Nov 5, 2015
Executives
Scott Saxberg – President, Chief Executive Officer and Director Neil Smith – Chief Operating Officer Greg Tisdale – Chief Financial Officer
Analysts
Pavan Hoskote – Goldman Sachs Kyle Preston – National Bank Financial Patrick Bryden – Scotiabank Travis Wood – TD Securities
Operator
Good morning, ladies and gentlemen. My name is Dona and I will be your conference operator today.
At this time, I would like to welcome everyone to Crescent Point Energy’s Third Quarter 2015 Conference Call. All lines have been placed on mute to prevent any background noise.
After the speakers’ remarks, there will be a Question-and-answer session for members of the investment community. [Operator Instructions].
Thank you. This conference call is being recorded today and will also be webcast on Crescent Point’s Web site, but may not be recorded or rebroadcast without the express consent of Crescent Point Energy.
All amounts discussed today are in Canadian dollars unless otherwise stated. A complete financial statement and management’s discussion and analysis for the period ending September 30, 2015 were announced this morning and are available on Crescent Point’s website at www.crescentpointenergy.com and on the SEDAR and EDGAR websites.
During the call, management may make projections or other forward-looking statements regarding future events or future financial performance. Actual performance, events or results may differ materially.
Additional information or factors that could affect Crescent Point’s operations or financial results are included in Crescent Point’s most recent annual information form, which may be accessed through Crescent Point’s website, the SEDAR website, the EDGAR website or by contacting Crescent Point Energy. Management also calls your attention to the forward-looking information and non-GAAP measures sections of the press release issued earlier today.
I would like to turn the call over to Mr. Scott Saxberg, President and Chief Executive Officer.
Please go ahead, Mr. Saxberg.
Scott Saxberg
Thank you, operator. I’d like to welcome everybody to our third quarter conference call for 2015.
With me is Greg Tisdale, Chief Financial Officer; Ken Lamont, Vice President of Finance and Treasurer; Neil Smith, Chief Operating Officer; and Trent Stangl, Vice President of Marketing and Investor Relations. Before we review the quarter, I’d like to take a minute to personally thank Greg for his strong financial leadership during the last 12 years.
Greg will be stepping down as Crescent Point’s Chief Financial Officer in March 2016 after our fourth quarter results are released. Greg will be replaced by Ken our Vice President of Finance and Treasure, Ken has worked alongside Greg for the past 10 years and in order to be a seamless transition given the strength of our team.
Thank you again Greg for all your hard work. Operationally we delivered a strong quarter with record production, continued per share growth supported by our top quarter in FX.
We continue to advance our long and short-term goals each of our core areas through step-out drilling, waterflood expansion and advances in technology. We did this well maintaining a strong financial position over $1.4 billion of unutilized credit capacity.
Throughout 2015 we focused on driving down our cost structure to reflect the permit low oil price environment. Based on our efforts we’ve reduced capital costs by approximately 30% relative to 2014.
We achieved this to a combination of capital savings and long-term operational efficiencies. These savings are important as they provide us with significant flexibility in managing our business.
We are currently focused on executing our October to March capital – and we are considering spending additional capital in Q4 to lock in the cost savings achieved to-date. This will positioned us to live within cash flow while setting this up to add additional capital ledges in the second half of 2016 should oil prices recover or reduce spending if prices stay low.
We planned to formally announce our 2016 budget in late fourth quarter or early January of 2016. During third quarter we continue to advance our waterflood programs to additional conversions of produced wells to water injection wells.
Results from our waterfloods continue to reduce decline rates and improve overall recoveries. Of note all of Crescent Point’s Canadian unconventional oil plays are affected by waterfloods, are scheduled to have pilot waterflood in place by 2016.
I would also like to highlight a significant environmental achievement for our provinces of Saskatchewan and the company. During the quarter, we eliminated fresh water use in the completion process of approximately 50% of new wells in our Shaunavon play.
Our goals eliminate fresh water usage in all of our Viewfield and Shaunavon completions by the end of 2016, we think this is technically achievable. I’ll now turn it over to Neil, who will discuss our operational highlights in more detail, Neil.
Neil Smith
Okay, great, thanks Scott. Our production of approximately 173,000 BOEs a day for the quarter was a record and it reflects the quality of our world class asset base.
Drilled a total of 153 net wells with a 100% success during the quarter, we are active in each of our core plays including our low risk, high returns conventional assets in Saskatchewan which are grown considerably over the last two years. We also advanced each of our emerging multi zone resource brought in place in the quarter.
We had encouraging results from two new horizontal wells in the Uinta Basin testing both the Castle Peak and Black Shale zones. And flatly three new step-out wells continue to expand the core area and our new Midale play is exceeding our expectations.
As Scott mentioned, our waterflood program continues to expand, while showing positive results across the board. Over 50,000 barrels a day of oils currently supported by waterflood, which continues to expand allowing for further improvements to our decline rate.
Within our ViewField Bakken play direct offset wells are showing significant improvements in estimated ultimate recoveries. On average these wells demonstrate ultimate recoveries that are three times greater than the average infill wells.
The Shaunavon waterflood which is the earlier stage waterflood is showing similar encouraging results. We are currently piloting new waterfloods in the Swan Hills Beaverhill Lake resource play as well as the unconventional Midale play.
We also planned to initiate additional pilots in the Uinta Basin and Saskatchewan Viking plays in 2016. I would also again like to thank our field staff for their hard work as especially as we start going into the Canadian winter period as well.
So I’d now like to hand things off to Greg to discuss our financial results.
Greg Tisdale
Great. Thanks Neil.
In the third quarter, we continue to grow generating production per share improvement of 4% compared to 2014. We reported capital per share of $0.96 which is supported by our strong net backs of $34.50 per BOE.
This resulted a payout ratio in the third quarter of 45% or 31% adjusting for our full quarter of the companies recently revised dividends. During the third quarter reported net loss of $201.4 million due to an after-tax non cash impairment charge of $374 million.
This impairment represents approximately 3% of our total assets as at September 30, 2015, reflecting the high-quality nature of the Company’s asset base. This impairment results from lower than forecasted commodity prices as of September 30, 2015 and had no impact the funds flow from operations or the non available under our credit facilities.
As of September 30 the company’s credit facility had unutilized credit capacity of approximately $1.4 billion with no material near term debt matures. We do not expect any change in our – to our covenant-based credit facility which is scheduled to mature in June of 2018.
We continue to remain diligent in our hedging program and bolster additional hedges as forward prices – price levels warrant. Currently we have approximately 53% of our oil production hedge for the remainder of 2015 and 33% hedge in 2016 at attractive prices.
We also have additional hedges which extended to 2017 and 2018 that can be brought forward to provide additional cash flow and balance sheet protection. I’ll now hand things back over to Scott for some closing remarks.
Scott Saxberg
Thanks Greg. We are pleased with the third quarter results and remain on track to exit the year in a strong position.
We are committed to our goal of internally funding our business which includes value creating opportunity such as acquisitions. At this time our acquisition strategy is focused on smaller size tuck-in type opportunities that we would be funded internally with cash flow.
We remain prudent in the current environment with the focus on our balance sheet, per share growth and long-term value creation. Before I open up to questions, I would like to thank all of our employees including our field staff, Executive Team, Board of Directors for their hard work in 2015.
At this point we are ready to answer questions and I turn it back to the operator.
Operator
Thank you. [Operator Instructions].
And your first question comes from Pavan Hoskote from Goldman Sachs. Your line is now open.
Pavan Hoskote
Thank you, good morning everyone.
Scott Saxberg
Good morning.
Pavan Hoskote
So, my first question is on waterfloods, based on the success you’ve seen with this program what do you think is the current basic run rate for the company and then the related question to that would be what are the good estimate for maintenance CapEx for Crescent Point in 2016?
Scott Saxberg
Yes, great question Pavan. We are right now I think by June [ph] around 28% to 30% decline rate and typically going into 2016 we conservatively bump that up to probably 31% or something like that to be conservative on our forward – forecast.
So, I think that’s – you are seeing the reflection I think over the last three or four years, as we have grown the company from 100,000 barrels a day to 172,000 barrels a day and increased our waterfloods from 2,000 barrels a day to now of course to 30,000 barrels a day combined with our Shaunavon and all of our other field. So we’re slowly mitigating that and then with the pull back of our capital program from last year to this year with the drop in commodity prices you’re also seeing an effect of lower declines from that.
And so depending on how much spare capital we spend next year will equate to whatever that decline rate heads up to depend on how much capital we spend. On the base line, I think if you look in our corporate presentation that’s $40 WTI pricing where we use a $1 billion of capital.
I would say that would be our base production level that keeps us flat. That number depends really on where we want to allocate and if we wanted to look at it from a just a short-term one year perspective we could probably do better than that, but when we look at and this is the challenge I think for next year and how we’re looking at our budget for next year is we want to take care of short-term, medium-term and long-term projects.
So I’d rather have a slightly higher capital efficiency number and take care of longer-term projects in holding land, drilling step-out wells, drilling horizontal test in Uinta and look to grow the long-term as well as concerns about short-term financial metrics and staying within cash flow and outbuilding debt. So those are the two sort of pieces that we’re looking at.
And that’s swing about a $100 million plus or minus kind of a number I think in our budgeting when you look at keeping those projects in the step-out drilling. And so when you look at this year in we spent for those kind of projects that six or seven wells we drilled in the winter horizontal tests those are pure exploration same with Flat Lake, some in Manitoba we drilled exploration wells and then all the injector conversions.
And then over line all that on top of that we’ve tested as you hear on salt water versus fresh water on our fracs, different fluids and sand concentrations and all of our fracs and all of our different programs all that kind of stuff probably adds up to $100 million to $150 million of excess capital that we could, if we wanted to just hunker and drill over by top, but that’s not how we plan to run our company. We want to look at it from a short, medium and long-term perspective company.
Hopefully that answers the question for you having on how we look at allocation of capital and that sensitivity around sustainable capital or not. Sustainable to less than over the long-term and the value growth of our company, not just a one year metric.
Pavan Hoskote
Great, thanks a lot for that very thoughtful response Scott. My follow-up is on the Uinta Basin, it looks like differentials in the basin that’s come in recently.
Can you talk at a very broad level production strength in the basin as well as do that capacity in terms of refining as well as excellent capacity. Really trying to get, what I’m trying to get is should we expect a further narrowing in the Uinta Basin differential going forward?
Scott Saxberg
Yes for sure, we’ve production there in the Uinta Basin drop off dramatically with above pullback in capital. In the past it’s around 18% differential and now we are seeing some of the markets in the 10% to 15% range, depending on the type of [Indiscernible] include that you’re selling.
So in some cases we’ve seen a slowest [indiscernible] and we think as time marches on and that basin opens up in some of the refining capacity yet to on-stream, so there is a dual effect of production becoming off in that basin and the refiners are expanding their capacity in Flat Lake, so we’ll see a narrowing of differentials, I think over the long-term, as long as capital allocation for that basin drops.
Pavan Hoskote
Great, if that does happen would – at what price point would you consider adding more capital to the Uinta Basin versus some of your other basins in Canada?
Scott Saxberg
Wells that’s – it’s a good question, we just added 9 locations 2Q for and so we are actually in the middle of that drilling program right now because of the narrowing of differentials and so any incremental production that we are bringing on there, we’ll hopefully get that narrower differentials if things saves and then so the economics in the Uinta when we apply now our 3D program or 3D that we have there to high-grade to the best locations from that 3D, so targeting Douglas Creek and some of the more prolific sense and the fact with the narrower differentials and then this 40% or 30% 40% drop in cost that we’ve seen there with that area, we’ve seen the lowest cost or the greatest cost reductions. So with all of those combinations, we’ve jumped on that and added another rig and 9 well program for the end of this year.
Pavan Hoskote
Great, thanks a lot.
Scott Saxberg
Great, thanks.
Operator
Thank you. Your next question comes from Kyle Preston from National Bank Financial.
Your line is now open.
Kyle Preston
Yes, thanks. May be a question for Scott or Neil, just wondering if you guys can expand on your reference to the ViewField offsetting wells three times increase in the recovery rate there relative to previous in-fills.
Just may be describe what’s change there and also does that include the impact from the reserves you loose from converting well to an injector?
Scott Saxberg
Yes, so if you look in our slide presentation. Slide number 15, shows you a graph of the average well in the field with like 100,000 barrels sort of EUR and when you apply waterflood and you look at the direct offset production which is the blue line on that curve, the higher curve, it’s actually increasing our flat production and it equates to about a 150 offset wells.
We see reserves of over 350,000 barrels on those wells. And so when we look at it and beside that there is a table that really looks at the holistic view on a per section basis, so we drill eight wells per section on primary get 19% recovery when we add in the waterflood, we feel we’ll get 30% to 40% recovery.
So on a overall net-net basis, our overall F&D drops dramatically into the single-digit per barrel range for all in including land cost and so full cycle economics were single-digit F&D per section and that’s what the waterflood brings and it bring us a sustainable low decline production for a long, long period of time and I’ll pass it to Neil here to have some on…
Neil Smith
Sure and I think the bigger picture what we’re trying to communicate here Kyle, a lot of the analyst particularly in the U.S. Bakken are making remarks of the quality of the U.S.
North Dakota infill versus the primary and really what we’re trying to demonstrate is trying to get away from that mindset, it’s going to get to the point when we have field wide waterflood, it doesn’t matter whether it’s a primary spacing or an infill spacing, it’s about how the water has been pushed to whichever well is producing. There is no doubt with the advances of our cemented line or techniques that the quality of our infills actually exceeds the recoverable factor under primary of what some of our initial primary wells did, but we’re now into the next point, it’s a waterflood analysis, it’s not whether it’s a primary or an infill, it just so happens what we’re showing is the wells particularly that about 200 meters offset to the injector wells.
They come off similarly in decline in the early six, eight months, but then it’s flattening. [Indiscernible] as the piston of the water pushes that oil towards us.
So this really isn’t a discussion long-term about primary or infill, it’s about waterflood.
Scott Saxberg
Yes, it completely – it’s a completely different view and perspective in long-term reserve that relative to a primary infill drilling scenario and so that’s what is sort of really highlights in this play that we’re going to get higher recoveries than any field in the U.S. under primary because we’re now secondary waterflooding and I think that’s for small dollars or low cost because as we go from four well infill to eight well to waterflood our dollar per barrel F&D cost were dropping dramatically because we don’t have to put as much capital into get those reserves or production.
Now on our financial basis, when we look at our one year plan, five year plan, we don’t allocate any incremental reserves or productions gains from the waterflood in any of those financial scenarios, so in our one year plan or budget we forecast based on the primary depletion of decline bases on the wells we drill and then on a five year plan similarly we budget based on a primary only, so we’re not taking into account that big dramatic increase and reduction and decline over the life of the asset on a financial basis when we put out those numbers.
Kyle Preston
Okay, great, thanks for that answer. I’m just wondering how repeatable do you think this performance is in some of the other play that you’re integrating the waterflood?
Scott Saxberg
Well, we’ve got, now Shaunavon has been wateflooded for five or six years now and because that field had the newer technology from the start and it’s the secured reservoir, we’re actually seeing as good or better response than we were on the – in the ViewField areas, so we’re pretty excited about that, that also is good for the upper Shaunavon and then we’ve started to pilot, we’ll be starting to pilot in Flat Lake, there is small pilot for a group of injectors in the Torquay play and Bakken and the Midale trend in the legacy acquisition we took on. And then we’ve also now got a year or two of history on the Swan Hills and we’re spending that waterflood and then we’re going to start, the Flat Lake is one of the really key waterflood for us because it opens up the information in data for North Dakota and so we have four, five townships of North Dakota depth style rock in the Torquay on Bakken that we’re now going to waterflood and test and we’ll have history on that well before guys in North Dakota do and that will allow us to apply it down to North Dakota.
And we’ve actually kick started our guys to look at the process of waterflooding and the regulatory side of it in North Dakota from that angle, so basically all of our plays across our company are being some stage of waterflooding or starting up a waterflood.
Kyle Preston
Okay, great. Thanks a lot.
Scott Saxberg
Thanks.
Operator
Thank you. Your next question comes from Patrick Bryden from Scotiabank.
Your line is now open.
Patrick Bryden
Good morning everyone. Just wondering if you might be able to elaborate a little bit further on some of the horizontal initiatives we are seeing in the Uinta, obviously you are letting to deploy more capital there, you got 3-D, you’ve got a physical model coming together.
I’m just curious what you are seeing and what you are excited about there?
Scott Saxberg
Yes, thanks Pat, great question. We went into this year with a big learning curve to learn – just how to drill those wells in the different zones and horizons there.
And then we try to refine on that, we lowered our drilling times on the subsequent wells, we are pretty excited about the results we’ve seen there, it’s early days, regulatory wise in Utah they are not used to horizontal drilling as of yet. And so, a lot of the regulatory side is still, we are still irony note on that end it’s same with the New Field and some of the operatives in the area.
And then just we have tested six different zones and so, we want to give those wells time to produce and get build that tight curve so then we can look where to drill next. And so, I would anticipate that we’ll be drilling wells most likely on the second half of 2016 depending on commodity prices and those results of those wells.
We’ve had some pretty good exciting results that turning into economics in our favor on horizontal drilling and we are now mapping and building the resource base and size of the different zones that we are chasing and then combine with our 3-D, the licensing process and all that kind of building that up for targeting to second half of 2016 so that by 2017 and 2018 we have more of the steady horizontal program similar to other areas.
Patrick Bryden
Great, appreciate that. And then I wonder if you can maybe just provide me a little bit more color along those lines with Flat Lake, I mean obviously it’s a big area and I guess even if you look at it in combination with Midale, what are you testing, what are you seeing in terms of encouragement there as you step out and play the concepts?
Scott Saxberg
Yes, that’s a – it turned into a very big area and we are – we’ve been surprised, I think got a positive on some of the results we had on the step-out locations and we are – went to a different fluid and different frack technique and that’s really improved the results out there. And so, we are going to follow up obviously this year in the quarter on some additional step-out drilling there.
And then really to focus that does have our guys on is science in the waterflood in depth and so we’re going to shut wells in there, take pressures, look at rock properties and studies and simulated and do all the proper long-term works that’s need to be done that will set us up for that data into North Dakota. And I think that’s really a key driver on value for us in the long-term on that play.
And then equivalently in the Midale that’s a very exciting play and getting water in the ground there is key to us and adding more injectors. We’ve seen some strong results there with the change in completion technique from taking it over from legacy.
And so we’re excited about that as well.
Patrick Bryden
Great. And if I can ask and you can big offer this, but because I appreciate this might be more in the proprietary side, but are you comfortable elaborating a little bit on what you’re playing around with in terms of fluids and problems in completion techniques and I guess how that interrelates long-term to the sliding sleeve technology.
Scott Saxberg
There is some new interesting fluids that we’re testing that kind of change the mindset of how some of these zones and areas that we thought may be more fracked probably and more frac probably. And so that’s kind of the testing that we’re doing where we went in and drilled in area used a relatively new completion technique, but didn’t see the results that we expected based on the primary production in the oil caps.
And so some of these fluids that really changed the mindset of us, and there is potential areas we think will expand pools and value because of that completion technique. And so that’s a big key to us for obviously proprietary on what we’re doing there.
And again what are the key things that I was highlighted that just going from fresh water to salt water on our completions and ability to do that and being in this industry and for us we just sort of take a lot of those things for granted, but I think when you look at it from the environmentalist perspective in the outside people not involved in the industry, it’s a huge dramatic shift and takes away any kind of negatively around the fracking and our completions in these areas, and that’s a real highlight I think the problem for Saskatchewan and for these plays for us to be able to do that and use that technology. And so we’re excited about that side of it.
Patrick Bryden
Great. Thank you.
Appreciate your time.
Scott Saxberg
Thank you.
Operator
Thank you. [Operator Instructions] And your next question comes from Travis Wood from TD Securities.
Your line is now open.
Travis Wood
Yes, good morning everybody. Just extending on some of the questions that have already been answered, focus that Flat Lake and Midale specifically.
What time as we look forward call it one, two or three years, what you see as the largest hurdles in terms of getting this project for is play, to start to have compete head-to-head with your core ViewField infill well and what do you see in terms of infrastructure expansion over the next couple of years to get the product to market?
Scott Saxberg
Yes, so in Flat Lake we’ve just commissioned our gas plant out there, so that’s a key milestone I think for us getting that gas plant on and conserving the gas in that area, I think right now the economics in that play in Flat Lake compete with our infill in ViewField and it compete – and the Midale definitely competes at that level and so we’ve added hundreds of locations in the Flat Lake in Midale area through our step-out drilling and infill drilling and testing that, I think some of the challenges we have is with the Bakken and Torquay play and understanding whether there is communication between those two zones or not. The waterflood and how effective the waterflood will be between the Torquay and the Bakken and the Midale in that area and so we are very early days in both of those plays relative to ViewField, ViewField were only about halfway through the life of that play not even [Indiscernible] way through the life of that play, here we are 15% through the life of this play and still expanding the play.
So it’s a very exciting play for us, it’s billion of barrels of oil in place compared when you add in the Torquay, Bakken, Midale and [Indiscernible] zones in these areas and so we are pretty excited about this southern Saskatchewan play and the expansion of it.
Travis Wood
And knowing what you know right now, do you think that this will be a bit easier to go ahead for unitization if waterflood looks like it’s going to be the best commercial sense for this region will be easier to unitize this region rather than some parts of the ViewField, greater ViewField area?
Scott Saxberg
Yes, that’s a great question because, highlight because that whole southern area is all crown land. So we actually don’t have to unitize it, we can just add injectors whenever we want.
So that’s a key differentiation between ViewField where it’s 60% Crown, 40% fee title and that unitization took us two or three years. That’s the challenge in North Dakota and anywhere in the U.S., these all the fee title owners and the time around building units down there to get waterflooding and that’s why we kick started our North Dakota guys to look at the regulatory side, look at the unitization, get that process underway on our lands that are down there and because that’s going to take several years to put in place and implement.
And so that’s why Flat Lake is a real key to us because it’s all Crown Land and we could add a kind of injectors there over its lifetime without much of an application. So similarly in Shaunavon in the same way, we actually don’t have to unitize any other lands there as well.
And so that’s why the Shaunavon is progressing more rapid than Viewfield because of the Crown versus fee title.
Travis Wood
Okay. Thanks for the time.
Scott Saxberg
Great. Thanks Travis.
Operator
Thank you. There are no further questions registered at this time.
I’d like to turn the meeting back over to Mr. Saxberg.
Scott Saxberg
Great. Thank you very much and again we had another great quarter record production, we’re in a strong position and flexibility to manage through this commodity price environment and we’re excited to finish off 2015 and prepare for 2016.
Thank you very much.
Operator
Thank you ladies and gentlemen for participating in Crescent Point Energy’s third quarter 2015 conference call. If you have more questions you can contact Crescent Point Investor Relations department at 1855-767-6923.
Thank you. Have a good day.