May 12, 2016
Executives
Scott Saxberg - President and CEO Neil Smith - COO Ken Lamont - CFO
Analysts
Brian Kristjansen - Dundee Capital Markets Thomas Matthews - AltaCorp Capital Travis Wood - TD Securities Patrick Bryden - Scotiabank Arthur Grayfer - CIBC Neema Delu - Veritas Investment Research
Operator
Good morning, ladies and gentlemen. My name is Donna and I will be your conference operator today.
At this time, I would like to welcome everyone to Crescent Point Energy's First Quarter 2016 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 any express consent of Crescent Point Energy.
All amounts discussed today are in Canadian dollars unless otherwise stated. A complete financial statement and management's discussion and analysis for the period ending March 31, 2016, were announced this morning and are available on Crescent Point's website at www.crescentpointenergy.com and on the SEDAR and EDGAR websites.
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 may be accessed through Crescent Point's website, the SEDAR website, the EDGAR website, or by contacting Crescent Point Energy. Management also calls your attention to the forward-looking information and non-GAAP measures sections of the press release issued earlier today.
I would like to turn the call over to Mr. Scott Saxberg, President and Chief Executive Officer.
Please go ahead, Mr. Saxberg.
Scott Saxberg
Thank you, operator. I'd like to welcome everybody to our first quarter conference call for 2016.
With me is Ken Lamont, Chief Financial Officer; Neil Smith, Chief Operating Officer; and Trent Stangl, Senior Vice President of Investor Relations and Communications. I'll give an overview of our quarterly results and outlook, Neil will discuss our operational highlights, and Ken will speak to our financial highlights.
We're happy to report that Crescent Point has had an excellent start to 2016 and remains on track to achieve its annual production guidance. During first quarter, we exceeded our production targets and achieved record production of over 178,000 BOEs per day.
As highlighted in our year-end conference call, this outperformance allowed us to shift approximately CAD100 million of capital from first half of 2016 to second half. This capital shift protects our balance sheet and puts us in a strong position for 2017.
In the first quarter, we were successful in expanding each of our core resource plays and have outperformed in all of our core areas. In ViewField, Bakken and Shaunavon resource plays, we advanced our waterflood programs, initiated project optimizations that improved the productivity and tested new completion fluids that expanded each play’s economic boundaries.
In our emerging growth Flat Lake area in south-east Saskatchewan, we added over 60 new drilling locations due to our successful first-quarter step out program. This play continues to be a growing area within our company.
Since 2012, production in Flat Lake has grown from 1500 BOEs per day to over 17,000 BOEs per day and now has over 800 drilling locations across several zones. We are also driving success in our multi-zone Uinta resource play in Utah.
Our most recent horizontal wells are outperforming expectations and generating returns, similar to our top quartile ViewField, Bakken play. We plan to expand on the success and shift more capital to this area in the second half of the year.
We remain disciplined in our capital spending and acquisition plans and are focused on living within cash flow and protecting our balance sheet. Our outlook for 2016, initial plans for 2017 remain unchanged with annual capital expenditures of CAD950 million each year and average annual production of 165,000 BOEs per day.
Our balance sheet remains strong with more than CAD1.3 billion of unutilized credit capacity and net debt to funds flow of approximately 2.3 times. If oil prices average near current strip prices of $45 WTI during 2016, we expect to generate CAD300 million of free cash flow in excess of our capital programs and our current dividend.
This would provide us with additional financial flexibility during the current environment. Our acquisition plans remain focused on smaller sized internally funded opportunities within our core resource plays.
We are also considering rationalizing our portfolio through non-core asset sales in order to further increase our focus. Before handing it off to Neil, I’d like to thank all of our employees and including our field staff and executive team and our board of directors for all their hard work in helping deliver another great start to the year.
Neil?
Neil Smith
Thanks, Scott. First quarter was successful in several areas, including our cost reduction initiatives, waterflood programs and new completion technologies.
During the quarter, we successfully improved our cost structure by reducing capital costs by 4% over fourth quarter 2015. This is in addition to the 30% capital cost savings that were already realized during all of 2015.
Our waterflood development continues to expand throughout each of our core resource plays. So to put our significant waterflood program into perspective, we managed the largest unconventional waterflood in the world.
40% of our oil production is currently under flood. Our waterflood programs are expected to improve our ultimate recovery factors and our decline rate going forward.
In first quarter, we converted approximately 30 producing wells to water injection wells across our entire asset base and remain on track to convert more than 120 wells during 2016. This represents a 70% increase in the number of wells being converted, compared to 2015.
In the ViewField Bakken play, we’re targeting to fully unitize our second waterflood unit by the end of 2016. Full unitization will allow for accelerated waterflood development and help manage pressure in a larger portion of the reservoir.
We are also evaluating additional unitization opportunities, which would potentially increase the available land for future waterflood unitization by approximately another 60%. We are currently budgeting for the conversion of 50 producing wells to water rejection in the ViewField Bakken play this year, with initial plans to potentially double that amount in 2017, as unitization in waterflooding advances.
Our new technology initiatives are also yielding strong results. For example, new completion fluids in the ViewField Bakken play have increased total oil production by over 40% in comparison to average offset wells in certain areas of the play.
In addition to increased production, this new fluid presents the opportunity to potentially expand the economic boundaries of the entire ViewField Bakken resource play. We are currently testing similar completion fluids in several of our other resource plays.
We are continually optimizing our completion process to enhance overall efficiencies. For example, in the lower Shaunavon resource play, we recently increased the number of stages per well from 25 stages to 35 stages, which has increased initial 30 day IP production rates by approximately 13%.
We expect to build upon this success during 2016, as we continue to advance each of our resource plays. Before I hand things over to Ken to discuss our financial highlights, I’d like to thank all of our staff, especially our field staff for their hard work and determination in delivering another successful quarter.
Importantly also is I’d like to thank our vendors for continuing to be tremendous partners through this downturn of the oil commodity price cycle. Ken?
Ken Lamont
Thanks, Neil. In the first quarter, we continue to protect our balance sheet, while generating record production.
Crescent point generated funds flow from operations of CAD378 million or CAD0.74 per share, which included CAD42 million of proceeds from the company's previously disclosed crystallization of a portion of its 2017, 2018 oil hedges. This was supported by strong netbacks of CAD27.49 per BOE, relative to average selling prices of CAD31.29.
The company benefited from its conservative hedging program and its high-quality, high netback asset base. Our balance sheet and financial liquidity remains strong, as we target to align our cash inflows and outflows.
At quarter end, unutilized credit capacity was more than CAD1.3 billion, with net debt to funds flow of approximately 2.3 times, maintaining our financial flexibility. In addition to the CAD42 million crystallized into Q1, 2016, we also brought forward 2018 crude oil hedges into the first half of 2017 in order to add more near-term protection.
We currently have 40% of our 2016 oil production hedged at approximately CAD77 per barrel and 25% of our first half of 2017 oil production at approximately CAD70 per barrel. In March 2016, we revised our monthly dividend to CAD0.03 per share.
This revised dividend protects our balance sheet and also provides us the ability to generate significant free cash flow. At $45 WTI, we would expect excess free cash flow of approximately CAD300 million in 2016 over and above our capital expenditures and our dividend.
This free cash flow will continue to increase, as commodity prices rebound. With the strength of our balance sheet and results we've had to date, we are well positioned to continue to maximize shareholder return through our total strategy of long-term growth plus dividend income.
I will now hand things back to Scott.
Scott Saxberg
Thanks, Ken. We've had an excellent start to the year, gives us a tremendous amount of flexibility to manage our go forward capital program.
I think one of the key points is our outperformance in first quarter allows us to shift and as we mentioned before, shift the CAD100 million of capital into the later part of 2016, which again then positions us very well for 2017, and our targets -- our two-year outlook remains focused on living within cash flow, protecting our balance sheet, maintaining that average production of 165,000 BOEs per day based on a capital expenditure of CAD950 million annually. And again, as Ken mentioned, at $45 WTI, we have excess cash flow of CAD300 million, which really helps out in this environment, protects our balance sheet further, gives us more flexibility.
On our asset base and business bases, we’ve outperformed -- and really based on the high-quality assets we have in the large oil plays, our low recovery to date, we have over 23 billion barrels of oil in place, where we’ve only recovered 3% to date. So we’re very early on in all of these resource plays and if we get a 5% change in recovery factor over the next 5 to 10 years, it adds 1 billion barrels of reserves to our base, which basically doubles the reserves of the company and sets us up in a very long growth path for the next five to 10 years.
And then I think really key that we've announced in this quarter is the success we've had in Flat Lake and that emerging play and how expansive that is, pushing close to 3 billion barrels of oil in play, which now is competing with our Shaunavon and ViewField assets and then Uinta and the exciting results we've seen there on the horizontal basis and I think a key point there is the shift of our capital from some other areas into the Uinta and expanding that horizontal well program and getting after it sooner in this year versus delaying that. So we remain focused on executing our business strategy and long-term growth and returns for shareholders and I think we are very well positioned to do that.
I'd love to hand it back to the operator for additional questions.
Operator
Thank you. [Operator Instructions] And the first question is from Brian Kristjansen from Dundee Capital Markets.
Please go ahead.
Brian Kristjansen
Good morning, guys. Thanks, Scott.
With respect to -- can you outline what your remaining plans are for the Ratcliffe this year, and when do you see foresee transitioning that from an emerging play to maybe a core one, assuming all goes well?
Scott Saxberg
Yeah. We’ve drilled -- I think, we’ve posted nine wells there now.
And we’re actually just in the shift to move a few more wells into that, a little bit more capital into that play. I think we’ve defined the edges and the scale of it and so it's going to become more of a core play.
I think on a reserve basis, just on a high-level oil in play, so it's over 100 million barrels of oil in plays and recoveries, because it’s conventional play and shallower, we don't have to frac the wells. It’s -- some of our highest returned wells in our entire company and so we're shifting a bit more capital there and when you add in waterflood and primary recovery in this type of field, based on historical and this is older pools like Ongar and Neptune and stuff that are to the north-west of this play have on primary or upwards of 25% recovery and secondary 30% to 40% recovery.
And so just this play alone is a year's reserves for the entire company. So I’m pretty excited about this play and the development of it.
So it’s quickly moved into more of a development phase than exploration.
Brian Kristjansen
Okay, great. And a similar question with respect to Uinta, what are your plans for the second half there and when do you see that coming out of the emerging category maybe something in 2017?
Scott Saxberg
There it’s quite early, but we’ve had some really good success in couple key zones there and we are following up. We’ve got basically a horizontal well in each of the zones and so we are following with second wells in those zones.
And then based on the success of those wells we will continue one rig program basically through to the end of the year expanding that program and as we see the success of that program and then I think you would see in 2017 an optimization on the completion technique and cost as we get more results and expand the play. So it’s a little bit more of an early stage there and sort of wait and see on the next set of results, but out first set have been pretty tremendous and very encouraging and it’s a scalable play that I think will provide really strong growth for us into the future.
Brian Kristjansen
And on that one rig program what are your current cycle times in drilling these new zones?
Scott Saxberg
We were around 14 days to drill a well and so I think it’s probably a two months kind of turnaround at this stage. Again I think our first well earlier in the last year was like 21 days and we got it down to 14 and I expect that would improve as we have a bigger program and that one rig kind of gets more optimized, but early days on that.
Brian Kristjansen
Okay, thanks. Just have one last question maybe for Neil.
You mentioned in your MD&A that some of the op cost savings in the quarter were due to reduction in maintenance and workovers, where do you see that? Can you quantify what that is and with prices rising I would assume you get back in the field to do those maintenance and workover activities again?
Neil Smith
I mean basically a combination of that is being a lot more streamlined. One of the things we’ve done is just on the callouts, what was happening was things were extremely busy.
You get callout stations say in the northeast part of the field and showing to a southwest workover and the southwest callout going up to the northeast. So first thing is we are lot more efficient about the travel time.
We are working closely with the operations to reduce the actual times to be just faster what we are doing and then of course large part of that is just negotiating more efficient cost here, so definitely we will be overall sub-CAD12 operating cost for our operations this year. And the one thing that we are really introducing a lot more into the field operations is technology, so we haven’t quite introduced drones into the fields yet, but we are using a lot more technology in our trucking, in our sourcing, in our surveillance, so that’s big steps for us.
Brian Kristjansen
That’s great, thank you guys.
Scott Saxberg
Thanks, Brian.
Operator
Thank you. The next question is from Thomas Matthews from AltaCorp Capital.
Please go ahead.
Thomas Matthews
Hey, guys, just a couple of quick questions. First is on the CAD100 million of capital deferred to the second half, will that mostly be allocated towards longer term projects, because obviously you haven’t revised your guidance, so going into the ground you would expect some production bumps here and there.
Scott Saxberg
Yeah, just the way - so we took out CAD100 million out of Q2 and shifted it to Q4, so you drill a well in Q4, by the time you get it on stream, it really comes on stream in January and so it doesn’t affect your overall yearly average, so because we - I think in December, January I would have told you Q1 would have been 170, 172 and we are 178 and so we really outperformed in Q1 and so that allowed us to then shift capital out of Q2 which we would have drilled in Q2, all those wells would come on towards the end of Q2 that would have bumped our average in Q3 and Q3. And so we would have out-beat the 165 average considerably and so instead we moved that CAD100 million to the back end of the year.
So it’s equivalent to cutting the capital by CAD100 and then that capital and the volumes associated really show up in ’17, but we obviously drill the wells at the end of this year and the capital goes into this year and the production roles into ’17. And that allows us to hit that 165 number and 950 CapEx for 2017 more easily.
Thomas Matthews
No changes to ’17 I guess is where it’s going.
Ken Lamont
Yeah, Thomas, keep in mind that we are just reiterating that capital shift that was announced two months ago, so there is no change to the guidance and there is no change to the capital from two months.
Scott Saxberg
Yeah, because we knew in March that we were 6,000 barrels a day ahead of our numbers and so that was the guidance from March saying, hey, we are well ahead of our numbers, this shift in capital allows us more flexibility and keeps our average the same, so the de facto CAD100 million cut in CapEx was the same production essentially.
Thomas Matthews
Okay. And then just more on the Uinta, there is a bureau of land management of Utah application or information session, just wondering if you could talk a little bit more on that just obviously very long dated, but just wondering if that will be partnered or all Crescent Point and then given that there is 3,900 wells or so scheduled in that application and you only have 1,150 in that wells identified, I would assume these are all new wells or just wondering if you could just shed some more light on that?
Scott Saxberg
Yeah, so in those applications, you have to give your full historical disclosure of what you are going to drill on all of those lands over time and so you kind of lay out that would be like a 10 or 20 year drilling program and it’s really identifying every drilling location you have on the books to show environmentally the impact and what you are going to do. It doesn’t necessarily speak to the exact this year, next drilling program.
We obviously identify a tremendous amount of vertical basis, thousands of drilling locations out there, you are basically drilling between two old fields from the 1960s. And if you recall this land base that we acquired was a tribal land that had been basically held by the government for 50 years until they gave it back to the tribe and allowed them to then access it to then develop.
And so it’s cutting the center out of the Cardium field in Alberta and still dating it for 50 years and then now companies are coming back into drill that land up and so that’s essentially the project that we have here. Further to that we are trying to develop at horizontally those seven different zones that are prospective horizontally that we could drill whatever number wells per section horizontally if that works out.
So that’s sort of all encompassed in that big report, basically to outline on environmental standpoint the overall impact of the entire basin. New fields put similar applications in for a larger development as well and it’s just sort of the process that they want you to upfront kind of put your application in on every possible drilling location that you could think of to understand the environmental impact.
Thomas Matthews
Okay, great.
Scott Saxberg
I hope that helps define it.
Thomas Matthews
I mean, obviously it does. It’s just for information more than evaluating today’s market, but anyways.
And then my last question is just on that Pembina C plant, obviously with liquids pricing kind of quite low just wondering if that’s - is that a long term contract that you have to go through that plant or is there a price where you just say, okay, we are just not going to extract these liquids anymore?
Scott Saxberg
And we’ve actually have moved some liquids back into the gas, so we have that flexibility. We don’t have to take all liquids out and lose that, so we - and we’ve I think - correct me if I am wrong, Neil, but I thought we did move some - we have moved some back, to get the gas price.
Neil Smith
Yeah, I mean, that’s what’s happening in with the downward pressure on the liquids price and there are instances where we are getting money out of the heat value of the gas than we are taking it out of the liquids, so we’ve got that flexibility. There are certain commitments that we have to do for them to realize their return that they are - to get longer term better pricing there is certain volumes that we are committed to in the near term, but over those volumes we do have some flexibility.
Scott Saxberg
Yeah, we are producing more than what’s in that contract now.
Thomas Matthews
Perfect. Okay, that’s it from me.
Thanks guys.
Scott Saxberg
Okay, thanks.
Operator
Thank you. The next question is from Travis Wood from TD Securities.
Please go ahead.
Travis Wood
Good morning, all. At Viewfield and just talking about the water flood, you have the approval on the first, expect to have approval on the second, what’s the process for the remaining two and can you give any kind of timeline in terms of when you think that would be fully onboard from the approval process?
Scott Saxberg
Yeah, before maybe Neil answers I would just - I think one of the key highlights in our press release there is that we are actually adding even more units to the field and once the first one was done, when was it, last year or whatever, it just gets accelerated because, A, we now have the approval system and like if you recall that’s the first unit that’s been put together in like 20 years and it was the guys who did the unitizations for the government retired literally the year before we went to get this unit. So they had to hire a new guy into learn even how to unitize and so now we’ve gone through all of that and now it’s just going to accelerate and as we title owners see all the other guys sign up to units and the benefits of all that, all of these units just fall into price and will accelerate and happen a lot quicker.
And so I would expect, Neil, maybe you can answer the timing on.
Neil Smith
Sure. I mean part of the process here and like Scott said, I mean there has been some small units done here and there over the last couple of decades, but certainly nothing of this size in a long time.
And the first thing that we have to do is come up with definitive oil in place and then we bring that technical data to the government and they review it and they approve not only the unitization but the track factors. So the second unit or the NS unit, it’s another 60 odd sections that we are going to be putting under fled here.
We expect in the next month or two that the government, we are going to get approval from them and then the next step is we go out to the different individual freehold mineral owners and get their approval on that so we are - it’s probably a bit of we are sandbagging. I am hoping by the end of the year but truthfully hopefully before the end of the year that will be unitized and then the next couple of units over 2017 is what we are pushing.
We are well into working on the next two units just confirming our mapping of the oil in place and track factors. So we are well into that.
And as Scott said, once we have the cookie cutter developed with the first unit, the Stoughton unit, it’s moved a lot quicker. Unitization is nothing new in Saskatchewan.
The freeholders, they understand that under primary horizontal wells decline rapidly and that this is an opportunity to flatten out that production to keep their checks up, so we were 100% compliant of the freeholders. It was unanimous both on their part to participate in the Stoughton unit.
We will have over 1 billion barrels of oil flooded in place over the next couple of years here. And then as Scott mentioned we have another five units that now start going outside of these units where we have a high working interest and that can add another 0.5 billion barrels to be flooded.
So we are - I mean the Viewfield play we are getting a lot of wins on the primary still at the completion techniques, the step out expanding it, but this really has developed into a low risk large oil in place, world class, unconventional resources play and it’s been pretty exciting for us that this play - put in perspective Viewfield in 2004, the entire Bakken was 100 barrels a day, today it’s the second largest producing pool in Western Canada, second largest ever discovered oil in place and it is strong free cash flow for the company now, so big part of our future.
Scott Saxberg
Yeah. And one of the - I think it’s important to understand that on - historically across the world, if you look at every single water flood and on average in rule of thumb, you get two time primary recovery, so we have the primary recovery out here as 15% to 20%, we’re going to get twice that 30% to 40% on water floods and that’s our historical average of all water floods in the world.
And so we are seeing that kind of response and view with the initial flooding that we've done in these units and in areas of the field and we'd expect to outperform that even beyond that based on the characteristics of this field and the fact that it’s a shallow reservoir, the shallowest unconventional field I think in you know one of the shallowest unconventional fields in North America and that gives us huge benefit on perm and prosody and water flood ability relative to anything else in North America combined with the low royalties in Saskatchewan, so there definitely is a continuing big play for us in early stage still.
Travis Wood
And the 775 injectors that you have in the releases, is that associated with just the four units?
Scott Saxberg
That's with the four units for now so, by the end of this year, at the end of next year we will have 150 to 200 injectors some of those injectors have between 5 and 10 years track record so our confidence level in the recoveries is quite high because we such a strong database to follow from.
Travis Wood
And that one-to-one ratio kind of based on that 5 to 10 years?
Scott Saxberg
Ultimately, that's something we are continuing to optimize here, we’ve certainly seen two injectors in the section responding quite well supporting the other six wells there but that’s something we’ll continue to optimize.
Travis Wood
And in the Shaunavon, you talked about the 35 stages, have you - how many wells have you drilled at this 35 stages and do you see any interference on that?
Scott Saxberg
We are getting up there, we were doing that all this at the end of Q4 and into Q1 and we've been experimenting with that.
Travis Wood
Any interference with 35 stages at all?
Scott Saxberg
We are not seeing that, what we are doing is smaller tonnage of the stages so we're taking that into account.
Travis Wood
And then last question as you enter, any infrastructure constraints right now kind of in that 15,000, 16,000 barrel a day mark?
Scott Saxberg
No, they are all single well batteries that gases flow lined into our gas compression facility and we have no restrictions on that end. And then if you look into Salt Lake, they are desperate for crude in there because of the pullback in the whole industry in that basic and the drop in production in general in the entire reason.
And so and there are expanding the refineries as we speak there as well to increase the capacity, so you have drop in production with expanding capacity so there is room there to grow.
Travis Wood
Do you have a sense of what the spare takeaway would be out of the region right now?
Scott Saxberg
Like a 30,000 barrels a day probably.
Ken Lamont
Say between 20,000 and 30,000 barrels a day.
Scott Saxberg
At one point they were railing 25,000 on top of that in the past, so you could easily double the volumes out here without any much of a concern on that and the dips have narrowed because of that.
Travis Wood
And that 20 to 30 approximately can you remind me is that all pipes?
Scott Saxberg
It's all truck. It's a three-hour truck ride to the refinery.
Ken Lamont
And we are in a basin there as well there is lot of elevation between where we are producing up the side of a mountain into Salt Lake.
Scott Saxberg
All the barrels there because they are waxy they are all trucked to the refinery and it's really close.
Operator
Thank you. The next question is from [indiscernible] from BMO Capital Markets.
Please go ahead.
Unidentified Analyst
Just I have only one question and hopefully it‘s a quick one. I just want to touch on kind of your non-core asset sales in terms of how you're considering them and just wondering what the trigger points are for accelerating that potential market core asset sales is there something that you can do in second half of the year, is it going to be kind of one for one if you buy let's say CAD50 million worth of assets would you sell CAD50 million worth of assets as well to, so just want to get some color on that?
Thank you.
Scott Saxberg
Our balance sheet is pretty strong, we don't need to sell any assets in that regard. And with the excess cash that we have we are paying down debt right now.
And then that gives us some flexibility from smaller transactions I think I’ve said in the past we are kind of looking at CAD100 million to CAD200 million type range on acquisitions at this stage. We basically are saying we view Alberta as our non-core area and strategically we feel you know we’d like to consolidate in Saskatchewan, consolidated in Utah, we’re looking at as additional basins in the US and opportunities there.
and if were to transact on any kind of larger transactions, we would need to obviously sell some assets and consolidate. So we are right now just in the process of looking at I guess on selling an Alberta asset or Alberta asset to improve our balance sheet and put us in a position to look at other acquisitions in our core oriented US.
And we are in no rush to do any of that but that's just something we've identified and said that we could contemplate. And so that's kind of where we are at, again we are not a big rush to do it but if we were to do any kind of larger transaction, it would be based around a sale prior to us doing something.
Unidentified Analyst
Perfect, thank you.
Scott Saxberg
So we're not going to do a deal then try to sell assets, we’d most likely sell assets and then look for those transactions.
Operator
Thank you. Your next question is from Patrick Bryden from Scotiabank.
Please go ahead.
Patrick Bryden
I'm not sure if you might be able to elaborate on this given the competitor considerations but what would you say are the factors that play that have augmented your economics in horizontal wells in Uinta basin?
Scott Saxberg
It's a new zone that nobody has tested, so we haven't really used, we’ve obviously applied the technology and knowledge we know from the previous areas and other completions we've done but if the zone at the stage that is showing us the outperformance and economics and I think that's the biggest key. And in a couple of zones that nobody else has ever drilled into and so we are expanding that and so that's probably the biggest key.
And then we would and you’ve see it in every single play where as guys drill more wells tweak a frac completion technique, the fluid, the mechanics they get better and better results. So to have really strong results early on is impressive and gives us a lot of confidence to test more locations and so now we are kind of in that, we’ve got it mapped out.
And what’s unique about Uinta is, we can drill all these vertical wells frac seven zones, put it on production, their economics. So we have really cheap well testing to test the scale of the play and where it's developed so we can drill a lot of vertical wells to define this edges of the pool and then infill drill it horizontally in those red zones and still have economic vertical wells to do it.
So it's a bit of a uniquely in that regard and so part of our capital program this year is step out drilling, we’re doing a whole bunch of core on all of the different zones that we’re testing with the vertical wells and then we’ll frac them and put on stream and pay for that test and then we’ll follow up with horizontal wells later once we've defined the extent of the play. And so we’re now in the phase where we’re following up on our first horizontal wells that in those zones we've identified and then the second phase will be optimizing those completions to even enhance the rates of return even further.
Patrick Bryden
And just a few quick questions on the water flood, when we think about the producer injector ratios that you have touched in your release. Can you give us a sense for the steps that you taken to arrive at that number and then you’ve alluded to the potential for on the technical side to outperform that over the factors be in your mind that we drive you get a better ratio or optimize the ratio?
Scott Saxberg
So in any water floods you have, you take a core sample you pump water through that core to how much oil you can get out of that core through the core labs. And I think in our tests for Viewfield its 70% recovery factor and so then it becomes down to how good are you in physical terms of pumping water in the reservoir and the conformance it’s called of the injection.
And so typical water flood you get 50% so that 70% turn into 35% recovery right away. What we've discovered and you can look at studies and Richard Baker at the University of Calgary has done these kind of studies that the largest fields and the larger fields outperform recovery factors because you have so much soil there you can test all kinds of different things to improve that conformance and get that 50% up to 60% or 70% so that your recovery factors goes in our case from 35% to 40% or 45%.
And some of the unique technologies that we are developing are mechanical so putting in different ways to inject water through a horizontal well into the different fractors to control the fractors one of the key ones that we've discussed I think a year ago or two years ago now is that closable sliding sleeve so we are actually going in and we can close every second sleeve in a horizontal well on the injector side and then inject and move oil around within the field by just opening and closing those doors. That’s one example another one is just putting in packers, a couple of packer assembly in the horizontal wells to ensure water is being dispersed in compartments between each lengths of the horizontal well and then we can adjust that flow of water and either inject more in the toe or the heel or in the middle of the well bore.
And so when you think of it from a technical perspective of how many wells we have per sections, the ability to control where the water goes in, eight wells times 30 fracs so 240 fractors that we can control the water in each one of those fractors are recovery factors that are going to go up considerably and these are really cheap methods of doing it. And so we are very, very excited about that.
Then we also are testing chemicals and UR concepts which are basically the diverters, probably the best example I can use is when you go to wash your car and you hit the deluxe carwash and at the end you have the spotless – spot free rents or whatever and there is chemicals within that water that disperses the water in a way that leaves your car nice and shiny and clean and those are the types of chemicals that we are using to inject into the reservoir to disperse to wells to improve the recoveries over time. And those are tremendous and they are well used historically in the world on conventional water floods, so we know they work.
And, so we're excited about the work that we've done in there but I can go on and on and the list is probably 20 different technologies and things that we are implementing and testing that we’ll for sure move up that recovery factor beyond your standard two times primarily. So when you actually take a step back and you look at look at Viewfield Shaunavon, relative to the rest of North America we are two time outperforming every reservoir because we've got water flood secondary recovery versus all the other guys have primary recovery guys and so that's to us is exciting and obviously drops our cost per barrel and our economics and the rates of return go up that much more so.
So we're pretty excited from that side of it on all aspects of the waterfall.
Patrick Bryden
And then maybe if we can just get a little more collaboration at Shaunavon and then I will step out of the way here a bit. But what are the factors in your mind so far that make it similar do you feel and what makes it different and would you say the progress has been on track with what you’ve experienced at Viewfield are ahead and why?
Scott Saxberg
So Shaunavon which is interesting is outperformed Viewfield in our minds on response and we believe it's mainly two things one is Shaunavon, the technology was more advanced when we went into that play, so if you recall, Viewfield, we started drilling up in 2004, 2005, 2006 and 2007, whereas Shaunavon started in 2007, 2008, 2009 and 2010. And so just that change in years changed the completion technique from that packer system to cemented liner system.
And then on top of that, Shaunavon is three times thicker reservoir, and so we are getting better benefit I think from the waterflood quicker there as well it’s almost all Crown and so we actually don’t have to unitize Shaunavon, the Crown or the government has given us a go ahead to essentially put water injectors wherever we want, whenever we want and so it expands and accelerates the ability for us to waterflood that play quicker. And I think while those three sort of combinations have in general terms outperformed Viewfield from that perspective.
But again, that play is still behind and earlier stages of development, we have drilled as many infield wells there yet, so we still got many years of just getting to primary versus the waterflood there still.
Patrick Bryden
Okay. Appreciate it.
Thanks very much.
Operator
Thank you. The next question is from Arthur Grayfer from CIBC, please go ahead.
Arthur Grayfer
Good morning. Just one quick one for me.
What I think about the Uinta, you talked about moving to more horizontal wells and the great success you have had. Can you maybe frame it for us, when you saw the transition from vertical drilling to horizontal drilling, you had a multiplier effect typically in place either on IP or EUR and there being the multiplier effect on the cost, but the multiplier effect on the rates would likely overshadow the cost skew, maybe frame that for us in that way.
Scott Saxberg
Yes, I mean, it’s super early days. I mean you go to – we have only drilled a well in each zone, so we are trying to take one data point and extrapolate, but it’s essentially more than two times on the IP rates and probably twice the – the capital is only twice, I think on the horizontals.
So I think the economics are pretty stellar from just that early success. But we have to obviously drill more wells to get the data that you kind of want to get to do that math.
Some of these wells have really hung in there at high levels beyond what we would have predicted.
Arthur Grayfer
Okay. Thank you.
Operator
Thank you. The next question is from Neema Delu from Veritas Investment Research.
Please go ahead.
Neema Delu
Good afternoon. Quick question.
Just want to know with respect to the spending for the remainder of the year, it seems to be loaded in Q1, so you’re still on track for the CAD950 million for total CapEx for 2015?
Ken Lamont
Yes, we have only spent – we have got 55% of our capital still to spend and we are essentially only spending about CAD60 million or CAD80 million in Q2. And so basically, it’s pretty balanced between through the year between first half and second half.
So majority of our drilling, a big chunk was in Q1 and then a big chunk is Q3, Q4 and gets you to that CAD950 million. And that’s rarely related because we shifted the CAD100 million out of Q2 and put into Q4 to balance out more at the second half of the year with the first half.
Neema Delu
Is it also because you are seeing the trend in futures pricing and pricing you think will become more favorable towards Q4?
Ken Lamont
No, I think it was just – it was actually the opposite. It was because we had such an outperformance in Q1, so the luxury of – on our yearly average of adding 8,000 barrels or 6,000 barrels a day in the quarter in Q1 beyond our budget, allowed us to then shift capital into Q4, so we don’t get any production value out of the year with that shift.
So we have effectively took out – production out of the average of the year and kept the capital in, but put on the backend, which then gives us flexibility that if oil prices trended back down to the CAD30 level we could cut that capital and it wouldn’t affect our yearly average, and it would protect our balance sheet a little further and protect us into 2017 if prices went south. And then we also have obviously a lot of capacity to add capital into the second half of the year, prices do continue to improve and we can add just more days to the drilling rigs and more wells on the backend.
And we could easily grow and exit at over 170 at the end of this year if prices do improve in September, October. Our inclination is to be very cautious on adding capital this year until we see a real stability in oil prices and can pay some debt down and position ourselves for 2017.
So the more likelihood would be that we would add capital to 2017 than 2016 at this stage.
Neema Delu
Great. One final question, I think it’s really interesting to think with respect to oil companies in terms of a sustaining capital and what sort of budget is necessary for growth?
So given that there is modest growth over last year, would this CAD950 million represent a sustaining capital number for your 165,000 barrels a day? And on the second part of that question, how much more money would you need for let’s 2% or 5% growth?
Ken Lamont
Yes, it’s an interesting question. So we basically said 950 as our flat production profile for 2016, 2017 and that’s – within that 950 we still have a 150 million of long-term capital spent, so we could grind that down a little bit lower to show a sustainable what you would theoretically say, just drill to stay flat.
And then secondly, as we’ve mentioned, we are not drilling our juicy in the heart of our play Viewfield, Shaunavon, Viking stuff in this budget. We are actually shifting capital to an exploration play in Utah that we arguably can get zero production out of those next wells.
We have incorporated that into our production forecast. So we actually, probably expanded on that long-term capital in this latest release and discussion of our shift to capital, so from that perspective.
And then when we run our sensitivities, if we add CAD50 million to CAD100 million, it’s where do you add that capital and our inclination first would be in some longer term projects, like the Utah exploration stuff and some further step out drilling. But we could add CAD100 million of capital and as I said, probably exit at CAD170 million, which gets you that couple of percentage sort of growth.
So it doesn’t take us much to kind of get to higher exit or higher production for 2017 on that capital spend.
Neema Delu
Ken Lamont
Thank you very much.
Operator
Thank you. We have time for one more question, and the question comes from [indiscernible] please go ahead.
Unidentified Analyst
Hi, it’s actually Eric Piper [ph]. Thanks for the time for the question.
I want to follow-up on the 40% uplift you have seen on select wells at Viewfield, is this new technique something you can apply across the field to the remaining allocations or is it only going to work in certain areas? And then secondarily, over what timeframe are you measuring the 40% uplift, is that a 30-day accum or 9-day?
I know it’s probably early, but just any additional color on that would be appreciated.
Ken Lamont
So the 40% is accum to date number on those wells Really what we are trying to – what we are using there is a different fluid that transports the sand into the reservoir that fits with our reservoir characteristics and so in some place like you have read about the slick water and how pumping the slick water creates expansion of the fracking and the extension of the fracs and then that has been determined to show higher IPs, higher reserves in a whole bunch of different plays. This type of fluid is different than that and it’s more dialed into the Viewfield play and what we are trying to do in Viewfield and it’s applicable across the entire field.
And then secondly, we have taken that fluid and we are testing it into some other plays within our portfolio and looking at that and looking at what advantages we can take on relative to our competitors to capitalize. So there is combination of things.
So that’s really I think a key – and this is where the whole industry has gone and what – how we have been successful in that past in that. We went to eight well infill drilling before everybody else to learn that that was an advantage, hence we did acquisitions based on that and we are big winners on that.
We went to cemented liners before everybody else in North America, I think in 2009 for advantages of the waterflood and the results we saw there were tremendous and that gave us huge advantage to consolidate the Shaunavon and then we have moved to sliding sleeves and the water flooding that gives us an advantage than other guys. And so this is just another technology in that, and it’s very applicable across the entire field and again into some of our other plays and so we are testing that to further that.
Unidentified Analyst
Will all the go-forward Viewfield completions incorporate this new approach?
Scott Saxberg
Yes, some variation of that. I mean, we are – I mean, Viewfield has never been quirky cut play at all that we come up with something, I mean, we are continually advancing type of sand, type of fluids, the staging looks pretty good, but take a look, we went from 25 to 35 stages at Shaunavon.
So we are constantly – the advantage that we have is we have such a deep inventory. There is close to 1,400 wells in inventory just on primary level, only huge upside from the waterflood, so we are continuingly optimizing that.
Ken Lamont
And there is probably another 1,000 or 500 on the hedging of the field. If this is successful, as much as we expand the play, we will add even more locations.
So there is a big pen game win proving up that further. And there is further gains that we see even mechanically on the slide and sleeve systems and some of the other mechanical systems we are looking at that are continually being tweaked.
Unidentified Analyst
Is there any added cost to this new technique or is it same well cost?
Scott Saxberg
No, it’s getting offset. There is the plus and minuses, but we are getting the cost down.
We are getting more efficient.
Neil Smith
I think we are 1.3 million per well there from we were 2.1 million to 2.2 million prior in 2014.
Scott Saxberg
I mean, our drilling days are less than half of what they used to be five years ago.
Neil Smith
Yes, we drill the well – we drilled wells there this quarter under five days, which is unheard of in the past, that was from 9 or 10 days. I think just in the last year we dropped it to under 5.
Scott Saxberg
Yes, I mean, our original wells were 14 days.
Unidentified Analyst
Which is the oldest well that you’ve – that you have that you have completed with this new technique?
Scott Saxberg
It’s in the past year.
Unidentified Analyst
So it’s a meaningful cumulative period where the 40% is kind of measured against. I assume you haven’t factored this into your outlook at all, this uplift or you have?
Scott Saxberg
No, they are just – they are factored into budget, not like in our production forecast and they are not budgeted into our forecast, like a production forecast.
Unidentified Analyst
So you are using your flatter type curve, not – no 40% uplift to that curve.
Scott Saxberg
Yes.
Unidentified Analyst
Okay. All right.
Great, That’s all I had. Thank you.
Scott Saxberg
Okay. Well, thank you very much and I appreciate you attending the 2016 Q1 conference call.
I will turn it back to the operator.
Operator
Thank you, ladies and gentlemen for participating in Crescent Point Energy’s 2016 first quarter conference call. If you have more questions, you can call Crescent Point’s Investor Relations department at 1-855-767-6923.
Thank you and have a good day.