Veren Inc (VRN) 2013 Q4 法說會逐字稿

Good morning, ladies and gentlemen. My name is Jade, and I will be your conference operator for today. At this time, I would like to welcome everyone to Crescent Point Energy's fourth-quarter and year-end 2013 conference call.

(Operator Instructions)

Thank you. This conference call is being recorded today, and will also be webcasted on Crescent Point's website, but may not be rerecorded or rebroadcasted without the express consent of Crescent Point Energy. All amounts discussed today are in Canadian dollars, unless otherwise stated.

The complete financial statements and Management's Discussion and Analysis for the period ending December 31, 2013, 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, and 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 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 now like to turn the call over to Mr. Scott Saxberg, President and CEO. Please go ahead.

Thank you, operator. I would like to welcome everybody to our fourth-quarter and year-end conference call for 2013. With me is Greg Tisdale, Chief Financial Officer; Neil Smith, Chief Operating Officer; and Trent Stangl, Vice President of Marketing and Investor Relations. I will give an overview of our quarterly and year end results, and Neil will discuss our operational highlights, and then Greg will speak to our financial highlights.

We're very happy to report that Crescent Point executed another record quarter and an excellent year. 2013 was a year of tremendous organic growth across all of our core areas, and thanks to both the success of our drilling program and continued great results from our cemented liner completion technology and our waterfloods. The highlight is that we received technical reserve revisions in the core of the Viewfield Bakken play attributed to the waterfloods for the first time, I think, which is significant.

In addition, we had a large technical reserve addition due to results from the latest generation of cemented liner completion technology. This independent assessment speaks to the success we have seen in the waterflooding and cemented liners. In the future, we expect to see similar reserve increases in the Shaunavon and our other core plays as we continue to refine our technologies and implement them.

Looking at the year as a whole, some key metrics and highlights of our strong performance during the year, we grew production by 22%, which represents a two-year average of 28%. We grew 2P reserves by 9%, which represents a two-year average of 26%. And we grew cash flow by 28% which represents a two-year average of 26%.

As a Company, we're following what we describe as a dual-track growth plan. Our plan involves leveraging our technical advancements, such as our cemented liner completion techniques, to our drilling inventory at a measured pace, and at the same time, implementing our waterfloods to improve production and lower our overall corporate decline.

Waterflooding, which is the second track of our plan, is now increasing in scale, and more significantly contributing to the lowering corporate decline rates. We will continue to grow our waterflood exposure as we continue to convert more producing wells to water injection wells in our plays.

One of the key areas that we had to prove, I think, to the market in 2013, was the Uinta Basin in Utah. We believe we demonstrated that this year. Last year we grew production in the play by more than 30%. We grew reserves, including production by more than 30% from November, when we acquired this property, to year end 2013.

We also established and grew our rail operations to help broaden the market for Uinta Basin crude, which ultimately gives us access to better pricing. In addition, we are on our second generation of our coil frac technique in the play, and we are very excited about our operations in Uinta as we move forward in 2014.

Looking at the fourth quarter, we achieved a new production record of nearly 128,000 barrels per day, a 9% per share increase from -- over our fourth quarter 2012 numbers. We also beat our 2013 exit guidance of 124,000 barrels in November, and then when we updated this guidance to 126,500 in January, so a great quarter on a production basis.

In 2013, we delivered material per share growth in production reserves and cash flow to our shareholders, and we plan to have another excellent year in 2014. To ensure we meet and exceed our targets, we will continue our dual approach, which means refining our cemented liner completion techniques and pushing forward with our waterflood programs to enhance their impact on our overall corporate declines.

We have had an active start to 2014, both in the field and financial markets. In January, we listed in the New York Stock Exchange under the symbol CPG, and plan to visit the Exchange on the 24th of March to celebrate our listing and ring the market open bell. We have had a great start to the year, and we believe we are in a fantastic position to meet and exceed our targets again this year.

And before I hand things over to Neil to talk on the operations, I would like to thank all of our employees, field staff, executive team, and Board of Directors, for ensuring Crescent Point executed another year of outstanding results. And I'm proud of our teams and excited about the year ahead. Now, I will pass the discussion to Neil for highlights on the operations.

Great. Thanks, Scott. During fourth quarter, we spent CAD389 million on drilling and development, and drove production to a new record of 128,000 BOEs a day. Our annual production hit a new record as well, at more than 120,000 BOEs a day.

During 2013 we achieved material reserve additions by any measure. We increased our proved plus probable reserves by 55 million BOE, representing per share reserves growth of about 4%. We also increased proved reserves by 32 million BOE, or a per share increase of about 3%.

We did this effectively with finding and development costs of CAD18.42 for proved plus probable BOE, representing a recycle ratio of 2.8 times. For the twelfth year in a row, we have achieved F&D costs of less than CAD20 per proved plus probable BOE. This is an incredible testament to our skilled technical staff, and our ability to consistently and efficiently add reserves in all of our resource plays.

Speaking of technical developments, we are very pleased with our waterflood programs and cemented liner completions, which continue to drive costs down, reduce the amount of water we use, lower initial decline rates, lower overall corporate decline rates, and increase recoveries. Our successes with these technological advancements were recognized in our year-end reserve assessment.

At year-end 2013, we received significant technical reserve additions, due to results from the latest generation of cemented liner completion technology, as well as technical reserve additions attributed to waterfloods. I would really like to emphasize the significance of having qualified independent engineers recognize our waterflood reserves for the very first time. This is evidence that our waterfloods work, without question.

If you remember last summer, independent engineers completed an initial study of our Viewfield Bakken waterflood, and concluded that they saw potential for a recovery factor of upwards of 30%. That is more than a 50% increase above our primary recovery factor.

In the first year, they initially recognized a 3% increase in recovery factor in immediate areas under waterflood, or a 16% increase already over the EURs above primary. This is a great start and shows there is lots of room for waterflood reserve additions over time, as we convert more wells to water injection wells and have more performance history.

In 2013, we hit other major milestones with our waterflood programs, having received approval for our first waterflood unit in the lower Shaunavon resource play and technical approval for our first unit in the Viewfield Bakken. This year we plan to pursue approvals for subsequent units in both plays, which would allow us to implement our waterfloods across larger areas.

Based on solid results from our 25-stage cemented liner completion technique so far, we will continue to refine this technology in our Viewfield Bakken and Shaunavon resource plays. We are now using this completion technology on every well we drill in those areas, and we continue to see improved production and first-year decline rates coming in at roughly 10% lower than those of the previous generation of completion.

Aside from our focus on technological advancements, for the rest of 2014 we plan to continue to develop our high-quality asset base, focusing on our key Viewfield Bakken, Shaunavon, and Uinta Basin resource plays. As we mentioned last quarter, we have multiple initiatives under way in the Uinta Basin to further increase production levels and improve ultimate recovery rates.

We plan to begin collecting data in the third quarter 2014, using a three-dimensional seismic program in the Randlett area, and to initiate our first waterflood pilot in the basin next year in 2015. And as Scott mentioned, we are now already into our second generation of coil frac technologies there.

Before handing things to Greg, I would also like to thank all of our employees, and especially our field staff. It has been a very hard and cold winter, and our field staff have continued to show they are the best in the industry. I would like to thank them all for their hard work to deliver another excellent quarter and year. Well done, everyone.

Greg will now discuss financial highlights. Greg?

Great, thanks, Neil. I'm pleased to report that Crescent Point generated cash flow in the quarter of CAD533 million, or CAD1.35 per share. This represents a 14% per share increase over the CAD1.18 per share generated in the fourth quarter of 2012. On an annual basis, in 2013 we generated over CAD2 billion of cash flow, providing a 9% per share increase over 2012, as we continue to add shareholder value.

In 2013, we had tremendous success through the drill bit and had an excellent fourth quarter, growing production per share by 9%. This strong production momentum and robust Canadian oil prices in the first quarter of this year have positioned us well for a great start to 2014, and have contributed to our increased funds flow from operations guidance for the year. We now expect to generate cash flow of CAD2.25 billion, or CAD5.59 per share, in 2014, based on forecast oil pricing of CAD100 per barrel, CAD4.65 per mcf, and an exchange rate of CAD0.90.

With the weaker Canadian dollar and support of oil prices, we continue to lock in oil at very attractive prices. Our current hedge targets are in excess of Canadian dollars CAD100 a barrel, and currently for 2014 we are now 65% hedged at an average price of CAD94. Looking beyond this year, we are now 35% hedged for 2015, 21% for 2016, and a commensurate 2017 hedging program. On the oil differentials, we continue to be disciplined, and now have approximately 14,200 barrels a day locked in for 2014.

On the balance sheet side of our business, we remain strong, with significant unutilized credit capacity and debt-to-cash of approximately one times. Some significant items to note in 2013 included the suspension of our premium DRIP in the fourth quarter, along with the issuance of $300 million of senior guaranteed notes as part of our long-term liquidity strategy.

The final financial item to highlight, as previously mentioned by Scott, is our listing on the New York Stock Exchange on January 22, 2014. This is a natural evolution of our capital markets platform, as we continue to grow and expand our Company in both Canada and the United States. I will now hand things back over to Scott.

Thanks, Greg. We have had a great start to the year. We believe -- we really believe that what sets us apart from our competitors is our dual-track approach to growth, combining advancements in completion technology and waterflooding. We look forward to the rest of 2014.

At this point, we are ready to answer questions from the members of our investment community. Operator?

Thank you.

(Operator Instructions)

The first question is from Pavan Hoskote from Goldman Sachs. Please go ahead.

Good morning, everyone. A question on the Viewfield Bakken EURs. You have discussed higher EURs in the core area of the Viewfield Bakken because of the 25-page cemented liner technique.

Can you remind us how much of your acreage lies outside this core area and what your expectations are for EURs in this region outside the core? And what is the potential upside from use of similar completion techniques?

Great question. In the core, when we started developing the Bakken in 2007, we were getting 100,000, 75,000, I think on the high end, you will see in our corporate presentation, in the main core cores, like 115,000 EUR per well, and the initial completions. Now, we're getting 250,000 to 300,000 barrels per well with this new technique, and that's progressed, obviously, from 2007 and all the way to today.

And what the impact of that is, it is not only in the core that we are increasing that reserves, but what it does, is it actually expands the size of the pool. So areas in 2007 that were uneconomic and that would maybe have only got us 30,000 barrels of reserves, are now getting us 50,000 to 75,000.

So it is kind of a three dimensional exercise in the fact that our rates of return in the core of the play have gone up dramatically, and then the size of the pool has gone up. And then our inventory on the edges has gone up, and the rates of return on the inventory has gone up dramatically. The pool expanded, just due to that technology change.

With the cost that we're seeing and the productivity on those wells, one great example is in the northwest part of the field, where the older technology we fracked out a zone, and the wells didn't perform as well. They were basically uneconomic.

We turned those wells from being uneconomic to being 100,000-barrel type wells that are highly economic, and sub 18-month payout. Those are like one-year payout. I think it has had a tremendous effect on that. And obviously, it will have that same effect across all of our other fields.

Thanks. And on an unrelated topic, in the past, you have talked about the potential to export oil to international markets, from either the US or Canada East Coast. That definitely makes sense from a high level, but can you pull out a little more detail in terms of specific regulatory approvals that you might need to make this happen, both on the Canada on the US side?

And then discuss the cost structure involved? And have you started to do any work on this?

I will let Trent Stangl, our VP of Marketing, answer that.

Sure, thanks, Pavan. That is really a natural evolution of our strategy to diversify the marketing portfolio. If you look back, over two years ago, we started getting into the crude by rail business, which allowed us to access markets that we couldn't access on pipelines,

And we started to access some of those coastal markets, and move further down the value chain towards international pricing, or Brent crude pricing. So the exports really is an evolution of that strategy. Canadian crude is, obviously, well positioned. It's got a competitive advantage in the sense that there are no regulatory hurdles, so to speak, in order for us to export.

On the Canadian side, to export through Canada, we would need NEB export permits, and we would need access to a deep water port. On the US side, we would need be to able to ensure that our crude remains segregated from US crude, so, obviously, the rail strategy makes a lot of sense there.

The permits on the US side come from the US department Of Commerce and the Bureau of Industry and Security. And we know there is already some Canadian crude that is being exported through the US, so it is very doable.

We are working hard to try and get something in place by the end of the year. We don't have a whole lot more that we want to say about that right now, other than we do have a number of irons in the fire along those lines, and we look to be able to speak more of that later in the year.

Thank you.

Thanks.

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

Good morning, guys. I have three questions for you. The first is just related to the 3% improvement that you got from the waterflood scheme. Can you translate that into a BOE number, an aggregate barrel number, by chance?

I will let Neil answer that.

Sure, thanks, Travis. This is something we have said in the last couple of quarters. Initially, what will happen with the independent engineers. The example is one of our first units, the Tatagli unit. It was under primary, just going to waterflood when we acquired it turning from a junior to a trust.

So what independent engineers do, is they -- More than anything, the first time, it is a signal, it works, we believe in it, under strict NI 51-101 assignments, it passes the test, we are now going to give you some waterflood reserves. And then what they do is they give you a little bit each year, once we do more injectors, get more production history.

We had a 30-, 40-year plus reservoir engineer come in, go through everything, do the classic, what I call, conehead, type of calculations, not putting numbers into a simulator, but just old bacon-and-egg type of reservoir engineering that developed the House Mountains, the Judy Creeks, the Pembinas. He went in there and he showed that it is possible to get up to 30%.

So what the independent engineers do is they come along, they take a look at that and they say okay, this is the first step on the journey towards that end of going to the full amount. So the Tatagli unit, which is a different type of quality, but just on a scale, it was like a 6% recovery primary. They went to 6.5%, 7.1%, 8.3%, every year they increased, and it is about 12%.

So within the area that has got enough history right now, there is about 100 million barrels in the immediately waterflooded area that has enough production history and enough response by the strict calculations to give them that 3%. The amount attributed to waterflood in that 100 is about that 3 million, plus or minus, barrel area.

But what I expect now that we are on this journey, is we will get a little bit every year. We are doing 30 water injectors to the 62 we've got already. In 2014, another 30, we are going to be putting in applications for the next two units before the year is out. We have to have some partner meetings now because we have some partners with them.

So, it is commercial, it works. The government recognizes it works. The independents recognizes it works. You're seeing great production numbers from us. If anything, that demonstrates that it works, because of the increase in production by the lowering of the decline rate.

And I would add, to comment, too, that if you -- to put it into perspective, up until about 2005 or 2006, the largest oil pool discovered in Western Canada was like 100 million barrels. And since then, we have had all the great growth, obviously, in the unconventional resource plays.

And a 3 million-barrel reserve uptick on a 100 million-barrel pool is pretty significant. It is like a 16% increase on a EUR basis relative to primary. So, it is not to be taken lightly and that it's minor. It is a pretty significant undertaking from that perspective.

And the other thing, Tad, this is 3 million barrels that we don't have to drill for. So, 3 million divided, whatever you want to use, CAD150,000, CAD200,000. Yes, there is CAD60 million in capital we don't have to spend, and we can redirect that into more development activities.

Okay. No, that is perfect. And then I will ask the next two questions in tandem here. Staying in Saskatchewan, what does break-up look like? Are you starting to see that already, by chance?

And then my last question is just related to taxes. How are you guys forecasting cash tax? What year does that start to take effect? And if you can share forecasted aggregate tax value, cash tax value, that would be helpful.

Okay. Break-up, I think, is a little delayed this year because of the cold weather, obviously, last week, or last couple of weeks, was pretty cold. So break-up is a little bit delayed. We don't expect, with the snow and snow pack and that, that it will be hugely affecting our numbers as far as what we have already disclosed and presented.

We put in a pretty strong break-up number in Q2 every year, and so I don't think this year will be any different than in the past. I don't think we are looking at a scenario like 2011 or whenever, where the flooding was. But just probably more of a normal break-up is what our expectation would be. And then on the tax side, I will maybe let Greg Tisdale answer that.

Sure. Based on the current guidance right now that we're looking at in 2014, we're slightly cash tax payable, so call it around 1%. That is under current guidance pricing. That being said, so, obviously, contingent on capital spend and acquisitions and taxables, et cetera.

And then when we fast forward into 2015, we will be based on current strip pricing, where anywhere between 5% to 10%. And same thing, depending on capital profiles and taxables required through acquisitions, that number will change, obviously. But that is where we're sitting here currently.

And when you guys talk about those percentages, some of your peers use it on a pre-tax fund flow or cash flow. Is that the same thing? Or is this an income --

Pre-tax.

Pre-tax?

Yes.

Okay. That's all. Thank you.

But our cash flow is based on that.

Yes, so our cash flow that we're disclosing is on an after-tax basis. Just to be clear.

Okay. And so those percentages are the percentage of taxable income or --

I'm using it based on a percentage of pre-tax cash flow on taxes.

Perfect. Thank you very much.

Thank you. Your next question is from Kyle Preston from the National Bank Financial. Please go ahead.

Thanks a lot, guys. And congratulations on a good quarter there and a good year. I've got a few questions here. The first one, just on your operating costs. I've noticed that that's been trending down the last couple quarters.

Can you just talk to what is driving that? Is that a function of the higher production volumes? And also what you expect going forward?

Yes, Kyle, thanks for the question. A couple points. Number one, yes, absolutely. With our production per well up, that drives your dollar per BOE down with your fixed portion. So for sure, that is true.

The other thing -- one of the things that we do as a company, the operating budget, operating cost comes from the field. It is not something that Calgary puts together.

The way our approach is, is our two senior field managers, they present the budget. So they've got all of the data, the guys that are spending the money are the guys that are preparing the budget. They're safe, but they're cheap. So they really spend a lot of time going through it.

One of the areas that we identified was our downtime frequency for our pump jacks. And what we found, a start in the Bakken field. It was a little more corrosive. So what we have been doing is we have changed our chemical program out there.

So our downtime is down, our repair and maintenance is down. Again, we have got the best field guys that are in the industry. They work hard. When it is minus 1,000 out in the field, they're out working hard. It is a real tribute to them.

I think to that end, we put a really strong program in each of our areas together, attacking chemical, attacking costs. And I think there is another leg, really, on the Uinta side, because we just took that over in the last year, of driving the cost down there, as well, changing operations over. So a pretty positive year across the board in all of the areas on that end.

And would you expect that to continue at that CAD11 level going forward?

We always expect it to continue, Kyle. (laughter) We are (multiple speakers) hoping to get another 5% out. But, no, we think there is still remaining efficiencies to carry on.

Yes. I think in our -- (multiple speakers) We used CAD12.

We used CAD12.50 in the guidance.

So we're a bit conservative, maybe, on our guidance, but I think we are in a good position on those numbers. And I think the area there is probably Uinta, as we have taken over those operations and changed how that field is being operated. And then we are doing some things on that end, on the capital side, as well as in our other fields, on tie-ins and facilities.

Okay. And can you talk to where you see your corporate decline now?

I think we budget around 33%, which is probably on the high end. And I think we're now sub-30%. If you look at our Bakken field now, all of the charts push to below 30%. So I think we are probably in that 29% to 30% range, and with it coming down.

Last question here, just on the Uinta, you guys talked about a few horizontal wells that you're participating in. Can you give more details as to what you're seeing there with respect to IPs and initial declines? And also talk to your current marketing efforts, where you're shipping your crude, and what kind of pricing you're realizing there on your Uinta?

Yes, on the horizontal side, we have participated with wells with Newfield mainly, small working interests in those wells initially. The production rates, the reserves, associated with those wells, are very strong, very positive.

The negative side to that is the capital costs are very high. And so we feel, and I think Newfield would probably say the same thing, that their costs are going to come down over time as they add more wells to their program. And results, hopefully, will get better.

They are using, from our definition, older technology. They're not using our cemented liner completion techniques, or things like that. In fact, I don't think anybody in the US is using that kind of technique.

So we're planning to -- I think we've got about a dozen wells surveyed, or more. And we are planning a small program through, starting hopefully sometime in the summer or late Q3, on the horizontal side.

By the end of the year, hopefully, we will have better understanding of the results on a cost side, because we will be in control of it, and on the completion side, because we will be bringing our technology down there to test it. Then we are actually going to be testing some other zones that none of the other operators have tested.

We are pretty excited about that program. And it is going to here start probably second half of the year. From that end and on the marketing side, we rail in crude. We've got our first real big rail commitment in April, starting in April. We can't really speak to where and --

Yes, I think during 2013, Kyle, we averaged probably around 2500 barrels a day on rail. We have opened up the market with a few new refiners to getting them running this crude. We would like to get probably another half a dozen guys.

We were quite far down the line with a few of the guys that, either through cold weather in the winter, or in the process of getting their facilities in place, are likely to start taking some crude here into the spring and into the summer, and that's going to help expand that market.

Our permanent rail facility is now up and running. It's got capacity for up to 10,000 barrels a day, which can be expanded beyond that. So we like to grow into that rail capacity and get more volumes going into some new refiners and create a little more price competition for that barrel as we go forward.

And what sort of pricing are you realizing on that crude?

It is not all that dissimilar from the local market at this ten seconds, which is why we would really like to get another half a dozen guys running that crude so that we can again get some more competition for the barrel. It will help getting into the spring and into the summer here and get some increased refinery runs on it.

And the way I look at it, it is very similar to how our Bakken rail started, where our first deals in the first part of that Bakken, were sort of neutral to the pipeline until they started running it and we opened up those markets, and added more refiners and created competition. We didn't get that great pricing, and now, we do.

And I think, really, our goal for 2014 is to build that market. We're not necessarily -- we obviously like better pricing, but I think the first goal is just to establish the shipments and then the different refinery markets, and then push for price in 2015.

Okay. Thanks a lot.

Thanks, Kyle.

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

Good morning. It looks like you have been -- that the Flat Lake area is becoming increasingly an area of focus for you. Can you maybe tell us about how the economics of that place stack up against the others and IP rates, EURs, costs, et cetera you're seeing down there?

Yes, so we're obviously very excited about our Torquay play. We didn't really go too detailed into it our press release, but we have grown production there from 0 to about 7,000 barrels a day as a whole in that area. I think we're about 5,000 barrels a day out of the Torquay.

The three townships that we own that are just north of the border is where we see the play develop. And those wells are basically in the same realm of rates return and payout as our Viewfield Bakken core. From our perspective, we have replaced a significant amount of our core Bakken high return drilling inventory with that development in the Torquay, or Three Forks. So we're very excited about that.

The cost there, depending on if it is a one mile or two mile, I think the one mile there is about CAD3 million, CAD3.3 million per well, and the two miles are about CAD4.5 million. We are seeing the costs and they're very attractive. We're using -- we have a two-mile coil tubing rig that is proprietary to us, that we are using to do the completions down there.

We have had great success, again, on the cemented liner completion technique down there. We are also looking at building a gas plant and pipeline down there to accommodate the growth in the gas volumes there, as well.

Very exciting play. It adds a tremendous amount of drilling inventory. I think in our numbers now, we are pushing close to 600 locations or something in that area. The oil in place on our lands, when you combine the Bakken and Three Forks, is close to 2 billion barrels of oil in place.

It would compete with the core of our Viewfield Bakken, and basically looks -- it would basically double our Bakken core volume. So very exciting play, and we obviously plan to spend, I think, about CAD200 million there this year, so pretty exciting.

Okay. And then presumably as it develops, you could move into waterfloods in that area?

Exactly, yes. And because it is all crowned, 100% crowned, that can probably move a lot more rapidly, obviously, than the fee title crown mix.

Okay. And then, now you do run science experiments, as you call them, from time to time, or I think every year. You move to the 25-stage cemented liners. Where do you think the next generation of -- what's the next uptick for you?

What kind of things are you looking at? Is it more in the way you drill and complete the wells, or is it in the fluids you use? What kinds of things are you looking at to improve lower drilling costs, improve EURs?

Well, we started the cemented liner technique in like 2008, so it has been quite a few years. These kind of technologies and what we have developed don't just happen. They're not easily transferable from company to company.

And I think that is something that needs to really be probably highlighted for people, is that not all companies are going to be able to just step into this, and be able to just use the service company to get them to carry that operation over. We have spent multiple of years.

We have created -- within the version of our first version of the cemented liner, there are several steps in between. And the latest generation would have been -- would it be the burse collars, going from the sliding sleeve, going from basically the mongoose tool that we use that cut a slot in the liner.

We're continually looking at the amount of fluid that we pump. Reverse direction of what the US guys are going, where they're going with higher volumes of water and sand and fluid. We're actually going in the opposite direction, and I think the key high light of cutting our fluid volumes in half is big.

When you think about it, if you can get the same effect and pump less fluid, the water costs are cheap, but to transport it, store it, pump it, produce it, dispose of it, all has associated costs with it. And just that one change I think saved us CAD50,000?

CAD50,000 to CAD100,000.

CAD50,000 to CAD100,000 per well, just by making that one change and fracking down coil. I think we're pretty excited about the continued advancements. What those are, I can't really tell you. Some of that is, obviously, proprietary to us.

We are working on some patents in and around the waterflood. Again, that technology is very proprietary, and difficult for guys to just step into immediately. I think we've got a tremendous amount of years ahead of guys on that.

And then that scale, and the fact that we drilled 2,300 wells to date, or something, and by the end of this year, we will be pushing close to 3,000 wells. It is not like we're doing this one or two times. It is significant.

Okay. Thanks.

Thank you. Your next question is from Patrick Bryden from Scotia Bank. Please go ahead.

Good morning, everyone. Thanks. Just curious on the federal waterflood. Can you give -- is it possible to get a sense for what kind of producer-to-injector ratio you might be thinking about now? Or is it still in the science phase?

Well, in some of the areas we have gone four injectors, four producers per section. And then in other areas, two injectors, and like six producers. And it is a combination, probably between the two and four. So I think -- if you asked us today what our optimal view would be, it would be probably three injectors per section, would be probably at our phase right now, the ideal amount.

Okay. And that would correlate to four producers?

Four to five producers. Eight wells per section.

Okay. Got it. And then in the schematic in your presentation today, you show the waterflood. I'm just curious if you can speak to the idea of, do you think you're getting a lot of effective sweep as you flood here, in addition to pressure maintenance?

Yes, I think that is one of the things that we have discovered. And what we tried to show in those graphics, is that the fracs aren't these perfect channels that shoot them through the rock that you would see from the surface companies. I think that has really created a lot of misnomer on the flood, which obviously can be to our advantage. But it is a more of a torturous path through the rock with these fractures and where the water goes.

In a lot of our wells, offsetting injectors, we're seeing a tremendous amount of production growth from the water injection. That indicates not only pressure maintenance, but sweep as well. And I think we have a chart that we show in our montage of all the wells offsetting our injectors.

You see increasing productivity from, on average, 40 barrels a day, upwards to 80 barrels a day over a two-year period. It is pretty evident, pretty straightforward from that perspective. I think, obviously, with our third-party engineer is pretty confident on the results.

Great. And I don't know if you can maybe elaborate a little bit more on, as you take coil frac technology down to the Uinta and some of the other zones you might be trying to attack. I wouldn't want to compromise anything proprietary there, but are you able to speak more about what you are doing there?

Yes, we did some more science around the fracs and the stages and the rates that we pump at. This next generation is a little bit different than our 25-stage that we set as our first pass-through. We are gearing up in the next month or so.

We're moving our proprietary flow rate down there to actually, to do this new generation of fracs. We haven't done any yet, but based on the modeling and what our theory and the results we've seen in other areas, we're pretty excited about testing it.

Okay. Much appreciated. Thank you.

Thank you. Your next question is from Cristina Lopez from Macquarie. Please go ahead.

Just one quick question as some of my other questions were answered. But with respect to your change in future development capital, you recorded a change in negative FDC for your approved reserves. Can you give some sense as to where that came from? Is it cost improvements that you're seeing in some of the wells versus what was booked last year?

Yes, definitely the change in our technique, and now, we have history in behind the capital spend. To go back to GLJ or Sproule to show them, to demonstrate, hey, it is not CAD2 million a well, it is CAD1.9 million a well, that obviously has a big impact.

And again, from my perspective, being an engineer and the FTC rules, I think another highlight that you can speak to is that our F&D from the past years is high, is overstated. And high in that, if you went back to redo all of the calculations back with that new capital, we would have a lot more F&D, even better than we already have.

It just speaks to that kind of hokeyness of that calculation. But it is a one-year calculation, I think is really what you have to emphasize, even though in the industry we use these three-year, five-year averages. That's my rant on FTC. But yes, it has been pretty positive, obviously, from that perspective.

And maybe I'll just do a follow-up question on the Flat Lake/Torquay play. Well costs of CAD3.3 million for one miles versus CAD2 million in the Bakken. Do you see an ability, obviously, deeper the play, but do you see an ability to bring those costs down further?

Yes, I think so. We are still -- I think we have only drilled 30 wells there.

30 are on production.

As we get more scale there, and more rigs, and as we have less -- for instance, the difference between Viewfield right now. We drill a well, equip it, it is already tied in, essentially, and it's on stream. Whereas down there, you would have a single well batteried for a period of time, then you convert it over, and then tie it into the battery, and then we're building batteries. For sure, you would see some cost efficiencies there.

And then as we have more rigs running, I think our initial wells in there were with one or two rigs running in the play. And we will probably upwards of five rigs in the play at some point. We will, obviously, push our costs down.

Okay. Perfect. Thank you.

Great, thanks.

Thank you. The next question is from Alan Knowles from Haywood Securities. Please go ahead.

Hello, Scott. On the waterflood, you guys are going to be converting some 80 wells this year. I was wondering, can you tell us the impact that might have on your production through the year? And then also, what that level of activity might look like in 2015?

It is hard to say. We don't really do that kind of math of oh, if we had 80 injectors, it is going to equate to X. We just know we are going to affect -- that incremental, probably adds another 5,000 or 10,000 barrels of affected waterflood volume.

You are going to see the effect of -- we have already been pumping in all of those other wells, so the barrels that are being affected, are still being affected. This is the beauty of the waterflood. It is a cumulative approach. Just every year, you lower your decline on what you have already been injecting on, and then we're expanding it at the same time. So you are getting a double effect.

We would expect a 1% or 2% change, maybe, in decline, on our overall volumes. We have seen, I would say, from what I showed you on our charts, just on the Viewfield alone, our declines have dropped from 30% to 20% in a year. So on 15,000 barrels a day, it is significant.

Our plan is to try to move it to 30,000, over the next couple of years. So 2015, 2016, late into them, we should have almost those units, at least a good chunk of it now waterflooded. To describe that impact, it's tough, but directionally we see it has been pretty strong.

Okay. No, that is good color. Thanks.

Thank you. The last question is from Brian Kristjansen from Dundee Capital Markets. Please go ahead.

Morning, guys. Hi Scott. Wanted to see if you could comment on what, if any, service cost inflation you've seen or expect in 2014?

Oh, I think we've seen things stay pretty steady, is what our guys would say in Saskatchewan. If anything, any offset, increase in service costs, have been reduced by our change in our techniques and the drill times. I think what you have seen, and this is probably common to the last five or six years, is that day rates and inflation of that may have increased.

But because we're not using that equipment as much, we have offset that increase and maintained, or and in this case, lowered our per well costs significantly. So we don't see any big real lift in service rates. In fact, I think in North Dakota and the US, we would say that those would probably come down.

Yes, they're coming down. The one thing with us, certainly, in Saskatchewan, we're the big number one driller and service cost user. So we're good already, just because of economies of scale.

And absolutely, as Scott says, the way to get your costs down is to use less, and that's what our drilling completion groups are really probably the best, also, in the industry at doing that. We are always trying new things, new ideas. With inflation, it is offset by efficiency.

Great. Thanks. And then lastly, maybe for Neil, if you could quantify the capital that is going to be required for the gas plant and the associated infrastructure in Flat Lake?

Yes, sorry, I think it is about CAD30 million, is what we've got on the books. That is going to be between this year and next year. But that is also -- that's just not the plant. That is also the gathering systems into it, sales line, the whole amount.

Great. Thanks.

Thank you.

Thank you. There are no further questions registered at this time. I will turn the meeting back over to Mr. Saxberg.

Great. Well, thank you very much.

And again we're very excited about 2014 and to go forward and that dual approach of growth, and lowering corporate declines, growing at a measured pace, and hitting our numbers. And we've got some pretty exciting plays in the fold that are going to really impact Crescent Point down the road into the future. So, thank you again for participating in our conference call.

Thank you, ladies and gentlemen, for participating in Crescent Point Energy's fourth-quarter and year-end 2013 conference call. If you have more questions, you can call Crescent Point Investor Relations Department at 1-855-767-6923. Thank you. And have a good day.