Baytex Energy Corp (BTE) 2009 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Baytex Energy Trust Yearend Conference Call. Please be advised this call is being recorded.

I would now like to turn the meeting over to Mr. Derek Aylesworth, CFO. Please go ahead, Mr. Aylesworth.

Thank you, operator. Ladies and gentlemen, while listening, please keep in mind that some of our remarks will contain certain forward-looking statements within the meanings of applicable securities laws. 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. We refer you to the advisory in our press release regarding forward-looking statements and the material factors that could cause actual results to differ materially from the conclusion, forecast, or projections in the forward-looking statements. 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.

Unless otherwise noted, all amounts are stated in Canadian dollars.

I'll now turn the call over to Tony Marino, Baytex's President and Chief Executive Officer.

Thank you, Derek. Thank you for participating in our conference call to discuss our fourth quarter and yearend 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 continued to be strong in the fourth quarter and for 2009 as a whole with respect to both production and reserves.

We achieve quarterly production just over 42,700 boe per day in Q4, which was within our guidance range of 42,500 boe to 43,000 boe per day and the highest in the history of Baytex Energy Trust. This resulted in a second-half production average of just under 42,700 boe per day. For 2009 as a whole, we averaged approximately 41,400 boe per day, which was also a record annual production level for Baytex.

Comparing the first quarter of 2009 to the fourth quarter, oil equivalent production increased approximately 3,000 boe per day, a 7% increase. Oil production increased 8% and gas production 6% over this period. This production profile over the course of the year reflected two components - our southwest Saskatchewan acquisition in Q3, which added 2,800 boe per day in Q4, and our organic E&D capital program, which grew our production base slightly from Q1 to Q4 '09.

Our E&D CapEx in the fourth quarter was CAD45 million. For full-year 2009, E&D CapEx was CAD157 million, or about 47% of funds from operations, or FFO. To put this in perspective, we achieved a small increase in production organically during the course of the year while reinvesting a little less than half of our cash flow in organic activities, also known as E&D activities.

At the end of our prepared remarks, I'll address our plans for organic growth during 2010.

We also had CAD37 million in acquisition CapEx in Q4, which was largely for the prepayment of remaining deferred acquisition payments for our Bakken/Three Forks land position in North Dakota. For the full year, our acquisition CapEx was CAD133 million, with the acquisition CapEx for the first nine months of 2009 represented largely by our southwest Saskatchewan acquisition in Q3.

Production by product was very close to guidance levels for 2009. Our heavy oil production performance was particularly strong, with production averaging 26,400 barrels per day in the fourth quarter.

As Derek will discuss later, heavy oil pricing continued to be relatively strong due to a significant and persistent narrowing of heavy oil differentials. With current market prices for heavy oil around CAD65 per barrel at the well head in the Lloydminster area, heavy oil drilling projects in that region continue to have recycle ratios of about 4, making them among the most desirable projects in the North American oil and gas industry.

We drilled ten wells in the Lloyd area in Q4, bringing our total for the year to 70. We plan a similar level of drilling for Lloyd in 2010.

Production at Seal remained very strong in Q4, averaging 6,400 barrels per day, about a 20% increase over Q3 levels (sic - see correction made by company speaker below). Development investment at Seal yields even higher recycle ratios than in the Lloyd area.

I want to correct something I just said. It's not a 20% increase over Q3 levels. It would have been a 20% increase over the previous year.

Our development techniques at Seal have evolved over our five years of drilling history. When we started drilling at Seal in 2005, we used mile-long, single-lateral, horizontal wells. Those wells cost about CAD1.1 million per well to drill, complete, and equip and had initial rates of about 160 barrels of oil per day per well. This combination of capital costs and production rate resulted in excellent capital efficiencies of about CAD7,000 per barrel per day of oil production.

Beginning in 2007, we began to drill wells with more than one horizontal lateral emanating from each vertical well. Over the past three years, we have become progressively more active in our use of multilaterals, and we drilled three eight-lateral horizontal wells in Q4 2009. These wells cost about CAD2 million per well to drill, complete, and equip and have initial rates of about 550 barrels of oil per day per well. These wells have reduced our capital intensity to under CAD4,000 per barrel per day of oil production.

There are several advantages to the use of multilaterals. They reduce the amount of capital required to generate a barrel per day of production. They should increase ultimate recovery due to down-spacing effects. In some cases more than one spacing unit may be developed from each vertical well location, so our surface land use on these oil sands leases is reduced from what is already a low level of land use intensity. And OpEx per unit of production is reduced because per-well production rates are higher.

During 2010, we plan to drill approximately 20 more horizontal wells at Seal, up from 17 in 2009, with a large majority of the 2010 wells employing multilateral designs of various types. In addition, we plan to re-enter several existing, single-lateral wells and drill additional laterals at closer spacing.

Let me now cover each of the light oil resource plays we're involved in.

In the Bakken/Three Forks in North Dakota, we drilled two more Baytex-operated wells in Q4 in which we have a three-eighths interest. These horizontal wells were completed using multistage, hydraulically fractured completions. We now have three Baytex-operated wells with sufficient history to establish a reliable 30-day peak rate. Based on this 30-day convention, the first three wells have averaged an initial rate of 300 barrels of oil per day per well. We are continuing our Three Forks drilling with an estimated 15 to 20 gross wells to be drilled at a three-eighths Baytex working interest during 2010.

In our Viking light oil resource play in southeast Alberta, in Q4, we drilled two, un-stimulated, multilateral wells at an average initial rate of over 150 barrels of oil per day per well. We plan approximately five more wells in the Viking in Alberta in 2010. We did not drill any wells in our Viking play in southwest Saskatchewan in 2009 but plan approximately five wells in 2010. We plan to use single-lateral horizontals with multistage fracs in Saskatchewan.

Baytex is not one of the larger Cardium players, but we did drill two Cardium wells in the fourth quarter out of a potential inventory of 43 Cardium locations. We don't have long production and testing histories on these wells yet, but initial rates were above 100 barrels per day. We plan to drill up to five Cardium wells during 2010.

Finally on our light oil resource plays, we have now tested the Mowry Shale horizontal well in the Powder River Basin in Wyoming that we drilled in the third quarter. Its production rate averaged only 33 barrels of oil per day in its first full month on production, even though we believe we achieved the hydraulic fracturing orientation and dimensions we were targeting. We'll continue to analyze the micro-seismic monitoring and tiltmeter data we acquired during the fracs before making decision about further investments in this play.

With respect to production guidance for Q1 2010, in our December release regarding capital and production plans for 2010, we guided to production for Q1 that was flat with second half 2009 levels, or about 42,500 to 43,000 boe per day. We still see that range as valid, with a bias to the upper end of the range. We continue to expect production for 2010 to be in the range of 43,500 boe per day, with rates increasing as we progress through the year.

Our estimate for 2010 E&D CapEx remains CAD235 million.

Shifting to reserves, our 2009 yearend proved plus probable reserves, as evaluated by Sproule, increased to 197 million boe as compared to 187 million boe at the end of 2008. This represents replacement of 165% of 2009 production, considering both acquisition and development activities, and 113% replacement through development activities alone. Our reserve life index stands at 12.4 years, based on our guidance production rate for 2010.

We continue to add those reserves at relatively low costs and relatively high recycle ratios. For 2009, including both our development and acquisition programs, our FD&A cost was CAD11.63 per 2P boe, excluding future development cost, consistent with our three-year average FD&A cost of CAD11.89 per 2P boe.

When these FD&A costs are combined with our netbacks, we're pleased to report a 2009 recycle ratio of 2.4, excluding FDC. This recycle ratio for 2009 is very comparable to our three-year average recycle ratio of 2.5, illustrating the consistency of our reinvestment program.

I'll now turn the conference over to Derek to discuss our Q4 and full-year 2009 financial highlights.

Thanks, Tony. During the fourth quarter of 2009, we generated funds from operations of CAD97.3 million, an increase of 12% over the prior quarter. Fourth quarter results were supported by continued improvements in oil prices, with the average WTI oil price in the quarter increasing by 12% over Q3, to average $76.19 per barrel in Q4. Heavy oil pricing continued to be strong, with Q4 differentials averaging just 16% of WTI.

In December, we increased our monthly distribution by 50% to CAD0.18 per unit, per month, commencing with the distribution payable in respect to December operations. Total fourth quarter distributions of CAD37.3 million represented a low and sustainable payout ratio of 38% of Q4 funds from operations.

The quarter also saw us past the significant milestone of having paid out cumulative distributions of CAD1 billion since Trust inception.

Our balance sheet continues to improve as well, with total debt reduction of about CAD60 million from the end of 2008 to a 2009 yearend level of CAD474 million. This debt level represents a debt to 12-month, trailing cash flow level of 1.4 times, leaving us with almost CAD200 million in available, undrawn credit facilities.

Our yearend balance sheet reflects the long-term success of our sustainable business model. Over the life of the Trust, we've been able to fund a very significant level of distributions; fund the capital program, which has consistently resulted in reserve and production growth; and maintain prudent and manageable debt levels.

As we look back on the full 2009 year, we're pleased to see full-year funds from operations coming in at CAD332 million. This level, while down from 2008, was the second-best result in our Trust's history. To achieve this level of cash flow during the deepest recession in recent history is an achievement we're very pleased with, and it bodes very well for future cash flow results as economic strength continues to be restored worldwide.

The current strip for WTI for the balance of 2010 is over $80 per barrel, as compared to the 2009 average of $61.80. The outlook for heavy oil pricing continues to be very strong, with a differential so far in Q1 averaging just below 12% and a forward curve for the balance of the year below the full-year 2009 (inaudible).

Going forward, we will more fully enjoy the benefit of improving pricing, as the end of 2009 saw the expiree of a series of heavy oil supply contracts which have locked in a 33% differential on over 10,000 barrels per day of sales of heavy oil blend.

Our 2010 production guidance at 43,500 boe per day will be the highest average in our Trust history.

With all of these positive factors supporting us, 2010 has the potential to be the best year in our history and will position us very well as we transition back to a corporate legal form at the end of 2010.

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

Thank you, Derek. The general economic environment appears to have improved further since our last conference call in November. Oil pricing, especially heavy oil pricing, remains relatively strong. We've consciously positioned Baytex to be very oil-weighted, and that positioning is illustrated in our yearend '09 reserve report. Baytex's 2P reserves are now 89% oil, based on converting gas at a 6 to 1 equivalency ratio.

Because we have less confidence in the natural gas market, we have also positioned Baytex to be less exposed to gas pricing through our gas hedges. For 2010, 44% of our gas production is hedged at levels above current market prices. We have also directly protected 33% of our FX exposure for 2010 with forward contracts that were entered into at approximately $0.88 per Canadian dollar. We believe that the fundamental changes in the supply, transportation, and demand for heavy oil that have occurred over the past few years supports strong, longer-term heavy oil pricing. Nonetheless, to protect cash flow, we have also locked in differentials on about 55% of our heavy oil for 2010 at levels that are close to the current market differentials.

Taking into account these risk management measures and using the current forward commodities strip as a basis for projecting funds from operations, we expect to be able to fund our E&D CapEx and distributions for 2010 out of internally generated cash flow. Please keep in mind that our E&D program is projected to generate 4% to 5% organic production growth during this year. Hence, we believe that our approach represents a sustainable growth in income model.

We're honored that the capital markets have rewarded this model with a total equity return of 121% in 2009, assuming reinvestment of distributions. This total return was among the highest in our peer group.

It is our intent to convert to a corporate legal structure towards the end of 2010. Upon conversion, we will be executing the same growth in income model that we are currently employing as a Trust. We believe we may receive even broader capital market acceptance once we convert to a corporation and that the capital discipline and capital efficiency we've learned as a Trust will serve us well as we compete against the new corporate peer group.

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

(Operator instructions). Roger Serin, TD Securities.

I'm just looking for some information - the length of your horizontal wells in North Dakota and where you might take that and, also, the length of the multilateral wells in the Viking in Alberta.

Okay. In North Dakota in the Bakken/Three Forks, those wells are what we call 640s, to date. They're about a mile long; actually, working out usually to about 5,000 feet long. Where we might take that length is to what is called a 1,280 location or a 1,280 well, which means that it's two miles long, referring to the number of, I guess, sections that are initially developed by the two-mile-long well, the number of acres developed by each well being 1,280 acres. So then we'd be going from a mile long, or about 5,000 feet, to around a 10,000-long lateral. And we'd be increasing the number of stages accordingly.

In Alberta, we've employed both half-mile-long and mile-long laterals, and they vary to some degree, depending on the particular land and geologic situation in the wells that we drilled so far.

One last follow-up. What happens to the well costs in North Dakota if you go from 640 to 1,280?

They increase, but they certainly don't double. I don't have an exact number handy right now. But I'd say we might be looking at approximately a 50% increase in well costs, something like that, to double the length.

And, on 640, how many wells per section would you look to be drilling to fully exploit a section?

Well, what we've currently said about the development spacing is that we do see one to two wells per section. I would say that that's an early estimate. I know that well densities are higher in southeast Saskatchewan, four being quite common and a lot of work being directed toward bringing those up to six to eight wells per section. Now, I don't know that North Dakota would ever end up as high a density as six to eight wells per section. But, nonetheless, I do think our initial expectation of one to two wells per section may well go up in the future.

Perfect. Thanks very much, Tony.

Jason Frew, Credit Suisse.

Tony, there's a lot happening at Seal in terms of the multilaterals and the technology there. Are you changing your techniques at all in the Lloydminster area? Is there anything going on on the technology side there?

Jason, I would say that there is always an evolution of techniques that occurs in Lloyd as well. The historic method of developing Lloyd has largely been to drill vertical wells with coproduction of sand to get this worm-holing effect that increases production rates, sometimes to quite high levels. And that is still, I would say, the mode for our development in Lloyd.

However, in 2010, we are employing a greater number of horizontal wells. At present, we have not gone to multilaterals in Lloyd, but there are certain formations in the Lloyd area that we're studying for the use of multilaterals, which we might try out in 2010 or, maybe, as we go into later years.

Okay. Thank you.

Rob Mark, MacDougall, MacDougall & MacTier.

Just wondering if you can give me maybe a bit of idea on strategy on your asset base on the unconventional side. Are you happy with your portfolio, or do you feel you need to add or subtract anywhere? I'm also thinking sort of on the Cardium side. Is it big enough to be material ongoing for you guys?

With respect to our unconventional portfolio, we quite like what we put in place. And, I guess, as we-- Just talking about the light oil plays alone, without even including Seal in the resource plays, we have, I think, now a nicely diversified mix of light oil projects. You can never have too much project inventory, and, if there was a way to accretively add a new project or add to the developable land that we have in any of the existing plays, we would sure do it.

The Cardium position we have is-- We talked about it here for the first time because we get a lot of questions about the Cardium. It's understandable. It's become quite prominent in the industry. And, as you know, land prices have dramatically gone up in the Cardium.

I do consider it a good play. It's certainly quite early. There haven't been that many wells drilled in it, and they haven't-- The ones that have been drilled haven't been on production for long periods of time.

At a potential inventory of up to 43 wells in our current land base, it has moderate importance within the project portfolio. I think the economics are good enough that we want to have a measured pace of development in the Cardium. If we could acquire land at a reasonable price in the Cardium to expand it further, I think we would do it. I do know that land prices have escalated enough in that play that where we see them at today is probably beyond, and maybe quite a bit beyond, our willingness to pay at those levels.

Great. Thanks a lot.

We have no further questions at this time, and I will turn you back over to Mr. Marino. Please go ahead.

Thank you, again, for your participation in our conference call. We look forward to our next discussion at our Q1 call in May.

Thank you. Bye-bye.

The conference has now ended. Please disconnect your lines at this time. We thank you for your participation.