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Baytex Energy (NYSE:BTE)

Q4 2012 Earnings Call

March 07, 2013 11:00 am ET

Executives

Brian G. Ector - Vice President of Investor Relations

James L. Bowzer - Chief Executive Officer, President and Director

W. Derek Aylesworth - Chief Financial Officer

Marty L. Proctor - Chief Operating Officer

Analysts

Mark J. Friesen - RBC Capital Markets, LLC, Research Division

Jeremy Kaliel - CIBC World Markets Inc., Research Division

Gordon Tait - BMO Capital Markets Canada

Cristina Lopez - Macquarie Research

Operator

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.

Brian G. Ector

Thank you, operator. Good morning, everyone. Again, my name is Brian Ector Rande. I'm the Vice President, Investor Relations for Baytex and I will be hosting this morning's conference call.

With me here on 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 continued resources at year-end 2012. These evaluations have been prepared in accordance with Canadian disclosure standard, which are not comparable, in all respects, to United States or other foreign disclosure standards.

Our remarks regarding reserves and continued resources 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. I would now like to turn the call over to Jim.

James L. Bowzer

Thanks, Brian, and good morning, everyone. I'm going to break down my comments into 3 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'll close with an update on our marketing portfolio and the oil differentials and use of rail transportation.

With respect to the fourth quarter, Baytex generated quarterly production 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 87% to crude oil and natural gas liquids and 13% to natural gas. Our funds from operations totaled $127 million, or $1.05 per basic share, earning our funds from operations for the full year to $533 million or $4.44 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 nonrecurring adjustment to our royalty expense, which reduced our funds from operations by $4 million or $0.03 per share. So excluding this adjustment, our funds from operations would have come to $1.08 per share for the quarter.

Our payout ratio, net of dividend reinvestment plan, remain 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 $603 million, representing a debt to funds from operations ratio of 1.1x based on funds from operations for the trailing 12 months. And we have significant financial flexibility with over $580 million of available undrawn credit facilities and no long-term debt maturities until 2021.

Subsequent to the end of the fourth quarter, we divested of approximately 22,000 net acres of Viking rights in the Kerrobert area of southwest Saskatchewan for $43 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 $67 million on exploration and development activities, with full year expenditures coming in at $418 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 2 significant transactions during 2012 that did affect our reserve volumes.

In May, we sold our nonoperated interest in North Dakota for net proceeds of $312 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 land -- oil sand leases and an improved SAGD project in an area we call Angling Lake in the Cold Lake region for $120 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 SAGD -- 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 BOE, 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 a resulting FD&A cost of $11.56 per barrel. This results in a one-year recycle ratio of 2.7x, our 3-year average F&D cost are $14.04 per BOE and our 3-year recycle ratio is 2.3x.

Excluding acquisition and divestiture activity, we replaced 170% of production with an F&D cost of $19.84 per BOE. Our 3-year average F&D cost are $16.59 per BOE. We are pleased with our 2012 reserve report. We continue to demonstrate consistent reserve growth. We reported very strong FD&A cost, indicating a very profitable business model, as reflected in our 2012 recycle ratio of 2.7x.

That concludes my remarks on our year-end reserve report. And now, I'll 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 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 6 cold multilateral wells being drilled. A total of 83 laterals were drilled from the 6 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, 7 wells receive steam and 6 wells commenced post steam flowback operations. The cumulative steam-oil ratio for the projects 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 7 gross, or 1.7 net wells during the fourth quarter, all 2-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 second -- 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 plan. We have laid out a total capital budget of $520 million, which include $90 million for our 2 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 production or cash flow in 2013, but we are building productive capacity for future years.

The remaining $430 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 midyear, 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'll 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 full year, 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 $32 per barrel. Based off this differential, we should be able to capture a significant pricing uplift through our marketing arrangements. The forward market for the balance of 2013 currently reflects an improved -- 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 $24 per barrel and improving in 2014 to around $22 per barrel. And we are optimistic that as refinery demand grows in the U.S. midwest and as we access new markets for our heavy oil, such as the Gulf Coast and the U.S. 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, U.S. And 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 production by 8%, grow our reserve base by 16%, return over $215 million to our shareholders as dividends and reduced our debt by over $50 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 nonoperated 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'll turn it back over to Brian.

Brian G. Ector

Okay, thank you, Jim, for those comments. And at this time, operator, we would like to open the lines for any questions.

Question-and-Answer Session

Operator

[Operator Instructions] First question is from Mark Friesen from RBC Capital Markets.

Mark J. Friesen - RBC Capital Markets, LLC, Research Division

Just a few quick questions. First of all, you made specific reference to the rail marketing arrangements that you've 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?

W. Derek Aylesworth

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 at over [ph] $5 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've got about double the volumes and the WCS environment is worse in Q4 -- or in Q1 than it was in Q4. So I think it's reasonable to expect a much more material contribution from rail in Q1 than in Q4.

Mark J. Friesen - RBC Capital Markets, LLC, Research Division

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

James L. Bowzer

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's 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 haven't participated directly in the operations itself of rail or loading facilities.

Mark J. Friesen - RBC Capital Markets, LLC, Research Division

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

James L. Bowzer

It's 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. And so, if we run into those kinds of things, that may be the case. I don't mean to imply that we have some sort of disposition target that's outlined for the year.

Mark J. Friesen - RBC Capital Markets, LLC, Research Division

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

James L. Bowzer

Yes, well, let me start off by saying our budgeting process that we undertook this past year is pretty similar to what we've 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 in -- if you refer back to my comments there in Q1. So clearly, we're essentially full up and running in terms of our rig program right now, and you'll start to see that impact in Q2 and on into Q3. So I think that answers your question. I would ask Marty here to step in and talk little bit about the Q1 plans that we had in place. Marty, do you mind commenting on that?

Marty L. Proctor

Sure, Jim. Yes, there were certainly some unique circumstances in Q1 for us. For example, at Peace River, we're drilling on previously undeveloped sections of land in the Harmon Valley area, and that required significant lease construction, the new roads and of course, that led to additional regulatory attention. And we're working hard to minimize our impact on the environment in the area. So it was to improve -- we want to improve the efficiency of our gas gathering and our infrastructure. So we've designed and built a couple of larger-than-usual PADD sites for drilling this year. And that required some of our applications to be submitted on a non-routine basis. For example, we've got one PADD that's got 9 wells on it, which is the largest PADD ever for us for our cold multilateral drilling. Most of our previous drilling had only 3 or 4 PADDs so that's a significant increase in size. Anyway, consequently, there's was additional regulatory process time built into that plan -- into our budget plan in order to accommodate the change. It was a relatively minor change in our strategy. Though we've noted, as Jim said, we got our roads and our leases constructed and our drilling program is well underway. Cost of company we've got 15 drilling rigs running right now. That includes 4 at Peace River drilling production wells and 2 at Peace River drilling stratigraphic test wells. And since we're drilling from PADDs, we expect we can drill through spring break up this year at Peace River. It should also be noted that at our corroborate SAGD project, we drilled an infill, a thermal infill well during the first quarter. And that required us to take our thermal production offline for about 10 days. In general, I'd say, I'd just reaffirm that we're on track to meet our annual guidance of 56,000 to 58,000 barrels equivalent per day.

Mark J. Friesen - RBC Capital Markets, LLC, Research Division

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

Marty L. Proctor

That's correct, yes.

Operator

The next question is from Jeremy Kaliel from CIBC.

Jeremy Kaliel - CIBC World Markets Inc., Research Division

I think a couple of my questions have already been answered by the first speaker. So maybe I'll 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 just maybe reaffirm whether or not there's been any changes recently?

James L. Bowzer

Yes, this is Jim again here. Concerning our quarterly guidance, we've 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's 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's 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%.

Operator

Our next question is from Gordon Tait from BMO Capital Markets.

Gordon Tait - BMO Capital Markets Canada

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?

Marty L. Proctor

Sure, Gordon, it's Marty here. We've got over 200 wells in our inventory at Peace River for cold development drilling. At the current pace, we're look at about 6 years of inventory.

Gordon Tait - BMO Capital Markets Canada

Oh, yes. I guess, by that time, Cold Lake, Kerrobert should be up and running to sort of...

Marty L. Proctor

Yes, yes.

Gordon Tait - BMO Capital Markets Canada

And Harmon Valley as well. Is that right?

Marty L. Proctor

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

Gordon Tait - BMO Capital Markets Canada

And maybe this question is for Jim. I know you've been quite clear about the -- and very constructive on the potential for these WCS, WTI differentials to narrow over time in rails, I guess. So like what would you share, maybe what do you see sort of going on in the overall market that would lead you to consider -- lead you to continue to lead that with or without Keystone XL?

James L. Bowzer

Gordon, we've been quite clear on our views on that. There is a large demand for Western Canadian Select in the U.S. It's the largest transportation network in the world of 18 million barrels a day of refining capacity. It's largely gone through over the last 15 years a significant conversion to heavy and sour crudes. And there, 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 that's 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's a lot of pie to be carved up between the various entities that participate in those efforts.

Gordon Tait - BMO Capital Markets Canada

And just sort of a little more background question. I presume that when oil gets into the U.S. 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, where it's fairly fungible and you just have to get it to some place where it can be delivered and then moved by some other means. Does that happen as well in that market?

James L. Bowzer

Gord, that is a fair assessment. And to further expand on that just a bit, you heard various companies announce barge 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 various ways you can connect in. I think you'll see more of that to come with Cushing that should get, 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.

Operator

[Operator Instructions] The next question is from Cristina Lopez from Macquarie.

Cristina Lopez - Macquarie Research

Just a couple of quick questions. One has to do with transportation cost, 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 cost as you start railing more volumes as well and having to move more through long-haul -- the haul trucking to get to the railing loading facilities?

W. Derek Aylesworth

Cristina, it's Derek. Directionally, that's correct. The single biggest contributor to the increase in trans ex is, as you identified, the cost to truck volumes out of Seal to delivery points. And 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're doing some rail deliveries. The trucking distance to rail loading points is about the same as to pipe loading points, with the incremental cost that unloading trucks at a rail delivery point is a little bit slower, so you're paying standby fees and those kinds of things. So that -- but directionally you're correct, it likely is to increase as we continue to increase volumes at Seal.

Cristina Lopez - Macquarie Research

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

W. Derek Aylesworth

That's correct. Although I think net-net, obviously, when you're moving to rail, were accessing a higher market. So there's a net contribution to us, but the trans ex component does go up.

Cristina Lopez - Macquarie Research

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

W. Derek Aylesworth

All things being equal, it kind of breaks even around a $15 differential.

Cristina Lopez - Macquarie Research

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

W. Derek Aylesworth

When I say that, Cristina, I mean, blending cost, what the cost of condensate, what is the WCS environment, all of those kind of things. But in a current kind of pricing environment, a $15 WCS differential, it means you're neutral between pipe and rail.

Cristina Lopez - Macquarie Research

And that includes that increased transportation expenditure in there?

W. Derek Aylesworth

That's correct.

Cristina Lopez - Macquarie Research

Okay. And with this year's 2013 capital program, obviously, over the past 3 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?

Marty L. Proctor

Cristina, it's Marty. Probably a little more level loaded by quarter this year. We have tended in the past we want to spend the exact amount that we put in it. Just execute it efficiently as we can and that has led to us spending our capital allocation a little early this year because of some of the startup and blueprint work that we did at Peace River, we're probably level loading more than past years. But it's still likely we'll be tapering off near the end a little bit.

Cristina Lopez - Macquarie Research

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 in 2014, do you expect a similar magnitude increase in spending or relatively flat to 2013? Obviously, understanding it's still early and any sort of budgetary process?

Marty L. Proctor

Yes, Cristina, you're right, it is early and we haven't released our 2014 numbers yet. But just directionally, I would expect to see the thermal come down. We don't have those specific components that we have this year. So the remainder, again, all things being equal, differentials improving, cash flow getting to where it needs to be as a result that. We should -- we have -- we certainly have the projects to continue at about the same baseload that we have.

Cristina Lopez - Macquarie Research

Okay. I'm going to ask one last question and then I'll hang up and let somebody else ask some questions. But with respect to a world where heavy oil differentials begin to narrow, or 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 CapEx expenditures? Where would you see the priority as it stands today?

W. Derek Aylesworth

Well, we'll be consistent with what we've done in the past there. We'll 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's been the company's history, and that would be our full intentions.

Operator

And, Mr. Ector, we have no other questions registered at this time. Please go ahead, sir.

Brian G. Ector

Okay, operator. Well, 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.

Operator

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

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