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 - VP, IR: Thank you, operator. Good morning, everyone. Again my name is Brian Ector. I am the Vice President, Investor Relations for Baytex. 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 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 reserve and contingent resources are also forward-looking statements. I refer you to our advisory 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 - President and CEO: Thanks, Brian and good morning, everyone. I am going to breakdown my comments into three parts for you today. First, I am going to comment on our fourth quarter results and our year end reserves. Second, I am 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 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 weighed at 87% to crude oil and natural gas liquids and 13% to natural gas. Our funds from operations totaled C$127 million or C$1.05 per basic share, bringing our funds from operations for the full year to C$533 million for C$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 the 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 C$4 million or C$0.03 per share. So, excluding this adjustment, our funds from operations would have come to C$1.08 per share for the quarter.
Our payout ratio, net of dividend reinvestment 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 C$603 million representing a debt-to-funds from operations ratios of 1.1 times based on funds from operations for the trailing 12 months. We have significant financial flexibility with over C$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 C$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 C$67 million on exploration and development activities, with full year expenditures coming in at C$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 two significant transactions during 2012 that did affect our reserve volumes. In May, we sold our non-operated interest in North Dakota for net proceeds of C$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 oil sands leases and an approved SAGD project is an area we call Angling Lake in the Cold Lake region for C$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 cost. 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 boe, an increase of 12% on 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 reserve 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 boe which shows an impressive organic growth rate considering that we disposed-off 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 C$11.56 per barrel. This result in a one year recycle ratio of 2.7 times our three year average F&D costs our (C$14.04) 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 C$19.84 per boe. Our three year average F&D costs are C$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 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'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.
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 and 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 six cold multilateral 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 flowback 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 and Three Forks development in North Dakota, we drilled 7 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 rate 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 average 2,500 barrels per day. This is the highest quarterly rate of production we have experienced North Dakota which has 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 C$520 million which includes C$90 million for our two long-term thermal projects, our 15 well CSS module at Cliffdale and 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 C$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 reduced 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 four 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 plan 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 90 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 C$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 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 C$24 per barrel and improving in 2014 to around C$22 per barrel.
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 C$98.46 per barrel U.S. For the full year for 2013, 40% of our net production at an average price of C$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 C$215 million to our shareholders as dividends and reduce our debt by over C$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 approved SAGD project at 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.
Brian G. Ector - VP, IR: Thank you, Jim, for those comments. At this time, operator, we would like to open the lines for any questions.
Operator: Mark Friesen, RBC Capital Markets.
Mark Friesen - RBC Capital Markets: 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 netbacks that you realized in the fourth quarter?
W. Derek Aylesworth - CFO: Yeah, Mark, it's Derek here. I think what I would tell you is in Q4 of 2012 we had net uptick relative to the next best alternative at the time that we could have sold those barrels (for about) C$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 Friesen - RBC Capital Markets: Sure. And with just 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?
James L. Bowzer - President and CEO: Yeah, Mark, this is Jim. We typically don't see a need to do that. The infrastructure that is in place that we delivered to has been paid for by others. It's really not where we want to spend our capital. If indeed it continued 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 Friesen - RBC Capital Markets: Okay. Changing gears here, you had 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 - President and CEO: 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 opportunities that it may be more valuable to someone else in their hands versus ours, and so if we run into those kind 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 Friesen - RBC Capital Markets: And just 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 return to, say, Q4 levels of 55,000? Like, is that end of Q1, is that a Q2 type of target? When does this turn around?
James L. Bowzer - President and CEO: 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 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 a little bit about the Q1 plans that we had in place. Marty, do you mind commenting on that?
Marty L. Proctor - COO: There were certainly some unique circumstances in Q1 for us. For example, at Peace River we are drilling on previously undeveloped sections of land at Harmon Valley and that required significant lease construction and new roads and of course that led to additional regulatory attention. And 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 the couple of larger than usual pad sites for drilling this year, and that require some of our applications to be submitted on a non-routine basis. For example, we've got one pad that's got 9 wells on it, which is the largest pad ever for us in our – for our core multi-lateral drilling. Most of our previous drilling had only three or four pads, so that's 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's a relatively minor change in our strategy. As Jim said, we've got our roads and our leases constructed and the 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. And since we are drilling from pads, we expect we can drill through a spring breakup this year at Peace River. It should also be noted that at our Kerrobert 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, just to reaffirm, that we are on track to meet our annual guidance of 56,000 to 58,000 barrels equivalent per day.
Mark Friesen - RBC Capital Markets: So, if I understand you correctly the fluctuation going to Q1 is purely a timing issue it is got nothing to changes to decline rates in any of your producing areas?
James L. Bowzer - President and CEO: That's right.
Operator: Jeremy Kaliel, CIBC.
Jeremy Kaliel - CIBC: I think a couple of my questions have already been answered by the first speaker. So, maybe I'll just taking a little bit further, would you be able to give us some guidance on expected production levels for Q2, even just a range to get the sense of what kind of a recovery we should expect? Could you actually give us what your corporate decline rate is and as well as your decline rate at (indiscernible) and just maybe reaffirm whether or not there has been any changes recently?
James L. Bowzer - President and CEO: 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 have 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 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: Gordon Tait, BMO Capital Markets.
Gordon Tait - BMO Capital Markets: Approximately, how many years of drilling inventory do you have for these cold wells are sealed given the pace you're currently drilling them at?
Marty L. Proctor - COO: 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 looking at about six years of inventory.
Gordon Tait - BMO Capital Markets: And I guess by that time Cold Lake, Kerrobert should be up and running to sort of and Harmon Valley as well, is that right?
Marty L. Proctor - COO: Yeah. Well, of course, Harmon Valley we're 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'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 above over 300 sections of land, these stratigraphic test wells are going to identify additional development opportunities for the future.
Gordon Tait - BMO Capital Markets: And maybe this question is for Jim. I know you've been quite clear about the – and fairly constructive on the potential for these WCS, WTI differentials to narrow over time and rails (putting out). So, like what would you share; maybe what do you see sort of going on in the overall market that would lead you to continue to (lead) that with our without Keystone XL?
James L. Bowzer - President and CEO: 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 today a lot of those crudes are being purchased off a water at near WTI prices in order to fulfill those needs and the Canadian market is setting here and soon as the transportation gets unlocked which I believe 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 unlocks the Bakken and it is 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.
Gordon Tait - BMO Capital Markets: Just little more background question. I presume that when oil gets into the U.S. network if you get it across the border by rail or something. It doesn't necessarily have to be transported all the way down to Gulf I presume there is lot of delivery points. Within that even the pipeline network which is fairly fundable and you just have to get it to some place where it can be delivered and then moved by some other means. Did that happened as well in that market?
James L. Bowzer - President and CEO: That is a fair assessment. And to further expand on that just a bit you 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 various ways you can connect in. I think you will see more of that to come with Cushing that should get, I believe, will get cleared this year. That's going to open up news ways for Western Canadian Select to get into different points as well.
Operator: Cristina Lopez, Macquarie.
Cristina Lopez - Macquarie: Just a couple of 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 cost as you start railing more volumes as well and having to more through long haul trucking to get to the railing loading facilities?
W. Derek Aylesworth - CFO: Cristina, it's Derek. Directionally, that's correct. The single biggest contributor to the increase in transects is as you identified the cost of truck volumes out of Seal to delivery points. As steel 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 real deliveries. The trucking distance to rail loading points is about the same as the pipe loading points with the incremental cost that unloading trucks had a real delivery points a little bit slower. So you're paying standby fees and those kind of things. But directionally you're correct, it's likeliest to increase as we continue to increase volumes at Seal.
Cristina Lopez - Macquarie: 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 - CFO: That's correct. Although I think, net-net obviously when you're moving to rail we're accessing a higher market, so there's an end contribution to us, but the transects component does go up.
Cristina Lopez - Macquarie: And so then 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 being 100% dedicated to pipe?
W. Derek Aylesworth - CFO: All things being equal, it kind of breaks even around a C$15 differential.
Cristina Lopez - Macquarie: The big assumption there is all things being equal, which in the last 12 months is outside of our norm?
W. Derek Aylesworth - CFO: When I say that, Cristina, I mean blending cost; what's the cost of condensate, what is the WCS environment, all of those kind of things. But in the current kind of pricing environment, C$15 WCS differential means you're neutral between pipe and rail.
Cristina Lopez - Macquarie: And that includes that increased transportation expenditure in there?
W. Derek Aylesworth - CFO: That's correct.
Cristina Lopez - Macquarie: And then with – and 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?
Marty L. Proctor - COO: Cristina, it is Marty. It's 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've budgeted and just to execute as efficiently as we can and that has led to us spending our capital allocation a little early. This year because of some of the start-up and (indiscernible) work that we did at Peace River, we're probably level-loading more than past years, but it's still likely will tapering off near the end a little bit.
Cristina Lopez - Macquarie: 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 since 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?
James L. Bowzer - President and CEO: Yeah, 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 of that, yet we should – we certainly have the projects to continue at about the same base load that we have.
Cristina Lopez - Macquarie: And let me 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 where we see a structural narrowing of heavy oil differentials, order of priority; what 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?
James L. Bowzer - President and CEO: 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 intention.
Operator: Thank you. Mr. Ector, we have no other questions registered at this time. Please go ahead, sir.
Brian G. Ector - VP, IR: 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.