on this example equates to an upgrade of $64 million a year upgrade on the NGLs.
So who gets that value? Again, it's all based upon the contracts that you have in place. Within our business, we used mainly 2 different types of contracts, either a fee-based contract, also represents about 75% of our business. Again, that's where the producer will pay us a fee for the processing service. The producer will then bear the shrink in fuel. They'll get 100% of their residue gas, but they'll receive 100% of the value of their NGLs back to the plant. The other process that we have is a keep-whole margin business. Again, that represents about 25% of our business, and that's where -- as the gas goes through the plant, it'll shrink. And as a processor, we have to replace the Btu value of that gas, give that back to the producer, but we'll keep 100% of the value of the liquids. So we'll get that margin upgrade as a processor and little of the fee from the producer. The producer keeps all of their gas, goes on 100% of their gas to market.
So how we've done over the last 5 or 6 years within our Midstream business? This slide kind of points out a couple of things. Our revenue growth over time, you've got 3 main components that we have; gathering, we have gathering fees for what we do out there, the processing fees and then the keep-whole margin portion. And the one thing that we've been able to strive to do as you can see there, we've had about a 23% compound average growth rate over this time period on our net revenues. But what we've tried to do and have been successful in, is to try and stay within the 70% to 80% range on fee-based revenues so that we sort of lower the flexibility or the -- I've lost my train of thought, lower the risk. Thank you. Lower the risk of the commodity pricing -- was the word I was trying to think of -- over time. You can see, there are our revenue stream for this year. We're looking at about between $380 million and $390 million, relative back to 2006 about $139 million. So the high niche [ph] to those revenue streams is the volume growth on our gas gathering business. We've had about a 12% compound growth rate of our volumes, and again about 50% of this is third-party business and 50% of it is our equity business. We've had about a 15% growth rate on our processing fee volume business and a 12% growth on our NGL volume business with the lion's share of that growth coming this year.
As you can see there, that has to do with our Iron Horse processing plant coming online earlier this year and the Blacks Fork plant as well. You can see there a picture of our treating facility in Northwest Louisiana.
So putting those together, our EBITDA growth over this time period has been about 29% compound growth rate. We've about tripled the value or size of our business over this time period. One thing that's interesting to point out by this slide is in the Midstream business, you won't have EBITDA and capital expenditures always be the same every year like what we tried to do within our business. So there's fluctuations in there because it takes -- you have to spend a lot of money upfront to build a processing plant, but you don't start getting the benefit of that until after it's built and put into service. So you can see it's kind of a lumpy growth over that time period, but interesting to point out over that time period, we have spent right within our cash flow, total EBITDA has been the just shy of $1 billion, as well as our total capital during that time period. Down below you can see some of the larger facilities that we have constructed and put in place during that time period. Again, most recently, the 3 major facilities that we've recently just completed was our Iron Horse plant, our Blacks Fork II cryo plant and then we've put in a large, 1,000 GPM CO2 treater, we call our Hall Summit facility in Northwest Louisiana.
So what's next for us in our Uinta hub over the next couple of years? We're actually going to be constructing 2 new processing trains. We're going to construct an additional cryogenic train at our existing Stagecoach/Iron Horse complex as you can see there on the map. About 150 million a day, which is identical size to Iron Horse. And that plan is really underpinned by third-party agreements, long-term contracts that we have in place for about half of it will be for fee-based processing and the other half we'll be utilizing for the keep-whole margin on that facility. And that's projected to come online here in the first quarter of 2013. We're just getting underway on that.
The next facility that we'll be looking to build would be 100% for our equity gas up there in the Red Wash. You can see the yellow represents our acreage out there in the air and our Red Wash complex is right there in the middle of that acreage. So we're looking to build a processing plant, again, initially at 150 million a day plant that's adjacent to our refrigeration plant there. We've got it coming online first quarter in 2014, but our hope is obviously to get that done sooner, like we did at Blacks Fork this year. And a lot of that has to do with permitting and when we can get the permitting done, as well as the construction process.
In our Blacks Fork hub, one of the projects that we'll be doing this next year is we're going to expand our local fractionation there at our Blacks Fork plant. And the way you look at that is you have to look at the value that you would receive for those products by fractionating and transporting them locally through our rail system, our trucking facilities there and the value we give versus piping those NGLs down to Mont Belvieu and paying the transportation and fractionation down there. And we think we have the ability to catch and value there on 10,000-barrel a day fractionator. It's almost like you consider it if you're paying your fees, those transportation and fractionation fees, and you're able to capture those fees yourself by doing that locally, it's like a fee-based type of business.
Eventually, we will be expanding Blacks Fork again as the Pinedale volumes grow. And as long as the fractionation and the margins are high, we'll be definitely expanding that again. You can see on the map there, the Vermillion area. We will be doing things out there as well. I might mention behind each of these planned expansions will be compression, gathering and things like that we'll be adding as well. The picture there also shows where the Pinedale facility is in relation to our Blacks Fork complex. Pinedale Field is actually about 100 miles to the north where Blacks Fork is. So we gather the gas, we compress it up there in what we call our Gobblers Knob compressor facilities and compress it and push that gas all the way down to our processing plant.
Specifically for 2012, you can see that about 2/3 of our capital budget will be on processing type facilities. And the table there, you can specifically see the breakout of those costs. Iron Horse II being about $40 million. I might mention that it takes about 1 1/2 year to 2 years to build a processing plant from the initial conception to where you bring it on. So those costs will go over a couple of years time period, so don't think that this is the total cost for these facilities. That would be varying -- well, actually there are those over a couple of years time period.
So finally, in review, QEP Field Services were a complementary business to our energy company. We're the first mover presence in many of our areas. 2011 revenue is fee-based, pretty much guaranteed under long-term contracts that will be with us for many years to come. About 50% of our business is third-party and one of the things, critical reasons why we have a Midstream business incorporated in with our E&P business is it allows us to control the timing and the scope of our gathering and processing infrastructures as our E&P business grows. It also allows us to add value downstream. And we've been able to pretty well do things -- well, we have been able to grow organically over the last 5 years and think we have enough existing projects in place to continue to grow organically and be able to at least double our size within the next 5 years.
With that I'll take some questions.
Perry H. Richards
Yes. The question was, fee-based contracts, how long are the time period relative in comparison to the keep-whole contracts. Most of our contracts are either life of lease or 10- to 15-year time period on a lot of our fee-based. And the way that we structure a lot of our fee-based contracts is we'll go in and require some sort of volumetric commitment from the producer. And so over time, the producer is telling us they're going to produce XYZ amount of volumes each year and we'll go in and as part of the contract we'll only be required to produce that volume or pay as if they did produced that. On keep-whole side, it's the same sort of deal. We have long-term contracts for life of lease. And, hopefully I'm answering your question here on the keep-whole, long term, that we capture that margin over that time period. Any other questions? Yes?
Perry H. Richards
On the Vermillion process -- I'm sorry, he wanted to know the total capital on the different processing plants or what the costs are. In Vermillion, we actually, what you see there on our capital expenditures for 2012, oh yes, good idea. There you go. The $15 million next year is actually it's kind of right now, we have about $40 million a day cryogenic processing plant in the Vermillion area. We're actually moving about $80 million a day through that facility. So we're looking to put some short-term processing in place to handle that until we get better idea on the QEP side, energy side as to the depth of the growth of the processing that we'll need longer term out there. So that's what that represents. And that -- it will be a refrige-type plant, not a cryo, just enough to get us more cheaper option out there. A plant like your Iron Horse plant, generally speaking, the cryogenic plant is going to run you between $70 million to $80 million on that 150 million a day plant.
Can you translate the cost to pay for 100% [indiscernible]?
Perry H. Richards
Yes, that's about -- now is about -- the fractionator is about $40 million, $45 million in total.
I think you mentioned the Red Wash [indiscernible]?
Perry H. Richards
Actually, our plan, that plant will be almost filled from day one with equity gas. So -- oh, the Red Wash. Sorry.
Perry H. Richards
From the gas that our QEP affiliate will be drilling in the Uinta Basin.
The third-party [indiscernible].
Perry H. Richards
Actually, interesting enough, our third-party business historically has been a little bit higher than that but as our E&P business has come up, it's about 50-50 now. I would anticipate that it would stay pretty close to that over the near term and probably a little bit longer term if you would tend to see the same trend of our E&P equity business be a little bit higher. Any other questions? Thanks. With that, I'll turn it back to Chuck.
Charles B. Stanley
I always like to look back and see how we've done. Many of you probably don't remember, but when we went out on the road in June of 2010, in our roadshow book, we actually included what for us some pretty, out over our skis predictions of 3 years of forecasted production growth, remainder of 2010 plus the 2011, 2012, production growth and EBITDA growth. And so I thought we'd take a quick look and see how we've done. You can see, we beat our production target in 2010 and delivered 222 Bcfe of production. The midpoint of this year's forecast is 272 and that's against the 252 forecast that we put out in June of last year, and the midpoint for next year is 307.5 against our original forecast of 285 Bcf. So I think we've done pretty well at forecasting. Some might say we've done a lot better than we forecast.
The growth in production particularly in the Haynesville has helped drive the volumes, obviously, but we've also done quite well on EBITDA forecast. And this is particularly important when you look at the prices that we used back in 2010, in June of 2010, when we put this EBITDA forecast together. You can see this year, we're forecasting sort of in the middle of the range about $1.33 billion of EBITDA last year. In June we were forecasting about $1.22 billion and for 2012, but our midpoint is about $1.5 billion compared to $1.45 billion. So the businesses are performing better than we expected both in terms of production growth and in terms of EBITDA growth. And as I mentioned, we believe we can continue to propel growth in production and EBITDA going forward. And I was telling some of you at lunch that when we look at our 5-year plan, we always go back and we've looked at it since 2002 when I showed up and we look out 5 years and then in 2007, we looked at how we had done in that 5-year forecast and we've tended to do better than forecast. The interesting thing is there are a lot of things that we don't anticipate like changes in focus and changes in capital allocation as a result of changes in well results, changes in costs. And what we've seen is we've been able to deliver the growth both in production and EBITDA, that we were forecasting just in the 5-year time horizon comes from different parts of our portfolio than we forecasted back 5 years ago.
So I think once again, it speaks to the resilience and depth of our portfolio that we've been able to continue to deliver this growth, and we think we still have an opportunity to do so in the future. So I told you, I'd tell you what we're going to tell you and then come back and remind you what we've told you and this slide does it. So we're hope you've garnered an impression today on the quality of our asset base. We think we can continue to grow and thrive in today's commodity price environment. We think we can generate competitive returns on invested capital, take advantage of the high-quality portfolio to drive the business while basically living in and around EBITDA. And we think that we're unique in the E&P space or our ability to do that. We've got what we hope we've demonstrated today a great inventory of low risk, repeatable development drilling opportunities in our core assets, track record of driving down cost and a great inventory of midstream projects that complement and basically -- or follow along to the investment opportunities we have in our upstream business that we hope will drive our growth over the next 5 years.
So with that, I'll throw the floor open for some follow-on questions that you didn't want to ask any of my guys and I'll see if I can answer.
Charles B. Stanley
William B. D. Butler - Stephens Inc., Research Division
What keeps you awake at night [indiscernible] and mitigate it?
Charles B. Stanley
What keeps me awake at night and of those risks, what do we do to mitigate them? The things that keep me awake at night are things that the government action or inaction. I think you've heard today, in some areas that we operate, we've been waiting for over a year for drilling permits. It's very frustrating. Our ability to control that is de minimis. The only way that we're able to respond to that is by having an active portfolio that we can allocate capital to other places when we're frustrated or disappointed in the case of delivery of permits. Along that same line of reasoning, we had a little discussion, in fact at this table, about changes in tax laws that could impact our business but would also broadly impact the E&P business in particular the possibility of elimination of deductibility of intangible drilling costs in the first year after a well is drilled. We can think about it and we can plan for it, but there's little we can do to control it other than point out to folks that it would be a job-destroying and activity-destroying decision. But once again, there's little we can do to mitigate it. The risk that -- or day-to-day in our business, drilling, completion risk, operational risk. I think, we have a great team of people. I hope you've seen the depth and breadth of the folks that we have managing our assets. I don't lay awake at night worrying about their ability to execute and manage the risk on a day-to-day basis, It's the broader macro issues that cause me concern and frankly there's little we can do to mitigate them other than to try to identify each and every one of them. We talk to our board frequently about the macro business risk that are facing our industry and our company in particular and plan for those risks. But there's little we can do to control it other than just good planning. Other questions? We've worn everyone out. Andy?
Andrew Coleman - Raymond James & Associates, Inc., Research Division
You've been shying [indiscernible]?
Charles B. Stanley
Andy asked if -- says that we have not been shy about shutting in gas and what else now? Andy, we have managed production growth in the Haynesville in part because of reservoir management. As Linden described to you, we are absolutely convinced that maintaining a strong or maintaining a small choke and maintaining a high flowing bottom hole pressure is important for the long-term performance of Haynesville wells, but it also has the knock-on benefit of managing gas volumes in the current environment. We're going to produce wells at economic rates, but we will manage production volumes in response to prices. Do we have a specific price for a specific deal? Yes, but we're not going to tell you what that is.
Chuck, you haven't addressed the [indiscernible] Midstream and [indiscernible] and everybody [indiscernible].
Charles B. Stanley
Okay. David asked the question about the thought process around the Midstream business and the cost to capital around this business and the appropriate structure. And I think we've had that call, a question on the earnings call and I'll sort of repeat what I said. This management team is focused on long-term value generation for our shareholders. We're cognizant of the value gap between current MLP valuations or other valuations for Midstream assets versus the current valuation sitting inside QEP resources. There are some challenges or headwinds around unlocking that value. In part, we have to have a user proceeds for any cash that's unlocked from a transaction that would either MLP a portion or all of our Midstream assets or an outright sale, and there are also challenges around tax basis and the fact that we have very low tax basis in our Midstream business. So there's challenges around tax leakage in any type of transaction. That being said, we're continuing to think about study, analyze all alternatives. Clearly, in the current environment, the MLP structure does generate a much lower cost of capital than a traditional sequel because of the tax efficiency. Just like the list of things that make me lay awake at night, the question about the sustainability of the current tax preference for MLP structure is an open question and one that I don't think that you can make any decision about restructuring a Midstream business without thinking about whether or not about the time you got it done, the super committee or some successor to that organization, U.S. Congress, being the most likely to successor, if the super committee fails to do anything, might overhaul the tax code and that may result in a change in tax treatment for this type of vehicle. So it's not a decision we take lightly. We're focused on the sustainability of whatever we do and whether or not it ultimately places a higher value for our shareholders. Other questions? Did I answer yours, David? All right. Well -- do you have any?
Yes. [indiscernible] portfolio ready to take within our [indiscernible].
Charles B. Stanley
Well, we're never happy. We always think we can do better and we challenge ourselves to look for opportunities to grow our business and to grow it profitably. There are a number of things that you saw today. I think one of them that is particularly interesting, there are a couple, the opportunity to drill through an old oilfield at Red Wash where we know there's 700 or 800 million of barrels of oil in place originally and less than 15% of it's been produced today presents a very interesting and I think unique opportunity. The old saying, you look for oil in the middle of more oilfields, it continues to be borne out. And the opportunity to see these reservoirs again with new wellbores and figure out where the oil that was originally in the reservoirs at the time of discovery has been pushed and migrated through the millions of barrels of water have been injected in the field since the 1950s. It's a huge opportunity. We can't quantify it today, but we know that oil is in the ground. That could be a needle mover for us going forward. If you think about opportunities to get oilier, that's a sort of thing you'd look for in an acquisition, find an old oilfield that has an atypically low recovery factor and go in and try to redevelop it. Well, we have one in our portfolio and we're going to have an opportunity to not only drill wells to develop the gas rich Mesaverde -- liquids rich gas in the Mesaverde section, but also to see that oil horizon again or the oil horizons again. That's a tremendous opportunity where you get the leverage from an active development play and you get more data to help drive opportunities. The other area that I'm quite excited about is the Powder River Basin. It's still early days but multiple stack oil pays [ph] That should help drive production growth is, at this point, hard to forecast because we really don't have enough well control to pound the table on the growth trajectory. But there's an opportunity to respond to positive well results and drive future growth in oil in that part of the portfolio. Looking outside, we're constantly on the lookout. Austin Murr and his team are constantly looking at opportunities to acquire additional assets that are complementary to our existing asset base, and we would obviously focus preferentially on liquids rich gas and oil properties over, obviously dry gas properties in this environment. The challenge is always the bid asked and the seller's expectation versus what we think is a reasonable price to pay. This commensurate with the risk that we would take in any kind of transaction like that, and that's been a challenge. So most of the margin -- currently, most of the margin has been priced out of current transaction values in the oil space and it makes it very difficult to make money in acquisitions at this point, especially on oil properties. Yes?
[indiscernible] are you looking ahead [indiscernible]?
Charles B. Stanley
Two questions. One, are we looking for basically leasehold-type development or proven properties with upside? The challenge with buying a lot of undeveloped leaseholds frankly is that we struggle to make the numbers work, very much like my previous comment, the acreage values alone are pricing in the flawless execution with the drill bit post acquisition, which has made it quite challenging in plays like the Bakken and in other liquids rich plays or oily plays in particular. There's very little room for error either in forecasting well cost, oil price or in pace of development in order to get there. That being said, we continue to look. We've made offers as recently as -- well, we have one working on this week on some of properties. And so we continue to look for opportunities primarily in areas where we already have a presence, where we already think we understand the operational challenges and opportunities to drive down costs in these core areas. So a combination of producing properties where we can go and drill horizontally and enhance recovery. And then in other places, it's underdeveloped leasehold that we can bolt on to our existing properties. And as for leverage, I could let the CFO answer the question. I'll tell you my view on it. I think we're wired similarly. You saw in Richard's slides earlier, our current debt to EBITDA actually around $1.1 million, and if you think about that in terms of just the leverage ratio that we would feel comfortable getting to on a temporary basis in order to fund an acquisition with an eye toward paying it back down, I start to toss and turn at night at probably 1.8x debt to EBITDA and I probably stay awake most of the night at 2 or higher. So that gives you a feel for the way, and would that be different than Mr. Doleshek?
Richard J. Doleshek
[indiscernible] comments. When we did our credit facility in August, the agency [indiscernible] notes and both said that we'd have to more than double our leverage with no intended increase in EBITDA before we have -- they consider downgrades. We have plenty of room under their guidelines in terms of increasing leverage, but in terms of our comfort zone in our volume inside of where they are.
Charles B. Stanley
Was there another question in the back?
Charles B. Stanley
So looking at human capital, where would we like to add capabilities and then where could we leverage our capabilities on assets. Is that the question? On the first, I think it's across the board. If you look around the industry in general, what you see is an aging industry with the sort of a barbell-shaped age distribution. And we tried to show you that today. We have a bunch of 50-something year olds to early 60-something year olds and a bunch of under 30-something year olds, and it's going to be a challenge for this industry across the board. Our company's demographic looks no different than that of the rest of the industry in that there is this sort of lost generation when we as an industry didn't hire people. And as a result, as the folks in my demographic age and start to retire, we have a huge challenge in front of us in bringing up the under 30-somethings up a learning curve very rapidly to be able to take over our business. And the one way that we can do that is by very aggressively going out and hiring new college hires and bringing them up to learning curves quickly as we can through leadership programs and through real-life experiences like today standing up in front of a bunch of investors and getting used to the idea that, hey, before you know it, you're going to be running this company. And that's a big challenge for the industry in aggregate because it is going to be key. And as we drill more and more horizontal wells and we move more and more toward resource plays as opposed to the conventional oilfields that have been the sustaining assets of most companies for the past, well, since the beginning of the history of the industry, the level of manpower and intensity, and I think these guys will tell you, is going up dramatically. So how do we also bolster ourselves? More use of technology. The folks we're hiring out of school today runs circle around us and we thought, we were pretty smart with using technology, but the application of technology, the application of artificial intelligence and using that to help steer wells and to help us become more efficient, I think, is one of the areas where we'll see dramatic strides in the next 5 to 10 years. And then on the question of how we leverage our expertise, when I think about our core strengths, I think one of our core strengths is we are great drillers and completers of wells, and we have a track record of driving down costs. And we look around for opportunities where we think we can do a better job drilling and completing wells than the current owners of assets, and we're trying to find ways to leverage that into either a joint venture or outright ownership of those assets. And it's easy to say but in reality, it's quite hard to apply that paradigm to the actual real world because everybody thinks they're the best, right? I don't think you'll have anybody who'll stand up here and say, well, we're just mediocre drillers and completers. Everybody thinks they're the best and so it's hard to convince folks otherwise. We've been successful in doing that. This year, we drilled a number of Haynesville wells for another operator where our well costs were clearly lower and our efficiencies were clearly higher. And that operator let us drill wells in which we had a very small working interest because they saved money and we saved money in the process and helped us maintain our level of activities necessary to keep our costs down. So that's the leverage and I see opportunities in and around our current assets to do that, and we're working on strategies to try to make it happen.
All right. Seeing no further questions, thank you all for your interest in QEP and thanks for taking time to be here with us today.