Baytex Energy Corp (BTE) 2006 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Baytex Energy Trust 2006 first quarter results conference call.

[OPERATOR INSTRUCTIONS]

I would now like to turn the call over to Derek Aylesworth, Chief Financial Officer; Anthony Marino, Chief Operating Officer; and Ray Chan, President and Chief Executive Officer. Please go ahead, gentlemen.

Ladies and gentlemen, while listening, please keep in mind that our remarks in this conference call contain certain forward looking statements within the meaning of the Securities Act. 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 in other factors, many of which are beyond our control.

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 forecasted.

Thank you, Derek. Ladies and gentlemen, I'm Ray Chan. Thank you for attending our first quarter 2006 results conference call. I'm please to report that Baytex had another strong start to 2006. The two main issues that affected our industry in the first quarter were our rising costs and the lack of service availability impact on capital programs and cost of doing business, and two, the precipitous decline in natural gas prices. As our Q1 numbers will attest, we were able to successfully deal with these challenges.

In early January, we announced that we set a capital budget of $105 million for 2006, with 40% of that to be spent in the first quarter. We came pretty close to that, spending $44 million in Q1. Despite the warmest winter in recent memory, which exacerbated an already extremely tight service environment, we were able to essentially complete all the capital projects we set out to do in the first quarter. We still have a few gas wells drilled during the quarter that need to be tied in during the second quarter.

From the standpoint of cost and industry inflation, the cost of doing business in the oil patch is definitely on an upward trend. Our operating costs for Q1 were $8.74 per BOE, 7.8% higher than the $8.11 per BOE for Q1 of 2005, but 8.5% below the $9.55 for BOE for the fourth quarter of 2005.

The main reason for the quarter over quarter decrease is the sale of the Celtic [inaudible] production at the end of December, which had very high operating costs. We will continue to diligently control our costs and capital expenditures, and we will review the need for any potential adjustments to our capital budget after the second quarter results become available.

Alberta's [inaudible] gas price for 2006 for the last [inaudible] hit a high of $12.29 per MCF in December 2005, but due to warm winter weather throughout North America, rapidly declined to $6.51 per MCF in March of 2006. For the first quarter, our realized well [inaudible] gas prices averaged $8.36 per MCF, representing a 22% decrease from the average price in Q4 last year. Our average realized well [inaudible] price for crude oil was pretty similar for the two quarters.

Despite this drop in gas price, we reported a 7% increase in cash flow in Q1 to $70 million, setting a new high in quarter cash flow for our Trust. This is entirely due to the expiry of the lower price WTI hedging contract at the end of 2005. Our 2006 WTI hedging contracts where we have 8,000 barrels per day [inaudible] between U.S. $55.00 and $84.00 should give us ample downside protection and allow us to fully benefit from the current high oil prices.

To celebrate the expiry of the low price hedging contracts, we raised our monthly distributions beginning in January by 20% to $.18 per unit. Yet our cash distributions net our drip participation equated to a paid out ratio of only 53%, which should place Baytex amongst the lowest in the oil and gas income trust factor.

Our production average 35,319 BOE per day in the first quarter, in line with our target of averaging 35,000 BOE's per day in 2006. Our capital programs are planned out in such a way that we hope to have 30 constant production levels throughout the whole year.

Looking ahead into Q2, gas prices would likely average about 15% below Q1. However, WTI prices so far in Q2 are significantly higher than the $63.48 average in Q1. And more importantly, differentials for Canadian crude, both light and heavy, have improved substantially over Q1 levels. Overall, higher realized oil prices will most probably ensure that will continue to show growth in cash flow.

Our financial position is constantly improving, as well. For the remainder of the year, we expect cash flow from operations to exceed distributions and capital spending requirements. In other words, we are projecting a true operating surplus. Our debt is steadily coming down, as well, with a continuous conversion of the 6.5% convertible debentures and the foreign exchange gain on our U.S. dollars nominated subordinated notes due to the rising Canadian dollar.

Combined with a recent increase in our bank facilities to $300 million, we have excellent financial flexibility to manage our operations and pursue other business opportunities.

The price of our Trust units has performed very well so far this year. With rapidly improving fundamentals, we are confident to be able to continue delivering superior returns to our unit holders.

Ladies and gentlemen, thank you for your attention. We are now open for your questions.

Thank you. [OPERATOR INSTRUCTIONS]

Our first question comes from the line of Jonathan Fleming from Sprott Securities. Please proceed with your question.

Following the Shell BlackRock announcement, we're trying to come up with a valuation for your Seal assets, and looking at your corporate presentation dated the 18th, your further Seal play say that you have 4 million proof plus probably barrels booked based on 20 wells. So my question is are these 20 wells representative of the whole play based on the additional information that you have from your strat. test wells and other sources?

Jonathan, this is Tony. I would say that the 20 wells that we have booked at Seal currently are representative of the Western portion of the play that we have delineated for coal development. In the remainder of the play, over time we will probably find that we have a number of other areas to develop using coal production methods. I think though it is too early to say if that kind of reserve level per well would occur in those other areas, as well.

Over the longer term, I think the results of the potential for thermal development, of which we have not booked any reserves, and that could also apply to several parts of the Seal leasehold.

That's good, Tony. Can you tell us the recovery factor that [inaudible] used on your reserves that you've booked so far?

It was approximately 10% for the portion of the interval that is amenable to cold production.

Can you give any estimate of the total original oil in place on the Seal lands?

I think the best way to approach this probably would be to talk about - you're going to have to digress just a little bit and talk about the two different types of potential production out there. The first is the cold production, which in certain portions of a leasehold is going to be possible, of course, without the use of steam injection, and that cold production method would probably be applicable to perhaps a third of the total oil in place in the Blue Sky interval in those sections where we undertake that primary development.

If you look at the entire interval, the portion that would be potentially amenable to both cold and thermal production, we have perhaps as much in certain parts of the field as 65 million barrels of oil in place per section. Now, by no means have we delineated the entire block, and we're certainly not going to suggest that thermal methods would be applicable to the entire leasehold position that we have. But to give you an idea of the oil in place in the areas that we've delineated thus far, if you consider both the portion of the Blue Sky oil sand that would be applicable to cold and to heavy, that would be the oil in place.

That's really helpful. One final question, can you provide any more color on any kind of a pipeline project that might go forward then in the timing around such of a project?

Jonathan, we're definitely working with other area operators to see what is the best way to sell the oil. But one good thing about it is we're dealing with oil. So at the end of the day we may not necessarily just have to move the oil through pipeline alone; we can easily put the oil on trucks and take it to the delivery point to get us best net back. So we are still looking at that, and obviously, the change in ownership of the current infrastructure from BlackRock to Shell is going to change the discussions we have so far. But we are quite confident that in time we will be able to work our solution that is good for Baytex.

Okay. Thanks for answering all of my questions.

[OPERATOR INSTRUCTIONS]

Mr. Chan, we are showing no further questions at this time.

Again, ladies and gentlemen, thank you for your time in participating in our Q1 conference call, and we look forward to speaking with you when we report our Q2 results.

Thank you. Ladies and gentlemen, that does conclude the conference call for today.