Baytex Energy Corp (BTE) 2010 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Baytex Energy Trust second quarter results conference call. Please be advised that this call is being recorded. I would now like to turn the meeting over to Mr. Derek Aylesworth, Chief Financial Officer. Please go ahead, Mr. Aylesworth.

Thank you, Nelda. Ladies and gentlemen, while listening, 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 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 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 for participating in our conference call today to discuss our second quarter 2010 results. I'll start with our operational discussion, Derek will follow with our financial results, and then I'll make some summary comments before opening the conference to your questions.

Operating results in the second quarter were among the best in our Company's history. We achieved record quarterly production of over 44,100 BOE per day in Q2, an increase of 9% from year ago levels and 2% above our previous record in the first quarter of this year. Oil production was particularly strong, increasing 14% over year ago levels, reflecting both organic development and our Lloydminster area acquisitions over the last year.

We continued to contain costs during Q2. Unit operating costs were 1% lower than year ago levels on both quarterly and first half comparative bases. Our lower OpEx is partially attributable to the increases in production, allowing us to spread our fixed costs over a bigger production base. Our E&D CapEx in the second quarter was CAD62.5 million bringing our first half E&D CapEx to CAD119.6 million, which is approximately half of our budgeted E&D CapEx of CAD235 million for 2010. To put this in perspective, we produced organic growth of approximately 3% over the first half of 2010 while reinvesting only 55% of our funds from operations or cash flow into organic activities.

As Derek will discuss later, heavy oil pricing continued to be relatively strong in Q2, continuing the new structural regime for heavy oil that has been in place since the end of 2007. Market prices for the Hardisty Heavy marker, which represents the value of raw heavy oil, averaged around CAD59 per barrel in Q2. To take advantage of this pricing, we participated in the drilling of 17 heavy oil-producing wells in the second quarter, 12 in Lloydminster and five at Seal. Production at Seal averaged 8,900 barrels per day in Q2, a 22% increase over Q1 levels. All five of the new wells were multi-lateral horizontal wells with a total of 43 laterals drilled. Average initial 30-day rate for the new wells was about 400 barrels per day per well. In addition, we reentered four existing wells, drilling additional laterals which increased production in these wells from a pre-workover level of 33 barrels of oil per day to approximately 500 barrels of oil per day per well. For the second half of 2010, we plan to drill about 25 wells in Lloydminster and ten wells in Seal.

Turning to light oil development, we advanced several of our light oil resource plays in the quarter. In the Bakken/Three Forks in North Dakota, we participated in five gross, 1.3 net wells in Q2. To date, Baytex has operated the drilling and completion of nine wells in this play. All the wells we have operated are one mile long horizontal wells, otherwise known as 640 wells, to denote the number of acres held for land tenure purposes by each well. Seven of these wells have sufficient history to establish a reliable 30-day average rate, excluding down time, for use in decline curve equations. Based on this 30-day convention, our operated wells have averaged an initial rate of approximately 280 barrels of oil per day per well. In addition to these 640 wells, we have participated to date in five two-mile-long or 1280 wells operated by other companies. Of these five 1280s, three have enough history to establish a 30-day average rate of approximately 420 barrels of oil per day per well.

In our press release, we also announced that we have increased our lease position in this play from 96,000 net acres previously to 124,000 net acres at present. In addition, we have also acquired approximately 150 square miles of additional 3D seismic. The new seismic and a substantial amount of the new land are in Divide and Williams Counties to the south of our original Divide County land position in areas where we believe well productivity may be higher than in our original lands.

We are continuing our Bakken/Three Forks drilling with an estimated 15 to 20 gross, six to nine net wells to be drilled during the remainder of 2010. In our Viking light oil resource play in southeast Alberta we drilled two unstimulated multi-lateral wells in Q2. Our average 30-day IP to date in this play is approximately 115 barrels of oil per day per well. We drilled three wells in our Viking play in southwest Saskatchewan in Q2, all single-lateral horizontal wells equipped to employ multi-stage fracs. One of our wells that was drilled in Q1 now has sufficient history to establish a 30-day IP of 82 barrels of oil per day. Our average 30-day rate from the three wells in the southwest Saskatchewan Viking play that have sufficient history is approximately 100 barrels of oil per day per well. We plan to drill five to ten wells in our Viking plays during the remainder of 2010.

With respect to acquisitions, we closed the purchase of a small private corporation with assets in the Lloydminster area at the end of May. Cash consideration, net of working capital surplus, was CAD40.9 million. The acquired assets included production of approximately 900 barrels per day of heavy oil and 32,100 net acres of undeveloped land. The assets were easily integrated into our existing Lloydminster infrastructure. We see numerous development opportunities on the acquired assets and will conduct some investment activities on them this year. Nonetheless, these investments will represent minor substitutions in our capital program for 2010 and we are maintaining our E&D CapEx guidance of CAD235 million for this year. We are, again, increasing our full year 2010 production guidance, this time to a range of 44,000 to 44,500 BOE/D because of stronger than expected production results from our E&D program.

I'll now turn the conference over to Derek to discuss our Q2 financial highlights.

Thanks, Tony. During the second quarter of 2010, we generated funds from operations of CAD109.1 million, an increase of 2% over the prior quarter and 26% over the second quarter of 2009. These results were largely driven by increased sales volumes following our record production in the quarter. During the second quarter, heavy oil differentials averaged 18% of WTI, which was wider than the previous quarter, driven by third party refinery turnarounds and the weaker shoulder demand season for refined products.

Currently, pipeline delivery issues following the break in the Enbridge line have resulted in wider spot differentials. We expect differentials to narrow again with the completion of line repairs and the recommencement of pipeline deliveries. In the near term, our cash flows are protected from the impact of wider differentials through our comprehensive hedging program. For the balance of 2010, we have hedged approximately half of our heavy oil differential exposure at an average rate of 16%. Subsequent to the end of the quarter, we hedged a portion of next year's differential entering into contracts with a fixed dollar differential on 2,000 barrels a day for calendar 2011, and a further 2,000 barrels per day for April through September of 2011 at a weighted average differential of CAD15.46 per barrel, or 19%, based upon the current strip pricing in 2011.

In addition, subsequent to the quarter end, we swapped 1,500 barrels a day of WTI at CAD83.22 for the last four months of 2010. These contracts form a part of our overall risk management program and will contribute to maintaining the stability of our cash flows. We continue to monitor the market and when appropriate we'll add to our hedging program.

During the second quarter, we continued to make progress on structural improvements to our balance sheet. We reached agreement with our lending syndicate to increase the amount of our credit facilities to CAD550 million from CAD515 million, and to extend the maturity to June of 2012. The increased borrowing capacity and extended maturity add to our considerable existing financial flexibility which had allowed us to finance a number of transactions in the quarter entirely with debt. At the end of the quarter, our total monetary debt was CAD554 million representing a debt to Q2 annualized funds from operations level of 1.3 times, and leaving us with undrawn credit facilities of over CAD150 million. Both of these metrics are well within our leverage and liquidity targets and provide ample capacity to finance our operations.

Recently, Standard & Poor's increased both our corporate credit rating to BB and the issue rating for our outstanding senior unsecured debentures to B+, citing our strong operational consistency and financial management as reasons for the upgrades. We are pleased to have received this external recognition of our operational and financial management. We continue to work towards a planned conversion from the current trust structure to a corporate legal form and expect to have this conversion completed at the end of 2010. In the absence of a significant decline in commodity prices, we expect to maintain our current distribution level at a dividend upon conversion to a corporation. I'll now ask Tony to provide his concluding remarks.

Thank you, Derek. Since our last conference call in May, volatility in the commodity markets has subsided somewhat and oil prices have recovered most of the drop that occurred in May. Through these ups and downs in commodity prices we are sticking to our strategy to partially insulate Baytex from and take advantage of this macroeconomic and commodity environment.

First, we have consciously positioned Baytex to be very oil-weighted, and that positioning is illustrated by the increase in our oil production in Q2. Converted on a six to one thermal equivalency basis, our production mix was more than 79% oil and liquids in Q2 and 90% of our revenue came from oil and liquids.

Second, as Derek pointed out, our relatively underleveraged financial structure leaves us in good shape to ride out market volatility, as evidenced by our ample liquidity and our 13% ratio of debt to enterprise value. The term out and bank facility increase we put in place in Q2 impart even greater financial stability to Baytex. Furthermore, the ratings upgrade we received from S&P is a further endorsement of our strong and still improving financial position.

Third, we have also hedged a significant percentage of each of our commodity exposures for the second half of 2010. In the case of WTI, we are 48% hedged with swaps and collars that are in line with current market prices. In the case of natural gas, 39% of our exposure for the rest of 2010 is hedged well over current market prices. For currency, 40% of our USD exposure is forward sold at levels that are well above current market levels. And finally, 49% of our heavy oil differential exposure for the remainder of this year is hedged at differentials that are better than current market differentials. We've also put in place and continue to add coverage for each of these exposures for 2011.

These hedges limit our exposure to financial and commodity market volatility and allow us to confidently go about the business of developing our heavy oil and light oil resource plays. These risk management measures, coupled with our strong operational results and the future commodity pricing implied in the forward strip, also mean that we expect to be able to fund our E&D CapEx and cash distributions for 2010 out of internally generated funds from operations. Our E&D program provides for approximately 5% organic production growth this year and we expect higher growth rates, approximately 8%, beyond 2010. We believe that our approach represents a sustainable growth in income model.

The strong production performance recorded during the second quarter is a demonstration of this model even before we convert into a corporate legal form. We're honored that the capital markets have rewarded this model with the year-to-date total equity return of 20% including reinvestment of distributions as measured through August 10. This continues the strong equity market returns we achieved in 2009 and is the highest in the energy trust sector for this year. As Derek indicated, it is our intent to convert to a corporate legal structure at the end of 2010. We believe we may receive even broader capital markets' acceptance as a corporation and that the capital discipline we learned as a trust will serve us well as we compete against a new corporate peer group.

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

Thank you. We will now take questions from the telephone lines. (Operator Instructions).

Thank you. The first question is from Jason Frew of Credit Suisse. Please go ahead.

Hi, Tony. How are you?

Good, Jason.

I just thought I'd ask a little bit about the reentry of existing wells at Seal and if that's going better than you'd planned and if it's different than you'd planned? And just what is the scope of that program or magnitude of the program overall?

The program, I would say, is probably going about as well to maybe a little bit better than we had intended. What we do here is we're taking some of the original single-lateral wells and drilling an additional or new seven to ten laterals in them and in a lot of cases we plug off the original laterals. The production performance has been pretty good from those wells. They are, I guess, behaving on the order of what a new multi-lateral well would do to date, at least in the wells that we've worked over so far.

And for the balance of the year, is this something that you could accelerate or is it really just going along as per your original plan?

We're probably not going to deviate much from our original plan and we will do a few more reentries in the second half.

Okay, thanks.

Thank you. The next question is from Roger Serin of TD Securities. Please go ahead.

Afternoon, guys.

Hello, Roger.

So, following up on that question, can you give me a sense of your inventory of single leg horizontals that would be eligible for reentry?

Yes. Actually, Roger, I don't know exactly what the remaining available account is. It depends on the specific circumstances around the well and probably not all of them would be amenable to it, but the number is going to be approximately ten remaining.

Okay, and what's the cost of the reentry?

Oh, gosh, I think that the reentries have been running around CAD1.3 million, something like that, CAD1.4 million.

Okay, good. One question on your Bakken land additions. So you added some land. Was the bulk of your land additions in the quarter related to the Bakken lands that you acquired in North Dakota?

I'm sorry, Roger. Would you restate that question please?

Sure. The Bakken land that you acquired in the quarter, was the bulk of the lands that were acquired or the money spent on lands in the quarter for the Bakken lands or were you active elsewhere?

We are always adding some lands in western Canada but with respect to the -- we made a few million dollar acreage and well and seismic purchase in North Dakota, so that was the bulk of that CapEx that we listed for the property acquisitions.

Okay. And so, just in terms of drilling, when do you think you would look at because you said in the press release that these are south of your existing operations. When would you think you'd be getting at testing some of this?

We're going to do some reentries this year on some of those acquired lands. There are some older wells that were either not fracked or have what are called pump-and-pray completions, unlined wells with really no selected control over where in the horizontal lateral the frac, the hydraulic fracturing treatment exits.

And in those wells, we're going to run liners and do some selective stimulation. And so, I think that for the remainder of this year on the new lands that will be the bulk of the activity. And then probably sometime in 2011 we would move into the lands further south in Williams County.

Okay, great. Thanks very much. Good quarter.

Thank you very much, Roger.

Thank you. (Operator Instructions). There are no further questions registered at this time. I'd now like to turn the meeting over to Mr. Aylesworth.

Great. Thank you again for your participation in our conference call. Well look forward to our next discussion at our Q3 call in November. Thank you, bye-bye.

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