Baytex Energy Corp (BTE) 2012 Q4 法說會逐字稿

Good morning, ladies and gentlemen, welcome to the Baytex Energy Corp fourth-quarter 2012 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.

Thank you operator, good morning, everyone.

Again, my name is Brian Ector, I am the Vice President of Investor Relations for Baytex, 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, 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 reserves and contingent resources at year-end 2012. 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 and contingent resources are also forward looking statements. I refer you to our advisories raised 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.

I would now like to turn the call over to Jim.

Thanks, Brian, and good morning, everyone.

I am going to break down my comments into three parts for you today. First, I'm going to comment on our fourth-quarter results and our year-end reserves. Second, I'm going to provide an update to you on our operations, and then we will close with an update on our marketing portfolio, heavy oil differentials, and the use of rail transportation.

With respect to the fourth quarter, Baytex generated quarterly protection of just over 55,000 BOEs per day, which brings us full-year production to approximately 54,000 BOEs per day, right at the midpoint of our full-year guidance. Production during the quarter was weighted at 87% to crude oil and natural gas liquids and 13% to natural gas. Our funds from operations totaled CAD127 million, or CAD1.05 per basic share, bringing our funds from operations for the full year to CAD533 million, or CAD4.44 per share.

This represents the second-highest funds from operations in our Company's history, which given the volatility we have experienced in heavy oil differentials over the past year is a sign of the underlying strength of our core business. During the fourth quarter, we had a non-recurring adjustment to our royalty expense, which reduced our funds from operations by CAD4 million or CAD0.03 per share. So excluding this adjustment, our funds from operations would have come to CAD1.08 per share for the quarter. Our payout ratio, net of dividend investment plan, remained conservative at 43%, which is consistent with the 40% payout ratio realized for the full year.

We ended the year with total monetary debt of CAD603 million, representing a debt to funds from operations ratio of 1.1 times, based on funds from operations for the trailing 12 months. And we have significant financial flexibility with over CAD580 million of available undrawn credit facilities, and no long-term debt maturities until 2021. Subsequent to the end of the fourth quarter, we invested approximately 22,000 net acres of Viking rights in the Kerrobert area of Southwest Saskatchewan for CAD43 million. Production associated with this sale was approximately 100 barrels per day, and those sales proceeds have been used to repay bank borrowings.

On the capital spending front, we spent CAD67 million on exploration and development activities, with full-year expenditures coming in at CAD418 million. During the fourth quarter, we drilled 20 net wells with 100% success rate. Now let's switch gears and talk about our year-end reserves, which were highlighted by a 16% increase in our proved plus probable, or 2P, reserves. As a reminder, we completed two significant transactions during 2012 that did affect our reserve volumes. In May, we sold our non-operated interests in North Dakota for net proceeds of CAD312 million. This disposition resulted in a reduction of 12.5 million barrels of proved reserves and 18 million barrels of 2P reserves.

In October, we acquired 46 sections of undeveloped oil sands leases, and an approved SAGD project in an area we call Angling Lake in the Cold Lake region for CAD120 million. The SAGD project was assigned 43.6 million barrels of 2P reserves, almost all of which are classified as probable reserves today. All of the reserve data that I will reference reflects our 2P reserves and are inclusive of changes in future development costs.

I would also like to point out a reserve classification change that has taken place this year. In accordance with Canadian reserve reporting standards, all of the reserves associated with our thermal projects at Cliffdale, Angling Lake and Kerrobert are now classified as bitumen.

With that background in place, I will now review the highlights of our year-end reserve report. Our base reserve increased 16% to 291 million BOEs, an increase of 12% on a per-share basis. 93% of our reserves are oil and NGLs. Based on the midpoint of our 2013 production guidance, we have a reserve life index of 14 years. At Peace River, our reserves increased 8% to 109.8 million barrels, consisting of 63.4 million barrels of primary reserves and 46.4 million barrels of thermal reserves.

At our Gemini SAGD project at Angling Lake, reserves totaled 43.6 million barrels, which is consistent with our view at the time of the acquisition in the fourth quarter. And in our light oil resource play in North Dakota, our reserve base increased 5% to 34.5 million BOEs, which shows an impressive organic growth rate, considering that we disposed of 18 million BOE of reserves in 2012.

In 2012, we replaced 300% of production inclusive of acquisitions and divestitures, with the resulting FD&A cost of CAD11.56 per barrel. This results in a one-year recycle ratio of 2.7 times. Our three-year average F&D costs are CAD14.04 per BOE, and our three-year recycle ratio is 2.3 times. Excluding acquisition and divestiture activity, we replaced 170% of production with an F&D cost of CAD19.84 per BOE.

Our three-year average F&D costs are CAD16.59 per BOE. We are pleased with our 2012 reserve report. We continue to demonstrate consistent reserve growth. We reported very strong FD&A costs, indicating a very profitable business model as reflected in our 2012 recycle ratio of 2.7 times.

That concludes my remarks on our year-end reserve report, and now I will review with you an update of our contingent resource assessment. At year-end 2012, our best estimate contingent resource is 796 million BOE, which represents a 2% increase over year-end 2011. The notable changes to the contingent resource assessment this year are as follows. First, our new best estimate contingent resource for North Dakota is 28 million barrels. This includes adjustments for the North Dakota asset sale, land adjustments, and actual drilling during the year, which converted resources into reserves.

Second, Sproule completed an assessment of our Angling Lake oil sands leases acquired last year. The best estimate contingent resource on these new lands is 87 million barrels. This reflects the thermal potential on the acquired lands beyond the already-approved Gemini SAGD project. And third, following the disposition of our remaining Saskatchewan Viking lands, we chose not to include the remaining Alberta Viking lands in the contingent resource assessment, as they represented about 1% of the total, and are no longer material.

Of our best estimate contingent resource of 796 million barrels, over 0.5 billion barrels comes from our Peace River region. In this year's reserve report, the best estimate contingent resource for the Peace River region increased 4% on a year-over-year basis to 551 million barrels. The increase is largely attributable to new to data from our ongoing stratigraphic well test program, which further indicates the potential of our lands in Peace River.

Now let me provide you with a quick update on our operations. Production from Peace River properties averaged approximately 21,000 barrels a day during the fourth quarter. On a year-over-year basis, production at Peace River was up 20%. During the fourth quarter, we wrapped up our drilling program for the year with six cold multilaterals wells being drilled. A total of 83 laterals were drilled from the six wells, and they established an average 30 day peak production rate of approximately 400 barrels per day.

In the Cliffdale area, successful operations continued at our 10-well cyclic steam stimulation, or CSS module, with production averaging 400 barrels per day. During the fourth quarter, seven wells received steam, and six wells commenced post-steam flow back operations. The cumulative steam oil ratio for the project sits at 2.4, which is consistent with the project design parameters. We continue to plan for a new 15-well CSS module at Cliffdale. Upon receipt of regulatory approvals, we will commence facility construction, with drilling operations planned for the third quarter of 2013.

Turning to Lloydminster, production here averaged approximately 19,300 barrels per day in the fourth quarter. Drilling included 6.3 net horizontal wells, and 1.4 net vertical wells, which brought our full-year drilling program to 75 net wells. This area is characterized by stack pay, which has led to successful exploitation of multiple horizons, with projects in the area generating consistent and repeatable results. In our Bakken Three Forks development in North Dakota, we drilled seven gross or 1.7 net wells during the fourth quarter, all two-mile long horizontals. 11 Baytex-operated wells came on stream during the quarter and established average 30-day peak production rates of approximately 475 BOEs per day.

We also continue to see improvements in our drilling performance. We recently set a Baytex record from spud to rig release of 15.9 days. This compares to our average for the second half of 2012 of approximately 22 days. During the fourth quarter, production here averaged 2,500 barrels per day. This is the highest quarterly rate of production we have experienced in North Dakota, which is an impressive milestone considering the disposal of approximately 1,000 barrels per day in May, so our results here are very strong.

Now let me spend a couple of minutes detailing for you our 2013 plans. This past December, we released our production guidance and capital spending plans. We have laid out a total capital budget of CAD520 million, which includes CAD90 million for our two long-term thermal projects, our 15 well CSS module at Cliffdale, and our Gemini SAGD project at Angling Lake, where a single well pair will be drilled this year. These projects are not expected to contribute to production or cash flow in 2013, but we are building productive capacity for future years.

The remaining CAD430 million of capital is designed to generate an average production rate for 2013 of 56,000 to 58,000 BOEs per day. As part of our guidance for the year, production during the first quarter is expected to average approximately 52,000 BOEs per day. At the midpoint of our guidance range, this equates to a growth rate of 6% on an oil equivalent basis and 8% on oil. As part of our budget plans last December, consideration was given to reduce spending, which did occur during the fourth quarter of 2012, as well as the timing of surface agreements and regulatory approvals in the Peace River region, which now have been received.

Our plan calls for drilling approximately 4 multilateral wells during the first quarter, and approximately 14 during the second quarter. So, by mid-year we will have completed close to half of our planned drilling program at Peace River. For the full year we expect to drill 37 multilateral wells, and in addition, we will drill 26 stratigraphic test wells, as we continue to further delineate our land base and set up future drilling locations. We expect this year's program to be consistent with what we have delivered historically in the area. In our Lloydminster region, we will drill over 100 wells about evenly split between vertical and horizontal wells, and in North Dakota, we will drill approximately 9 wells.

I will now move on to a discussion of our hedge portfolio and marketing efforts. In my comments here, I will refer to the WCS differential, which represents the difference between prices for West Texas Intermediate, a light sweet crude, and Western Canadian Select, a Canadian heavy oil. We continue to hedge our exposure to commodity prices and foreign exchange rates. As part of our hedging program we look to mitigate exposure to pipeline delivery interruptions and WCS differentials by transporting crude oil to higher-value markets by rail.

During the fourth quarter, we were delivering approximately 21% of our heavy oil volumes by rail, and by the end of the first quarter, we expect to be delivering approximately 40% of our heavy oil volumes by rail. With respect to our heavy oil sales portfolio, for the first quarter of 2013 we have hedged 43% of our exposure to WCS differentials through a combination of long-term physical supply contracts and rail delivery. And for the fully ear, combining rail contracts with our long-term physical supply contracts, we would be hedged on 34% of our exposure to WCS differentials.

During the first quarter of 2013, forward trading for the WCS differential averaged CAD32 per barrel. Based off this differential, we should be able to capture a significant price uplift through our marketing arrangements. The forward market for the balance of 2013 currently reflects an improvement from the WCS differential in the first quarter.

Currently, the forward market indicates a WCS differential for the balance of this year of approximately CAD24 per barrel, and improving in 2014 to around CAD22 per barrel. We are optimistic that as refinery demand grows in the US Midwest and as we access new markets for our heavy oil such as the Gulf Coast and the Northeast through both pipeline projects and increased rail deliveries, that this pricing differential for heavy oil can continue to improve going forward.

With respect to our WTI hedging, we have established forward contracts for the first quarter of 2013 on 47% of our net production at an average price of $98.46 per barrel. For the full year for 2013, 40% of our net production at an average price of $98.30 per barrel.

So in summary, 2012 was a very successful year for Baytex, in an environment which was especially challenging for heavy oil producers, we were able to grow our protection by 8%, grow our reserve base by 16%, return over CAD215 million to our shareholders as dividends, and reduce our debt by over CAD54 million. This year also saw the successful execution of several strategic objectives, including the acquisition of 46 sections of land, oil sand leases, and an approved SAGD project in Angling Lake, the expansion of our land base at Peace River, and the disposition of certain non-operated assets in North Dakota at attractive metrics. Baytex is well-positioned to benefit from an improving market with quality assets, and an experienced staff.

That concludes my remarks, and I will turn it back over to Brian.

Thank you, Jim, for those comments. At this time, operator, we would like to open the lines for any questions.

(Operator Instructions)

The first question is from Mark Friesen, from RBC Capital Markets. Please go ahead.

Just a few quick questions.

First of all, you made specific reference to the rail marketing arrangements that you have been undertaking. Could you quantify the impact of that on either your price realizations or your net-backs that you realized in the fourth quarter?

Yes Mark, it's Derek here.

I think what I would tell you is, in Q4 of 2012 we had a net uptick relative to the next best alternative at the time, that we could have sold those barrels for CAD5 million. Obviously, the uptick is dependent upon the WCS environment at the time; and we actually lost on our rail deals in October and November, because the differential environment was quite tight then. If we fast-forward to Q1, obviously we doubled the volumes and the WCS environment is worse in Q1 than it was in Q4. So I think it is reasonable to expect a much more material contribution from rail in Q1 than in Q4.

Sure, and keeping on that theme, I understand you delivered to a local marketer in the Alberta region. Would you consider taking that all the way yourself, to improve those realizations?

Yes, Mark; this is Jim.

We typically don't see a need to do that. The infrastructure that is in place that we deliver to has been paid for by others. It is really not where we want to spend our capital. If indeed, it continues to expand in the future, and our participation would help get a new facility kicked off, we might consider that, but there really hasn't been a need to do that at this point in time. So we have not participated directly in the operations itself of rail or loading facilities.

Okay. Changing gears here -- you had a small disposition subsequent to year-end, and then there was of course the North Dakota one last year. Do you see any more asset dispositions in your future here?

It is always a possibility, Mark. We continue to review the portfolio for things that either don't fit, or are no longer core to us; and on occasion, find some opportunity that it may be more valuable to someone else, in their hands versus ours. So if we run into those kinds of things, that might be the case. I do not mean to imply that we have some sort of disposition target that is outlined for the year.

Okay. And finally for me -- you made the point of being a little more specific with production guidance, dipping to about 52,000 in the first quarter. When do you expect we could see production returned to Q4 levels of 55,000? Is that end of Q1? Is that a Q2-type target? When does it turn around?

Let me start off by saying our budgeting process that we undertook this past year is pretty similar to what we have done in the past; and if you look back at our past couple of years, our fourth-quarter program did always slow down, and that was consistent. And this year was really no different.

With respect to the pace in 2013, though, we did plan for a reduced pace, if you refer back to my comments there in Q1; so clearly, we are essentially full-up and running in terms of our rig program right now, and you will start to see that impacting Q2 and on into Q3. So I think that answers your question.

I would ask Marty, here, to step in and talk a little bit about the Q1 plans that we have in place. Marty, do you mind commenting on that?

Sure, Jim.

There were certainly some unique circumstances in Q1 for us. For example, at Peace River, we are drilling on previously undeveloped sections of land in that Harmon Valley area, and that required significant lease construction and new roads; and of course that led to additional regulatory attention. Then, we are working hard to minimize our impact on the environment in the area, so we want to improve the efficiency of our gas gathering and our infrastructure, so we designed and built a couple of larger than usual pad sites for drilling this year, and that required some of our applications to be submitted on a non-routine basis. For example we have one pad that has nine wells on it, which is the largest pad ever for us, for our full multi-lateral drilling. Most of our previous drilling had only three or four pads, so that is a significant increase in size.

Anyway, consequently, there was additional regulatory process time built into our budget plan in order to accommodate that change. It was a relatively minor change in our strategy, but we now have got, as Jim said, we have our roads and our leases constructed, and our drilling program is well underway. Across the Company, we've got 15 drilling rigs running right now. That includes four at Peace River drilling production wells, and two at Peace River drilling stratigraphic test wells. Since we're drilling from pads, we expect we can drill through spring break-up this year at Peace River.

It should also be noted that at our Kerrobert SAGD project, we drilled a thermal infill well during the first quarter, and that required us to take our thermal production off-line for about 10 days. In general, I would say and reaffirm that we are on track to meet our annual guidance of 56,000 to 58,000 barrels equivalent per day.

Okay. So if I understand you correctly, the fluctuation going to Q1 is purely a timing issue, and has nothing to do with changes to decline rates in any of your producing areas?

That is correct.

Great, that's all for me, gentlemen. Thank you.

Thank you; and this question is from Jeremy Kaliel from CIBC. Please go ahead.

I think a couple of my questions have already been answered by the first speaker. So maybe I will just take it a little bit further.

Would you be able to give us some guidance on expected production levels for Q2? Even just a range, to give us a sense of what kind of recovery we should expect? And could you actually give us what your corporate decline rate is, and as well as your decline rate at Seal? And maybe reaffirm whether or not there have been any changes recently?

This is Jim again here.

Concerning our quarterly guidance -- we got it out for the first quarter, here. We intend to build back up through the year, and that was all consistent with the plan we had built to reach the midpoint of about 57,000 BOEs per day.

On our Peace River decline rates -- that has been consistent. The base there is about 33% or so for, on average, for the entire production base; and the wells, typically on new year first year wells are kind of in the 50% range, ranging up as high as 55%, and that has been consistent with what we've seen in the past. On a corporate basis, our underlying decline for the entire corporation is about 28% to 29%.

Okay, great. Thank you very much.

Thank you. Our next question from Gordon Tait from BMO Capital Markets. Please go ahead.

Approximately how many years of drilling inventory do you have for these cold wells at Seal, given the pace you're currently drilling them at?

Sure, Gordon, it's Marty here.

We have over 200 wells in our inventory at Peace River for full development drilling. At the current pace, we're looking at about six years of inventory.

I guess by that time, Cold Lake, Kerrobert should be up and running, and Harmon Valley as well -- is that right?

Of course Harmon Valley we are currently developing already; but you're right. By then, we'll have a significant contribution from our relatively new Cold Lake SAGD project; plus it should be noted that we are drilling a lot of stratigraphic test wells this year -- more than ever before -- and we expect with that large land position we have now, we now have over 300 sections of land, that these stratigraphic test wells are going to identify additional development opportunities for the future.

And maybe this question is for Jim.

I know you been quite clear and fairly constructive on the potential for these WCS-WTI differentials to narrow over time, and rail is probably the answer. What do you see going on in the overall market that would lead you to continue to leave that, with or without Keystone XL?

Gordon, we have been quite clear on our views on that. There is a large demand for Western Canadian Select in the US. It's the largest transportation network in the world, of 18 million barrels a day of refining capacity. It is largely gone through over the last 15 years a significant conversion to heavy and sour crudes. And today, a lot of those crudes are being purchased off of water at near-WTI prices in order to fulfill those needs.

And the Canadian market is setting here, and as soon as the transportation gets unlocked -- which I believe that is going to happen quicker than people think, regardless of Keystone XL, because of the fact that you can get down there on rail, and that was clearly demonstrated. The manufacturing industry has built the capacity to do that; it unlocked the Bakken, and it's in the process of unlocking Western Canadian Select. So there is a lot of pie to be carved up between the various entities that participate in those efforts.

And just a little more background question -- I presume that when oil gets into the US network, if you get it across the border via rail or something, it doesn't necessarily have to be transported all the way down to the Gulf. I presume there's lots of delivery points within that, even the pipeline network, were fairly fungible. And you just have to get it to someplace where it can be delivered and then moved by some other means. Does that happen as well in that market?

Gordon, that is a fair assessment. To further expand on that just a bit, you have heard various companies announce large deals and ties into pipeline or rail at different take points, so all of those are possibilities, and in fact realities, as people are announcing the various ways you can connect in. I think you will see more of that to come with Cushing, that I believe will get cleared this year. That's going to open up new ways for Western Canadian Select to get into different points, as well.

Okay, thanks.

(Operator Instructions)

The next question is from Cristina Lopez from Macquarie. Please go ahead.

Just a couple quick questions.

One has to do with transportation costs -- obviously up on the quarter, and up significantly from last year; trucking being a good portion of that. Do you expect this to be the new level for your transport costs as you start railing more volumes as well, and having to move more through long-haul trucking to get to the railing loading facilities?

Yes, Cristina, it's Derek.

Directionally, that's correct. The single biggest contributor to the increase in TransEx is, as you identified, the cost to truck volumes out of Seal to delivery points. As Seal volumes increase, the trucking cost goes up with it. In the fourth quarter, that was exacerbated a little bit by the fact that we are doing some rail deliveries. The trucking distance to rail loading points is about the same as to pipe loading points; with the incremental cost of unloading trucks at a rail delivery point is a little bit slower, so you're paying standby fees and those kinds of things. But directionally, you are correct. It is likely to increase, as we continue to increase volumes at Seal.

And because you're moving that rail volume from 21% in Q4 to 40% at the end of Q1, we actually should directionally even see that go up then, through the year?

That is correct, although I think that, net-net, obviously when you're moving to rail, we're accessing a higher market, so there is a net contribution to us. But the TransEx component does go up.

And so then that brings me to my next question on what the breakeven differential on the dollar basis would be? Where you start to see a benefit from rail versus being 100% dedicated to pipe?

All things being equal, I think it breaks even around a CAD15 differential.

Okay. The big assumption there is all things being equal, which in the last 12 months is outside of our norm.

When I say that, Cristina, I mean blending costs, plus the cost of condensate. What is the WCS environment, all those kind of things. But in that current pricing environment, a CAD15 WCS differential means you're neutral between pipe and rail.

And that includes that increased transportation expenditure in there?

That's correct.

And then, with this year's 2013 capital program, obviously over the past three years you've had this big dip in Q4 spending. Is that again expected to occur in 2013, or more of a level loaded program by quarter?

Christine, this is Marty.

It will be a little more level-loaded by quarter this year. We have tended in the past -- we want to spend the exact amount that we have budgeted, just to execute as efficiently as we can; and that has led to a spending or a capital allocation a little early. This year, because of some of the startup work that we did at Peace River, we are probably level loading more than past years. But it is still likely we'll be tapering off near the end a little bit.

And then my last question actually is looking a little further out into 2014 again, with CapEx spending a good jump from 2012 expenditures to 2013. As you then accelerate or move forward with more thermal projects into 2014, do you expect a similar order of magnitude increase in spending? Or relatively flat to 2013, obviously understanding it's still early in any sort of budgetary process?

Yes, Cristina, you are right, it is early, and we have not released our 2014 numbers yet. But just directionally, I would expect to see the thermal come down. We do not have those specific components that we had this year, so the remainder -- again all things being equal, differentials improving, cash flow getting to where it needs to be as a result of that -- we certainly have the projects to continue at about the same base load that we have.

Okay, I'm going to ask one last question and then I will hang up and let somebody else ask some questions.

With respect to a world where heavy oil differentials begin to narrow, where we see a structural narrowing of heavy oil differentials -- order of priority, what do you do with incremental cash flow? Do you look at increasing the dividend, do you look at paying down debt? Acquisitions increasing? Cap expenditures? Where would you see the priority as it stands today?

Well, we will be consistent with what we have done in the past, there. We will have a little bit more capital need as the Company grows. If our cash flow grows, we would expect to pass along some of that in dividend. That has been the company's history and that would be our full intentions.

And that is everything for me. Thank you so much.

Thank you; and Mr. Ector, we have no other questions registered at this time. Please go ahead, sir.

Okay, Operator -- thank you very much; and thanks, everyone for participating in this morning's conference call. That does conclude the call. Thank you for your participation.

Thank you; the conference call has now ended. Please disconnect your lines at this time. We thank you for your participation.