Baytex Energy Corp (BTE) 2013 Q1 法說會逐字稿

Good morning ladies and gentlemen. Welcome to the Baytex Energy Corp first quarter 2013 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, Vice President Investor Relations. Please go ahead, Mr. Ector.

Thank you operator. Good morning, everyone. Again my name is Brian Ector. I'm the Vice President Investor Relations for Baytex Energy, and I will be hosting this morning's conference call. With me here in the call today are James Bowzer, President and Chief Executive Officer; Derek Aylesworth, Chief Financial Officer; and Marty Proctor, 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 and non-GAAP financial measures contained in today's press release. I would now like turn the call over to Jim.

Thanks, Brian, and good morning, everyone. I'm going to break down my comments into three parts for you today. The first part will be on our first quarter results. Second I will provide you with an update on our operations, and then we'll close with an update on our hedge portfolio and marketing efforts. During the first quarter, we generated production of 52,000 boe per day and funds from operations of CAD102 million, or CAD0.83 per basic share. Production was consistent with our previous guidance, and our full year budget expectations.

As previously disclosed, first quarter production was impacted by the timing of our development activities at Peace River and the suspension of our Kerrobert thermal production to facilitate the drilling of an infield well. I will expand on the initial drilling results from our 2013 program in just a few minutes, but suffice it to say, we are very pleased with the execution of our capital program to date. We are currently producing approximately 56,000 boe per day, and our full year production guidance is unchanged at 56,000 boe per day to 58,000 boe per day. At the might mid point of this guidance range, this would equate to an approximate 6% growth rate.

Heavy oil prices were challenged during the first quarter. The benchmark price for heavy oil is Western Canadian Select or WCS, which trades at a discount to WTI. This discount during the first quarter is measured -- as measured by the price differential between WTI and WCS averaged 34%. Second quarter trading for the WCS differential is currently averaging 21%. One variance for us this quarter related to our operating costs, which from our perspective were unacceptably high, we expect to return to more normal levels in the range of CAD12 to CAD12.50 per barrel going forward.

The main components of higher operating costs were the snow removal and road maintenance costs which resulted from a very harsh winter weather conditions experienced in both Saskatchewan and North Dakota. With improved pricing for heavy oil in the second quarter and a growing production profile, we certainly expect to see an improvement in our cash generating capacity as compared to the first quarter.

With respect to our balance sheet, we ended the quarter with a total monetary debt of CAD686 million representing a debt to funds from operations ratio of 1.4 times based on the funds from operations for the trailing 12-months. And we have significant financial flexibility with over CAD540 million of available undrawn credit facilities and no long-term debt maturities until 2021. We are currently finalizing documentation with our lending syndicate to increase the amount of our credit facilities by CAD150 million to CAD850 million and to extend the term of our facilities by one year to four years. We expect to have the increased facilities available by the end of the second quarter.

Now, let me provide you with a quick update on our operations. During the first quarter, our capital spending activity was weighted towards the latter portion of the quarter, with almost 50% of the capital expenditures incurred in March. In total we spent CAD167 million, which included the drilling of 110 net wells, with a 99% success rate. Our guidance for capital expenditures for the full year remains at CAD520 million. In the Peace River area we drilled 26 stratigraphic test wells, 4 service wells, and 6 horizontal wells encompassing a total of 66 laterals. Subsequent to the end of the quarter, these six horizontal wells established average 30-day peak production rates of approximately 800 barrels per day, with our best performing well averaging over 1,000 barrels per day.

These are among the highest rates we have drilled to date in the Peace River area and compare favorably to the historic average 30-day peak production rate of approximately 500 barrels per day. The stratigraphic drilling program I referenced was the largest we have undertaken in the area. These stratigraphic tests allow us to continue to improve our geologic understanding and potentially expand our inventory of future drilling locations. Production from Peace River property operations averaged approximately 18,900 barrels per day during the first quarter, and current production is approximately 22,000 barrels per day. We plan to drill approximately 31 multilateral horizontal wells during the remainder of 2013.

In the Cliffdale area, successful operations continued at our 10-well cyclic steam simulation module with production averaging over 500 barrels per day. During the first quarter, six wells received steam and commenced flow back operations. To date the Cliffdale project has demonstrated a cumulative steam-oil-ratio of 2.4. The initial Cliffdale pilot well recently completed fourth cycle production operations, producing 118% more oil than the previous cycle, and achieving a cycle SOR of 2.1. Fifth cycle steaming operations commenced on April 4, with flow back operations scheduled for late in the second quarter. Regulatory approval for our Cliffdale 15-well CSS module was received in late March. The facility construction is underway and drilling operations are scheduled to commence mid year.

Turning to Lloydminster, production here averaged approximately 18,600 barrels per day during the first quarter. Drilling included 25 net horizontal wells and 32 net vertical wells. We also drilled one thermal infield well in the Kerrobert SAGD project which will commence production in the second quarter. We plan to drill an additional 55 net wells in the Lloydminster area during the remainder of 2013.

At Angling Lake preliminary work continued on the Gemini SAGD project including installation of groundwater monitoring wells and facility engineering. We expect to commence construction of the SAGD pilot facilities during the second quarter. In our Bakken Three Forks development in North Dakota we drilled 7 gross or 3 net horizontal wells and fracture stimulated 5 gross or 1.5 net wells during the first quarter. During the first quarter, two Baytex operated on 1,280 acre spacing established 30-day average peak rates of approximately 375 boe per day. We plan to drill approximately 13 gross or 5.5 net wells in North Dakota for the remainder of 2013.

I'll now move on and talk about our hedge portfolio and marketing efforts. For the remainder of 2013, we have entered into hedges on approximately 44% of our WTI exposure at a fix price of $98.10 a barrel. 42% of our exposure to WCS heavy oil differentials through a combination of long-term physical supply contracts and rail delivery. 45% of our natural gas exposure, and 39% of our exposure to currency movements between the US and Canadian dollars. As part of our hedging program, we are focused on opportunities to further mitigate our exposure to WCS price differentials by transporting crude oil to higher value markets by railway.

During the first quarter, we were railing approximately 12,000 barrels a day of heavy oil as compared to 7,500 barrels per day for the full year 2012. And our volumes on rail continue to grow. Today we are railing approximately 17,000 barrels per day of our heavy oil, and we continue to explore opportunities for additional rail deliveries. The forward market currently reflects an improvement in the WCS differential relative to that experienced in the first quarter. Currently the forward market indicates WCS differential for the second quarter of approximately 21%. We are optimistic that as the pricing differential for heavy oil can continue to improve as refinery demand grows in the US Midwest, and as transportation capacity expands to the US Gulf Coast and Northeast through both pipeline and increased rail deliveries.

So in summary, our operational execution remains on track, production during the first quarter was consistent with our expectations and our 2013 drilling program is well underway with very encouraging results. We expect to, a continuing ramp up in our production in the coming quarters, which is likely to occur in a much stronger pricing environment for heavy oil, and with production averaging approximately 56,000 boe per day today, we remain confident in achieving our full year guidance. That concludes my introductory comments here. I'll turn it back over to Brian.

All right. Thanks, Jim for those comments. At this time operator we would like to open the lines for any questions.

(Operator Instructions)

Mark Friesen with RBC Capital Markets.

Thanks, good morning gentlemen. Just a few quick questions here. First of all on steel. I wonder if you could outline the number of locations that, that you currently have identified that, that would still fall within the range of economics that you've outlined in your presentation and maybe how many locations you have remaining -- or you think you have remaining that would be more in line with the really strong wells that you drilled in the first quarter?

Mark. Thanks for the question, good morning. We've got about 238 remaining locations that we've identified to date that are in our five-year plan. We at this point haven't changed our guidance, our type curves around the mix of wells. So, it is outlined in our IR materials what we're projecting to date of the CAD5,000 to CAD9,000 per day per barrel capital efficiencies. The IPs of 300 boe to 700 boe per day for 30-day average initial producing rate. So that remains the same as we speak today. And I do recognize that we've exceeded those with a few wells we had in our 2011 program and a few of the wells that we've drilled so far this year.

Do you think you still have a few more of those around?

Like I said, we're sticking to our guidance but we certainly hope so.

Okay. And then, moving into, thinking about Reno, how many locations have you currently identified there and how would you say that the relative economics are versus Seal and how much is Reno part of the '13 program?

Yes. We don't expect to get drilling back in Reno in probably until late this year, into next year, but it's about 10% of our remaining locations that exist in our portfolio. There are, I think, on the order of 20 to 22 identified locations there. Those wells are the less expensive wells. We drill fewer laterals there because the pay is thinner and you can recover from a greater area, so they only cost about CAD2.6 million. But as a result of the shorter footage associated with fewer laterals, they produce in the 300 barrel a day range. And the capital efficiencies are about CAD9,000 to CAD9,500 per day barrel.

Okay. That's great. Just curious regarding the bank line you mentioned that you're trying to expand that. What would be the reason behind looking for that increase?

Yes. Mark it's Derek here. Really all we're doing there is introducing additional financial flexibility to our balance sheet. We don't have any immediate plans to be using that line, but the market today, there are opportunities out there and having incremental free line allows us to add quickly if we see acquisition activities.

Okay, so you're active then in looking for those type of activities?

We're always looking.

Okay. Great. Thanks very much. That's it for me.

Thanks, Mark.

Thanks.

Kyle Preston from National Bank.

Yes. Thanks, most of my questions were asked by Mark. But Jim, I'm just wondering if you can expand on what the reasons were for those higher well rates out of Seal there, that 800 barrels, was that just a function of being in a sweet spot of the play or did you put in extra laterals in those wells? I'm just wondering if you could expand on that? Thanks.

Certainly it's a combination of effects there. We do have a little more length in some of those wells. In addition the pay is thicker there, and there's certainly the mobility ratio, which is the combination of a little less viscosity of the crude itself with a little higher permeability, the combination of those factors allows for some really good flow rates there that are quite impressive.

And can you guess how many of your remaining 31 wells might be in a similar area?

We hope to have a few more of them that exceed our expectations. But in terms of specifically well to well, we'll see how that goes as we get through our program.

Okay. Thanks a lot.

You bet.

Thank you. Cristina Lopez from Macquarie.

Just a couple questions for you gentlemen. With respect to production, obviously, a big lift coming out of Q1, and are you seeing any downtime in Q2 -- understanding that of course, you can be drilling through breakup in the Peace River arch. But are you expecting anymore downtime or do you expect production growth now sequentially as we go forward?

Sure. Hey, Cristina, it's Marty here. Spring breakup does affect us in some of our areas. It usually does, we always account for it with the -- we account for that impact in our production forecasts. This year, as in most years, we're, we suspended our drilling operations in Saskatchewan between April and June. But at Peace River where we're drilling from multi-well pads we should be able to drill right through breakup, so minimal impact at Peace River. As Jim mentioned we're currently producing about 56,000 barrels per day. On top of that we've got about 1,000 barrels per day shut in due spring breakup impact in Saskatchewan, a little bit in North Dakota. But we expect those road bans to come off in Saskatchewan soon and be able to get back on those wells and get them back up to production again.

And following on from Mark's question about the bank line and the potential for acquisitions, is there any way you could potentially prioritize acquisitions that you might be looking at. If you're looking at heavy oil, more thermal or light oil and in an order of ranking which you would prefer at this point?

Yes, we certainly don't talk about and speculate on acquisitions, but in terms of priority, Cristina, as we've stated in the past, we don't have a set priority, but what we do have is a set philosophy. It is around what minimizes risk, which come in two categories. Number one, the things that we are familiar with that we can assess the risk on from a subsurface and operational standpoint, and the second risk is execution so that it fits our skill sets well. The third driver that tends to lead us towards what we end up doing is, the entry costs are typically lower and the competition is a little bit lower for heavy oil opportunities.

Therefore we do seem to end up landing more of those, but we're looking across the spectrum of the three things you mentioned. But as you've known in the past, we've ended up looking from a economic standpoint straightforward on what will end up adding the greatest value, the highest competition in North America is in and around light oil opportunities. That is also the highest entry costs which sometimes leads to of course, the full cycle economics. So that ends up telling you what drives us.

That's perfect. And now looking forward a bit into 2014, obviously the 2013 budget has a good percentage of thermal related to it. You've alluded to the fact that there will be a smaller component of that in 2014. Year-over-year then do you expect production -- or sorry CapEx to be flat or down somewhat? Can you address the longer term outlook on CapEx? Is the 2013 budget a bit of anomaly as far as its size goes?

Yes. Christina, we, as you know, we don't put out our guidance until the end of the year. But directionally I, I would say that your estimates there are, your comments are correct. We do have CAD90 million that are tied to two specific projects this year that are in our capital budget, they are not re-occurring next year. So we do, I'll just leave it to say that we don't have those -- we don't have specific projects identified for '14 in our capital budget at this point, for thermal.

Perfect. Thanks, guys.

(Operator Instructions)

Travis Wood from TD Securities.

Yes, good morning, guys. Just a quick question around the dividend and how you think about that in the context of the volatility of today's heavy oil pricing. Generally you've been as a percentage of cash flow in that 50% to 60% range. So, how do you think about that going forward, and how important is rail in the hedging policy related back to that?

Yes, Travis, this is Jim. Maybe I should start by talking about how we build up our budget in priority order because it's kind of the reverse order should a pricing scenario present itself where cash flows are significantly reduced. We first look at the amount of capital it requires to maintain our production flat and maintain our dividend payment. Those are the first two priorities. Our dividend flows run around CAD220 million. In order to keep our production flat this year based on the projects we have, that was about CAD340 million, so that is kind of our first two most effective spends and that's what we would look to protect the most.

Then the second piece we add on is what does it take to provide some capital associated with production growth and then in this year, we had a couple of projects that we just talked about that were CAD90 million associated with longer term growth. So it would basically come off in that reverse order, if you will. If differentials were -- or WTI prices were suppressed sufficiently that we weren't going to meet our needs. So that's the first steps we would take.

And in terms of what rail does is, yes, it's a big factor in what we do from a WCS standpoint. It is our hedging mechanism for the most part, and it does really several things. There are, there are several factors into the benefits. The first one is, is that you bypass the pad to market and get into the higher Mayan Gulf Coast market where people are willing basically to buy WCS for WTI plus [5]. That's the first up lift you get. The second negative is, that it costs more to get there versus transporting on pipes, so you have that as a negative. The third point that it is a factor in, is it allows you to avoid diluent mixing, which is quite expensive to get it on pipe. Because we produce raw heavy oil and transport it on truck, we're, we can get it a -- full rail cars filled with no diluent in them, which is a benefit that we have.

And then thirdly anytime that you're putting a heavy crude into a pipe system that potentially could -- has to be available to go to any refining point, and mix with crudes that may not have quality discounts associated with the acid content or metals that sometimes heavies contain. Because many specific refineries have the metallurgy that acids or metals aren't an issue with, and most of them are that way in the Gulf Coast and other places where they've been upgraded. If you can get to that specific refinery and you can be a rail, you then also lose the discount you have on pipe associated with quality. So it's the combination of all of those factors that make quite a big difference and that's why you're seeing the movement to rail.

Okay. Sure. And then one question just on current volumes. The big step function from the Peace River area, so you're 22,000 a day, up call it about 4,000 from last quarter, is that -- or from this quarter, is that generally how the growth will shape out through the rest of this year and is it fair to say that corporate current production is closer to 56,000?

Yes. We stated that currently we're right around 56,000 boe a day. You know what we averaged in the first quarter. We made that clear in our -- we're going to definitely hit our guidance range as we go out, so it doesn't take too much to do the math to figure out where we need to be towards the second quarter. So I don't know that I would throw in a quarter-on-quarter build like that, but we'll seek to manage our capital so that we are clearly in the guidance range of both capital and production by the end of the year.

Thank you.

You bet. Thank you, Travis.

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

Yes, I just have a couple of concluding comments. This is Jim Bowzer again. Certainly, it was a challenged quarter with differentials where they were. We're certainly glad to have the quarter behind us. We are excited about our drilling results to date and where we're going. We expect to see growing production in the coming quarters as we just talked and look forward to reporting on those results in the coming quarters. Brian?

With that, operator, we will wrap the conference call. Thank you very much.

Thank you. The conference has now ended. Please disconnect your lines at this time. And we thank you for your participation.