Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy fourth quarter and year end 2017 conference Call. [Operator Instructions] I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Public Affairs. Please go ahead.

Thank you, Ria. Good morning, ladies and gentlemen, and thank you for joining us today to discuss our fourth quarter and year end 2017 financial and operating results. With me today are Ed LaFehr, 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. I refer you to our advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial and capital management 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 2017. 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 Ed.

Thanks Brian and good morning everyone. I'd like to welcome everybody to our year end 2017 conference call. For Baytex, 2017 was a year about delivering on our commitments. Our primary goals were to restore operational momentum, increase cash flow and develop plans to address our level of debt. And as always, we remain tenacious in our drive of cost and capital efficiency, while maintaining an outstanding health, safety, environmental and compliance culture and results. First, I will start with our fourth quarter results which demonstrate the impressive cash generating capability of our assets as commodity prices improved. With WTI averaging $55 a barrel, we realized our strongest operating netback in three years and generated adjusted funds flow of $106 million, a level we have not seen since mid-2015. Production of 69,500 BOEs per day was up 7% from Q4 ’16. In the Eagle Ford, activity remained steady with four to five drilling rigs and one to two frac crews on our lands, which delivered 37,362 BOEs per day, up 12% from Q4 2016. In Canada, we delivered 32,194 BOEs per day, up 2% from Q4 2016. Now, turning to full year results. We are excited that we increased our production, reserves and adjusted funds flow for 2016 -- versus 2016, while delivering our best ever health, safety, environmental and compliance results. We generated adjusted funds flow of $348 million, which is $1.48 per basic share, an increase of 26% over 2016. Backing out the financial derivative gains from 2017 and 2016, our adjusted funds flow actually increased 90% over this period, which illustrates the upside torque of our operations to improving commodity prices. We delivered annual production of 70,242 BOEs per day, above the high end of our guidance range, while spending $326 million in capital. Our cash costs…

[Operator Instructions] Our first question comes from Greg Pardy of RBC Capital Markets.

Thanks. Good morning and thanks for the rundown. I had a couple of questions for you. The first one is just with respect to free cash flow in the balance sheet. So how should we think about your program this year? What are you budgeting in terms of WTI pricing? I may have missed it in your release. And then if you do have that excess cash flow or is the game plan then that again you'll continue to pay down the revolver?

Well, we set up a cash flow budget Greg and that was back in December of last year and what we've just reaffirmed essentially is a cash flow budget. So, there's really no change. What we're seeing is higher pricing in the Louisiana light position we have in the Eagle Ford and the cash flow from those assets offsetting the current widening of the differential here in Canada. We're moving into breakup now. So we're -- obviously we've completed our Q1 program and we're very excited about those results, but as always, we will take a pause and reflect on where commodity prices are going and where we are and then how we position ourselves to come out of breakup with respect to our Canadian activity program. We're pushing hard for more activity in the Eagle Ford, but I think the bottom line Greg is it's still a cash flow budget. Our number one priority is still to drive the investment returns for our shareholders from our portfolio. We generated some excess funds flows last year to pay down the revolver as I mentioned and we could continue to see some of the same this year.

Okay. Thanks for that. So I mean if -- let's just say, sake of argument, you come up and you've got $50 million, $75 million of free cash flow. It sounds as though you will evaluate conditions at that point as opposed to at this stage saying, no, we're going to pay down the revolver. Is that the right read?

Right. I think it's too early to say what we might or might not do with additional cash flow that we might or might not have depending on where prices go. So we would probably start to talk about that in Q1, Q2.

Okay. Roger that. And in your release, you flagged a couple of nice chalk wells. Could you talk about just the performance you're seeing in the chalk and how much running room and how that's going to fit into the 2018 program.

Well, it's a phenomenal trend and it's one that needs to be fully apprised. We've only got two wells in it, but it's in our reasonably strong working interest area at an average of 26% working interest across that northern part of the Longhorn acreage. So we've got six wells planned and Rick correct me if I'm wrong, but we've got six wells planned in the 2018 budget and what we want to test with the operator is how far south this trend moves from the central [indiscernible] how far east it trends. We know how far east it trends because EOG has got a dozen wells out there and so does the operator of our piece of business. The question is how far west does it go? So these, you'll see these six wells testing the edges a little bit more. We booked locations that are what we would consider direct offset locations of about 5.7 million barrels net to Baytex on 24 locations. So you'll see -- you can run the math, but these are going to be some of the best wells in the entire field.

Our next question comes from Thomas Matthews of AltaCorp Capital.

Hey guys. Great quarter. Just a couple of questions from the press release that I caught. So I was wondering if you could touch on the remapping of the Bluesky play. Was that done on existing acreage? Was that done on acquired acreage or throughout the play and what are you seeing that's changing the way you're drilling the wells?

Will really throughout the play, since we acquired the properties in the Seal area, we've more than doubled our strap well count. So as you know, our core capability is to be able to take those core data, integrate with logs and the subsurface information and actually map the coal flow areas through understanding viscosity and permeability. So we've now got maps that are much more robust than we've ever had before and we can see channel systems and the major geologic features to the north very clearly and no one else in the area can and we can actually map these features across other people's acreage as well. So it's quite a step change in terms of our ability to map and then target what we want to do. But Rick, did you want to say anything more on that? Thomas, does that help your --?

Yeah. Just from a production standpoint, I know in your presentation, you have just a 350 barrel a day IPs, but given the enhanced mapping and some of your recent results, is that proving to be conservative?

Well, we talked about averaging IPs of 400 barrels a day last year and that was more offsetting some existing areas that we know quite well. We don't have a single well in the high productivity area of the Seal assets that we just acquired yet because we've been spending some time and putting some capital in to upgrading roads and pads and the gas infrastructure that's required to be compliant. So this area varies quite a bit. As you know in the old Harmon Valley area, we had wells that were north of a 1,000 barrels a day IP 30 and there are other parts of the field that are not that productive. So, you will see some of that from us in terms of high productivity wells in the northern Seal area this year. We fully expect that.

Okay. Yeah. That helps. And then just kind of along the same lines, but shifting down to the Eagle Ford, I noticed a lot of technical revisions kind of 7% to 8% on the approved -- on the shale gas NGLs and tight oil, so all good things. Just wondering again, are your type curves proving to be conservative, given those revisions or how are you seeing the dynamic between the wells in the ground versus what you think is going to happen going forward.

Well, the well performance has consistently surprised us to the positive over the last several quarters and actually years. So we talked about a step change of another 12% improvement on our IP30s this year versus last year, but you saw from the operators, not just IP30s, it’s IP180s. So the front end of the curve looks very strong, but I would also say we've got production that's been on for a considerable length of time in this field even before we've acquired it. So as we look at the total curve, the base performance has been very, very strong, not just the front 30 to 90 days. So, I guess what I'm saying is the whole curve is lifted up and it's -- we're very excited about it and we're going to keep it going.

Our next question comes from Michael Dunn of GMP FirstEnergy.

Ed, I just wondered if you could walk us through the profile of, sort of on a quarterly basis, how production looks this year and I guess relative to Q4, and your average guidance for 2018.

Well, we haven't changed guidance, Michael. We're sticking with our 68,000 to 72,000 BOEs a day. Our run rates are strong right now as they were in Q4. We'll go into break up, so we'll have some weather impacts and the usual sort of quarterly swings. But we don't typically put out a quarterly production profile if you will.

Well, yeah, I guess I'm just wondering, is there a dip in the first half, looked higher in the second half to your average or.

We're pretty steady as she goes, like, we're running right now 69 plus thousand barrels a day and Q1 looks a lot like Q4 so far, despite the fact that we had very little activity in Canada in Q4 actually since the end of the summer. So we're running pretty steady right now and then we’ll move in to break up. We’ll reevaluate and we’ll come out very strong, but the Eagle Ford is running about 37,000 barrels a day. It's been trending very consistently post Hurricane Harvey right around those levels. So we're, that's kind of where we are and we'd like to grow it, but we'll see where we get on pricing. We'd like to -- we believe the differentials are going to come down, but probably won't start seeing that until about June-July.

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Ector for any closing remarks.

Okay. Thank you, Ria and thanks everyone for participating in our year end conference call today. Have a great day.