Baytex Energy Corp (BTE) 2008 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Baytex Energy Trust 2008 third quarter results conference call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded Thursday, November 13, 2008. I would now like to turn the conference over to Derek Aylesworth, Chief Financial Officer. Please go ahead, sir.

Thank you. Ladies and gentlemen, while listening to this conference call please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable security laws. We caution that the 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 regarding forward-looking statements in our press release issued today for additional information about the assumptions used in the preparation of the forward-looking statements, and the material factors that could cause actual results to differ materially from the conclusion, forecast or projection in the forward-looking statement. 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. I would like to turn the conference call first to our CEO, Ray Chan.

Thank you, Derek. Ladies and gentlemen, thank you for taking time to participate in our conference call. With the recent development around the world and in the commodity and financial markets, many observers may say that the third quarter results are obsolete and not relevant for gauging the future performance of the reporting entity. I strongly feel that this sentiment is not the case for Baytex. Our record production and financial results are good indicators of the efficiency of our asset base and our potential in generating class leading performance under a healthy price environment. We achieved record production through one of the most modest E&D capital programs in our sector and we actually generated over $40 million of surplus cash after paying for this program and distributions to unit holders. But more importantly, we utilized this surplus cash to help fund two new and exciting initiatives that will allow Baytex to pursue profitable production and reserve growth in light oil for many years to come. Combine these attributes with the successful thermal pilot test at Seal and the implication it has on this large resource asset, our accomplishments during this quarter are highly relevant in assessing the future of Baytex. I will turn the conference over to Tony and Derek to provide you with a more detailed review of our quarter.

Thank you, Ray. Baytex had a very strong operating quarter in Q3. Both of our Canadian business units, our heavy oil unit and our light oil and natural gas unit had record production levels in the quarter and our US unit registered its first reporting period with meaningful production following the closing of a major land acquisition in North Dakota. We achieved an average production level of about 42,500 BOE per day in Q3, up 12% from both the second quarter of 2008, and the third quarter of 2007. There were several drivers for the production increase.

The largest factor was the inclusion of the production from our acquisition of Burmis Energy which we closed in June of this year. Burmis accounted for approximately 3600 BOE per day of our production increase. This production level for Burmis is in line with our preacquisition forecast. A second factor was US production of approximately 400 BOE per day with the bulk coming from production associated with the North Dakota acquisition. Finally, as I mentioned earlier, heavy oil production reached record levels due to continued development at Seal and in the Lloyd area.

Strong production performance continues in each of our key assets. Seal hit a record quarterly production level of approximately 3900 BOE per day in the third quarter. We began drilling a total of nine new wells in the third quarter which will go on production during the fourth quarter. Though it is very early in their producing history, by all indications all nine are going to be successful, continuing our record of 100% drilling success in Seal. We have now drilled 44 horizontal producers in the project.

On September 4, we announced results of our cyclic steam stimulation pilot at Seal. To update you on that project, five months after steaming our pilot well is currently producing at rates that are double its projected rate on coal primary production. Our thermal efficiency continues to improve, with an incremental steam oil ratio or SOR, of 1.7 at present. Lower SORs represent higher thermal efficiencies and better project economics. I'd like to point out three things about the SOR we've achieved in this project. First, our SOR is about one-third to one-half of the SORs recorded in many steam enhanced oil recovery projects in Canada, indicating relatively high thermal efficiency in our pilot.

Second we have calculated our SOR in the most conservative fashion possible by only counting oil production that is incremental to projected coal primary production. And finally, our SOR will continue to decrease as the pilot well continues to produce above projected cold primary rates. Based on results from this test, we are proceeding with design of a commercial scale thermal project for Seal.

The Pembina Lindbergh assets we acquired in the second quarter of 2007 continue to perform well. During the third quarter we averaged over 6,000 BOE per day from these properties, which is significantly above the properties 4500 BOE per day production level prior to Baytex assuming operations.

Let me now shift to a discussion of two major light oil resource play acquisitions that we made in Q3 outside of our normal E&D CapEx program. The first and more significant play in terms of size is in northwestern North Dakota. We entered into an agreement with the private company to buy a 37.5% working interest in a large contiguous land block with an ongoing Bakken/Three Forks development program. The seller retained the remaining 62.5% working interest. In the transaction, we are acquiring 98,600 net acres of rights to essentially all horizons, plus initial production from the lands of about 300 BOE per day.

We paid the sellers $60.5 million US at closing in July, which translated to $61.2 million Canadian at the time of the payment. In addition, we will make a series of deferred payments to the seller totaling $46.5 million US over the next three years, with the precise timing dependent on the pace of development of the properties. That will bring the cumulative purchase price to $107 million US. Using a value of $80,000 US per barrel per day for the purchase production, that results in an acreage price of approximately $840 US per acre, which is relatively low for a Bakken/Three Forks project with proven productivity.

The Bakken/Three Forks and the project area has excellent characteristics for a light oil resource play. High quality source rock and a reservoir face who is equivalent to other successful Bakken/Three Forks projects. The project will be developed using horizontal wells with multiple hydraulic fracture stimulations. Well placement will usually be in the Sanish member of the Three Forks formation which is just below the Bakken.

This is a project that has proven productivity in wells already drilled by our partner and is economic based on that performance at current light oil prices of around $60 US per barrel. We believe well performance and economics will improve significantly as we move up the learning curve. It's a large project, offering the potential for 400 gross wells on one well per section spacing and we believe there is enough resource in place to allow future down spacing to two or more wells per section. At the present time we're developing at a relatively slow pace of 10 wells per year but we expect this pace of development to increase in the future.

The second project is in Southwest Saskatchewan. In this project we have acquired about 20,800 acres at 100% interest that are prospected for light oil development in the Viking formation. Also using hydraulically fractured horizontal wells. In this case the land was acquired through a combination of private and Crown leasing. The expenditure for the Viking land was $8 million Canadian, primarily in the third quarter. The Viking is a tight reservoir by conventional standards but actually relatively permeable by resource play standards. For several technical reasons it's a good candidate for multi zone fracturing using horizontal wells. We have encouraging results from a well that we have drilled and as in North Dakota we're confident that well performance will improve as we move up the learning curve. At quarter section spacing we have the potential to drill around 125 wells on the land we acquired.

In addition we want to make you aware of some other lands that we hold that are prospective for light oil horizontal development. We have prospective lands for Viking development that are already in our portfolio in Eastern Alberta, adding around 3,000 net acres to our total Viking holdings. We have a more exploratory program in the Mauri shale in the Powder River Basin in Wyoming where the development concept also is for multi zone fracturing of horizontal wells. In the Mauri shale play we have a 60% interest in about 15,000 gross acres or 9,000 net acres. There has been horizontal drilling by other industry participants near our acreage but results have not been made public.

Finally, on this topic, let me describe the purpose of putting these light oil resource plays in our portfolio. First of all, we expect them to be accretive to our NAV and our overall production profile. Our assessment is that these are very good projects based on results to date and we believe their performance will improve as we do more development over time. Secondly, over the long term, they will help balance the product mix developed by our overall capital program. We've demonstrated significant potential for both cold and thermal development at Seal and these new projects give us a significant light oil program to go with that Seal development.

To finish up on the operations discussion, let me discuss production and CapEx guidance. Given the strong production performance in this quarter, we're moving up our production guidance for the fourth quarter of 2008 to 42,000 BOE per day, an increase of 1,000 BOE per day from our previous guidance. We're also revising our E&D CapEx guidance for full year 2008 upward to $180 million Canadian, a $10 million increase from our previous guidance. The increased CapEx reflects development spending in the second half of 2008 on the properties acquired in North Dakota. Please keep in mind that this E&D CapEx figure doesn't include approximately $76 million Canadian and acquisition CapEx for the Bakken/Three Forks and Viking assets that we announced today.

In our fourth quarter E&D program, we'll finish drilling the Seal wells we started in Q3, continue our Lloyd area heavy oil development, participate in two to three wells in a 3D seismic survey in North Dakota and continue normal levels of light oil and gas development in Canada. We'll be presenting our 2009 CapEx program to our Board of Directors in early December. Once we have a Board sanctioned CapEx budget we'll provide guidance for 2009. I'll now turn the conference over to Derek to discuss our second quarter financial results.

Thank you, Tony. During the third quarter, the Trust generated record cash flow at $146.6 million. The fourth consecutive quarter of record cash flow results. This represents a 17% increase over the results of the second quarter, and the cash flow for the first nine months of $373.4 million is already about 30% higher than the full year 2007 results. The increase in cash flow over the second quarter can be traced to the growth in production in the quarter which Tony has already discussed and the continued very strong heavy oil pricing. Canadian heavy oil differentials averaged only 15% of WTI in the quarter and 18% year-to-date, as compared to 29% in both the third quarter of 2007 and the first nine months of that year. This improvement is a continuation of the positive trend in heavy oil pricing we have seen since early 2006, reflecting changing fundamentals in the heavy oil market and additional third party refining and transportation capacity come on stream.

Subsequent to the end of the quarter, differentials have widened out as we head into the traditionally lower demand winter months but fourth quarter differentials are markedly improved from those of one year ago. During the quarter our current oil sand projects at Seal worked project payout and the 1% prepayout royalty converted to a post payout 25% net profit interest. Looking ahead to the fourth quarter, at current commodity prices and considering projected capital spending, we estimate that this change will result in royalties increasing by less than $2 million when compared to what would have been payable under the prepayout regime.

In this time of market uncertainty, we are very pleased with the state of our balance sheet. We exited the third quarter with total net monetary debt of approximately $458 million. Which translates to less than one times trailing 12 months cash flow. Or approximately 22% of our current total capitalization. More importantly, we continue to have ample liquidity with access to approximately $226 million in undrawn credit facilities at the end of the quarter. The benefit of our strategy of maintaining significant levels of open credit were evident in the quarter, as we were able to fund the land acquisitions which Tony described without the need for external financing in this difficult market.

Since the end of the quarter, the world's equity, credit and commodity markets have experienced unprecedented levels of volatility. While the current environment is undoubtedly challenging, we are confident that our stable production base, supplemented by our consistent hedging program and financial strength will permit us to continue to profitably manage our business. I'll now turn the conference over to Ray for concluding comments.

Thank you, Derek and Tony. This third quarter of 2008 from the standpoint of Baytex development is undoubtedly the highlight of my ten years at the Company. The success of the thermal pilot at Seal and the acquisitions of the two light oil projects will ensure operating success at Baytex for many years to come. As Derek just said, our financial strength and prudent corporate strategies will allow us to manage through this current difficult environment and realize on the tremendous potential of our asset base for the benefits of our investors.

As we announced today I will be moving into the position of Executive Chairman in the beginning of next year. And Tony will be promoted to President and Chief Executive Officer at this time. We have built a strong and deep management team over the past few years. I'm happy to continue to be engaged in the strategic issues affecting our Company and to assist our management team in any way I can. It has been a privilege to lead this organization since our inception. I look forward to my new role and also for your continued support. Thank you for your attention and we're now open for questions. Operator?

Thank you. (OPERATOR INSTRUCTIONS) Our first question comes from the line of Jonathan Fleming. Please proceed with your question.

Hi, Ray and Tony. First of all, congratulations on your new roles I'm sure that will be exciting for both of you. I wonder if there -- if this is a good time tore you guys to give some incremental guidance with respect to the North Dakota properties? I guess I'm looking for better idea of what the capital costs for these wells are, what are the IPs the reserve information?

Yes, I can describe the well model based on current results. Well cost would be around $4.5 million US. IPs would be about 190 BOE per day and current model shows about 280 MBOE of EUR.

That's the kind of information I was looking for. That's perfect. Now, is there any challenges in that area with respect to access to equipment? I mean, in rigs as well as service equipment.

Oh, it's a busy area because the Bakken has ramped up so much over the last couple of years with the horizontal hydraulically fractured wells but we believe we can get all the equipment we need to conduct our program.

Okay. Good stuff, guys. That's an exciting new area and I really look forward to seeing the results that you guys can drive out of that. Thanks very much.

Thank you.

(OPERATOR INSTRUCTIONS) Our next question comes from the line of Roger Serin. Please proceed with your question.

Hi, guys, again, congratulations, Jonathan. Got a couple easy questions for you. First of all, could you give me the same stats, Anthony, on the Southwest Saskatchewan Viking?

We have a well model there. It doesn't have as much history behind it or, multiple tests, but currently we would say that the well cost would be about $1.45 million Canadian. IP in an initial test was about 70 barrels per day. Headed toward an EUR of approximately, we believe, based on just a little bit of data, 50 MBO. In both projects, actually, I do believe that the well performance model is going to move up over time because there is definitely a learning curve in these types of projects.

Okay. Great. And just give me better perspective, maybe I missed it in the note, in the deferred. Like are there expectations in terms of activity or in terms of results for the payment of the deferred amounts?

It is not dependent on the results of the project. It's kind of a complicated agreement. It's based on the pace that we drill at. As we drill, subsequent wells, we make additional payments to our partner in the project, the seller. There are certain election points that we can make if we want to stop making payments. There is no election for the seller to do that. We do, though, anticipate making all of the payments that we showed in the schedule in our quarterly release.

And is there any -- they're the operator so it would seem to me that they would drive the pace of development?

Well, they're the operator at this point in the project. Even the transfer of operations is -- has some complexity to it also. We're going to start operating the drilling and completion and equipping phase of some of the wells next year. And then once we have made all of these deferred payments, the project area is going to be split and we will have three-eighths of that area. We've already predetermined what these areas will be and it roughly corresponds to the working interest in the project as a whole. Our working interest of course is an undivided interest over the entire land block but it's most efficient ultimately to identify a discrete operating area, both for our partner in the project and for us.

I think this might be the last question. Can you give me a sense of royalties on the North Dakota stuff?

Yes. The royalties usually range from about one-sixth to 19%.

Thanks very much. Good quarter and again, congratulations, Ray and Anthony.

Thank you.

Thank you, Roger.

Our next question comes from the line of [Joseph Vanuto]. Please proceed with your question.

Can you give you us an idea of the prospective coverage of the present dividend level?

By your question, do you mean sort of the payout ratio on the current pricing? Is that what you mean, sir?

If you want to give us an income versus payout ratio, that would be all right, also.

Okay. Well, the third quarter payout ratio was listed in the press release at 50% before the dividend -- distribution reinvestment plan and 39% counting the DRIP participation.

Has that been typical of over the past year or so?

The 50% or so is very, very typical of our last three years payout history.

Okay. That takes care of it. Thank you very much.

Thank you.

There are no further questions at this time. I will now turn the call back to you.

Thank you, operator and I want to thank everyone for participating in our Q3 conference call and we look forward to talking to you about our year-end results in early March of next year. Thank you.

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your line.