Good morning, ladies and gentlemen and welcome to the Baytex Energy Corp’s Fourth Quarter and Year End Results Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instruction will follow at that time. [Operator Instructions] as a reminder this conference is being recorded. I would like to turn the conference over to your host Mr. Brian Aster, Senior Vice President, Capital Markets and Public Affairs. Please go ahead.

Thank you, Denise. Good morning ladies and gentlemen and thank you for joining us today to discuss our fourth quarter and year end 2016 financial and operating results. With me today are Jim Bowzer, our Chief Executive Officer; Ed LaFehr, our President; Rod Gray, our Chief Financial Officer; and Rick Ramsay, our Chief Operating Officer. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable security laws. I refer you to our advisory’s regarding forward-looking statements, oil and gas information and non-GAAP financial measures and the notice to US residents contained in today’s press release. On the call today, we will also be discussing the evaluation of our reserves at year end 2016. These evaluations have been prepared in accordance with Canadian disclosure standards which are not comparable in all respects to United States or other foreign disclosure standards. Our remarks regarding reserves are also forward-looking statements. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified and I would now like to turn the call over to Jim.

Thanks, Brian and good morning everyone. I’d like to start by expressing my thanks to Jim Bowzer, that we transitioned the CEO role later this spring. Jim has lead our organization for the past 4.5 years with passion and dedication and as a result I’m inheriting a highly focused team poised to build on our three quarter areas and take on the challenges and opportunities that lie ahead. Through 2016 I had the opportunity to visit all of our field operations from Peace River to Lloydminster and down to the Eagle Ford in Texas. I can tell you our teams are very committed and focused on driving value, over the past two years. The emphasis is been on lowering our cost structure both in Canada and the US, which we continue to relentlessly pursue. I think it’s important to note that as a result of these improved cost efficiencies, our light oil projects in Texas and our heavy oil project in Canada are competitive with top tier plays in North America. I’m extremely pleased to be working with a team that delivers what it sets out to accomplish. In that vein, we generated a solid set of results in the fourth quarter and full year 2016. Production average 69,500 barrels of oil equivalent per day in 2016 with capital expenditures of $225 million both in line with guidance. In addition, we strengthened our financial liquidity, reduced our overall debt and completed a significant transaction in Peace River that we’re very excited about and I’ll update you on this today. All of this has now given us the strength and momentum to take on two key priorities for Baytex in 2017. The first is to arrest [ph] production declines, through a highly efficient capital development program in both the Eagle Ford…

[Operator Instructions] and your first question comes from Mike Dunn with GMP Firstenergy. Your line is open.

Thanks. Good morning folks. A couple of questions if I may. First, just wondering maybe if you can quantify it all. You mentioned the Eagle Ford, the recent wells with the higher intensity completions having large improvements in rates. Can you put a number on that?

Well we said the rates have been increased from 1,100 barrels to oil equivalent per day to about 1,300 so that’s a 20% improvement. But in particular we’re moving the program north preferentially to the Longhorn oil window, so in those cases we’ve roughly doubled the proppant intensity from back you would have seen, when we were in the Longhorn window, a couple of years ago and even last year we were to sand loading about 800 pounds a foot. We’re now sitting at almost 2,000 pounds a foot and also tightening up the stage facing from roughly 300-foot stages down to gallons of 250, 200. So it’s a matter of being in the oil window and increasing proppant and not just overall. The average overall is increased from 1,200 pounds a foot to 2,000 pounds a foot but we’ve also been running some stimulations up in the 2,500 pounds a foot range and higher than that. But we’re getting that 1,300 barrels a day equivalent rate, that’s a good solid rate to hang onto.

Okay and secondly just on the technical revisions for the reserves. Maybe just talk to the heavy oil, I guess the tight [ph] oil and shale gas revisions, if you could?

Yes. Let me start with the heavy oil, keep in mind we haven’t invested in any sort of drilling and not only that no strapped wells for about two plus years. So when there is that live investment and there is no additions clearly, but also it gave us an opportunity to revise some of our mapping and we have revised our mapping, we looked at performance and we got two issues really, the first one is 27 locations have been moved from 2P reserves into 15 of those were moved to contingent and 12 were moved out altogether. So that was in sort of broad area north of Reno. There is secondly a very specific issue that effected about 12 locations, but significantly affected rates in an isolated area of about 3.5 sections north of Reno and that was just simply a reduction of type curves in an area where we had a blocked [indiscernible], but it’s a very small number of sections and fairly isolated. So this revised mapping I think has improved our view of also acquiring Murphy acreage as well, so we took that into consideration and have a really good view of the asset at this point in time. On Eagle Ford that tank just keeps getting bigger. We - let me talk about technical revision, we were very aggressive in developing upper Eagle Ford this last year and as we developed the upper Eagle Ford we made some revisions in the lower Eagle Ford, but overall we had it over 60 million barrels of oil equivalent and we took off 36-ish, so we are now sitting in a place where we moved our reserves from 204 million barrels in the Eagle Ford to 2016 over two-year period we’ve grown the reserve base 30%. So overall great new story in Eagle Ford.

Great and maybe, if I can just, so I understand, the lower Eagle Ford reserves saw negative revisions, was that because the upper Eagle Ford because of I guess spacing wise you were sharing some of the resource between the wells?

Right, we very aggressively developed the upper Eagle Ford as I said and so there was a small sampling of wells in the lower Eagle Ford in that area, we call the stack and frac last year, which comes through the middle of the gas condensate window, where we reduced reserves on those wells, but we’re getting far greater numbers increased the upper. But yes, you’re right.

Okay.

Thanks for the questions.

Thanks Ed, that’s all for me.

Your next question comes from Jason Frew with Credit Suisse. Your line is open.

I was just wondered if you could talk a little bit about inflation risk? To what extent you’ve been able to lock down some services in 2017? And how you’re just managing the risk overall of inflation on both sides of the border? Thanks.

Yes, very good question Jason and we’re seeing different things on different sides of the border. But the bottom line is, we’re seeing the lowest well cost we’ve ever seen in the Eagle Ford as well as in our Peace River and Lloyd assets. So let me talk about Canada for just very briefly and then I’ll go with the Eagle Ford, but in Canada we locked in unit cost on rigs, bit cementing, casing and we’re - as I mentioned in the call. We’re seeing 15% lower cost both in the Peace River and in Lloydminster and that’s lower than what we would have shown the market previously. So we’re very excited about that, we believe that will continue. We project deflation where we’re running the business in Canada because we don’t compete with the high pressure pumping, the fracing business in the Deep Basin or down in the light oil in Southern Saskatchewan. So these are largely open hole multi-lateral completions, very simple and it’s all about the drilling. So our drilling supply chain costs are down a lot and we’re generating 15% reductions below quite a stretchy budget number. In Eagle Ford, we mentioned we’re seeing the lowest well cost ever at $4.5 million. So you would have seen the operators talking about sub $4 million and we, in Canada will add in the equipment tie-in and we - that’s about $500,000, $600,000 for us. So we’re sitting at $4.5 million, while the operator is saying sub $4 million on just the D&C component. Now having said that, for the rest of the year we projected some inflation into our budget numbers on just the pressure pumping business, so we’ve actually budgeted $5 million well cost as we’ve shown in some of our IR materials, but we’re seeing cost today realized cost of $4.5 million, we haven’t seen that inflation kick in yet. But we should see it; we should probably see some in the Eagle Ford only later this year. If that helps, Jason.

Yes, that’s very good color. Thank you very much.

Your next question comes from Thomas Matthews with AltaCorp. Your line is open.

I just had a question on Canadian op costs. So I know you shut-in a lot of high op cost at Lloydminster production and then [indiscernible] recently brought it back on. And I know there is a bit of an integration period with integrating some of the new Murphy Oil assets. But I’m just wondering, how much of the increase in op cost carries forward into 2017? Or what kind of normalized Canadian op cost are you guys projecting?

It’s good question, Thomas. Our big priority in Canada is to integrate the Peace River acquisition that we just did. So I think as we’ve published in most of the markets, we acquired $30 barrel asset and we run our, production operations at $8 barrel OpEx plus $4 transportation, so all in its $30 versus $12. We have no intention of continuing a $30 barrel operation, so we’ve already taken steps to reduce without skewing our numbers to answer your question. But that’s what we projected publicly though our internal plans are to dramatically reduce the dollar per barrel on those acquired lands. So you’ll see things like us loading up the production through the 433 facility, we’ve already we have an inventory of 30 to 40 wells that we’re basically replacing rod pumps and going in and fixing completions and we’re already about 20 some wells into that program, so we’re loading up facility there number one. Number two, is we’re looking at everything out there, the centralized labor model, the infrastructure model, chemicals, the polymer flood, there are lots of things that our Chief Operating Officer and his team are looking at to drive that cost down. So you’ll see that come down and you’ll see us drive the operation model more towards the way we operate. So I can’t give your number right now other than what’s already in the guidance or it’s already out there publicly, but we’ll meet those numbers.

Okay, great. And then just on the one well. I know on the Peace River the 600 barrel per day well. Was that a result of drilling into some virgin reservoir? Or was that changing incompletion techniques or the way you’re drilling it? Or the number of laterals? Just if you could shed some light on that one well that would be great.

Well it’s very similar to what we’ve done in the past. It’s 13 laterals, it’s completed much in the same way, but I would say we’ve had two years to rebuild the inventory here and as [indiscernible] part of it’s the negative on the technical revisions that we had earlier in the call. But a lot of it is positive in terms of seeing the best locations even better, so we’ve mapped out a program 2016 that is very attractive it’s going to move around. We’re already on our third well, although we’ve only brought back in production this one well. It’s 20,000 centipoise, so it’s not the best viscosity we’ve seen, it is a Darcy permeability rock. It’s good rock across that whole 13 laterals. Our geosteering is probably the best I’ve seen in my 30-year career in terms of the way, Baytex geosteer’s it’s wells. We have high confidence the additional locations coming in, but this is a top decile well and we’re still sticking to our guidance sort of numbers of 300 and 350 barrels a day would be for an IP30 that would be a standard type curve. But this is a fantastic well and it’ll probably show off on the Alberta [indiscernible] report sometime, so keep your eyes tuned.

Perfect that’s it for me thanks.

Okay, there are no further questions at this time. I’d turn the call back over to Mr. Aster.

That’s great. Thank you Denise. Thanks everyone for participating in our year end conference call. Have a great day.