Crescent Pt Energy's CEO Discusses Q3 2013 Results - Earnings Call Transcript

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Crescent Pt Energy (CSCTF) Q3 2013 Results Earnings Call November 7, 2013 12:00 PM ET

Executives

Scott Saxberg - President and Chief Executive Officer

C. Neil Smith - Chief Operating Officer

Greg Tisdale - Chief Financial Officer

Analysts

Patrick Byrne - Scotiabank

Travis Wood - TD Securities

Don Rawson - AltaCorp Capital

Gordon Tait - BMO Capital Markets

Neal Jacobs - Cambrian Capital

Cristina Lopez – Macquarie

Operator

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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session for members of the investment community. (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 expressed consent of Crescent Point Energy. All amounts discussed today are in Canadian dollars unless otherwise stated. The complete financial statements and Management’s Discussion and Analysis for the period ending September 30, 2013 were announced this morning and are available on Crescent Point’s website 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 Crescent Point’s most recent Annual Information Form which maybe 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 non-GAAP measures section of the press release issued earlier today.

I'd like to turn the call over to Mr. Scott Saxberg, President and CEO. Please go ahead, Mr. Saxberg.

Scott Saxberg

Thank you, Operator. I'd 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'll 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'd like to take this opportunity to thank Dave 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, but as I've worked with Dave here for 20 years, it's 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'll continue to work with Crescent Point in an advisory role. And on behalf of our staff, Board of Directors and executive team, I'd like to wish Dave all the best in his retirement.

At the same time we'd like to congratulate Derek Christie, our current Vice President of Geosciences 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're 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 lowering of corporate declines, great results from our cemented liner completion technique and the continued success of our waterfloods.

Production out-performance meant that we actually exceeded our 2013 exit guidance of 119,000 barrels a day early in September, after spending $250 million less than planned $1.5 billion capital expenditures budget. I think that's a key highlight to the out-performance of this year.

We're also pleased to report that we generated record cash flow of more than $550 million in third quarter, a 44% increase over third quarter of 2012. This equates to an annualized cash flow of $5.68 per share; strong netbacks and higher than planned production really drove the cash flow for this quarter.

During the quarter, we 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 -- high oil prices and increased our hedge position, and we continue to see outstanding results from our cemented liner completion technology, which we've used for more than three years now.

Overall and across our plays we're seeing cost come down, while production performance keeps improving. In third quarter we transitioned our whole drilling program in Shaunavon resource play to 24-stage cemented liner completions and continue to optimize completions in Viewfield Bakken. And I'd really like to make the point to not underestimate the results we've had with this technology in the last three years, and the potential technological improvements we'll see in the future.

With these record results in both Q3 and year-to-date and factoring in the current commodity price environment, we increased our capital expenditure program by $200 million to $1.7 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've increased our 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've raised our cash flow guidance from 2013 to more than $2 billion, an increase of approximately $300 million since the beginning of the year. Forecast cash flow growth in 2013 is expected to fully fund the $200 million capital expenditure budget increase. We expect to spend approximately $132 million of the $200 million increase on drilling and completions adding 52 net wells, more than previously planned, which adds approximately 5,000 barrels to our exit.

We'll drill a majority of these wells in our Bakken areas; Saskatchewan, Manitoba and North Dakota and will spend the remaining increased capital on infrastructure, undeveloped land and acquisitions -- land acquisitions and seismic. We believe the new budget will allow us to continue the momentum we generated this year and will set us up for an active 2014.

Before handing things to Neil, I'd like to thank all of our employees, field staff, executive team and Board of Directors for everything they do to drive Crescent Point success. Thanks to you, we are delivering another outstanding quarter to our shareholders.

Neil will now discuss our operational highlights. Neil?

C. Neil Smith

Okay. Thanks, Scott. During the quarter we spent $376 million on drilling development and drove 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 a recent completion technique which we've 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 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 a first waterflood in Manitoba Bakken play and to apply for 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 light 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 through years to come.

We now have waterflood programs or pilots across all of our plays. For the rest of this year, we're trying to continue to develop our high quality asset base and to refine technologies in concepts across all of our plays.

Our new capital expenditure budget of $1.7 billion will allow us to add 52 net wells, primarily in the Bakken areas of Saskatchewan, Manitoba and North Dakota. It's worth noting that we are pleased with results to-date in the Uinta Basin in Utah also where we have many initiatives underway to further increase production levels such as re-completing wells to access bypass pay and resizing pumps to reduce fluid levels. We plan to begin collecting data in the first quarter of 2014 using a 3D seismic program in the Randlett area and to initiate our first waterflood pilot in the basin in 2015.

Before handing things to Greg, I'd really like to thank all of our employees and especially are field staff, and especially this time of year when we're 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?

Greg Tisdale

Great. Thanks, Neil. I'm pleased to report that Crescent Point generated record fund flow from operation of $554 million or $1.42 per share in the third quarter. This represents a 44% increase over the $384 million generated in third quarter of 2012.

Cash flow was driven by higher than expected production and continued high netbacks of over $59 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 increased from 112,000 boe to 119,000 boe per day and our funds flow from operations increased by 16% from $4.48 to $5.20 per share in 2013. With our increased capital we are positioned well for continued growth and expect a great start to 2014.

I'd also like to highlight the consistency and success for our hedging program. As we took advantage of the rally in WTI oil prices in the third quarter and proactively hedged throughout the fourth quarter.

Since July 1 the companies has hedged an incremental 14,500 barrels a day for 2014 with approximately half being swaps and average price of $98.80 per barrel and half being purchased put options with an average net price of $93.80. 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 differential locked in for the remainder of 2013; and 14,000 barrels a day for the first half of 2014. These differential hedges provide a measure of stability to volatile North American oil price differentials which we ware witnessing today.

As discussed last quarter with a strong financial position we have reduced the amount of equity being issued under our DRIP affected fourth quarter with a 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 growing inventory.

We remained disciplined in our approach to capital spending, including our upwardly revised guidance as well as our expected reduction of the DRIP. Our balance sheet remained strong with projected net debt to cash flow of approximately one times. Given the strength of our balance sheet and hedge portfolio, we are very well positioned to continue to generate further strong operating and financial results for the balance of 2013 and into 2014.

I'll now hand things back over to Scott.

Scott Saxberg

Thanks, Greg. We've 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 the members of the investment community. Operator?

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) First question is from [Pawan Ansari] from Goldman Sachs. Please go ahead.

Unidentified Analyst

Good morning.

Scott Saxberg

Good morning.

Unidentified Analyst

I'll start with a question maybe on your dividend program. You have a little more than $1 billion of dividends, and when you look at the operating free cash that's about $300 million to $400 million. And, at this point, you are effectively financing the rest with a combination of debt and equity. When you look ahead into maybe 2016, 2017 timeframe, how do you see this mix evolving? And then in your internal model do you see more of the dividends being financed with operating free cash, longer term?

Scott Saxberg

Thanks [Pawan]. When you look at that calculation, it's a back view calculation on our cash flow. We're obviously spending capital this year to grow production into future quarters. And I think this year is a pretty good highlight that we grew cash flow by over $300 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 a viewpoint.

What we view it as is we are spending capital where we have high return projects and we're getting our money back in six months, 12 months, and we are spending the appropriate amount of capital in each of our operating areas for the life of those areas and how 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, and our cash flow growth and 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've shown people our five-year plan. That's pretty consistent. That has a debt to cash flow of one times over almost any price environment and maintaining of that dividend would potentially grow that dividend over time depending on where the commodity price environment goes. And our per share growth depending 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.

Unidentified Analyst

Thanks for that. And then, moving on to the Uinta Basin in Utah, more recently there's been more industry optimism on the eastern portion of the play, and that's where you have most of your operating acreage. If you can then maybe give us a little more detail in terms of well economics in your operated acreage. And also because you've got non-operated acreage in other parts of the field, if you can compare and contrast the geology and well economics in the Eastern portion of the play versus the Western portion of the play.

Greg Tisdale

Yeah. That's another great question, [Pawan]. So, in Utah, in the Randlett area, we have 72 net sections of land. A good chunk of that is undeveloped. And it sits on that eastern side of the basin, really right up against the ultra transaction that just occurred. And there they had done step-out drilling and drove about 32 wells at the time, added -- went from zero to 4,000 barrels a day production on 12 sections of land.

So, to put it in comparative, our geological land acreage in Randlett in 72 sections puts up against the township next door to where that 12 sections were acquired. And so, honestly, 12 sections is small component of 72 section block that we have there, same geology, same potential upside, and obviously that's 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's just happening.

In general, we bought 270 net sections in that play. It's all within the basin, all within the main pool Uinta Basin and pool, and largely undeveloped. And we see tremendous amount of upside across that play over 3,000 locations available to us. Rate to return there range anywhere from six months to two years, on the low case I think 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. Its multiples, 100% rates of return, six-month payouts, over 200,000 barrels per well.

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

And so, you are seeing a tremendous value left from a year ago from the transaction just on that. Never mind the obvious 200 plus undeveloped sections of land and we are going to generate 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 place. So it's obviously a very big prize. At year-end we're very, very excited about the success we've had there and the future potential of that play.

Unidentified Analyst

Thank you.

Scott Saxberg

Great. Thanks.

Operator

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

Patrick Byrne - Scotiabank

Morning, gentlemen. I'm just wondering if you can 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?

Neil Smith

Yeah. So about three years ago we moved from the 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 eight stages cemented liner and then we went to 16-stage cemented liner, 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've seen a 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 lower pressure change and which then allows for the flattening of the production curves; and so we've seen that across all of the plays that we've implemented this in.

And to give you an example, I think the math on the Bakken is something like after 12 month instead of 50 barrels a day, it's at 100 barrels a day; and so, a pretty tremendous out-performance 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 fracs worked, the other four 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 get the good productivity. We've seen that in other plays.

Patrick Byrne - Scotiabank

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 it in some areas?

Neil Smith

No. The only area that 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 that two-mile depth. And so we built coil rig that gave us that capability to go out two miles and tested that in North Dakota and that rig we are using in our Flat Lake completions.

Patrick Byrne - Scotiabank

Good. Got it. Thank you. And then just moving over to the waterflood, can you just maybe walk us through the milestones that you would be looking for as we cast out ahead. I mean, obviously, it looks like you're going to get some reserve credit here and you're seeing continuing moderation in declines. What else should we look for by way of catalyst?

Neil Smith

Yes. I think Pat, we're at -- it's Neil here. We've got the technical support in the Bakken from the government. The Shaunavon area was easier because it was 100% crowned and then we were 100% working interest. What we have to do now that we've got the technical support in the Bakken pool is our people have to go now start knocking on the doors of the different landowners and just soliciting their support.

A lot of it's educating with a well on their sections getting turned into an injector and their neighbor on the other side is going to be producing more oil, helping them to understand that they're sharing that upside under unitization. So that's going to happen over the next quarter to two quarters. So some time through the year, next year we should be 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're trying to accomplish technically, and also doing on a formula for the tax factor.

And as far as an increase, this is going to be the first year now. We've had two kinds of indications that we are going to see in reserve, a true waterflood reserve assignment. Number one was a lot of the simulation work that we've 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 analyses 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's got 30, 40 years engineering experience. He's gone through, and his confirmation where we had enough history of waterfloods that yeah, we'll -- we should be seeing north of 30% recovery factor.

Everything that we've done during the last three, four years is showing that this is a pool that is going to be waterfloodable and strong economic returns. And it's really exciting. We haven't seen this type of development probably as engineers in a generation. It's very exciting, the upside here.

Scott Saxberg

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

Patrick Byrne - Scotiabank

Okay. Appreciate that. Then just 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 I guess, lastly, quick comment on relative valuation between you and the latest transaction there. Thank you.

Scott Saxberg

Yes. So I'll maybe start out and then hand it over to Trent on the rail side. I think on the rail side, my quick view is early, early days of building markets there. And so we're shipping a couple of thousand barrels a day by rail and building that marketing and that's going to take a bit of time to build that. And so we're excited about that. Our whole facility is up and running.

On potential upsides, there's a huge dramatic amount of upside just from infill drilling vertical wells and stepping out and continually drilling that. And so, we've been very pleased with the results there. We've gone back into wells that were previously drilled and re-completed wells and seen some 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 and -- in the Uteland Butte and Wasatch. And so we've got the magnitude of the value lift on just vertical drilling. And then it's unlocking zones that really aren't being drained by the vertical wells that could add a whole another lake to this play above and beyond. That's more of a longer-term prospect.

And then, just to put it into comparative, value-wise, Ultra paid $650 million for 12 sections of land, offsetting our Randlett area. And so, under our analysis, and I think we may have shown this across to investors as we've toured and walked through the details of our acquisitions, our upside value we see on this play, we acquired in the $800 million and we see the upwards of $4 billion to $20 billion of upside; and so, pretty excited about the value proposition of this play and the lift, and the relative lift to the valuation of Crescent Point. Obviously, we're early days one year in, but seem to be like that also gives the investment community a real sense of the valuation and the upside that we had in this area.

Trent Stangl

Yes, Pat, and if I can just add to that, it's Trent here. As Scott mentioned, we've been having good success. We're having some crude oil there. It takes time to build those markets. We think we're going to be continuing that process going into next year and adding some new markets to ones we already have.

This year has been little bit of a challenge in terms of the Salt Lake City market. There's been some refinery issues in that local market all year long that's kind of led to some depressed pricing. And I think we'll continue to see the rail helping. And we'll probably look at doubling the volume that we've got on rail as we get through into 2014 and continue to build out those refinery markets.

Patrick Byrne - Scotiabank

Yes. That's perfect. Thanks very much for your time.

Operator

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

Travis Wood - TD Securities

Hi guys, 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. kind of in that $75 million?

Neil Smith

Yes Travis, its Neil here. I mean some of the things here, absolutely -- I mean, when we talked a year ago, we had really with the 25 stage cemented liner; and again, we've been doing this for three years and probably are on at least the third generation internally of the cemented liner.

But a year ago, we had about four or five months of being up to 25 stage vintage. At 12 now we've got 17 months. We've already -- we are in initial discussions going through our year-end reserve report. And we certainly are getting indications back that a lot of the pods are going to see maybe at least a tight well increase, potentially in some areas of the core upwards of two type wells.

As far as the waterflood goes, and it's something that I've been really stressing for the one and ones, just for managing expectations is to understand that when we're booking waterflood reserves, under NI 51-101 you're not going to see us going from 19% to 30% in one year. That's not how independent rules work. What I don't want is we see 1% or 2% increase and there is a concern at Crescent Point saying 30% and the independents have only come out one or two.

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 to tackle unit. You saw from the initial assignment when we acquired it, four or five years later, it took them to double the recognized recovery factors. So it is a bit of an integral process, but the big thing is because we've got 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 has been related to just improved production performance. We know that improved performance has been from waterflood. So what we're 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've already assigned to us that we just called production improvement when it really was waterflood. So that's something we're going to try to delineate in Q1 once we've got the report done.

Greg Tisdale

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-well reserves. And so, that's a big step on how you determine reserves and you look at it. So we only 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 was just individual well-by-well reserves. I think that's the big change there which is hugely positive, obviously for our technical revisions and F&D going forward.

Travis Wood - TD Securities

Okay. That's -- thanks very much. That's all for me.

Scott Saxberg

Thanks.

Operator

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

Don Rawson - AltaCorp Capital

Hi guys. Can you comment on the rail initiatives just given weak Canadian prices why dips that we're seeing right now? About how much do you think of the 60,000 barrels a day of capacity would be using right now and what kind of uplift do you think you aer realizing? Thanks.

Trent Stangl

Thanks Don. It's Trent here. We saw some pretty tight differentials through the summer, and we ended up pulling back on some of our rail volumes and now as the differentials have widened out, we've increased our rail volumes again through all of our facilities. And we'll continue to do that over the winter here of differential statewide.

It's a bit of a shoulder season right now for differentials and so we've seen a significant widening here in the quarter. I think you'll see some of that improving in the next little bit, not just through our rail initiatives but other rail initiatives, and then with some of the additional pipeline additions that are coming on.

We've been saying it for quite a while that we're going to be through -- going through some volatile differentials where they are really quite tight and other times they are quite wide. That rail gives us that ability to reduce the volatility on that. We've got, as Greg mentioned, we have 18,000 barrels a day of fixed differentials this year and 14,000 next. And that really does a lot to mitigate that volatility differential.

Don Rawson - AltaCorp Capital

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

Trent Stangl

In Q4 here we're probably using upwards of 75% of our capacity.

Don Rawson - AltaCorp Capital

Okay. And again on Q4, because Q3 was a great period for debts, what do you think you might realize on a left on differentials versus where you would otherwise be?

Neil Smith

When you look at the difference at the different initiatives between the rail on a spot basis and rail on a term basis we'd probably be looking at and improving it by anywhere from $2 to $5 a barrel between the different crude streams on average.

Don Rawson - AltaCorp Capital

Okay. Thanks very much.

Operator

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

Gordon Tait - BMO Capital Markets

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

Greg Tisdale

On a go forward power and operating cost, on the actual completion that we're seeing, when we're talking water, Gordon, we're talking water usage for the frac.

Gordon Tait - BMO Capital Markets

Update on the usage on that in the injection.

Greg Tisdale

In the…

Gordon Tait - BMO Capital Markets

Is that obviously then going to show up in I guess some kind of left water to handle flow back and so on?

Greg Tisdale

Yes. So when you complete a well, just to give you a simple example, a set of 2,000 cubes of water we use 1,000 cubes, so less tank storage, less power to pump that fluid in. When you flow it back you're disposing of less water, all of that kind of stuff all goes into your capital cost. And so that sort of equates to 50,000 to 100,000 barrels $100,000 dollars per well savings on the capital side. And so those are the kind of things that we are seeing across-the-board and in our plays.

And so our guides, our completion guides are really focused in on reducing the amount of fluid. You hear sort of the ratings with their completion technique, they're doubling their fluid, doubling their sand, doubling everything and so their costs are going up.

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

Gordon Tait - BMO Capital Markets

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

Scott Saxberg

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. So on a relative term, we are drilling 400 wells to 500 wells now. The majority of our production is going to start swinging to that type of completion. I'd say in the Bakken, probably more than half of our wells -- or about half of our wells will be cemented liner.

Greg Tisdale

And that's right. The 25 stage -- pushing 250 wells that we've done with the 25 stage by the end of this year, but certainly half of the wells -- well, all of the wells in the last three years in the Bakken area have been done using cemented liners. It's just we moved up to the 25 stage. And then again, as we mentioned, the Shaunavon area were going to 24 stage cemented liners.

As we're seeing -- Scott was saying, we're using 30%, 40% less 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 fracs with more matrix of the rock. And that's why we're seeing better IP declines, shallow or deep lines. And then coming, chasing on that now is going to be the field-wide water flood over the next three to five years.

We're saying over 30%, well, that means 70% of the oil is still there, and you know that's not going to happen in the long run. With improvement in technology and better than expected performance those recoveries will go up through time is my expectation.

And with the increased budget for the end of this year, it sounds like you would under expect into Q3 so you've did quite a bit of spend in Q4. How much of that is going – because you must be happy to build out quite a bit of your infrastructure to handle the new wells coming on.

Scott Saxberg

So, about $70 million is on land and facilities, and I'd say probably half of that is facilities. The dollars in there are finishing off our gas plant expansion, some battery and tie-ins. But it's not a huge lift of facilities and retrospect of our drilling program. Because now in the Bakken area, Shaunavon areas, they were a little bit more mature with all the pipelines satellite, facilities and batteries are already established. That percentage is actually fairly low relative to earlier days.

Gordon Tait - BMO Capital Markets

Okay. And then, lastly, maybe this is something you'll deal with when you announced 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?

Scott Saxberg

Again, we're just sort of building that. But it's somewhere in the over across the whole company is probably about 84 I think.

Gordon Tait - BMO Capital Markets

For next year?

Scott Saxberg

Yes.

Gordon Tait - BMO Capital Markets

So that must be your corporate decline rate, presume its falling and do you…

Scott Saxberg

Sorry. I missed that last part.

Gordon Tait - BMO Capital Markets

Your corporate decline rate would be evolving, so do you have a sense of where that might get to over the next 12 months?

Scott Saxberg

Yes. It's hard to say because at the same time we're accelerating our drilling in newer areas. And so, in our modeling we're basically at this stage not including the waterflood effect. It basically keeps our declined flat at sort of at 32%, 33% range. I suspect it probably gets below 30% over this next year and the following year, but in our conservative forecast budget and go forward we don't allocate barrels to that. We are right now is probably 10,000 barrels to 12,000 barrels of water flooded production in Bakken, Shaunavon conservatively, and I think but it basically goes to about 20,000 next year.

Gordon Tait - BMO Capital Markets

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

Scott Saxberg

It's like 10% to 15% drop in decline rate. It is based on sort of directional map. You can save 1,000 to 2,000 minimum production per year, and we don't have to replace, which equates to $30 million to now would be $50 million a year of capital savings which is obviously cumulative. Then you go into kind of 2015. It will probably push to the $100 million a year of capital saving, so that sort of starts to get a bigger, bigger magnitude.

Gordon Tait - BMO Capital Markets

All right. Thanks.

Operator

Thank you. The next question is from Neal Jacobs from Cambrian Capital. Please go ahead.

Neal Jacobs - Cambrian Capital

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

Scott Saxberg

We have considered it. I think generally most companies have a DRIP program for their investors who want to acquire more stock. And so, we had a bit of tough time, getting heads around cutting the DRIP participation away and telling shareholders they can't buy stock, not to buy stock through that program. And so that's really one piece of the rationale.

And then the second piece is, we have $20 billion almost of projects ahead of us that are high returns. That capital is -- 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. That's why we've maintained that percentage.

Neal Jacobs - Cambrian Capital

Got it. Thanks a lot.

Operator

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

Cristina Lopez – Macquarie

Hi, gentlemen. Obviously a lot of questions have been answered so far. I just have a couple of quick questions. One, with respect to your Three Forks [inaudible] play into Saskatchewan, can you discuss sort of the results you've seen so far, you're doing one mile, two mile long horizontals? Whether or not this will become sort of a bigger portion of our program in 2014 understanding you're still in the budgeting process?

Neil Smith

Yes. Thanks. Great question. And it's also kind of highlights the differences in cost between North Dakota and Canada. We drilled two mile horizontal wells down in that area. All in total cost with -- upward of 72 fracs. I think we've done up in some cases there, $4.50 million per well all-in versus $9 million to $10 million in North Dakota, literally a mile away across the border, so very excited about that program and production growth there.

We've actually switched back to one-mile horizontals there because of the royalty holiday and the depth related to that. We get a bigger royalty holiday per well on the mile horizontals and the economics are much better because of it. 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're building a gas plant, building our infrastructure there, and we'll expand the capital program.

Part of this expansion for this quarter is in Flat Lake, I think with 10 more wells planned there. We don't see that play really stretching beyond our lands. We've been very fortunate, I think, in the development of this play that and our block of land that we acquired back from tracks on quite a few years ago that calculates that northern edge of Three Forks, [Parkway] from the U.S. and the previous years we spent a lot of or drilled a lot of wells in North Dakota in the Three Forks which incurred just to push across into Canada with great success there. So, we're pretty excited about that play.

And that will be significant production growth area for us. I think putting context, we were zero a couple of years ago and we're now I think 5,000 barrels a day almost in that area. So that is about 1 billon barrel oil pool to us at this stage, multi-zone Bakken and Three Forks so very exciting for us.

Cristina Lopez – Macquarie

And with that to move back to one-mile long horizontals. Wells costing you would that be closer to $4 million or is it about $1 million savings, what's the savings on the well cost understanding productivity changes and the royalty holidays.

Scott Saxberg

Yes. I think it's like $2.5 million I think on the one mile. So its $2.5 million to $3 million, I think. So I think quite a dramatic drop from the two-mile. So that's where the rates return are that much better.

Cristina Lopez – Macquarie

And then I've got one final question understanding this call is going a little long. With respect to the decline rate obviously people have asked questions already on this, but now where 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 of the decline rate as a result of the waterflood activity you've done thus far?

Scott Saxberg

Yes. So we've -- I think we're budgeting around 32%, 33% again this year. Last year, I think we actually were conservative with about 35%, 34% decline. It's probably closer to 30%, sub-30%. But we're cautious, obviously on how we forecast. And so, it's kind of in that ranges.

And as we get into further 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. Generally that's our -- that's sort of the direction that we're headed.

Cristina Lopez – Macquarie

Excellent. It's been a long day of conference call, so I will end my questioning there.

Scott Saxberg

Thank you very much.

Operator

Thank you, ladies and gentlemen, for participating in Crescent Point's third quarter 2013 conference call. (Operator Instructions) Thank you and have a good day.

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