Veren Inc (VRN) 2016 Q1 法說會逐字稿

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.

(Operator Instructions)

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 expressed consent of Crescent Point Energy. All amounts discussed today are in Canadian dollars, unless otherwise stated. The complete financial statements and Manager'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 section 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.

Thank you, operator. I'd like to welcome everybody to our first-quarter conference call for 2016. With me is Ken LaMonte, Chief Financial Officer; Neil Smith, Chief Operating Officer; and Trent Stangl, Senior Vice President of Investor Relations and Communications. I will 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 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 productivity, and tested new completion fluids that expanded each play's economic boundaries.

In our emerging growth Flat Lake area and Southeast 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 1,500 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 the living within cash flow and protecting our balance sheet. Our outlook for 2016 and 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 CAD45 WTI during 2016, we expect to generate CAD300 million of free cash flow in excess of our capital program 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 would like to thank all of our employees, 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?

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 into perspective, we manage 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 are 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 injection in the Viewfield Bakken play this year, with initial plans to potentially double that amount in 2017, as unitization and 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?

Thanks, Neil. In the first quarter we continued 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 remain 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.

Thanks, Ken. We've had an excellent start to the year, it 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 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, that $45 WTI we have excess cash flow of CAD300 million, which really helps out in this environment, protects our balance sheet further, and gives us more flexibility.

On an asset-base and business basis we've outperformed our -- really based on the high quality assets we have and the large oil in place our lower 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 place, which now is competing with our Shaunavon and Viewfield assets. And then Uinta and the exciting results we've see 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 Instructions)

Brian Kristjansen, Dundee Capital Markets.

Good morning. Thanks, Scott. With respect to -- can you outline what your remaining plans are for the Ratcliffe this year? And when you foresee transitioning that from an emerging play to maybe a core one, assuming all goes well?

Yes. We've drilled, I think -- yes, 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 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 place, it's over 100 million barrels of oil in place.

And recovery is with -- because it's a conventional play and shallower, we don't have to frac the wells. It's some of our highest return 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 Unger and Neptune and stuff that are to the northwest 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 pretty excited about this play and the development of it. So it's quickly moved into more of a development phase than exploration.

Okay, already. Great. And similar questions 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?

There it's quite early, but we've had some really good success in a 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 up with second wells in those zones.

And then based on the success of those wells, we'll continue a one-rig program basically through to the end of the year, expanding that program as we see the success of that program. And then I think you'd see in 2017 an optimization on the completion technique and cost there 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 our first set have been pretty tremendous and they're very encouraging. And it's a scalable play that I think will provide really strong growth for us into the future.

Cool. And on that one-rig program, what are your current cycle times in drilling these new zones?

We were all around 14 days to drill a well, and so I think it's probably a two-month turnaround.

Okay.

At this stage. Again, I think our first well earlier in last year was like 21 days, and we got it down to 14, and I expect that that would improve as we have a bigger program and that one rig gets more optimized. But early days on that.

Okay. Thanks. Just had 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 a reduction in maintenance and workovers. Where do you see that? Can you quantify what that is, and with prices rising I would assume you would get back in the field to do those maintenance and workover activities again?

Yes. 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 when things were extremely busy you'd get a callout station say in the northeast part of the field answering to a southwest workover and a southwest callout going up to the northeast.

So first thing is we're a lot more efficient about the travel time, we're working closely with the operations to reduce the actual times to be just faster what we're doing, and then of course a large part of that is just negotiating more efficient costs here. So definitely we'll be overall sub CAD12 operating costs for our operations this year.

And the one thing that we're really introducing a lot more into the field operations is technology. So we haven't quite introduced drones going over the fields yet, but we're using a lot more technology in our trucking and our sourcing, in our surveillance. So that's big steps forward for us.

That's great. Thank you.

Thomas Matthews, AltaCorp Capital.

Just a couple 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 if it was going into the ground you would expect some production bumps here and there.

Yes. 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've told you Q1 would have been 170,000, 172,000, and we are 178,000. And so we really outperformed in Q1. And so that allowed us to then shift capital out of Q2, which if we would've drilled in Q2 all those wells would come on towards the end of Q2.

That would've bumped our average in Q3 and Q4. And so we would have out beat the 165,000 average considerably. And so instead we moved that CAD100 million to the backend of the year.

So it's equivalent to cutting the capital by CAD100 million, and then that capital and the volumes associated with it really show up in 2017. But we would obviously drill the wells at the end of this year, and the capital goes into this year and the production rolls into 2017, and that allows us to hit that 165,000 number and CAD950 million CapEx for 2017 more easily.

Okay.

Does that answer your question?

But no changes to 2017 though, I guess is where I was going?

Yes.

Thomas, keep in mind that we're just reiterating that capital shift that was announced two months ago.

Yes.

So there's no change to the guidance and there's no change to the capital from --

Yes. 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 with the same production essentially.

Okay. And then just more on the Uinta, there's 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's 3,900 wells or so scheduled in that application and you only have 1,150 net wells identified, I would assume these are all new wells or just wondering if you could just shed some more light on that.

Yes. So in those applications you have to give your full historical disclosure of what you're going to drill on all of those lands over time. And so you lay out -- that would be like a 10-year 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're going to do. It doesn't necessarily speak to the exact this year/next year drilling program.

No.

We obviously identify a tremendous on a vertical basis thousands of drilling locations out there. You're 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 like cutting the center out of the Cardium field in Alberta and stale dating it for 50 years, and then now companies are coming back into drill that land up.

So that's essentially the project that we have here. Further to that, we are trying to develop it horizontally, and there are seven different zones that are prospective horizontally that we could drill whatever number of wells per section horizontally if that works out.

So that's all encompassed in that big report basically to outline on an environmental standpoint the overall impact of that 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 put your application in on every possible drilling location that you could think of to understand the environmental impact.

Okay. Great.

I don't know if that helps. I don't know if that helps define it.

Yes. I mean obviously it does from information more than evaluating current today's market.

Yes.

But anyways, and then my last question is just on that Pembina SEEP plant. Obviously with liquids pricing quite low, just wondering if that's -- is that a long-term contract? Do you have to go through that plant, or is there a price where you just say, okay, we're just not going to extract these liquids anymore?

Yes. No. And we actually have moved some liquids back into the gas, so we have that flexibility.

Okay.

But we don't have to -- yes, we don't have to take all the liquids out and lose that. So we -- and we've, I think, correct me if I'm wrong, Neil, but I thought we did move some -- we have moved some back to get the gas price.

Yes. I mean, that's what's happening with the downward pressure on the liquids price. There are instances where we're getting more money out of the heat value of the gas than we are out of taking it out of the liquid. So we've got that flexibility.

There are certain commitments that we have to do for them to realize their return. 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.

Yes. We are producing more than what's in that contract now.

Perfect. Okay. That's it for me. Thanks.

Travis Wood, TD Securities.

Good morning, all. At Viewfield, and just talking about the waterflood, you have the approval on the first, you 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 on board from the approval process?

Yes. Before maybe Neil answers that I just -- we've -- 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 that, 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 20 years, and it was the guy 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 in to learn even how to unitize.

And so now we've gone through all that, and now it's just going to accelerate, and now there's fee title owners see all the other guys sign up to units and the benefits of all that. All of these units just fall into place and will accelerate and happen a lot quicker. And so I'd expect, Neil, maybe you can answer the timing on that.

Sure. So we are -- I mean part of the process here, and like Scott said it's -- I mean there's 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 Innes unit, it's another 60-odd sections that we're going to be putting under flood here. We expect in the next month or two that the government, we're 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're -- it's probably a bit of a we're sandbagging. I'm 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're 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're 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 a unanimous vote on their part to participate in the Stoughton Unit.

We'll have over one 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 could add another 0.5 billion barrels to be flooded.

So we are -- I mean the Viewfield play, we're getting a lot of winds on the primary still with the completion techniques, the step-out, expanding it, but this really is developed into a low risk, large oil in place, world-class unconventional resource play, and it's been pretty exciting for us.

This play put in perspective, Viewfield in 2004, the entire Bakken was 100 barrels a day. Today it's now the second largest producing pool in western Canada, second largest ever discovered oil in place and it's just -- it is strong free cash flow for the Company now. So big part of our future.

Yes. And one of the -- I think it's important to understand that on historically in across the world, if you look at every single waterflood and on average in rule of thumb, you get two times primary recovery. So if the primary recovery out here is 15% to 20%, we're going to get twice that, 30% to 40% on waterflood. And that's a historical average of all waterfloods in the world.

And so we're seeing that response and view with the initial flooding that we've done in these units and in areas of the field, and we would expect to outperform that even beyond that based on the characteristics of this field and the fact that it's a shallow reservoir.

It's the shallowest unconventional field, I think, in -- or one of the shallowest unconventional fields in North America, and that gives us huge benefit on perm and porosity and waterflood ability relative to anything else in North America, combined with the low royalties in Saskatchewan. So it definitely is a continuing big play for us and very early stages still.

And the 775 injectors that you have in the release, is that associated with just the four units?

Yes. That's just with the four units for now. So by the end of this year, at the end of next year, we'll have 150, 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 have such a strong database to follow from.

Okay. And that 1-to-1 ratio based on that 5 to 10 years --

Yes. Ultimately yes. I mean, we're -- that's something we're continuing to optimize here. We've certainly seen two injectors in a section responding quite well, supporting six, the other six wells here. But that something we'll continue to optimize.

Okay. And in the Shaunavon you talked about the 35 stages. Have you -- how many wells have you drilled at the 35 stages, and do you see any interference on that?

I think it's close to 100 now. We're getting up there -- we were doing that all this --

Last year.

At the end of Q4 and into Q1 that we've been experimenting with that.

Okay and any interference with 35 stages at all?

We're not seeing that, because what we're doing is smaller tonnage on the stages. So we're taking that into account.

Okay and then last question at Uinta, any infrastructure constraints right now in that 15,000, 16,000 barrel a day mark?

No. They are all single -- essentially single well batteries that the gas is flow lined into our gas compression facility. And we have no restrictions on that end.

Okay.

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 basin and the drop in production in general in the entire basin. And so -- and they are expanding the refineries as we speak there as well to increase the capacity. So you have dropping production with expanding capacity, so there's significant room there to grow.

Okay. Do have a sense of what the take -- spare takeaway would be out of the region right now?

It's 30,000 barrels a day probably.

I would say it's between 20,000 and 30,000 barrels a day.

So if indirectly --

At one point they were railing 25,000 on top of that.

Okay.

In the past, so you could easily double the volumes out here without much of a concern on that. And the dips have narrowed because of that.

And that 20,000 to 30,000 approximately can you remind me, is that all pipe?

It's all trucked to the refinery.

Trucks. Sorry.

It's a three-hour truck ride to the refinery.

And we're in a basin there as well. There's a lot of elevation between where we're producing up the side of a mountain into Salt Lake.

Okay.

It's just the -- all the barrels there are because they're waxy they're all tracked to the refinery, and it's really close. So it's -- yes.

Okay. That's all. Thank you.

Thanks.

Ray Kwan, BMO Capital Markets.

I have only one question and hopefully it's a quick one. I just want to touch on 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 non-core asset sales.

Is it something you're going to do in the second half here? Is it going to be one for one where if you buy let's say CAD50 million worth of assets, would you sell CAD50 million worth of assets as well too? So just want to get some color on that. Thank you.

Yes. We have -- 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're paying down debt right now.

And then that gives us some flexibility from some smaller transactions. I think I said in the past we're looking at that CAD100 million to CAD200 million type range on acquisitions at this stage.

If -- we basically are saying we view Alberta as our non-core area, and strategically we feel -- we'd like to consolidate in Saskatchewan, consolidate in Utah. We're looking at additional basins in the US and opportunities there.

And if we were to transact on any larger transaction, we would need to sell, obviously sell some assets and consolidate. So we are right now just in the process and looking at I guess on selling an Alberta asset or Alberta assets to improve our balance sheet and put us in a position to look at other acquisitions in our core or into the US.

And we're no rush to do any of that, but that's just something we've identified and said that we would contemplate. And so that's where we're at, but again, we're in 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.

Perfect. Thank you.

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.

Patrick Bryden, Scotiabank.

Good morning. I'm not sure if you might be able to elaborate on this given competitive considerations, but what would you say are the factors at play that have augmented your economics in horizontal wells in the Uinta Basin?

Well, it's a new zone that nobody's ever tested. So we haven't really used -- we've obviously apply the technology and knowledge we know from previous areas and other completions we've done, but it's the zone at this stage that is showing us the outperformance and the economics.

And I think that's the biggest key, and it's in a couple zones that nobody else has ever drilled into. And so we're expanding that, and so that's probably the biggest key.

And then we would -- and you've seen it in every single play, where as guys drill more wells, tweak the 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, they're economic.

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 the edges of the pool and then infill drill it horizontally in those right zones and still have economic vertical wells to do it. So it's a bit of a unique play in that regard.

And so part of our capital program this year is step-out drilling. We're doing a whole bunch of cores on all of the different zones that we're testing with the vertical wells, and then we'll frac them, put them 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 are now in the phase where we are following up on our first horizontal wells that's in those zones that we've identified. Then the second phase will be optimizing those completions to even enhance the rates of return even further.

Great. Thank you. And just a few quick questions on the waterflood. When we think about the producer injector ratios that you've touched on in your release, can you give us a sense for the steps you've taken to arrive at that number?

And then you've alluded to potential for, on the technical side, to maybe outperform that. What would the factors be in your mind that would drive you to get a better ratio or optimize the ratio?

So in any waterflood, you have -- you take a core sample. You pump water through that core to see how much oil you can get out of that core through the core labs.

And I think in our tests for Viewfield it's a 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 that injection.

And so typical waterfloods you get 50%, so that 70% turns 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 oil 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 factor 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 fractures, to control the fractures, one of the key ones that we discussed I think a year ago or two years ago now is the closable sliding sleeve. So we're 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 packer assemblies 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 wellbore.

When you think of it from a technical perspective of how many wells we have per section, the ability to control where the water goes in 8 wells times 30 fracs so 240 fractures, that we can control the water in each one of those fractures, our recovery factors are going to go up considerably. And these are really cheap methods of doing it, and so we're very, very excited about that.

Then we also are testing chemicals and EUR-type concepts, which are basically diverters. Probably the best example I can use is when you go to wash your car and you hit the deluxe car wash, and at the end you have the spotless, spot-free rinse or whatever and there's chemicals within that water that disperse water in a way that leave your car nice and shiny and clean.

Those are the types of chemicals that we are using to inject into the reservoir to divert -- disperse the oil to wells to improve the recoveries over time. And those are tremendous and they're well used historically in the world on conventional waterfloods so we know they work.

So we're excited about the work that we've done in there. I could go on and on. The list is probably 20 different technologies and things that we're implementing and testing that will for sure move up that recovery factor beyond your standard two times primary.

So when you actually take a step back and you look at Viewfield/Shaunavon relative to the rest of North America, we're two times outperforming every reservoir because we've got waterflood secondary recovery versus all the other guys are primary recovery guys. And so that to us is exciting, and it obviously drops our cost per barrel and our economics and the rates of return go up that much more. So we're pretty excited from that side of it on all aspects of the waterflood.

Great. And then maybe if we can just get a little more elaboration on Shaunavon and then I'll step out of the way here, but what are the factors in your mind so far that make it similar to the Viewfield and what makes it different? Would you say the progress has been on track with what you've experienced at Viewfield or ahead, and why?

Shaunavon, which is interesting, has outperformed Viewfield in our minds on response. And it's -- we believe it's mainly two things. One is Shaunavon, the technology was more advanced when we went into that play.

If you recall, Viewfield, we started drilling up in 2004, 2005, 2006, 2007, where 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.

Then on top of that, Shaunavon is a three times thicker reservoir. So we're 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 at all.

The crown -- or the government has given us a go ahead to essentially put water injectors where we want whenever we want. So it expands and accelerates the ability for us to waterflood that play quicker.

I think all those three combinations have in general terms outperformed Viewfield from that perspective. But again, that play is still behind and earlier stages of development.

We haven't drilled as many infield wells there yet. So we still have many years of just getting to primary versus the waterflood there still.

Okay. Appreciate it. Thanks very much.

Arthur Grayfer, CIBC.

Good morning. Just one quick one for me. When I think about the Uinta, you talk about moving to more horizontal wells and the great success you've had.

Can you maybe frame it for us when you saw the transition from vertical drilling to horizontal you had a multiplier effect typically in place either on IP or EUR. And there being a multiplier effect on the cost, but the multiplier effect on the rates would likely overshadow the cost. So can you maybe frame that for us in that way?

Yes. I mean, it's super early days. I mean, you've got to remember we've only drilled a well in each zone. So we're trying to take one data point and extrapolate.

But it's essentially more than two times on the IP rates and probably twice -- the capital's only twice, I think, on the horizontals. 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 want to get to do that math.

Right.

Yes. Some of these wells have really hung in there at high levels beyond what we would've predicted.

Okay. Thank you.

Nima Billou, Veritas Investment Research.

Good afternoon. A quick question, just wanted to know with respect to spending for the remainder of the year, it seemed to be loaded in Q1. So you're still on track for the CAD950 million for total CapEx for 2015?

Yes. We've only spent -- we've got 55% of our capital still to spend, and we're essentially only spending about CAD60 million or CAD80 million in Q2. Basically it's a pretty balance 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 that gets you to that CAD950 million. And that's really related because we shifted the CAD100 million out of Q2 and put it into Q4 to balance out more of the second half of the year with the first half.

Is it also because you're seeing the trend in futures pricing, and pricing you think will become more favorable towards Q4?

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 effectively took out production out of the average of the year and kept the capital in, but put it on the back end, which then gives us flexibility that if oil prices trended back down to the CAD30 level, we could cut that capital and it would not affect our yearly average.

And it would protect our balance sheet a little further and protect us into 2017 if prices went south. So I -- and then we also have obviously a lot of capacity to add capital into the second half of the year if prices do continue to improve, and we can add just more days to the drilling rigs and more wells on the back end.

We could easily grow and exit at over CAD170 million at the end of this year if prices do improved in September or 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 to 2016 at this stage.

Great. One final question, I think it's really interesting to think with respect to oil companies in terms of the sustaining capital and what sort of budget is necessary for growth. So given that there's 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 say 2% or 5% growth? So if you could answer that --

Yes. It's an interesting question. So we basically said CAD950 million is our flat production profile for 2016/2017. And that's -- within that CAD950 million we still have CAD150 million of long-term capital spend.

So we could grind that down a little bit lower to show a sustainable -- what you would theoretically say just drill to stay flat. 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're actually shifting capital to an exploration play in Utah that we arguably could get zero production out of those next wells. And we've incorporated that into our production forecast.

So we actually probably expanded on that longer-term capital in this latest release and discussion of our shift of capital. 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?

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 percentage growth. So it doesn't take us much to get to a higher exit or a higher production for 2017 on that capital spend.

That's very helpful. It's interesting, I guess like you said it depends on where you put that capital and what agenda you have, whether it's like you said exploration or it's in the best parts of the play, you could achieve higher levels or lower levels of growth. But that's very helpful. Thank you.

Ryan Czul, SIR Capital.

Hi. It's actually Eric Pipa. Thanks for the question or time for the question. I wanted to follow up on the 40% uplift you've seen on select wells at Viewfield. Is this new technique something you can apply across the field to the remaining locations, or is it only going to work in certain areas?

And then secondarily, over what time frame are you measuring the 40% uplift? Is that a 30-day accum, a 90-day? I know it's probably early, but just any additional color on that would be appreciated.

Yes. So the 40% is accum to date number on those wells. Really what we're trying to do -- what we've -- what we're using there is a different fluid that transports the sand into the reservoir that fits with our reservoir characteristics.

And so in some plays, like you've 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're trying to do and Viewfield. So it's applicable across the entire field.

Then secondly, we've taken that fluid and we're 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. And so there is a combination of things. That's really, I think, a key.

And this is where the whole industry has gone is -- and how we've been successful in the past in that we went to eight well infill drilling before everybody else to learn that that was an advantage, and we did acquisitions based on that and we are big winners on that. We went to cemented liners before everybody else in North America in 2009, for advantages of the waterflood.

The results we saw there were tremendous, and that gave us huge advantage to consolidate the Shaunavon. Then we've moved to sliding sleeves and the water flooding, that gives us an advantage on other guys.

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're testing that to further that.

Will all the go-forward Viewfield completions incorporate this new approach?

Yes. Some variation of that. I mean, we're -- I mean Viewfield has never been a cookie-cut play at all. That we come up with something, we're 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's close to 1,400 wells in inventory just on primary, let alone the huge upside from the waterflood. So we are continually optimizing that.

There is probably another 1,000 or 500 on the edge of the field.

That's -- yes.

If this is successful, as much as we expand the play, we'll add even more locations. So there's a big end game when proving up that further.

And there's further gains that we see even mechanically on the sliding sleeve systems and some of the other mechanical systems we're looking at that are continually being tweaked in the play.

Is there any added cost to this new technique? Or is it same oil cost?

No.

No. It's getting offset. I mean there's the plus and minuses, but we're getting the cost down. We're getting more efficient.

I think we're at what, CAD1.3 million per well there from we were CAD2.1 million to CAD2.2 million prior in 2014.

Our drilling days are less than half of what they used to be five years ago.

Yes. We drilled wells there this quarter under five days, which is unheard of in the past. So from -- that's from 9 or 10 days. I think just in the last year we've dropped it to under five.

I mean our original wells were 14 days.

What's the oldest well that you have that you've completed with this new technique?

It's in the past year that --

Yes.

So it's a meaningful cumulative period where the 40% is measured against? I assume you haven't factored this into your outlook? You haven't factored this into your outlook at all, this uplift? Or you have?

No. They are factored into our budget model -- like in our production forecast, and they're not budgeted into our forecast like our production forecast.

So you're using your prior type curve, not --

Yes.

No 40% uplift to that curve?

Yes.

Okay. Great. That's all I had. Thank you.

Great. Well, thank you very much. I appreciate you attending the 2016 Q1 conference call. I'll turn it back to the operator.

Thank you. 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.