Good morning, ladies and gentlemen. Welcome to the Baytex Energy Corp. 2015 Year-end Results Conference Call. Please be advised that this call is being recorded. I would now like to turn the meeting over to Mr. Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead, Mr. Ector.

Thank you, Melanie. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our fourth quarter and year-end 2015 financial and operating results. With me today are Jim Bowzer, our President and Chief Executive Officer; 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 securities laws. On the call today, we will also be discussing the evaluation of our reserves at year-end 2015. 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. I refer you to our advisories regarding forward-looking statements, oil and gas information and non-GAAP financial measures and the notice to U.S. residents contained in today's press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. I would now like to turn the call over to Jim.

Thanks, Brian, and good morning, everyone. Today I'm going to discuss our results for the fourth quarter and year-end for 2015 and how we continue to position our company to withstand the low commodity price environment. I will also discuss how we remain focused on prudently managing our operations to maintain strong levels of financial liquidity. I will break my comments into four parts for you today. First, I will talk about our 2015 operating and financial results. Second I'll provide an update on our balance sheet and liquidity. Third, I'm going to discuss our year-end 2015 reserve report. And lastly, I will provide an update on our operational plan for 2016. Our operating results for the fourth quarter and full year 2015 were consistent with our expectations and reflect a reduced pace of drilling activity. Production averaged over 81,000 BOEs per day during the fourth quarter as compared to just over 82,000 BOEs a day for the third quarter. For the full year 2015, production averaged 84,600 BOEs per day in line with guidance. Capital expenditures for exploration and development activities totaled CAD141 million for the fourth quarter and CAD521 million for the full year 2015, in line with our annual guidance. In 2015, we participated in the drilling of 82 net wells with a 99% success rate. And importantly, we realized over CAD150 million in efficiencies in 2015 as we focused on cost reduction initiatives across all of our operations. Our performance in the Eagle Ford was strong during the fourth quarter as we maintained a consistent pace of development, averaging six drilling rigs and two frac crews on our lands. In the Eagle Ford, we produced approximately 40,000 BOEs per day as compared to 39,000 BOEs per day in the third quarter. Significant advancements were made in…

[Operator Instructions] The first question is from Dan Kecskes of Global Credit Advisers. Please go ahead.

Hey, good morning guys. Looking at the language in the release with regards to the revolver, it looks like there are things that you would do if pricing goes lower, how do you feel about convent compliance going into the middle of this year. And if it gets tight, is this something that you’re working on now or have not yet started?

Yes, Dan, just - I’ll let Rod answer any details that we may have here, but just suffice it to say that we have continued through this downturn to work successfully with our banks on the covenant release that we’ve released today and feel that’s sufficient now. And like we mentioned that we do have as in our debenture disclosures the ability to secure part of our facility if we deem necessary in the future.

How long would it take to go from starting those conversations to achieving that if you felt that oil moved to lower in the next month or two?

Yes, it’s really something that I wouldn’t speculate on start to finish conversation on something like that, but our bank syndicate has been supportive and if we need the ability to do that, that’s a potential for the future, but at this stage that’s really all we can comment on.

Perfect. Thank you very much.

Thank you. The following question is from Thomas Matthews of AltaCorp Capital. Please go ahead.

Hey, guys, just a quick question on Eagle Ford well cost, Marathon has come on and said that their well costs have dropped too as well as 5 million per well. Just wondering if you can translate that yours or are you still sticking with that US$6 million number?

No, we brought our cost down essentially in line with the actual data that we have seen to-date, and the AFEs that we are getting today. So relative to - and just for clarity here, we - I believe their numbers that they published do not include the tie-in cost, I may be mistaken if they changed that, but I don’t believe they include the tie-in and artificial lift, so we have a little bit of discrepancy, but our US$6 million that we were quoting we moved down for this year quite substantially to US$5.6 million and we hope to improve on that as the year goes on. But ours do include - our numbers that I just quoted include the full tie-in hook-up and artificial lift everything for the well.

Right, okay. Makes sense. And then just as far as the technical revisions going, your reserve report seems like you had very positive technical revisions down there. Are your EUR assumptions also changed internally here or is it still that the 800,000 per well?

They are still coming in on about that range. We got now four, five different areas, and four, five different levels of formation that we are drilling within the entire Eagle Ford window. So there is a range in that, but that’s kind of a decent midpoint. It’s a little early, the IP has continued to improve as they did from 2014 to 2015. Of course, it’s just here in the first quarter in 2016, but hopefully we will see another round of improvements this year.

Okay. And then just finally, so 30 wells brought on, some of those are in backlog. How many new wells do you anticipate drilling this year?

It’s about 30.

Oh, it is 30. So it’s 30 - kind of 30 for 30, so it’s not -

Yes, approximately. That’s about right, Thomas.

Okay. Sounds good. That’s all I had. Thanks.

Thank you.

Thank you. The following question is from Sean Sneeden of Oppenheimer. Please go ahead.

Hi, thank you for taking the question. Can you talk a little bit about the heavy oil wells that were shut in and what do you think you need to see in terms of price in order to bring those back online? And could you help us just understand what the cost associated with doing both of those actions might be?

Sure. It’s really the volume that we are shutting in is really a reflection of where pricing has been over the past quarter or here so far in Q1 of 2016. So as we get below CAD35 a barrel, part of the production becomes uneconomic at CAD14 to CAD15 WCS differential, which is where we were throughout parts of January and most of February. And we kind of anticipate of staying shut in through the second quarter. Now, if we get a price spike, we can bring it on in relatively short order and would probably seek to do that. But if prices kind of stabilize through the quarter and at the end - the end of first and on into the second, we're into spring breakup, we rose our required work if you're moving crude around and so our operating expenses are always a little higher during spring break up. So it's a good quarter if you're going to have production shut in to go ahead and forego the little bit of incremental operating expense that exists in that second quarter and then as you move into the third, hopefully, prices will follow the forward curve. We're up into the CAD37 to CAD38, CAD39, maybe CAD40 a barrel range and we anticipated at that stage, probably bringing all that back online at that timeframe.

Okay. That's helpful. So anything kind of close to that CAD40 range you feel like makes sense to assuming kind of a normal differential to bring it back?

Yeah. What we don't want to be is just continually turning it on and turning it off. So as prices got down into the 20s that we saw, in the high-20s and low-30s and the WCS differential was out at 15, that's when we made the decision to go ahead and take off this low margin or negative margin production, which some of it is, and get - go ahead and get that offline, it's likely will stay down for the second quarter. Differentials have moved in, they're in kind of the CAD12 to CAD13 range right now as we move out. So that will help a little bit as we move into the second quarter. Prices are up a little bit and if they move a little bit higher here towards the higher end of the 30s, we'll take consideration of it, knowing the fact that moving crude and fluids around all the fields in Canada is a little bit more expensive to do during the second quarter. So we'll take that into account, but if it looks like prices are going to sustain themselves in the high-30s or low-40s, I would expect at some point here, most of that production would come online and it would stay online.

Okay. That's helpful. And can you just remind me what the costs associated, is it material at all to bring it back online?

Not really. We can get, Brian, the details on that, if you've got some modeling, but to bring it back on, it is very expensive to shut it in, and it's not very expensive to bring it back.

Okay. That's helpful.

It does cost a little.

Sure. And then maybe just kind of two quick questions. I guess, number one, I appreciate the disclosure on the reserves in the release, and I’m just kind of curious if you guys have run what your kind of 1p or your PDP PV-10 numbers might be if you are to assume the strip rather than the price that was in there?

Yeah. If we've got modeling questions like that, why don't we follow up with, Brian, on the specific disclosures. All we have on NPVs are what are in the NI 51-101 disclosures at this stage.

Okay. Fair enough. And then maybe just lastly, perhaps as a follow-up to one of the other questions here, but if we kind of assume the strip plays out this year and we end up bringing back the kind of 7500 a day, do you feel that you should be able to maintain compliant with that comment that you guys have suggested there, that I guess the 5.25 times the revolver?

Yeah. This is Rod talking. We currently, under current strip prices, see ourselves well through Q2 and probably through Q3 under the current strip, but there is other options that we can do to see ourselves be in compliant with the covenants throughout 2016.

Okay. That's helpful. And I guess in terms of other options, would that like include asset sales or something along those lines or?

There is a number of options, but I don't want to speculate right now.

Thank you. The following question is from Dennis Fong of Canaccord. Please go ahead.

Hi. Good morning, gentlemen and congrats on another quarter as well as I imagine through a tough 2015. I have a couple of quick questions. The first one is on the Eagle Ford, specifically what the budget. I was just first curious as to how much associated facilities were included in your revised budget. And second, if you guys are participating in all of the wells drilled within the AMI?

Yes. Couple of answers there. I think the facility’s number is approximately 20 million in change US in that range that we got in the budget and I don't know that we will spend all of that, but that's what we've got in the remainder of our budget for the Eagle Ford in 2016. And your follow-up question was…

If you're participating in all of the wells within the AMI or if you're...

Yeah. Essentially, we're. We're making that judgment primarily based on the economics of the individual wells as they do vary across their acreage position.

Okay. And just one last question just with respect to Canada, the small amount of capital that you guys are allocating towards Canada, is that for just base maintenance or is that wells or what...

Yeah. Essentially just small amounts to base maintenance capital. We did have one drilled well that we did this year already that's in the number that's behind us, but the rest of it is just basically maintenance capital.

Thank you. The following question is from Thomas Matthews of AltaCorp Capital. Please go ahead.

Sorry, guys. I just wanted to follow-up on a prior question, so the existing guidance right now, the 68,000 to 72,000, that includes all of the shut in production assuming it doesn't come back on for the entire year or do you have a little bit coming back on in your assumptions?

Thomas, that assumes that it's shut in essentially as we're tapering into it from now until the beginning of the third quarter. So it assumes that does come back at mid-year.

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

All right. Thank you, Melanie and thanks, everyone for participating in our year-end conference call. Have a great day.