Veren Inc (VRN) 2013 Q3 法說會逐字稿

Good morning, ladies and gentlemen, my name is John, and I will be your conference operator today. At this time, I would like to welcome everyone to Crescent Point Energy's third quarter 2013 conference call.

(Operator Instructions).

Thank you. This conference call is being recorded today, and will also be webcast on Crescent Point's website, but may not be recorded or rebroadcast without the express consent of Crescent Point Energy. All amounts discussed today are Canadian dollars, unless otherwise stated. The complete financial statement and Management's Discussion and Analysis for period ending September 30, 2013 were announced this morning, and are available on Crescent Point's at www.crescentpointenergy.com and on the SEDAR website.

During the call management may make projections or other forward-looking statements regarding future events or future financial performance. Actual performance, events or results may differ materially. Additional information or factors that could affect Crescent Point's operations or financial results are included in the Crescent Point's most recent annual information form, which may be accessed through Crescent Point's website, the SEDAR website or by contacting Crescent Point Energy. Management also calls your attention to the forward-looking information and the non-GAAP measures sections of the press release issued earlier today. I would now like to turn the call over to Mr. Scott Saxberg, President and CEO. Please go ahead, Mr. Saxberg.

Thank you, operator. I would like to welcome everyone to our third-quarter conference call for 2013. With me is Greg Tisdale, Chief Financial Officer, Neil Smith, Chief Operating Officer, and Trent Stangl, Vice President of Marketing and Investor Relations. I will cover some of the highlights for the quarter, and Neil will discuss operational highlights, and then Greg will speak to the financial highlights.

But before I get into the results, I would like to take this opportunity to thank David Balutis, our Vice President of Exploration, for his hard work and dedication to Crescent Point over the last 12 years. Since day one, Dave has been instrumental in the Company's success. And some of you may not know that I have worked with Dave here for 20 years. It has been a great experience. I am excited for him on his well-deserved retirement, and he will be missed. But the good news is he will continue to work with Crescent Point in an advisory role.

And on behalf of our staff, Board of Directors and Executive team, I would like to wish Dave all the best in his retirement. At the same time, I would like to congratulate Derek Christie, our current Vice President of Geoscience for his appointment to Vice President of Exploration and Geosciences. Derek has been working closely with Dave for the past years to ensure a smooth takeover of Dave's duties. Derek will now be responsible for all geological, geophysical and exploration efforts.

Now turning to our third quarter results, we are happy to report that Crescent Point executed a record quarter for both production and cash flow. We set a new production record of more than 117,900 BOEs per day, 91% oil-weighted, in large part due to the lower -- lowering of corporate declines, great results from our cemented liner completion technique, and the continued success of our waterfloods. Production outperformance meant that we actually exceeded our 2013 exit guidance of 119,000 barrels a day early in September, after spending CAD250 million less than our planned CAD1.5 billion capital expenditures budget. And I think that is a key highlight to the outperformance of this year.

We are also pleased to report that we generated record cash flow of more than CD550 million in third quarter, a 44% increase over third quarter of 2012. This equates to an annualized cash flow of CAD5.68 per share. A strong [netbacks] and higher than planned production really drove the growth cash flow for this quarter. During the quarter, we drove -- organically grew production by more than 18,000 barrels a day or 18% over third quarter of 2012, showing continued per share growth. We capitalized on high commodity, and at high oil prices, and increased our hedge position. And we continue to see outstanding results from cement liner completion technology, which we have used for more than three years now.

Overall, and across our plays we are seeing costs come down, while production performance keeps improving. And third quarter, we transitioned our whole drilling program in Shaunavon resource play to 24 staged cemented liner completions, and continued to optimize completions in Viewfield Bakken And I would really like to make the point, to not underestimate the results we have had with this technology in the last three years, and the potential technological improvements that we will see in the future. With these record results in both Q3 and year-to-date, and factoring in the current commodity pricing environment, we increased our capital expenditures program by CAD200 million to CAD1.7 billion for 2013. We expect this to increase our average daily production for the year to 119,000 BOEs per day, and our exit production rate to 124,000 BOEs per day.

This is the third time we have increased exit guidance this year, for a total of 10,000 barrels per day, at capital efficiencies in our increased drilling capital of 27,000 per flowing. And I think these numbers speak to the strength of our assets, and the ability to leverage technology improvements across our entire Corporation. We have raised our cash flow guidance from 2013 to more than CAD2 billion, an increase of approximately CAD300 million since the beginning of the year. Forecast cash flow growth in 2013 expected to fully fund the CAD200 million capital expenditure budget increase. We expect to spend approximately CAD132 million of the CAD200 million increase on drilling and completions, adding 52 net wells, more than previously planned which adds approximately 5,000 barrels to our exit.

We will drill the majority of these wells in our Bakken areas, Saskatchewan, Manitoba and North Dakota, and we spend remaining increased capital on infrastructure, undeveloped land land and acquisitions -- land acquisitions and seismic. We believe the new budget will allow us to continue the momentum we have generated this year, and will set us up for an active 2014. Before handing things to Neil, I would like to thank all of our employees, field staff, executive team and Board of Directors for everything they do to drive Crescent Point's success. Thanks to you, we are delivering another outstanding quarter to our shareholders. Neil will now discuss our operation highlights. Neil?

Okay. Thanks, Scott. During the quarter, we spent CAD376 million on drilling development, and drill production to a new record of nearly 118,000 BOEs a day. We are very pleased with our waterflood programs and cemented liners, as they have contributed to our strong organic production growth, seen not just this quarter, but all year so far. As Scott mentioned, with our recent completion technique which we have been refining for more than three years, we continue to see positive developments such as reduced costs, reduced water usage, lower initial decline rates and increased recoveries. This will ultimately lead to a better recovery factor in our Bakken and Shaunavon resource plays. Our waterflood programs continue to improve production results as well.

Based on their ongoing success, we have plans to expand our program in the Viewfield Bakken resource play, to apply for our first waterflood in Manitoba Bakken play, and to apply for a second unit which would be adjacent to our first in the Lower Shaunavon. We continue to monitor results from our first shared waterflood in the Beaverhill Lake oil resource play, and expect to begin injecting water in the second Crescent Point pilot - operated pilot during the first half of 2014. We expect all of these programs will continue to grow and drive organic production growth for years to come. We now have waterflood programs or pilots across all of our plays.

For the rest of this year, we plan to continue to develop our high quality asset base, and to refine technologies and concepts across all of our plays. Our new capital expenditure budget of CAD1.7 billion will allow us to add 52 net wells, primarily in the Bakken areas of Saskatchewan, Manitoba and North Dakota. It is worth noting that we are pleased with the results to date in the Uinta basin in Utah also, where we have many initiatives underway to further increase production levels, such as recompleting wells to access bypassed pay, and resizing pumps to reduce fluid levels. We plan to begin collecting data in the first quarter of 2014 using the 3D seismic program in the Randlett area, and to initiate out first waterflood pilot in the basin in 2015.

Before I handing things to Greg, I would really like to thank all of our employees, and especially our field staff, and especially this time of year when we are coming into the tough winter days, for all their hard work to deliver another excellent quarter. We really do have an outstanding world-class team. So Greg will now discuss financial highlights. Greg?

Great. Thank, Neil. I am pleased to report that Crescent Point generated record funds flow from operation of CAD554 million or a CAD1.42 per share in the third quarter. This represents a 44% increase over the CAD384 million generated in third quarter of 2012. Cash flow was driven by higher than expected production, and continued high netbacks of over CAD59 per barrel per quarter. Since our original guidance, we have had tremendous success this year with our strong organic production and cash flow growth. Our average annual production guidance increase from 112,000 to 119,000 BOE per day, and our funds flow from operations increased by 16% from CAD4.48 to CAD5.20 per share in 2013. With our increased capital, we are positioned well for continued growth, and expect a great start to 2014.

I would also like to highlight the consistency and success of our hedging program. As we took advantage of the rally in WTI oil prices in the third quarter, and proactively hedged throughout the forward curve. Since July 1, the Company has hedged an incremental 14,500 barrels a day for 2014, with approximately half being swaps at an average price of CAD98.80 per barrel, and half being purchased put options with an average net floor price of CAD93.80. With these hedges, we are now 59% hedged in 2014, providing a strong base for our 2014 cash flows.

We also have approximately 18,500 barrels a day of WTI oil differentials locked in for remainder of 2013, and 14,000 barrels per day for the first half of 2014. These differential hedges provide a measure of stability to volatile North American oil price differentials, which are we are witnessing today. As discussed last quarter, with our strong financial position we have reduced the amount of equity being issued under our DRIP effective fourth quarter, with the suspension of our premium drip. In our first month without the premium DRIP, we have seen DRIP participation of approximately 29%. We will proactively manage our DRIP participation levels in future quarters to optimize our balance sheet and financial flexibility relative to short- and long-term acquisition opportunities, and our high rate of return drilling inventory.

We remain disciplined in our approach to capital spending, including our upwardly revised guidance, as well as our expected reduction of the DRIP. Our balance sheet remains strong, with projected net debt to cash flow of approximately 1 times. Given the strength of our balance sheet and hedge portfolio, we are very well-positioned to continue to generate further strong operating and cash flow results for the balance of 2013 and into 2014. I will hand things back over to Scott.

Thanks, Greg, We have had a tremendous year of organic growth so far, and an excellent third quarter, with record production and cash flow, continuous improvement in technology and its proven performance, expansion of our waterflood programs and the strengthening of our hedging program. We are in a great position to meet our new targets for the year, and are looking forward to strong start to 2014. At this point, we are ready to answer questions from members of the investment community. Operator?

(Operator Instructions).

First question is from [Pavon Mascotti] from Goldman Sachs.

Good morning.

Good morning.

I have a question maybe on your dividend program. You have a little more than CAD1 billion of dividends, and when you look at your operating free cash, that is at about CAD300 million to CAD400 million. And at this point, you are effectively financing the rest, with a combination of debt and equity. And you look ahead into maybe 2016, 2017 time frame, how do you see this mix evolving? And then, in your internal models, do you see more of dividends being financed with operating free cash along with them?

Thanks, Pavon. When you look at that calculation it's a back view calculation on our cash flow. We are obviously spending capital this year to grow production into the future quarters. I think this year is pretty good highlight that we grew cash flow by over CAD300 million, from the start of the year to the end of this year. And so, if you looked at that calculation, you would have that kind of that viewpoint.

What we view it as, is we are spending capital where we have high return projects, that we are were getting our money back in 6 months, 12 months. And we are spending the appropriate amount of capital in each of our operating areas for the life of those areas, of how they -- each of those areas has their own kind of life to them, and appropriate amount of capital to grow, and to prove up more plays, to extend the play, to add land, to consolidate acquisitions. And so, you have to look at our capital spend, our growth in our cash flow, growth in our production, and our strategy all as one. Versus just looking at a moment in time, backward-looking cash flow statement up against our capital spend.

So we have a long-term strategy, obviously, we have shown people our five-year plan. It is pretty consistent. It has a debt to cash flow of 1 times over almost any price environment, and maintaining of that dividend with potentially growing that dividend over time, depending on when the commodity price environment goes. And our per share growth, depends on where that commodity price goes. So I think, really, our focus is on our capital expenditures, as high return projects that provide that future growth going forward.

Thank you for that. And then, moving on to the Uinta basin in Utah. More recently, there has have been more industry optimism. On the eastern portion of the play, and that is where you have most of your operated acreage. If you can, maybe give us a little more detail in terms of the economics in your operated acreage? And also because you have got a non-operated acreage in other parts of the field. If you can compare and contrast the geology and economics in the Eastern portion of the play versus Western portion of the play?

Yes, that is another great question, Pavon. In Utah, in the Randlett area, we have 72 net sections of land. A good chunk of that is undeveloped. And it sits on the eastern side of the basin, really right up against the Ultra transaction that just occurred. And there they had done step-out drilling, and drilled about 32 wells at the time, added -- it went from 0 to 4,000 barrels per day production on 12 sections of land. So to put it in comparative, our geological land acreage in Randlett, the 72 sections, butts up against the township next door to where that 12 sections were acquired. And so, obviously12 sections is a small component of a 72 section block we have there. Same geology, same potential upside, and obviously that is what really excited us about the Uinta basin and that acquisition a year ago. And so you can kind of from that transaction, see the value creation from a small component of an acquisition that just happened.

In general, we got 270 net sections in that play. It is all within the basin, all within the main pool, the Uinta Basin and pool, and largely undeveloped. And we see a tremendous amount of upside across that play, over 3,000 locations available to us. Rates of return there, range anywhere from six months to two years. On the low case, its 100,000 barrels per well, about a two-year payout, 80% rates of return. So very strong economics on the low case. And then the high case, it is multiples, 100% rates of return, cost six-month payouts, over 200,000 barrels per well.

And what is interesting to that, is that those are based on the older technique, older technology, older completion technique, where they did 6 stage, sort of bullhead kind of fracking through each of those zones. And we know that, that doesn't work as efficiently as the method we are now pushing, which is coiled tubing and more isolated fracking. And so, in a typical well now, we are going back in and doing 25 fracks per well, opening up more zone, seeing better productivity and results, therefore better economics and reserves at the same cost. And I think that's a big key, is that is at the same cost.

And so you are seeing a tremendous value lift from a year ago, from the transaction just on that. Never mind the obvious 200 plus undeveloped sections of land that, we are going to generate an increased tremendous amount of value. That field alone has more oil in it, than all of Western Canada's unconventional plays put together, over 30 billion barrels of oil in place. So it is obviously a very big prize. And at year-end, we are very, very excited about the success we have had there, and future potential of that play.

Thank you.

Great, thanks.

Thank you. Our next question is from Patrick Bryden from Scotiabank. Please go ahead.

Good morning, gentlemen. I am just wondering if you could maybe provide a bit of color or elaboration on the evolution of completion techniques, particularly as you move to cemented liners? Any comment on how that is, in effect, moderating declines?

Yes. About three years ago, we moved from Packer system to cemented liners. And basically what it does is allow you more precision as to where you place the frac. And it allows you to go back into wells and do as many fracs as you want. So we started out with 8 stages cemented liner, and then we went to 16 stage cemented liners, then to 20, then to 25. We adjusted the amount of sand, the amount of water used, and did the correlation between productivity and reserves and cost. And we have seen tremendous up-tick in that.

Also what has occurred, which we didn't actually really expect, was that we got higher IPs, lower declines because we are opening up more rock. And opening up more rock, opens up more matrix porosity within the rock, which then allows more oil to flow, and flow at the lower pressure change. And which then allows for the flattening of the production curves. We have seen that across all of the plays that we have implemented this in. And to give you an example, I think the math on the Bakken is something like after 12 months, instead of 50 barrels a day, it is at 100 barrels a day. And so a pretty tremendous outperformance relative to the older 16 stage completion technique.

A lot of that is simply that in the 16 stage Packer system technique, you maybe got 10 to 12 of the fracks worked, the 4 don't work. So what we see is that there is a low percentage of fracs that work in that kind of methodology, and you wind up refracking the same frac in that case. And so you don't that get the good productivity. We have seen that in other place.

And if you by extension, maybe continue to transfer that to your other plays, are there any limitations on the transferability of the use of that technology where, why would it work, and why wouldn't work in some areas?

No. The only area where it created a little bit of limitation was in North Dakota, where the wells are deeper. And so the coil rigs couldn't reach out to the two-mile depth. So we built a coil rig that gave us that capability to go out 2 miles, and tested that in North Dakota. And that rig we are using in our Flat Lake completions.

Okay, got it. Thank you. And then just moving over to the tidal waterflood, can you just walk us through the milestones that you would be looking for, as we cast our eye -- I mean, ahead. Obviously, looks it like you are going to get reserve credit here, and you are seeing continuing moderation in declines. What else should we look for it by way of catalyst?

Yes. I think Pat, where we are it -- it's Neil. We have got technical support in the Bakken in from the government. The Shaunavon area was easier because it was 100% crowned, and then we were a 100% working interest. What we have to do now, we got the technical support in the Bakken pool, is our people have to go out now, start knocking on the doors of the different landowners, and just soliciting their support. And a lot of it is educating with a well on their section is getting turned into injector, and their neighbor on the other side going to be producing more oil, helping them to understand that they share in that upside with unitization. So that is going to happen over the next quarter to two quarters. Some time through the year, next year we should seeing unitization.

And then once that happens, you should see units two, three, and four after that should accelerate. A lot of it is just working with the government, to help them understand what we are trying to accomplish technically. And also [being on a formula for the track factor]. As far as an increase, this is going to be the first year now. We have had two kind of indications that we are going to see a reserve, a true waterflood reserve assignment.

Number one, was a lot of the simulation work that we had done previously, which is a computer modeling of putting data, and indicating that 30%-plus type of recovery factor beyond, or in total beyond the 17% to 19% primary.

The other thing is, I wanted to get some old school type of waterflood classic analysis, using some of the classic material balance techniques. So we brought in an expert from our independent engineers just to confirm a lot of the work that we did. This is a guy that has got [30 to 40] years engineering experience. He has gone through, and his confirmation where we have enough history of waterflood, that yes, we will -- we should be seeing north of 30% recovery factors. So everything that we have done during the last three or four years, is showing that this is a pool that is going to be waterflood-able, and strong economic returns. And it is really exciting. We haven't seen this type of development, probably as engineers in a generation. It is very exciting to us out there.

I think to put it into scale, we say over 30% recovery, we are talking hundreds of millions of barrels of incremental reserve adds, with very minimal capital costs associated with that. And to put into perspective of last year, we added 75 million barrels through technical revisions in the Bakken alone, which is basically our entire corporate reserves when we acquired Mission in 2006.

Okay. Appreciate that. Lastly, for me, just would be curious to hear a little bit more on the Uinta, in terms of efforts to rail and unlock the pricing within that local market? And then, what drilling catalyst we should be paying attention to? And then, I guess lastly, a quick comment on relative valuation between you and the latest transaction there?

Yes, so I mean, I will maybe start out, and handed over to Trent on the rail side. But I think on the rail side, just my quick view is early, early days of building markets there. And so we are shipping 2,000 I think barrels a day of by rail, and building that marketing, and that's going to take a bit of time to build that. And so we are excited about that. Our facility is up and running.

On potential upsides, there is a huge dramatic amount of upside, just from infill drilling vertical wells, and stepping out and continually drilling that. And so, we have been very pleased with the results there. We have gone back into wells that were previously drilled, and we recompleted wells, and seen dramatic positive results there as well. The other next catalyst, which is more of a longer-term catalyst from our perspective, is the horizontal drilling in the Uteland Butte and the Wasatch. And so, we have got the magnitude and the value lift on just vertical drilling, and then it is unlocking zones that really aren't being drained by vertical wells that could add another whole another leg to this play, above and beyond. And that is more of a longer-term aspect.

And then to put it in comparative, value-wise, Ultra paid CAD650 million for 12 sections of land, offsetting our Randlett area. And so, I mean, under our analysis, and I think we may have shown this across to investors as we have toured and walked through the details of our acquisitions, our upside value we see on this play, we acquired at CAD800 million, and we see the upwards of CAD4 billion to CAD20 billion of upside. And so, pretty excited about the value proposition of this play and the lift, and the relative lift the valuation of Crescent Point. We are obviously early days one year in, but seeing a deal like that also, I think gives the investment community a real sense of the valuation, and the upside that can be had in this area.

Yes, Pat, if I can just add too that. It is Trent here. As Scott mentioned, we have been having good success railing some crude out of there. It takes time to build those markets. We think we are going to be continuing that process late into next year, and adding some new markets to the ones we already have. This year has been a little bit of a challenge in terms of the Salt Lake City market. There has been some refinery issues in that local market all year long, that has kind of led to some depressed pricing. And I think we will continue to see the rail helping, and we will probably look at doubling the volumes we have got on rail, as we get through into 2014, and continue to build out those refinery markets.

Yes, that is perfect. Thank you for your time.

Thank you. Our next question is from Travis Wood from TD Securities. Please go ahead. Please go ahead.

Hi, most of my questions have been answered here. But maybe just back on the waterflood and the technical revisions, in terms of what you saw last year because of the applied technology. Are you looking at the same type of scale, in terms of the positive technical revisions because of the technology this year, i.e. in that kind of that 75 million [BOE]?

Yes, Travis, this is Neil here, I mean some of that things here, absolutely. When we talked a year ago, we had really with the 25 stage cement liner, in the game we have been doing this for three years. And we are probably on at least third-generation internally with cement liners. But a year ago, we had about four or five months of data of the 25 stage vintage. At 12, now we have got 17 months.

So we have already -- we are in initial discussions going through year-end reserve report. And we certainly are getting indications back that a lot of the PUDs are going to see maybe at least maybe a type well increase, potentially, in some areas of the core upwards of two type wells. As far as the waterflood goes, it is something that I have been stressing for the one and ones, just for managing expectations is to understand, that when we were booking waterflood reserves under NI 51-101 you are not going to see us going from 19% to 30% in one year. That is not how the independent rules work.

What I don't want, is we see 1% or 2% increase, and there is a concern that Crescent Point is saying 30%, and the independents have only come at 1% or 2%. Over time, we will drill more wells. We will add more injectors We will get more history. One of our -- one of the property that we acquired, when we turned from a junior into the trust, was the [Tagle] unit. And -- excuse me -- you saw from the initial assignment when we acquired it, four or five years later, it took then to double the recovery -- the recognized recovery factor. It is a bit of an iterate process, but the big thing is because we have the government approval, and we are moving down unitization path, that is the signal for the independent engineers that they need under their rules to start saying, yes, you bet.

A lot of the response so far, it has been related to just improved production performance. We know that improved performance has been from waterflood. So what we were going to be trying to do with them at the end of this year, is break out how much is incremental waterflood, and really how much they have already assigned to us that they just called production improvement, when it really was waterflood. So that is something we are going to try to delineate in Q1, once we have got the report done.

And I think, just in simple terms, the unitization of the field allows the engineers to now value it as a unit, versus individual well by real reserves. And so that is a big step on how you determine reserves, and how you look at it. So we are going to get waterflood reserves on the units on large-scale over time, and it will be a 1%, 2%, 3% per year growth in recovery factor on those larger scale units, versus where we are at today with just individual well by well reserves. I think that is the big change there, which is hugely positive, obviously, for technical revisions and F&D going forward.

Okay. Thanks very much. That is all for me.

Thank you. Our next question is from Don Rawson from AltaCorp Capital. Please go ahead.

Hello. Can you comment on the rail initiatives, just given weak Canadian prices, why [diffs] we are right seeing now? About how much you think of the 60,000 barrels a day of capacity would be using right now, and what kind of uplift are you -- do you think you are realizing? Thanks.

Thanks, Don. It's Trent here. Yes, we saw some pretty tight differentials through the summer. And we ended up pulling back on some of our rail volumes, and now with the differentials have widened out, we have increased our rail volumes again through all of our facilities. We will continue to do that over the winter here, if differentials stay wide. Yes, it is a bit of a shoulder season right now for differentials, and we are seeing a significant widening year in the quarter. I think you will see some of that improving in the next little bit.

Not just through our rail initiatives, but other rail initiatives, and with some additional pipeline additions coming on. We been saying it for quite a while, that we are going to be through -- going through some volatile differentials, where they are really quite tight, and at other times they are quite wide. And that rail gives us the ability to reduce the volatility on that. We have got, as Greg mentioned, 18,000 barrels a day of fixed differentials this year, and 14,000 next. And that really does a lot to mitigate the volatility in differentials.

Right. And right now, it should be -- among the most favorable times to be railing, I would imagine. Can you give me a sense of how much of the rail capacity you might be utilizing at this point?

In Q4 here, we are probably using upwards of 75% of our capacity.

Okay. And again on Q4, because it isn't -- Q3 was a great period for [ifs]. What do you think you might realize on a lift on differentials versus where you would otherwise be?

When you look at the different, at the different initiatives between the rail on a spot basis, and rail on a term basis, we would probably be looking at improving it by, anywhere from CAD2 to CAD5 barrel between the different crude streams on average.

Okay. Thanks very much.

Thank you. The next question is Gordon Tait from BMO Capital Markets. Please go ahead.

Good morning. Just on these new completion techniques, these 25 stage cemented liner wells, maybe you have a 45% reduction in water handling cost. So my question is that do you think going to eventually result in lower power and operating costs going forward?

On a go forward power operating costs, on the actual completion that we are seeing. When we are talking water, Gordon, we are talking water usage for the frack--

(Multiple Speakers). water usage of that in the injections?

In the -- (Multiple Speakers).

Is that obviously then going to show up in -- I guess -- some kind of (inaudible) because you have less water to handle flow back and so o n?

Yes. When you complete a well, just to give you a simple example, instead of 2,000 cubes of water, we use 1,000 cubes. And so less tank storage, less power tube to pump that fluid in. When you flow it back, you are disposing of less water, all of that kind of stuff goes into your capital costs. And so that equates to 50,000 to 100,000,00 barrels -- CAD100,000 per well savings on the capital side. And so those are the kind of things we are seeing across the board in our plays. So our guys, our completion guys have focused in on reducing the amount of fluid. So you hear sort of the [Whitings], with their completion technique, they are doubling their fluid, doubling their sand, doubling everything, and so their costs are going up.

We are trying to look at it from the opposite direction, and mitigate costs, and reduce costs, but get better performance. And that is what we have seen. And so we are pretty excited about that side of it. There is further ways to reduce those costs. So that is really, over the last year to two years, what has happened is, all -- any of the inflationary costs that you would have seen in capital programs, we have mitigated just by changing and optimizing our completion techniques.

And are these wells, what percent -- are they still a pretty small percentage of the wells -- these new -- these higher stage -- are they still a fairly small percentage of the overall wells you have producing right now?

No. Like over the last three years, we would have drilled probably two-thirds of our wells that way. And then this last year to two years, almost 100% that way. On a relative terms, we are drilling 400 to 500 wells now. So the majority of our production is going to start swinging to that type of completion. I would say in the Bakken, probably more than half of our wells will be cemented liner.

That's right. The 25 stage, we are probably about 200 -- pushing 250 wells that we have done at the 25 stage by the end of this year. But certainly half of the wells -- well, all of the Wells in the last two years in the Bakken area have been done through cemented liners. It is just we moved up to the 25 stage. And then again, as we mentioned the Shaunavon area, we are going to 24 stage cemented liners. And we are seeing, as Scott was saying, we are using 34% last water on the actual completion right now. We are seeing the overall cost being driven down.

We are just getting more efficient at connecting our fracks with more matrix of the rock. And that's why we are seeing better IP, shallower declines. And then, coming -- chasing on that now, is going to be the Viewfield waterflood over the next three to five years. So I always look, we saying over 30%, well that means 70% of the oil is still there, and you know that is not going to happen in the long run. That is -- with improvement in technology, and better than expected performance those recoveries will go up through time, is my expectation.

And then, with the increased budget for the end of this year, and it sounds like you would under spend in Q3, and you (inaudible) in Q4. About how much of that (inaudible) because you must having to build out quite a bit of infrastructure to handle the new wells coming on?

So about CAD70 million is on land and facilities. And I would say probably half of that is facilities. So the dollars in there are finishing off our gas plant expansion, some battery and tie-ins. But it is very huge lift of facilities in retrospect of our drilling program, because now in the Bakken areas, Shaunavon areas, they are a little bit more mature, with all the pipelines, satellite facilities and batteries are already established. So that percentage is actually fairly low, relative to earlier days.

Okay. And then lastly, maybe this is something you will deal with when you announce your budget, but do you know sort of offhand about how many water injector wells, or how many producing wells you plan to convert to injectors next year?

Again, we're sort of building that. But it is somewhere in the -- over, across the whole company is probably about 80.

For next year?

Yes.

So that must be your corporate decline rate I would assume is falling, and do you know that might be now? (Multiple Speakers).

Sorry, I missed that? Your corporate decline must be falling, so do you have a sense of where that might get to, over the next 12 months?

Yes, it is hard to say, because at the same time we are accelerating our drilling in newer areas. And so, in our modeling we are basically at this stage not including the waterflood effect. And it basically keeps our decline flat, sort of that 32% 33% range. I suspect it probably gets below 30% over this next year and following year, but in our conservative forecast budget and go forward, we kind of -- we don't allocate barrels to that. Where we are at now, is probably 10,000 to 12,000 barrels of waterflooded production in Bakken, Shaunavon conservatively. And I think what -- it basically goes to about20,000 next year.

And that has a significantly lower decline rate on those barrels I would assume?

It's like a 10%, 15% drop in decline rate. It is based on our sort of directional map. And so you can save 1,000 to 2,000 minimum of production per year that we don't have to replace. Which equates to CAD30 million, to now would be CAD50 million a year on capital savings which is obviously cumulative. So then you go into 2015. It will probably push to CAD100 million dollars a year in capital savings. So that is sort of -- starts to get a bigger magnitude.

All right. Thanks.

Thank you. The next question is from Neil Jacobs from [Cameron] Capital.

Thanks a lot for taking my question. Given how well you have executed this year, and your continued walk-up of your guidance. Obviously outlook for cash flow is much improved. You eliminated the premium component of the DRIP. Would you consider completely eliminating the DRIP?

We have considered it. I think generally most companies have a DRIP program for their investors who want to acquire more stock. We had a bit of a tough time getting our heads around, cutting the DRIP participation away, and telling shareholders they can't buy stock in that program. That is really one piece of the rationale. And the second piece is we have CAD20 billion almost of projects ahead of us, that are high returns. And so that capital -- and based on the pace of each of our different areas, we have lots of projects to spend that capital that will drive per share numbers. And so that is why we have maintained that percentage.

Got it. Thanks a lot.

Thank you. We have time for one more question. This question comes from Cristina Lopez from Macquarie. Please go ahead.

Hello, gentlemen. Obviously a lot of questions have been answered so far. I just have a couple quick ones. One with respect to Three Forks (inaudible) play into Saskatchewan. Can you discuss sort of the results that you have seen so far? Are you doing one you doing one mile, two mile horizontals? And whether or not this will become sort of a bigger portion of a program in 2014, understanding you are still in the budgeting process?

Yes. Thanks. A great question. It is also kind of highlights the differences in costs between North Dakota and Canada. So we drilled to mild horizontal wells down in that area. All-in total cost with I think, upwards of 72 fracks I think we have done up in some cases there. CAD4.5 million per well all-in, versus CAD9 million to CAD10 million in North Dakota, literally a mile away across the border. We are very excited about that program and production growth there. We have actually switched back to one-mile horizontals there, because of the royalty holiday and depth related too that. We get a bigger royalty holiday per well on the mile horizontals, and the economics are much better because of it.

So we have a huge advantage because of that in that area. We are very excited about that play, and the development of that play, and we are building a gas plant building out our infrastructure there. And we will expand the capital program. Part of the expansion for this quarter is in Flat Lake. I think we have 10 more wells planned in there. And we don't see that play really stretching beyond our lands.

We have been very fortunate, I think in the development of this play that our block of land we acquired back from [Torkway] on quite a few years ago, that encapsulates that northern edge of the Three Forks Torkway from the US. And the previous years, we spent a lot of -- or drilled a lot of wells in North Dakota in the Three Forks, which occurred just to push across into Canada, and with some great success there. So we are pretty excited about that play. And that will be significant production growth area for us. I think to put in context, we were zero a couple of years ago, and now we are now I think 5,000 barrels per day almost in that area. So that is about 1 billion-barrel oil pool to us at this stage, multi-zone Bakken and Three Forks. So very exciting for us.

And to move back to one-mile long horizontal wells costing you, would that be closer to CAD4 million or is it about CAD1 million savings? What is savings on the well costs, understanding productivity changes and the royalty holidays?

Yes, I think it is like about CAD2.50 million on the one-mile. So it is CAD2.5 million to CAD3 million. So it is quite a dramatic drop from the two-mile. That is where the rates of return are that much better.

And then I've got one final question, understanding this call is going a little long. With respect to decline rate, obviously people are -- have asked questions already on this. But now we would you project the decline rate to be? Are you still modeling 34%? Have you started to witness maybe some reduction in that decline rate sort of leveling out the decline rate, as a result of the waterflood activity you have done thus far?

Yes, so we have -- I think we are budgeting around 32%, 33% again this year. Last year, I think we actually were conservative with about 35%, 34% decline. It is probably closer to 30%, some 30%. But we are cautious, obviously in how we forecast. And so it is kind of in that ranges. As we get farther into next year, with more injector conversions, and then we start to see that affect. Obviously, the end of the year decline will be a little slightly different than the beginning of the year. So generally, that is sort of the direction that we are headed.

Excellent. It has been a long day of conference calls, so I will end my questioning there.

Thank you very much.

Thank you, ladies and gentlemen, for participating in Crescent Point's third quarter 2013 conference call. If you have more questions, you can call Crescent Point's Investor Relations department at 1-877-403-1678. Thank you, and have a good day.