Baytex Energy Corp (BTE) 2008 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Baytex EnergyTrust year end conference call. Please be advised that this call is being recorded. I will turn the meeting over to Mr. Derek Aylesworth, Chief Financial Officer. Please go ahead, Mr. Aylesworth.

Thank you. Ladies and gentlemen, while listening to this conference call 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 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 statements. There is no representation by Baytext that actual results achieved during the forecast period will be the same in whole or in part as those forecast. I'll now turn the call over to Tony Marino, Baytex EnergyTrust President and Chief Executive Officer.

Thank you Derek. Ladies and gentlemen thank you for calling into our conference call. We are pleased to report our fourth quarter and year end 2009 results. I'll start with our operational discussion, Derek will follow with our financial results and I'll make some summary comments before opening the conference to your questions.

Our operating results continue to be strong in the fourth quarter and for 2008 as a whole with respect to both production and reserves. We achieved quarterly production of just over 42,000 BOE per day in Q4. This resulted in a second half production average post-acquisition of the Burmis Energy assets of about 42,300 BOE per day. In terms of production level the third and fourth quarters of 2008 were the highest in our history.

For 2008 as a whole we averaged over 40,200 BOE per day which was a record annual production level for Baytex. These production results were aided by strong performance in the Burmis properties that we acquired at the end of the second quarter. The Burmis properties averaged about 3,400 BOE per day in the fourth quarter which was right on track with our preacquisition forecast. We drilled several strong wells on the Burmis properties and are in the process of installing a pipeline which will allow us to increase gas production rates from these new wells.

Our heavy oil production performance was also quite strong with production averaging about 24,600 BOE per day in the fourth quarter. Despite the decline in prices for WTI heavy oil pricing as of today remains relatively strong due to significantly narrower heavy oil differentials which Derek will discuss in more detail later in the call. With current market prices for heavy oil in excess of 45 per barrel at the wellhead in the Lloydminster area, heavy oil drilling projects continue to have recycle ratios in excess of 3 making them among the strongest projects in the North America oil and gas industry. As a result, in Q1 '09 we continued our originally planned heavy oil drilling program in the Lloydminster area despite the decline in WTI prices.

Production results at Seal were once again very encouraging. We continued our record of 100% horizontal drilling success in the fourth quarter of last year and recorded a production average of 4,700-barrels of oil per day at Seal in the fourth quarter. We are continuing with the posting production phase of our thermal pilot at Seal. The pilot well is still producing at production rates that are in excess of its presteam coal production rate. Incremental steam oil ratio or SOR for the pilot well stood at year end at approximately 1.5-barrels of injected steam per incremental barrel of oil production.

The incremental SOR will continue to decline as the well continues to produce above the presteam cold rate. I would remind listeners that we report SOR on a conservative fashion, not giving the steam pilot any credit for the oil that would have been produced by coal primary methods. We believe SOR is the single best indicator for thermal operating economics. The SOR we have achieved to date is indicative of very high thermal efficiency with the average steam required per barrel of oil well below the average for steam projects in Western Canada. We continue thermal design activities and are targeting a permanent thermal project for Seal with first production in 2011.

We are continuing cold primary development at Seal with the drilling of four horizontal producers in the first quarter. These wells remain highly economic even at current oil prices with recycled ratios that are similar to what we are achieve in the Lloyd area. However, we did scale back the first quarter Seal drilling program from the level we originally planned. The Seal wells have very high initial rates and we believe it is unwise to ramp production rates up significantly while oil prices are low. The forward oil curve and recent price increases suggest oil prices may be higher in the post-breakup period than they are today. Consequently after breakup, we plan to resume the more aggressive drilling program at Seal that we originally planned.

Finally with respect to Seal, we also drilled two stratographic tests during the first quarter to set up additional long-term drilling opportunities. With respect to light oil development we did idle our rig in the North Dakota Bakken Three Forks program in December due to low prices. The Bakken Three Forks wells also initially produced at very high rates with a very steep early stage decline. Had we continued drilling we would have sold a great deal of North Dakota oil at very depressed prices. We do expect to resume drilling on this project at about mid-year depending on where oil prices are at that time.

In February we announced that we had reduced our planned 2009 capital budget to 150 million for E&D activities and 10 million for deferred acquisition payments for a total of 160 million. This was down from our original guidance of 176 million for 2009. Our production guidance has been correspondingly reduced from 41,000 BOE per day to 40,000 BOE per day for 2009.

Shifting to reserves. Our 2008 year end proved plus probable reserves as evaluated by Sproule and excluding overriding royalty interest increased to 187 million BOE as compared to 168 million BOE at the end of the 2007. This represents replacement of 231% of 2008 production considering both acquisition and development activities and 119% replacement through development activities alone. I would point out that we achieved the 119% replacement by a development program that is equal to only 43% of cash flow for 2008. Our reserve life index increased from approximately 12.3 years at year end 2007 to 12.8 years at year end 2008.

We continue to add these reserves at relatively low costs and relatively high recycle ratios. For 2008 including both our development and acquisition programs our FD&A cost was 13.11 per two key BOE excluding future development cost and 16.06 per two fee BOE including future development costs. When these FD&A costs are combined with our netbacks we're pleased to report a 2008 recycle ratio of 2.9 excluding FDC and 2.4 including FDC. These recycle ratios for 2008 are very comparable to our three-year average recycle ratios illustrating the consistency of our reinvestment program.

I'll now turn the conference over to Derek to discuss our Q4 and full year 2008 financial highlights.

Thank you, Tony. Baytex' fourth quarter cash flow from operations was 60.5 million bringing total 2008 cash flow to a record level of 433.8 million. These full year results were driven by the record annual production which Tony has discussed and a commodity price environment which gave us higher average oil prices albeit with more volatility than we have ever seen before. Oil prices in the fourth quarter softened considerably as the worldwide economic challenges took their toll on crude demand. WTI averaged $58.35 US per barrel for the fourth quarter. Down a dramatic 51% from the Q3 average. And our wellhead natural gas price declined by 11% to average 7.05 per MCF. Our heavy oil wellhead price averaged 38.93 Canadian per barrel down from 84.65 Canadian per barrel in Q3.

Heavy oil differentials expressed as a percentage of WTI also widened in the fourth quarter, averaged 34% as compared to 15% in Q3. This widening was a result of both the seasonal lowering of heavy oil demand during winter months exacerbated by the method by which heavy oil differentials are set. Because heavy oil differentials are priced in dollars in the months preceding delivery of the heavy crude the percentage differential will typically increase in a rapidly declining WTI environment such as we experienced in the fourth quarter. I have taken quite a bit of time to talk about the fourth quarter differentials as we believe that the pricing obtained in that period has negatively impacted the equity market's view of the current pricing environment for this product.

In spite of the further decline in WTI in the first quarter of 2009 heavy oil pricing relative to light has significantly strengthened as differentials during the first quarter have averaged approximately US $9 per barrel or 22% of the WTI price. April differentials have recently been transacted at less than US $6 per barrel. As Tony said earlier, combined with the weakness in the Canadian dollar our current unhedged heavy oil wellhead prices would approximate 45 to 50 Canadian per barrel a level at which Baytex will earn a very healthy rate of return on incremental heavy oil investment.

2008 record net income of 259.9 million benefited from the inclusion of 119.9 million in unrealized gains on financial instruments. This result is largely associated with a series of WTI collars totaling 4,000-barrels per day for calendar year 2009 which have a weighted average floor price of US $100 per barrel. The cash flow benefit of the underlying contracts will be realized in 2009 as our hedging program contributes to the stabilization of 2009 cash flows. Our year end monetary debt level of 533 million represents 1.2 times trailing cash flow. The increase in net monetary debt over the third quarter was partly driven by an unrealized foreign exchange loss of 29.6 million resulting from the translation of US dollar denominated notes. Year end undrawn capacity of over 180 million on our credit facilities along with several corporate measures which we have taken to preserve our corporate liquidity which Tony will speak to will leave us with sufficient liquidity to manage our business through these turbulent financial times.

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

Thank you, Derek. The industry and economic environment we are faced with today is very different than it was at our last conference call in November. Even though it was clear in November that we were already in recession with an attendant decline in commodity prices, the ferocity of the recession and a commodity price decline were not yet fully evident. It now appears that this will be the deepest depression in the post-war era. Light oil prices as measured by WTI have fallen from a peak of $147 US per barrel in July of last year to a low of $34 during the first quarter of this year. This decline was more rapid and more severe than almost anyone predicted. For these reasons we have taken the unpleasant but necessary steps to keep our cash outlays in line with our cash inflow by reducing our distribution twice and by reducing our CapEx program.

Our guiding philosophy in the trust era has always been one of sustainability. These reductions in distributions and reinvestment are consistent with maintaining a sustainable oil and gas entity. The capital program we have in place allows us to maintain production at approximately the level we averaged during 2008 and our reserve base continues to expand. While we have reduced our overall cash outlays we are not reducing our capability for long-term success as a growth and income oil and gas entity. With continued delineation of our land base at Seal, heavy oil drilling in Lloyd, selected light oil and gas drilling and technical advancement of our light oil plays.

We continue to be one of the most oil-weighted companies in the Canadian industry. Our commodity market view is that erosion of the world's capability to supply oil will occur surprisingly rapidly during this period of low oil prices setting the stage for oil price recovery perhaps even before resumption of significant oil demand growth. We believe that Baytex its large portfolio of oil development projects and a consistent long term record of low development costs is in a strong position to benefit when the oil recovery occurs. In the meantime we will have taken the prudent steps required to preserve liquidity as long as oil prices stay at their current levels. Ladies and gentlemen, thank you for your attention. We are open for your questions.

Thank you. (Operator Instructions). Our first question is from (inaudible) from State Street Global. You may go ahead.

Thank you very much. Hi, I wanted to know, what are your plans for addressing your bank facility maturity? And I notice that you have some subnotes that are due in 2010.

Sure. The facility is a 364-day revolver. As you know it matures on June 30, of this year. The normal process for the extension of that facility is to make a formal request of the lending syndicate, the credit facility has a time frame which establishes when we can make that request and the earliest date we can make the request is April 1, of this year. So we will be going to the lending syndicate at that time. We will be providing them very shortly the details of our year end reserve picture and it's that reserve picture that they use to evaluate the borrowing base.

As far as the senior -- the US dollar notes, we do believe that the refinancing there has been perhaps unjustifiably been weighing on our equity valuation. Those notes mature over 16 months from today and we will be looking to potentially refinance those on the high yield market. The high yield market has dramatically improved recently since effectively reopening in December of last year. We do believe it will continue to improve and that acceptable refinancing rates will become available to us in the near term here. If it does not improve we think we have another -- we have several other options to consider and we will look at those when the time comes.

Do you anticipate addressing your bond issue at maturity when you do the refinancing of your bank facility?

No, I see them as independent things.

Okay. Thank you very much.

Thank you. (Operator Instructions). Our next question is from Roger Serin from TD Securities. You may go ahead.

Good afternoon, gentlemen.

Roger.

If you could give me a little bit of perspective. What allocation of your Cap-Ex do you think will be in Alberta in '09?

Roger, we will probably do a brief estimate here under the current program. We would probably be putting 90 million of our capital program probably in Alberta.

Last question. Derek, you talked about several other options. Could you give a little more clarity on what those other options might be to deal with the notes if the high yield market remains tight?

Actually, Roger, if you don't mind I'd probably prefer not to at this time. I think from a competitive perspective it is probably better to keep those to ourselves at the moment.

Thanks very much.

You're welcome.

Thank you. Our next question is from Gordon Tait from BMO Capital Markets.

You might have addressed it, I missed the first part of the call, but when you talk about the heavy oil light differential you indicate in Q2 that you could lock in a differential of 15%. Is that something you're looking at doing?

Yes. Gordon, we actually have -- at the beginning of the year we locked in some Q2 differentials on a combination of fixed diffs and percentage diffs. The percentage depth deal that we did was at 20% differential to WTI for WCS which is very comparable to Lloyd blend. The fixed differential deal was a CAD10 discount for WCS to WTI. Now, since we have done that, the heavy oil market has actually improved considerably and we actually are continuing to consider locking in additional volumes at something closer to today's market diffs which I think as Derek said earlier have traded at about CAD6 for the month of April.

Is that differential market becoming more highly developed?

I would say that it is becoming a broader and deeper market. Most of these deals we still do on a non -- we do on a one-off basis with counterparties over-the-counter but we do have more counterparties to deal with than we have in the past and there is also a small volume of trading that occurs on the net throughput system which has -- which is more of an electronic over the counter exchange.

All right. Thanks.

Thank you.

There are no further questions registered at this time. I would like to turn the meeting back to the presenters.

Thank you for your attention during our call. And we look forward to chatting with you in May with our Q1 results.

Thank you. Bye-bye.

Thank you. The conference call has concluded. Please disconnect your lines at this time, and we thank you for your participation.