Baytex Energy Corp (BTE) 2010 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Baytex Energy Trust third quarter results conference call. I would now like to turn the meeting over to Mr. Derek Aylesworth, Chief Financial Officer. Please go ahead, Mr. Aylesworth.

Thank you, Jeanette. Ladies and gentlemen, while listening, please keep in mind that some of our remarks will contain certain forward-looking statements within the meaning of applicable securities laws. We caution that assumptions used in the preparation of such information, although considered reasonable by us at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors, many of which are beyond our control. We refer you to the advisory contained in the press release issued today regarding forward-looking statements and the material factor that could cause actual results to differ materially from the conclusion, forecast, or projections in the forward-looking statements. There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast. Unless otherwise noted, all amounts are stated in Canadian dollars. I will now turn the call over to Tony Marino, Baytex's President and Chief Executive Officer.

Thank you for participating in our conference call today to discuss our third quarter 2010 results. I will start with our operational discussion, Derek will follow with our financial results, and then I will make summary comments before opening the conference to your questions. Our operating results in the third quarter were among the best in our Company's history with record production levels and our third highest funds from operations to date. The only two higher quarters for FFO were in 2008 when oil prices were near their all time highs. A record production of approximately 44,800 BOE per day in Q3 was an increase of 5% from year ago levels and 2% above our previous record in the second quarter of this year. Q3 2010 was the seventh consecutive quarter in which we have recorded production growth. Oil production in Q3 was particularly strong, increasing 9% over a year ago levels and 2% above second quarter levels. We continue to contain costs during Q3. Unit operating costs were CAD10.58 per BOE in Q3 as compared to CAD10.64 per BOE in Q2 2010. Comparing the first nine months of 2010 to the same period of 2009, unit OpEx was CAD0.01 per BOE higher than in the 2009 period. Our E&D CapEx in the third quarter was CAD62 million, bringing our nine-month E&D CapEx to CAD182 million, which is approximately three quarters of our budgeted amount of CAD235 million for the full year 2010.

As Derek will discuss later, with the exception of the impact of leaks on the Enbridge 6A and 6B pipelines, heavy oil pricing continued to be relatively strong in Q3, continuing the new structural regime for heavy oil that has been in place since about the end of 2007. After the resumption of service online 6A and 6B, market prices for the Hardest T heavy marker, which represents the value of raw heavy oil, are currently trading for the month of December 2010 at about CAD68 per barrel reflecting a differential of approximately 16%. Our Q3 drilling program of 13 heavy oil wells including four at Seal will be producing into this price string. Production at Seal averaged 10,100-barrels per day in Q3, a 13% increase over Q2 levels. All four of the new wells were multi-lateral horizontal wells with a total of 34 laterals drilled. Average initial 30 day rate for the new wells was about 480-barrels per day per well. In addition, we reentered one existing well, drilling additional laterals, which increased production from a pre-work over level of 38-barrels of oil per day to approximately 490-barrels of oil per day.

In the fourth quarter of 2010 we plan to drill about 25 wells in Lloydminster and as additional laterals to three of our existing single lateral wells in Seal. The most exciting results we have to disclose are in two thermal projects at Seal and at Kerrobert. Our success in these thermal projects is in large part due to our organization's growing technical capability in thermal EOR. We have been building this thermal expertise in Baytex since 2005 and in anticipation of ramping up our thermal investments in production. I might add that this thermal EOR has been the primary emphasis in my own engineering career and I'm very impressed with the thermal engineering, geoscience and production operating staff we assembled. Both projects that I am going to discuss were very successfully executed and that gives me confidence in our ability to effectively increase our investments in thermal EOR going forward.

Starting with Seal, we conducted a second successful cycle steam stimulation or CSS pilot during the second and third quarters. This test was in the Cliffdale area Seal located seven miles to the east of our first CSS pilot in the Harmon Valley area. Cliffdale is an area in which, at this point, we do not envision large scale coal development. Oil viscosities at this is at the subsurface elevation steamed at Cliffdale are approximately four times higher than in the Harmon Valley test and prior removal of cold oil through primary production at Cliffdale was minimal. The objectives of the test were four fold. One, to prove that steam injectivity in the bottom half of the Bluesky Sand and that higher oil viscosities than in the earlier Harmon Valley pilot would hit target levels. Two, to conduct a multi-cycle test with improvement in injectivity in production in the second cycle. Three, to validate our numerical reservoir simulation so that long-term performance on subsequent cycles can be more accurately predicted. And, four, to achieve economic levels of production and steam oil ratio or SOR. All of these objectives were met in the Cliffdale pilot test. The cost of the pilot was CAD7.7 million which included installation of much of the structure and steam plant to be used in a permanent project at this site.

At Cliffdale, because of the higher oil viscosities and minimal coal production prior to the steam test, we conducted two mini cycles to gradually heat the reservoir and thereby ramp up injectivity. From the first cycle to the second cycle we recorded a 20% increase in injectivity. Validating, we believe, our report to gradually heat the reservoir at relatively low injection pressures. From cycle one to two we achieved an increase in peak oil rates and most importantly we are achieving a significant decrease in SOR.

SOR is the key measure of thermal efficiency and thermal operating economics. The lower the SOR, the better because it means that less natural gas fuel is required to produce a barrel of oil. The average SOR in western Canada is around four, and our first Cliffdale cycle our SOR was about 2.7. In the second cycle projecting production to the end of the year when we plan to steam the well for cycle three, we believe we will finish at an SOR of about 1.9. For further detail please see our updated corporate presentation on our website which includes a graph of production from the Cliffdale pilot.

Our numerical reservoir simulation indicates that injectivity, oil rate and SOR should continue to improve on subsequent cycles as heating of the reservoir progresses. We're in the permitting phase tore the first module of commercial development which we plan to have in place by the end of 2011. Costs for the remaining nine wells and completion of the infrastructure and steam plant for this module is projected to be approximately CAD23 million.

Shifting to Kerrobert, on September 30, 2010, we closed the sale of our 50% interest in lands and wells comprising Phase I of a Thai in-situ combustion project. We received CAD18 million and a gross overriding royalty on the divested lands. The disposition of the Thai project will have a negligible effect on production, capital expenditures and funds from operations for 2010. We retained our 50% interest in the area of mutual interest surrounding the Phase 1 lands. Our other Kerrobert interest, including our 100% working interest in our SAGD project, were unaffected by the sale. In our Kerrobert SAGD project, we placed a new well pair on production late in the third quarter. Subsequent to the end of the quarter, this well pair produced at a 30 day average rate of approximately 1000-barrels per day. The SOR for the new well pair is currently 2.2, and we expect that SOR to remain relatively constant for some period of time. Costs of the well pair was CAD6.8 million which included an expansion of the steam distribution system to serve future well pairs. Through the remaining life of this project we believe that we can drill 11 additional well pairs at a cost of approximately CAD3.6 million per well pair.

Turning to light oil development, we advanced several of our light oil resource plays in the quarter. Briefly on our Cardium play in Alberta, we drilled two horizontal wells in the Pembina area which will receive multi-stage fracture treatments in the fourth quarter. A Cardium well drilled in the first quarter was put on production during the third quarter at a 30 day average peak rate of approximately 175 BOE per day. In our Bakken/Three Forks play in North Dakota, we participated in the drilling of nine 3.6 net horizontal wells in Q3. Due to constraints in fracturing services, only three of these wells were fracture stimulated during the third quarter and none of the third quarter wells was on production long enough to establish 30-day peak production rates. Four wells that were completed earlier in 2010 established 30 day production rates in the third quarter. Two Baytex operated wells, drilled on 640-acre spacing units, produced to the 30 day average peak rate of approximately 250-barrels per day per well excluding down time. Two partner operated wells drilled on 1280-acre spacing units produced at a 30 day average peak rate of approximately 400-barrels per day per well. To date in this play, the nine Baytex operated 640-acre wells that have sufficient data to establish 30 day peak rates have averaged 270-barrels per day per well. To date, five partner operated 1280-acre wells averaged 210-barrels per day per well for their peak 30 day periods. As of the end of the third quarter six 2.5 net wells were awaiting fracture stimulation.

In the fourth quarter of 2010 we plan to participate in the drilling of seven gross 1.9 net wells, in the Bakken/Three Forks including our first operated 1280-acre well. The non-Bakken/Three Forks building in North Dakota, Baytex participated in one gross 0.4 net dry holes targeting the Lodgepole formation, a shallower conventional zone. In our Viking play in Alberta, we drilled four horizontal multilateral wells in the third quarter with open hole, unstimulated completions. Three of the wells were placed on production during the quarter and have established 30 day average peak rates of approximately 90-barrels per day per well. To date in the Alberta Viking play, we have drilled nine wells with sufficient history to establish a 30-day average peak rate of approximately 110-barrels per day per well. Going forward in this play we are seeking down spacing approval on certain parcels of land so we can test the use of eight lateral horizontal wells. These wells would essentially double our down well hole density.

In our Viking play in Saskatchewan, our recent drilling has been primarily focused on step-outs to validate licenses acquired during 2008 that were approaching expiring. Our drilling has now validated all of the licenses acquired at that time, converting them to leases with new five-year terms. During the third quarter, we drilled two horizontal Viking wells. Wet conditions delayed completion of the activities one of the wells. The second well was drilled in the Herschel area, which is a very distance step out, approximately 13 miles to the east of the Dodsland field. The Herschel well produced at low oil rates after hydraulic fracturing. Given that this is such a long step out, it doesn't have a major impact on our plans or expectations for the Viking and Saskatchewan. To date in the Saskatchewan Viking play, excluding the sub-economic well at Herschel, we've achieved a 30-day average peak rate of 75-barrels per day from five wells that have been fully completed and placed on production. We believe we have approximately 200 high quality locations remaining in the Viking and Saskatchewan.

Let me finish with our guidance update. We're maintaining our E&D CapEx guidance of CAD235 million for this year. With respect to production, at the last quarterly call we increased guidance for full year 2010 to arrange of 44,000 to 44,500 BOE per day. We're now tightening up our guidance to the upper half of that range or 44,250 to 44,500 BOE per day for the full year because of stronger than expected production results to date. I will now turn the conference over to Derek to discuss our Q3 financial highlights.

Thanks, Tony. During the third quarter of 2010 we generated funds from operations of CAD112.8 million, an increase of 3% over the prior quarter and 27% over the third quarter of 2009. These results were largely driven by increased sales volumes following our record production in the quarter. During the third quarter heavy oil differentials averaged 21% of WTI which was wider than the previous quarter as a result of the pipeline delivery issues following the leaks on the Enbridge lines. Upon the completion of the repairs and announcement of resumption of operations those pipelines, differentials returned to about 18% of WTI.

Our hedging program largely mitigated significant financial losses from this temporary widening of differentials. We estimate our revenues in Q3 were about CAD2.5 million lower due to the impact of the pipeline leaks on differentials. More than offsetting this revenue loss in the quarter was a reduction in the blending costs of our heavy oil sales. This reduction resulted from the availability of a lighter diluent, meaning we needed to purchase less condensate volume to blend with our raw heavy. At the same time, the cost to purchase condensate came in lower than in the prior quarter. Together, the lower volume requirement and lower price resulted in a lower blending cost of approximately CAD3 per barrel as compared to the second quarter of 2010. We expect that for the foreseeable future there will be a continued availability of lighter diluent as a result of the commencement of shipments the Southern Lights condensate line, and as such, believe our blend ratio will remain relatively low.

As with many things in the heavy oil pricing recently, we see the negatives, such as the pipeline break, as being temporary and the positives, such as the ability to reduce our blending costs, as more durable. We have continued to expand our hedging position including transactions entered into subsequent to the end of the third quarter. We now have hedging coverage in place for 2011 of 26% of WTI at an average price of CAD86.31 per barrel and 35% of our heavy oil differential exposure. Under the majority of our differential contracts, we will sell Western Canadian Select, WCS, at a fixed dollar discount to WTI at an average discount of $15.53 per barrel. In the balance of our contracts, a differential is expressed as a percentage of WTI. Combining these types of contracts are 2011 differential hedges result in a weighted average discounted of 17.3% of WTI based on the current strip for 2011. In addition, we have contracted to sell a portion of our WCS volumes beyond 2011, resulting in the sale of 2,000-barrels per day for 2012 at a fixed dollar differential of $16.50 a barrel and 3,000-barrels per day for January to June of 2013 at a fixed differential of $17 per barrel. Finally, we have also hedged to sell 28% of our natural gas exposure at an average of CAD5.16 per MCS and 25% of our US dollar currency exposure at an average exchange rate of $0.9365 per Canadian dollar. We will continue to monitor the market and, where appropriate, will add to our hedging program.

Our balance sheet continues to be very strong. Total monetary debt at the end of the third quarter stood at CAD536 million, down CAD17 million from the end of the previous quarter. As we continue to fund our distributions and capital program from internally generated funds from operations. This net level represents 1.2 times our Q3 funds from operations on annualized basis and leaves us with about CAD168 million of available undrawn credit line. We believe our debt loads are very manageable and our available liquidity is sufficient to meet our operational and financial needs.

We have recently announced our planned conversion from the current trust structure to a corporate legal form pursuant to a plan of arrangement. A special meeting of the unit holders is scheduled for December 9, 2010, to vote on the plan -- the terms of the plan of arrangement. An information circular regarding the plan has been mailed to the unit holders. Assuming receipt of all required approvals, we expect that the conversion will be completed on December 31 of 2010. We look forward to the successful continuation of our growth and income model into the corporate era. I will now ask Tony to provide as concluding remarks.

Thank you, Derek. Let me briefly finish today by reviewing the significant changes in our business environment and activity since our last conference call in August. First, we're benefiting from an improvement in oil prices. Since our last call in mid-August, prompt WTI prices have moved from $71 a barrel to $87 per barrel, with that increase partially offset by strengthening of the Canadian dollar. The improvements in prompt WTI and the forward strip, if they are sustained, auger for higher cash flows ahead.

Second, in our view, the limited price impact of and rapid recovery from the Enbridge leaks indicates the fundamental strength of the heavy oil market in Canada. To remove 800,000-barrels per day from transport capacity and to only peak out at a 31% heavy oil differential, and then to be back to an 18% differential a month after assumption of service, speaks to fundamental strength in heavy oil pricing.

Third, we have taken advantage of improvement in WTI and differentials to dramatically expand our hedging program. As Derek said, we now have approximately 26% of WTI exposure and 35% of differential exposure hedged for 2010. In the case of differential, our fixed price swaps for 2011 translate to approximately a 17% differential based on the 2011 WTI strip. Even more importantly, we've been able to begin placing differential in over the counter swaps for 2012 and 2013 at the equivalent of an 18% differential. Not only does this mitigate volatility of our cash flows, but it also provides insight into the heavy oil market's confidence in long-term differentials. In addition, as Derek also discussed, we have a significant portion of our natural gas and Forex exposures hedged.

Fourth, operationally and strategically we have made significant advances in the demonstration of the viability of thermal development at Seal with our second successful CSS test. In addition, our success in our first Baytex operated SAGD pair at Kerrobert gives us more confidence in our organizational capability to expand our thermal operations.

Finally, we are moving steadily down our path to conversion to Baytex Energy Corporation at the end of this year. We believe the conversion may be advantageous in terms of market acceptance of our sustainable growth and income model. This is our last conference call as Baytex Energy Trust. We have been very successful in the trust form. We've had the highest total return of our trust peer group in our seven years plus tenure as a trust. Focusing on the most recent period, we had the highest total return in 2009 and also year-to-date in 2010. As of yesterday's close, our year-to-date total return, including reinvestment of distributions, has been 41%. It has been an honor for the employees of Baytex to serve our unit holders during the trust era. It's also been a rewarding challenge to engrain the doctrine of capital efficiency that has been central to our success during the trust era. We think the capital efficiency is the only way to achieve lasting success in our very capital intensive industry. Capital efficiency is less than we intend to bring with us into our new corporate era. We're looking forward to continuing to work for you as Baytex Energy Corporation. Ladies and gentlemen, thank you for your attention. We're open for questions.

(Operator Instructions) Our first question is from Gordon Tait from BMO Capital Markets. Please go ahead.

Good afternoon. Tony, I was wondering -- now that you've had thermal pilots in the Harmon Valley and also Cliffdale, two things, first of all, do you have any change in where you think the peak production might level out, sort of on a per pad basis, and secondly, does that help you indicate where you're going to situate your first ten well pads?

Thanks for that question, Gordon. The peak rate for a ten well module is not very much changed from the earlier simulation that we did at Harmon Valley as we do the new simulation in Cliffdale. In other words, we've got about the same projected peak rates based on the back match and then future simulation of continuing cycle steam project in either area. That's actually another thing that we detail on our corporate presentation, our corporate PowerPoint that is on our website, and these peak rates are roughly the same -- about 1,800 or 1,900-barrels a day for a ten well project. And so since the peak rates are similar, that particular parameter is not really a driver of where we would locate the first commercial module. The Cliffdale area tends to be tab a bit thicker pay. It is not an area that we're currently engaging in coal development in. And so I think that that is going to prove to be the best place for us to locate our first ten well module.

And then you would continue to drill cold wells I guess further East at Harmon Valley?

Yes. We're going to continue coal development in Harmon Valley. It is to the west of the Cliffdale area, and at some point in the future I am sure we will conduct thermal there as well.

And just switching to the Bakken/Three Forks, you mentioned that you had difficulty getting wells completed. Can we expect costs going up? Are there going to be cost pressures in that area?

There is a shortage of pressure pumping equipment in North Dakota. As a result, operators are having to wait quite a while to frac their wells. And whenever you have that situation you're probably going to have increases in service prices. Roughly to date we have been able to offset that just with improvements in our time efficiency. It is possible that we could end up with overall increases in well costs going forward.

And then, just last question, on the 1280 well, can you take a stab at or maybe give us an indication what you think the EURs might be on a 1280?

You know, there is not a huge amount of history, but I don't think it would be unreasonable in this area that we're working in to think that the increase in EUR might be comparable to the increase in the 30-day average peak rates. And that's about a 40% to 50% increase in EUR. Excuse me, in peak rate. And so I think that you might have a commensurate increase in EUR.

Thanks.

Thank you. Our next question is from Jason Frew from Credit Suisse. Please go ahead.

Hi, Tony.

Hello, Jason.

I was just wondering if we can step back a little bit from the granularity in your light oil business, and just maybe think about -- or maybe you could provide some insight on where you think the inflection point is in that business in terms of it being a flat business to a growth business?

Light oil grow -- light oil volumes overall are now growing slightly. Over the longer term, I think that we'll probably have roughly the same growth rates in light oil as we'll have in heavy oil. And that, in fact, is one of the purposes of putting the light oil projects in place over the past few years to provide that product mix diversity within the oil complex. And roughly keeping the same proportion of heavy oil to light oil production. The light oil production in our company has several components. There are conventional light oil areas, a number of them water floods, that are on the decline. There is a component that is NGLs that is slowly on the decline, too, along with our natural gas production. And then there is the growth component in the resource plays. And so what we've had to do is just reach the point where the growth in the resource plays could offset the declines in the conventional light oil, primarily water floods, and in the NGLs and that's the point that we're reaching now.

Thanks.

Thank you, Jason.

[ Operator Instructions ] Our next question is from Roger Serin from TD Securities. Please go ahead.

(Inaudible) over the last two or three years and what do you need to do in terms of gathering pipelines? Does it make sense to stop trucking? Could you talk a little bit about sort of different levels that you need to reach from a production point of view to move that forward?

Roger, you didn't come through on the first part of the question. If you could start over, please.

Sure. I am just wondering about infrastructure at Seal. You doubled production in the last year. You were at 10,000-barrels a day. What do you need to think about doing from an infrastructure point of view gathering batteries and pipeline -- larger transmission pipelines?

The area actually is pretty well served with pipeline capacity and, in fact, the pipeline capacity is going to be going up with the completion of Pembina pipeline project over the next year or so. Our disposition from the field area is in trucks. And we take them sometimes to longer haul markets and also to shorter haul markets, for example, in the Nipisi and High Prairie and Edmonton areas. And I think that this form of disposition will work quite well for us for the foreseeable future. For example, putting in the installation of the Pembina pipeline project gives us another place at which we can access the Nipisi market. So I actually think we're in pretty good shape going forward.

Okay. So I want to touch on one other thing, and it is really capital allocation based on your IR presentation. Really, all of your heavy oil projects are better in terms of IRRs at least than your say Bakken/Three Forks, and even maybe your Viking, even thermal. And you talked a little -- just last question about continuing to grow your light oil, but it seems to me that it is really only the Viking light oil that seems to compete with your heavy oil projects. So can you speak a little bit about capital allocation in light of that?

Yes. Kind of ties into the -- little bit to the question that we had earlier. All of the projects that we mentioned here, the three different -- actually four including Cardium light oil projects, the Seal thermal, the Lloydminster cold and the Seal cold, all have rates of return well above our cost of capital And we try to diversify the capital program so that we have a reasonable diversification of project risk. The biggest single project in the Company of any one field is in Seal. It does have the highest rates of return for the Seal coal development and it does make sense that most of the capital. But we're never going to put all of our capital into one project. Each of the projects has their own learning curve that we're moving up and so you have to capitalize them to some degree to continue that progress on the learning curve. And to give you an example of that, Seal thermal, at current prices we probably have around a 50% pretax IRR on thermal investment. And that is quite a bit less than the cold projects in both Lloydminster and Seal. Nonetheless, there are many, many thermal barrels available to us in the future and so we to want get the first project going to start to realize some of that MPV that is available on a very large number of barrels. The coal projects -- excuse me, the light oil projects also have a very large resource target. And we want to steadily ramp up that development so that we can, not only maintain the product diversification in the Company, as I mentioned earlier in an answer to the -- that other question, but also so we can start to realize some of the MPV per barrel that's available in those projects and continue to advance those as we go forward.

Okay, last question. Is the Mowry Shale play dead or will you spend more money on in it 2011?

I don't think we're going to have any significant spending on the Mowry. There are other targets potentially on that leasehold in Wyoming. The Mowry doesn't appear to offer very good rates of return the way the project results have been so far. I think not only for us, but for other companies as well.

Thanks very much. Good quarter.

Thank you, Roger.

We have no further questions at this time.

Thanks again for your participation in our call. We appreciate your interest in Baytex.

Thank you. The conference has now ended. We thank you for your participation.