Veren Inc (CPG) 2015 Q3 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 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). This conference call is being recorded today and will also be webcast on Crescent Point's website, but may not be recorded or rebroadcast without the expressed consent of Crescent Point Energy.

All amounts discussed today are in Canadian dollars unless otherwise stated. The complete financial statements and management's discussion and analysis for the period ending September 30, 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 now like to turn the call over to Mr. Scott Saxberg, President and Chief Operating Officer. Please go ahead, Mr. 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 LaMonte, Vice President, 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, Finance and Treasurer. Ken has worked alongside Greg for the past 10 years and I know this will 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-quartile netbacks. We continued to advance our long and short-term goals in each of our core areas through step-out drilling, waterflood expansion, and advances in technology. We did this while maintaining a strong financial position, over CAD1.4 billion of unutilized credit capacity.

Throughout 2015, we focused on driving down our cost structure to reflect the current low oil price environment. Based on our efforts, we've reduced capital cost by approximately 30% relative to 2014. We achieved this through 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 program, and we are considering spending additional capital in Q4 to lock in the cost savings achieved to date. This will position us to live within cash flow while setting us up to add additional capital wedges in the second half of 2016, should oil prices recover, or reduce spending if prices stay low. We plan to formally announce our 2016 budget in late fourth quarter or early January of 2016.

During third quarter, we continued to advance our waterflood programs through 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 or are scheduled to have pilot waterfloods in place by 2016.

I would also like to highlight a significant environmental achievement for the province of Saskatchewan and the Company. During the quarter we eliminated freshwater use in the completion process of approximately 50% of new wells in our Shaunavon play. Our goal is to eliminate freshwater usage in all of our Viewfield and Shaunavon completions by the end of 2016. We think this is technically achievable.

I will now turn it over to Neil, who will discuss our operational highlights in more detail. Neil?

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. We drilled a total of 153 net wells with 100% success during the quarter. We are active in each of our core plays, including our low-risk, high-return conventional assets in Saskatchewan, which have grown considerably over the last two years. We also advanced each of our emerging multizone resource growth plays 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. In Flat Lake, 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 oil is 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 well. The Shaunavon waterflood, which is in 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 plan to initiate additional pilots in the Uinta Basin at Saskatchewan Viking Place in 2016. I'd also again like to thank our field staff for their hard work, especially as we start going into the Canadian winter period as well.

So, now I'd like to hand things off to Greg to discuss our financial results.

Great. Thanks, Neil. In the third quarter we continued to grow, generating production per share improvement of 4% compared to 2014. Reported cash flow per share of CAD0.96, which was supported by our strong netbacks of CAD34.50 per BOE. This resulted in a payout ratio in the third quarter of 45%, or 31% adjusting for a full quarter of the Company's recently revised dividend.

During the third quarter, we reported a net loss of CAD201 million due to an after-tax, non-cash impairment charge of CAD374 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 of funds flow from operations or the amount available under our credit facilities.

As of September 30, the Company's credit facility had unutilized credit capacity of approximately CAD1.4 billion with no material near-term debt maturities. We do not expect any change to our covenant-based credit facility, which is scheduled to mature in June 2018. We continue to remain diligent in our hedging program and bolster additional hedges as forward price levels warrant. Currently we have approximately 53% of our oil production hedged for the remainder of 2015 and 33% hedged in 2016 at attractive prices. We also have additional hedges which extend into 2017 and 2018 that can be brought forward to provide additional cash flow and balance sheet protection.

I will now hand things back over to Scott for some closing remarks.

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 opportunities such as acquisitions. At this time our acquisition strategy is focused on smaller-sized, tuck-in type opportunities that would be funded internally with cash flow. We remain prudent in the current environment with a focus on our balance sheet, per-share growth and long-term value creation.

Before I open it 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'll turn it back to the operator.

(Operator Instructions). Pavan Hoskote, Goldman Sachs.

My first question is on waterfloods. Based on the success you've seen with this program, what do you think is the current base decline rate for the Company? And then the related question to that would be, what is a good estimate for maintenance CapEx for Crescent Point in 2016?

Yes, great question, Pavan. We are right now, I think, budgeting 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 forecasts. So I think that's -- you are seeing the reflection, I think, over the last three or four years as we've grown the Company from 100,000 barrels a day to 172,000 barrels a day, and increased their waterfloods from 2,000 barrels a day to now close to 30,000 barrels a day, combined with our Shaunavon and in all of our other fields.

So we are slowly mitigating that. And then with the pullback of our capital programs from last year to this year with the drop in commodity prices, you are also seen an effect of lower declines from that. And so, depending on how much capital we spend next year will equate to whatever that decline rate heads up to, depending on how much capital we spend.

On the baseline, I think if you look in our corporate presentation at $40 WTI pricing, where we use CADS1 billion-ish 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 want to look at it from 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 would rather have a slightly higher capital efficiency number and take care of longer-term projects in holding land, drilling step-out wells, drilling horizontal tests in Uinta, and look to grow the long term as well as concerns about short-term financial metrics and statements and cash flow and not building that. So those are the two pieces that we are looking at.

And that swing is about a CAD100 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 what we spent for those kind of projects, the six or seven wells we drilled in the Uinta horizontal test, 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 saltwater versus freshwater, on our fracks, different fluids and sand concentrations in all of our fracks in all of our different programs. All of that kind of stuff probably as up to CAD100 million to CAD 150 million of excess capital that we could, if we wanted to, just hunker in and drill all of our best stuff. 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 (technical difficulty).

So hopefully that answers the question for you, Pavan, on how we look at allocation of capital and that sensitivity around sustainable capital or not. Sustainable to us is over the long-term and the value growth of our Company, not just a one-year metric.

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 have come in recently. Can you talk at a very broad level production trends in the basin, as well as the spare capacity in terms of refining as well as export capacity? Really, what I'm trying to get at is should we expect a further narrowing in the Uinta Basin differential going forward?

Yes, for sure. We've seen production there in the entire basin drop off dramatically with a pullback in capital. In the past it was around 18%-ish differential. And now we are seeing some of the markets in the 10% to 15% range, depending on the types of (technical difficulty) crude that you are selling. So, in some cases we've seen as low as 10%. And we think, as time marches on and that basin opens up and some of the refining capacity gets on stream, so there's a dual effect of production is coming off in that basin and the refiners are expanding their capacity in Salt Lake. So we will see a narrowing of differentials, I think, over the long-term as long as capital allocation for that basin drops.

Great. And if that does happen, at what price point would you consider adding more capital to the Uinta Basin versus some of your other basins in Canada?

Well, it's a good question because we just added nine locations to Q4. So we're 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 will hopefully get that narrower differentials if things stay the same. So, the economics in the Uinta, when we apply now our 3D program that 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 sands, and the fact with the narrower differentials. And then the 30%, 40% drop in costs that we've seen there. That area we've seen the lowest cost -- or the greatest cost reductions. So with all those combinations, we jumped on that and added another rig and a nine-well program for the end of this year.

Great, thanks a lot.

Kyle Preston from National Bank Financial.

Maybe 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 infills. Just maybe describe what's changed there, and also does that include the impact from the reserves you lose from converting a well to an injector?

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, a 100,000 barrel EUR. And when you apply the waterflood and you look at the direct offset production, which is the blue line on that curve, the higher curve, it's actually increasing or flat reduction. And it equates to about 150 offset wells. We see reserves of over 350,000 barrels on those wells. When we look at it and decide if there's 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 will get 30% to 40% recovery. So, on an overall net-net basis, our overall F&D drops dramatically, into the single-digit per barrel range for all in, including land costs. And so, full-cycle economics, we are single-digit F&D per section. And that's what the waterflood brings. And it brings that sustainable, low-decline production for a long, long period of time. And I'll pass it to Neil here to add some more color.

Sure. I think the bigger picture, what we are trying to communicate here, Kyle, a lot of the analysts, particularly in the US Bakken, are making remarks of the quality of the US North Dakota infill versus their 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 is being pushed to which ever well is producing.

There's no doubt with the advances of our cemented liner 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 are 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 are showing is the wells, particularly that about 200 meters offset to the injector wells, they come off similarly in decline in the early 6, 8 months, but then it's flattening right out as the piston of the water pushes out oil towards us. So, this really isn't a discussion long-term about primary or infill. It's about waterflood.

Yes, and it just -- it's a completely different view and perspective in long-term reserve add relative to a primary infill drilling scenario. And so that's what this really highlights in this play, that we are going to get higher recoveries than any field in the US under primary because we are now secondary waterflooding. And I think that's -- and 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 costs are dropping dramatically because we don't have to put as much capital in to get those reserves or production.

Now, on a financial basis, when we look at our one-year plan, five-year plan, we don't allocate any incremental reserves or production gains from the waterflood in any of those financial scenarios. So in our one-year plan or budget we forecast based on a primary depletion or decline basis 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 in decline over the life of the asset on a financial basis when we put out those numbers.

Okay. No, great. Thanks for that answer. And just wondering how repeatable do you think this performance is in some of the other plays that you are integrating the waterflood?

Well, we've got now -- Shaunavon has been waterflooded for five or six years now. And because that field had the newer technology from the start and it's a thicker reservoir, we are actually seeing as good or better response than we were in the Viewfield areas. So we are pretty excited about that. That also is good for the UPPER Shaunavon. And then we've started a pilot -- or we will be starting a pilot in Flat Lake. There's a small pilot for a group of injectors in the Torquay and the -- or the Bakken and that 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 are expanding that waterflood.

And then we are going to start -- the Flat Lake one is a really key waterflood for us because it opens up the information and data for North Dakota. And so we have four or five townships of North Dakota depth style rock in the Torquay and Bakken that we are not going to waterflood and test. And we will have history on that well before guys in North Dakota do. And that will allow us to apply it down into North Dakota. And we've actually kick started our guys to look at the process of water flooding and the regulatory side of it in North Dakota, from that angle. So, basically, all of our plays across our Company are being at some stage of waterflooding or starting of a waterflood.

Okay, great. Thanks a lot.

(Operator Instructions) Patrick Bryden, Scotiabank.

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 looking to deploy more capital there. You've got 3D, you've got a petrophysical model coming together. Just curious what you are seeing at what you are excited about there.

Yes. Thanks, Pat. Great question. We went into this year with a big learning curve to learn, A, just how to drill those wells in the different zones and horizons there, and then 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 ironing out on that end. And same with Newfield and some of the operators in the area.

And then we've tested six different zones. And so we want to give those wells time to produce and get -- build that type curve so then we can look at where to drill next. I would anticipate that we will 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 turned the 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, combined with our 3D, the licensing process and all that, building that up for targeting the second half of 2016. So that by 2017 and 2018 we have more of a steady horizontal program similar to our other areas.

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. Obviously, it's a big area. And 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 with concepts?

Yes, that's a -- it is turned into a very big area. And we have been surprised, I think, to the positive on some of the results we've had on the step-out locations. And we went to a different fluid and a different frac technique, and that has really improved the results out there. We are going to follow up, obviously, this year in the quarter on some additional step-out drilling there. And then really the focus that I have our guys on is sciencing the waterflood in depth. We're going to shut wells in there, take pressures, look at rock properties and studies and simulate it and do all the proper long-term work that needs to be done that will set us up for that data into North Dakota.

And I think that's really a key driver of value for us in the long-term, on that play. And then, equivalently in the Midale, that's a very exciting play. 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. We're excited about that as well.

Great. And if I can ask -- and you can beg off of this, but -- because I appreciate this might be more on the proprietary side. But are you comfortable elaborating a little bit on what you are playing around with in terms of fluids and proppants and completion techniques? And how that interrelates long term to the sliding sleeve technology?

Yes. There is some new, interesting fluids that we are testing that change the mindset of how some of these zones and areas that we thought maybe were fracked properly that weren't fracked properly. That's the testing that we are doing, where we went in and drilled an area, used a relatively new completion technique but didn't see the results that we expected based on the primary production in the oil [cups]. So some of these fluids have really changed the mindset of that. And there is potential areas we think will expand pools and value because of that completion technique. So that's a big key to us; obviously proprietary on what we're doing there.

Again, one of the key things that I was highlighted is just going from freshwater to saltwater on our completions and the ability to do that. And being in this industry, and for us we just take a lot of those things for granted. But I think when you look at it from the environmentalists' perspective on the outside, people not involved in the industry, it's a huge, dramatic shift and takes away any kind of negativity around the fracking and our completions in these areas. And that's a real highlight, I think, for the province of Saskatchewan and for these plays for us to be able to do that and use that technology. And so we are excited about that side of it.

Great, thank you. Appreciate your time.

(Operator Instructions). Travis Wood, TD Securities.

Just extending on some of the questions that have already been answered, focused at Flat Lake and Midale specifically. What -- as we look forward call it one, two or three years -- what do you see as the largest hurdles in terms of getting this project or this play to start to compete head to head with your core Viewfield infill wells? And then what do you see in terms of infrastructure expansion over the next couple of years to get the product to market?

Yes. So in Flatlake we 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. Right now the economics of that play in Flatlake compete with our infill in Viewfield and it competes 00 and the Midale definitely competes at that level. So we have added hundreds of locations in the Flatlake in Midale area through our step-out drilling and infield drilling and testing that.

I think some of the challenges we have is with the Bakken and Torquay and understanding whether there's 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. We are very early days in both those plays relative to Viewfield. Viewfield, we're only about halfway through the life of that play; not even. About a third of the way through the life of that play. Here we're 15% through the life of this play and still expanding the play.

So it's a very exciting play for us. It's billions of barrels of oil in place compare -- when you add in the Torquay, Bakken, Midale and Ratcliff zones in these areas. So we are pretty excited about this southern Saskatchewan play and the expansion of it.

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 it be easier to unitize this region rather than some parts of the Viewfield, greater Viewfield area?

Yes. No, that's a great question and highlight, because that whole southern area is all Crown land. So we actually don't have to unitize it. We can just add injectors whatever we want. 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 US is all the fee title owners and the time around building units down there to get waterflooding. And that's why we've 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.

Because that's going to take several years to put in place and implement. That's why Flat Lake is a real key to us because it's all Crown land and we could add a ton of injectors there over its lifetime without much of an application. Similarly in Shaunavon, is the same way. We actually don't have to unitize any of the lands there as well. That's why the Shaunavon is progressing more rapidly than Viewfield, because of the Crown versus fee title.

Okay, thanks for the time.

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

Great. Thank you very much. And again, we had another great quarter of record production. We are in a strong position and flexibility to manage through this commodity pricing environment. And we are excited to finish off 2015 and prepare for 2016. Thank you very much.

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's investor relations department at 1-855-767-6923. Thank you. Have a good day.