Baytex Energy Corp (BTE) 2007 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Baytex Energy Trust 2007 third quarter results.

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 Wednesday, November 7, 2007. Your speakers for today are Ray Chan, President and CEO, Tony Marino, Chief Operating Officer, Derek Aylesworth, Chief Financial Officer.

I would like now to turn the conference over to Derek Aylesworth. Please proceed, sir.

Thank you, Shawn.

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 Securities acts. 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. 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 forecasts.

Thank you, Derek. Ladies and gentlemen, it's Ray Chan.

We're very pleased to report our third quarter results. In many ways it is a easy quarter for us to do as we had record production and record cash flow. I will let Tony and Derek provide a review on the operations and financial results. I'll then provide my concluding comments and we'll then be open for questions.

Here is our Chief Operating Officer, Tony Marino.

Thank you, Ray.

As you all know we completed our acquisition of Dominion assets of Pembina and Lindbergh near the end of June. We immediately went to work at Pembina making battery and compression modifications, as well as performing annual facility maintenance in July. We also consulted with other operators in the area to make some cooperative changes to improve operating efficiencies.

The results of our approach were very rewarding. Production at Pembina averaged over 4,000 barrels of oil equivalent per day during the third quarter, compared to 3,500 BOE per day when we announced this acquisition in May. There was minimal down time in the quarter except for the plant turnaround period in July. Of course the strong production performance was further enhanced by record oil prices during the quarter, because the majority of the production at Pembina is high net backed light oil.

At Lindbergh production averaged nearly 1,000 barrels per day. This is a non-operated property and does have somewhat higher operating costs, however, due to the high quality, multi-zone reservoir, capital requirements to maintain production at Lindbergh are quite modest. All in all, both Pembina and Lindbergh's performance more than met our expectations.

Turning to Seal, we completed the second half of our 2007 drilling program with resounding success. The eight new wells we drilled in the third quarter were all completed within targeted capital levels, and the initial production rates easily met our target of 150 barrels per day per well.

One of these wells has been competed with thermal down hole equipment to allow for the cycling steam pilot test we intend to begin in Q1 of next year. We now have a total of 25 producing wells at Seal, drilled at a 100% success rate and have current total production in excess of 2,500 barrels per day. We are very encouraged by our success to date and are planning a similar development program for 2008 in this area.

Our Q4 production should track pretty closely to our Q3 production level of about 38,100 BOE per day. E&D capital for Q4 should be in the neighborhood of $35 million. We are currently planning our 2008 capital budget and should be in a position to discuss it in early December.

I'll now turn the conference over to Derek to discuss our Q3 financial highlights.

Thank you, Tony.

As Ray alluded to earlier, we're reporting record cash flow of $75 million this quarter. Baytex has leveraged to oil prices very evident here as this high level cash flow was achieved despite an average well head gas price of $5.80 per MCF. The first sub-$6.00 quarterly gas price we recorded since Q4 of 2003, nearly four years ago.

WTI averaged $75.38 U.S. in Q3, 16% higher than the previous quarter. The Canadian dollar also matched the assent of the oil price, averaging nearly $0.96 U.S. in Q3. Obviously, these numbers are dwarfed by an oil price today of $95+ and a Canadian dollar at 1.09.

Baytex is one of the first companies among our peers to tap into the U.S. debt market with our original series of subordinated notes issued in early 2001. Although the administrative requirements and carrying costs may seem high at times, we believe that as a Canadian producer, this form of financing provides us with a natural hedge against the currency risk. Our strategy is delivering value in the current market.

Our main series of 180 million U.S. 9 5/8 notes had a Canadian equivalent of 253 million at the time of issue in July of 2003. It has a current value of C$165 million, a total gain of $88 million. Our associated interest expenses are also benefiting from this foreign exchange development as well, helping to offset some of the impact on the revenue side of the income statement.

To help finance the Dominion acquisition, we issued 7 million new trust units in June. Yet with the record cash flow our payout ratio net of drip declined 52% in the third quarter, bringing our year-to-date ratio down to 58%. Combined with a strong balance sheet, our debt to cash flow was 1.6 times with 100 million of undrawn credit facilities, we are very comfortable in maintaining our current distribution level of $0.18 per month heading into 2008.

Another noteworthy achievement in the quarter is our success in securing a portfolio of heavy oil supply contracts to replace the frontier supply agreement which is set to expire at the end of this year. In total, we have agreements to sell 15,340 barrels per day of blend crude in 2008, at a fixed differential of approximately 32% of WTI. We also have contracts totaling 10,340 barrels per day for 2009, at a 33% differential. These contracts demonstrate the liquidity is being developed in heavy oil market which will allow participants to manage volatilities on a go-forward basis.

I'll now ask Ray to provide his concluding remarks.

Thank you, Derek and thank you, Tony.

With all the good news you just heard I wish I could just end our remarks here, however, we are obliged to address the one external event which will have implications for Baytex in the future. Obviously I'm referring to the new royalty of framework announced by the government of Alberta on October 25th. Regardless of which side of the argument you are on, no one would argue that this new framework will affect the collective investment plans of the oil and gas industry in Alberta.

Simply put, more take by the government will result in less available for industry reinvestment, and that is not factoring in changes of investment plans due to the impairment in Alberta's relative competitive position. The new royalty framework will primarily affect Baytex in two of our core operating areas the high rate wells at Pembina and oil sands leases at Seal. Under the new rate, much of our light oil production at Pembina maybe subject to the maximum royalty of 50% under current prices.

We believe very strongly the new rates fail to take into account the high costs associated with drilling and producing these wells and the expiration risk inherent in these type of projects. We are working with other operators with similar deep oil operations to develop proposals whereby such wells could be included in a program similar to the deep gas drilling program.

At Seal the important development here is that the province elected to maintain oil sands status for coal primary programs rather than including coal primary in the higher royalty conventional oil regime as the review panel had recommended. Although the higher oil sands royalty will have a modest negative impact on rates of return, the fundamental economics of coal primary development remain strong, although we will be paying more royalties both before and after project payout.

Only 40% of Baytex's production is from the Province of Alberta. We are fortunate to have this geographic diversity. Regardless of the merits or fairness of this recent royalty announcement, it is management's responsibility to ensure that we invest in the best and most profitable projects possible within our means. We will continue to execute a strategy so that we can deliver sustainable and superior returns to our stakeholders.

Ladies and gentlemen, thank you for your attention, we are now open to your questions. Operator?

Thank you. (OPERATOR INSTRUCTIONS)

And our first question comes from the line of Roger [Fairen], TD Securities. Please proceed with your question.

Good afternoon, gentlemen.

Good afternoon, Roger.

I'm wondering if you could provide us a little color, given your bias to assets outside of Alberta and the current oil price, will you be allocating proportionately more capital to say, your heavy oil in Southwest Saskatchewan? Just give us a mix as to whether you expect a change in your capital allocation.

Roger, we're still just working on our 2008 capital budget. It will be approved by our Board of Directors in early December, after which we will announce the actual plan. Just thinking out loud here, we would like to maintain our production in roughly the 38,000 BOE per day range, which is what we are currently doing, and by and large, we would also try to maintain the mix of the three products as well, being what you see in the Q3 announcement.

So definitely we will look at which are the most profitable projects and skew the capital in that fashion, however, as you know, the Pembina wells, for example, the high rate wells still have a pretty good rate of return. If you don't drill into a dry hole. So we'll--if we want to tap into some of these less risky or more developmental locations in Pembina then we'll be spending the capital right in Alberta, but we already have 60% of our production outside their province. As you know, another good gas area for us is in BC and the (inaudible - heavily accented language). So I would assume that most of our--the majority of our 2008 capital program will be outside of the province.

Okay, one other question on Seal, maybe either you or Tony. In terms of the new or clarification on the new royalty rules, do you see this impacting infrastructure construction and what are your current netbacks and trucking costs in Seal?

Okay, let's start with the question about pipeline infrastructure. Roger, because the oil sands royalty changes did not have a very significant impact on project economics with the coal primary production staying within the oil sands regime, I do not think that infrastructure plans are going to be altered in the area. I think that given the amount of production that is being developed in East River that pipeline infrastructure, both blend line going out and [dillyon] line coming in is very likely to be put in over the next couple of years. There are proposals in regard to that that are being developed by mid-stream companies now, and I think the development is going to continue on the upstream side and therefore I think it will continue on the mid-stream side. With respect to netbacks and I think your other part of it was OpEx at Seal is that correct?

Yes, OpEx, trucking costs, however you would like to lump them.

Okay, well, just to let you know what our third quarter levels were, OpEx was about $5.60, netbacks were actually just a little bit north of $25 and the transportation cost is a little bit more complicated because it is a function of how we split up the deliveries into either the medium sour market or into Southeastern Alberta, but actually, we were able to generate a pretty decent well head price of around $30 during the third quarter. That does vary quarter to quarter and as does the mix between medium sour and the traditional heavy oil markets, but the number that I quoted there for well head price is of course already net of transportation expense.

Okay. Thanks, guys.

(OPERATOR INSTRUCTIONS)

Our next question comes from the line of Corey Wren from [Peacock].

Hi, I had a quick question in regard to the new royalty taxes. What would have been the impact this quarter if that would have been in existence at the beginning of the quarter to your financial statements, and given today's oil prices, if you could roll forward oil prices by--into today's prices, what would be the impact of those royalties this quarter?

Corey, it's Ray.

Yes, Ray.

It's a little difficult to estimate because as you know, royalties calculate on a well by well basis. So until the production accounting supply and the software side get you a new thing, you can pump all your 2000 wells and what you're really doing is just guessing a number, but I'm going to guess that the cash flow impact on Q3, using the new royalty rate would be in the range of $3 million to $4 million.

Okay.

And looking ahead into '09, we then have to make a whole bunch more assumptions as to commodity prices and productivity on some of these high rate wells and things like that, so--and that's why we try to use a fairly rough number of 5% impact on cash flow in 2009, based on what we know today.

Okay, what--as a U.S. investor, it seems like we're seeing a lot of-- from our perspective, at least, negative tax decisions going on with the changes in the distributions of publicly traded income trusts last year and then this, is there anything else we should be looking out for?

If I know that, I would probably be locked up in a vent by now because they don't want anybody doing insider trading.

Okay.

I don't know. I mean, obviously there is always the risk of other jurisdictions following the lead of Alberta, which we definitely hope that wouldn't be the case. I think that at the moment, maybe it would be wise for other jurisdictions to actually look at the impact on Alberta to see if they really be collecting $1.4 billion more than--more under the new system before they go ahead and do it because we all know that that $1.4 billion is calculated on a very isolated basis.

So I think overall, the impact on the economy would be much larger than that calculated number. So at the moment, we still feel that our stories, our projects are profitable. We will continue to operate as an income trust between now and 2010 as much as possible and I think beyond that, I think the fundamental of the story would dictate as to whether you will be a desirable E&P or hybrid company on a go-forward basis, which we certainly feel that we are.

Well, Ray, when do you think you're going to start swinging that dividend? Obviously you're paying your payouts fairly--well, actually right now your payouts are fairly low, but when do you anticipate starting to reduce the dividend as you get nearer to 2011?

In all ways you have to kind of base a decision on how the market is behaving from a cost of capital standpoint. All things being equal, I wouldn't mind to pay as long as possible at $0.18 that we are doing. Kind of deep into the 2010 situation and then convert closer to the 2011 date, but sometimes if the markets start I guess hitting the cost of capital harder on the trust side of things or we come upon a transaction that makes sense for us to combine the so-called conversion with this new transaction and do it right away, we would consider that as well. So at the moment I really can't say what our game plan is but definitely as long as we can, we would like to continue to pay the $0.18 out.

It just seems that with prices being so high, it would be an excellent reallocation of capital to more production and less on the dividend paying side, but I can see if people are expecting that payout, they probably don't want to see that reduction too soon.

Every investor is going to have their reason of selling or buying a stock and in my mind, we just want to make sure that we can run Baytex, sustainably as a trust and also profitably as hopefully an E&P business on a go-forward basis.

Okay, thank you.

And our next question comes from the line of [Caley Ramachandran] from State Street Global Advisors. Please proceed with your question.

I guess it's been answered, Shawn.

Yes, it's already been answered.

No problem.

There are no further questions at this time.

Okay. Well thank you very much, ladies and gentlemen for your time this afternoon, and we look forward to speaking to you in March--early March, about our 2007 fiscal results. Thank you and good-bye.

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