Baytex Energy Corp (BTE) 2005 Q4 法說會逐字稿

Welcome to the Baytex Energy Trust 2005 year end results conference call. [OPERATOR INSTRUCTIONS] As a reminder this conference is being recorded, Wednesday, March 8, 2006. I would now like the turn the conference over to Ray Chan, President and CEO and with him, Derek Aylesworth, Chief Financial Officer and Anthony Marino, Chief Operating Officer. Please go ahead, sir.

Thank you, operator, I will let Derek read an important message first.

Ladies and gentlemen, welcome to the Baytex Energy Trust conference call to review operating and financial results for the year ended 2005. While listening please keep in mind 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 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 forecast.

Thank you, Derek. Ladies and gentlemen, 2005 was a remarkable year for Baytex. We took Advantage of record high commodity prices and improve on all aspects of organization. Operationally we executed a relatively modest but extremely efficient and effective capital program. Capital expenditures during 2005 total $152 million, with 130 million spent on expiration and development activities and $22 million spent on acquisitions net of dispositions of assets. On [inaudible] programs led by drilling and Stoddart and Seal was an [inaudible] success.

Our reserve replacement ratio for E&D program alone was 128% of our production during the year. This outstanding program was augmented by excellent acquisition at Celtic, which added 16.5 million Boe, of heavy oil and natural gas reserves at $1.33 per Boe, net of the disposition we completed at year end. Our total capital program includes our heavy oil reserves by 21% and light oil natural gas reserves by 8% compared to one year ago. Our corporate FD&A costs of $4.69 per Boe and capital investment re cycle ratio of 4.7 should place Baytex amongst the leaders in our industry in 2005.

Overall we replaced production by 260% increased reserves per trust unit by 13% and improved reserve life index by 21%. All by spending only two-thirds of our cash flow. The benefits of this capital program go beyond these outstanding performance numbers for 2005. At starter we drilled a total of nine wells during the year resulting in eight successful natural gas wells with high-yields of natural gas liquids.

Production in this area has grown to over 4500 Boe's per day from the 3300 Boe's per day, at the time of acquisition in December 2004. Baytex has identified approximately 43 drilling locations in this area and is planning to drill six of these locations in 2006. We are pleased to have [inaudible] a starter to anchor replacement of our natural gas and NGL production for the coming years. At our fuel property in the peace river oil sands region, six horizon wells drilled in the 2004-2005 winter, currently producing about 500-barrels per day. Two horizontal wells and three vertical stratographic test wells are being drilled this winter to further eliminate this land block, where we identified hundreds of development locations.

Due to look of production infrastructure, curved production is being sold at a large discounted to market prices normally associated with this type of heavy oil. We are work on improving our marketing arrangements before embarking on a large scale development program. We're very excited about a vast potential for development on our 100 sections of land in this area and are certain that there will be a main contributor to our heavy oil production needs for years to come.

In September 2005 we purchased 3500 Boe's per day of mainly heavy oil production at Celtic for $69 million. And in December resulted in Baytex selling the steam assisted production just acquired for 45.3 million. Our decision to acquire these assets was based on the primary corporate production development opportunities which have been retained by Baytex. Production from the retained assets has grown to a current rate of over 3,000 Boe's per day from the original 1,750 Boe's per day at a time of acquisition.

Active capital program has been planned for this area in 2006, including the drilling of 30 wells. This acquisition complements the operation in or core area of [Tangleflags] and provides numerous low cost development opportunities. Financially, we are reporting record results. Oil and gas production during 2005 averaged 35,177 Boe's per day, an increase of 3% over the prior year.

Combined with a 25% increase in average well head oil price and 27% increase in average well head gas price, cash flow for the year set a record of $227 million representing an increase of 67% over that of 2004. The rapid assent of oil prices over the last two years cost Baytex to incur significant losses from its hedging program. Losses from WTI derivative contracts in 2005 totaled $48 million.

With the expiring of these low price contracts at the end of 2005, Baytex looks to reporting financial results in 2006 that for the first time since our inception reflect a true cash flow capacity of our production base. During 2005, Baytex maintained its monthly distributions at $0.15 per unit despite the significant hedging losses incurred pay out ratio in 2005 improved to 50% from the 83% one year ago. The low pay out ratio in 2005 brought accumulative payout ratio since insertion to the end of 2005 to a more sustainable 65%.

Total debt a year and 2005 was $419 million including the $74 million of convertible debentures with a conversion price of 14.75 per trust unit. With strong market performance of trust units, the pay of conversion has continued into the new year. As of the end of February 2006, a total of $45 million of the original $100 million issue of these debentures, have been tendered for conversion. The majority of the remaining debt is in the form of U.S. dollars denominated in subordinated terminal maturing in 2010.

Baytex has excellent financial flexibility as outstanding revolving bank debt amounts to less than half a year of current cash flow. Our expiration development capital budget for 2006 has initially set at $105 million, with 60% allocated to heavy oil activity and 40% to natural gas and light oil activities. One of the biggest challenges in 2006 is controlling our cost structure and inflationary environment caused by record demand for properties and services.

A production target for 2006 is 35,000 Boe's per day, comprising 21,000-barrels per day of heavy oil, 3800-barrels per day of light oil and NGL and 61.2 million cubic feet per day of natural gas. No acquisition of disposition is contemplated in this budget. We have increased monthly distributions in 2006 to $0.18 per unit. This will translate into about $140 million in cash distributions during the year net of the participation under our program. Therefore total cash requirements for the year combining distributions with capital spending is projected to be $245 million.

Under current commodity prices and hedging contracts with terms superior to current strip prices, we expect cash flow from operations during the year to be more than sufficient to fully fund our cash requirements. This expectation is substantiated by our 2005 performance where under similar production level with WTI averaging $56.00 U.S. dollars and U.S. well head gas price averaging $8.22. We actually generated $276 million of cash flow before hedging.

Finally we are pleased to report the New York Stock Exchange approved our application for the lifting of our trust units. With trading expected to commence in late March 2006. Baytex has been reporting issuance in the United States, since the issuance of senior subordinate notes in 2001. We believe that the NYSE listing will improve the trading liquidity of our trust units and further enhance future access to the capital markets in the United States. This marks the end of our prepared statements.

We will be pleased to take your questions at this time. Operator.

[OPERATORS INSTRUCTIONS] Our first question is from the line of Lou Nardi of BMO. Please go ahead, sir.

I was wondering what your thoughts are on the acquisition market given there seems to be a [girth] of non-trust EMP companies left. Do you see the remaining companies being bought by trusts on do you see the mergers in the trust market.

Lou, at the present time the announced deals are not that numerous. I think we all know there are very few barrels so to speak on the street that are for sale. Personally I expect that after the reporting season is over when everybody has fresh engineering and financials and so on, there may be more activities, but we definitely will be looking a lot of them and hope to add to our portfolio although 2006 budget currently the production guidance we're giving out entirely based on internal projects.

A couple of more accounting type items I was curious about. Drip participation might be able to go back and reconstruct it from what you just said. What are you budgeting there, like 5%.

We're expecting 9 or 10% participation.

Okay. I will review that. On the hedges for 2006 especially on the gas side, I guess, you have a number of fixed price contracts and I guess they're physical collars. Is that going to be accounted for in your realized price or will that be accounted for on the hedge line?

The callers will be mark-to-market. The physical will be accounted as part of our realized price.

Okay. Thanks a lot, gentlemen.

Our next question comes from the line of Marianna Cushner of Numera Asset Management. Please go ahead.

Hi. I just wanted to hear your thoughts on what's going on with the heavy crude oil up in Canada, if you look at Lloyd Blend, they just went out very dramatically in February and while I understand that you protected on the significant volumes of your heavy crude but still wanted to understand the situation better.

Okay. The Lloyd differential, Marianna, was complete 42% differential in January, and it did widen to about 51, 52% in February, but has come back to around that 40% mark in March, and it is very much seasonal adjustments and we do expect as in most of the time years that come spring and summer we'll get a lower rate and then it will widen out again in Q4. Last year the differential was 39%. That on the back of $56.00 in change in WTI numbers, so expect that 39% to maybe mirror what we have coming this year, but it was too far or too early to tell.

Are there any other specific factors beyond seasonal factors?

I am not aware of that other than there are refinery turn arounds and those type of issues, but there are no single event that we have some other years in the past.

And also condensate costs typically creates some volatility in your price realizations. Can you discuss where those prices have been so far?

They actually have been very good. There is a certain amount of seasonality too in the condensate price. So far in the first quarter of 2006 condensate is fetching about $5.00 U.S. premium over par crude. That's less than a 10% premium, so we sort of expect that to be hopefully narrowed down a little bit, the spring and summer seasons, so 9% during the winter months actually pretty good.

Thanks.

Our next question comes from the line of Steve Hooker of Aladdin Capital Management. Please go ahead.

Just a quick question. In aggregate, what is your hedging situation look like for 2006?

It is sort of described in the financials, but I think overall we have 8,000 barrels a day of WTI contracts bought at a wide collar with out put of $55.00 and a call at $84.00 plus. That's a pretty wide collar that we hope wouldn't be violated, and on the gas side we have about 30% of our winter gas sold through fix price of collar contracts and about 25% of our summer gas sold through similar arrangements, and the moment all those gas contracts are in the money, i.e., over strip prices.

Great. Thank you.

Our next question comes from the line of Cam [Raincast] of BMO Nesbitt Burns. Go ahead.

Wonder if you can add color on how the marketing arrangements is coming in, if you've been making any head way on that at Seal.

We are in discussion with several area operators and we hope to have some arrangement maybe finalized in the first half of this year, so by the end of the first half of this year, so that we can then plan on our larger scale drilling program in the second half and commence as soon as weather permits, so we are in earnest discussion and they are on the table so to speak. We haven't signed anything.

And so if you can ramp up the drilling by the end of 2006, what type of infrastructure will you be needing in the area as well, infrastructure spending to go with that.

I think that depends on what kind of deals we find out with the other operators, obviously we can pay a user fee to reduce the need to spend capital expenditures. That's one-way to skin the cat so to speak. If the terms being offered by the operators are not very beneficial, then we may have to spend some of our own capital. That's what we are working on right now.

Right. And capital drilling for that matter because it is somewhat uncertain at this point, have you factored that into your budget or does your budget exclude that capital?

Sorry, Cam, you come across fairly choppy here in the delivery. I couldn't just because my speaker phone couldn't hear your question.

Oh, sure. Does your budget current $105 million capital budget for '06, does that include any spending really on drilling or infrastructure at Seal?

No. The only items that are included in the $105 million budget are the drilling that we discussed in the press release, i.e., the three Strat wells and the two horizontal wells.

And one last question on op costs. Wondering with the assets dispossessed of, what are you budgeting or running this year for 2006 average op costs per Boe?

We're projecting approximately 950 per Boe for both our heavy oil and our light oil, and $1.15 per MCF for the gas.

Great. Thanks, guys.

Our next question comes from the line of Katherine Schenosky of Jefferies. Please go ahead.

Good afternoon. Wondering if you guys had a number for the crude developed reserves at the end of the year?

Yes, we do. That was announced on March 15, and on the Boe basis we have 45 million Boe's roughly of proved developed producing out of the 140 million of crude plus probable. Is that your question.

Yes, could you also distribute the guidance for 2006 production? I want to make sure I got all that far.

21,000-barrels per day of heavy, 3800-barrels per day of light oil and NGL and 61.2 million cubic feet per day of natural gas on a 6 to 1 basis that's 35,000 Boe's.

Thank you very much.

You're welcome.

Our next question comes from the line of Mark Bridges of CIBC World Markets. Please go ahead, sir.

Just had a quick question on the revisions, just wondering if you can comment on the probable revisions. I think that's the fourth straight year with negative revisions and I am wondering if you can comment on that?

The negative revisions, let me turn to the table here and speak to that a little bit. On the heavy oil side it's mostly comes from the property in Art Moore. That's where a lot of the new wells when they're first assigned reserves as you know they engineer go by volume metric assignments and a couple years of production history and then they can go into a decline analysis and also because of sudden growth performance we have scaled back bulking of some of the probable reserves, and in a lot of times, too, in the heavy oil probable bookings, it is a matter of recovery factors assignment and unless the proven part is holding up as well as originally signed, then you tend to lose the external recovery factor assigned on the probable side of things, so if I look at our reserve reconciliation table this year, in the revision side of things we lost 4.4 million Boe's, and out of that 3.6 is on heavy oil, so the other reserves are actually reasonably tight, competitively this year numbers and 4.3 million-barrels on 140 million-barrels is what 2 to 3%, and I don't believe in our mind that is a very significant issue.

No, no, I definitely agree it is not that significant. It is just that even just the trend last year things -- you guys had a very small revision. Prior to that there were larger revisions. I was just kind of interested.

Two years ago was National Policy 2B versus NI 51-101. That was quite a different situation. Last year we were very good in the revision number, and this year we lost the 4 million-barrels, so we definitely are hopefully booking reserves that are very sort of deliverable and with 51-101 now three years in the running as things sporule out reserve engineers also is getting more accomplished and used to our asset base as well.

Looks more like a one-time thing and you guys are pretty comfortable now.

We are, yes, we are.

Thanks, guys.

Thank you.

[OPERATOR INSTRUCTIONS] Our next question comes from the line of Rex Jones a Private Investor. Please go ahead, sir.

Gentlemen, thank you for a very nice year. I looked a little bit at your reserve information. I wonder if you can give me an idea what you have booked for reserves out of the Seal area.

We have booked a total of 4 million-barrels of crude plus probable reserves at Seal.

Okay. And that's obviously just based on the exploratory work you've done so far?

What we have done from a bookings standpoint is we have booked obviously six producing wells, one proved developed non-producing because the we will was drilled by year end December 31, but not in production, and we have also booked seven proved undeveloped locations. That's sort of the proved booking, and I believe six probable locations.

So would you anticipate a fairly significant revision in your bookings at the end of the 2006 on that area?

I don't believe so because I don't believe the drilling program would have sort of done that many wells in '06. It is going to be '06/ '07 winter program. I think most of the time wells will be counted at 2007 wells.

Very good. Thanks again.

You're welcome.

Mr. Chan, I have no further questions at this time.

Thank you very much for attending the Baytex year end 2005 conference and look forward to speaking to you again when we announce our Q1 2006 results. Bye bye.

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