Baytex Energy Corp (BTE) 2009 Q2 法說會逐字稿

Good afternoon ladies and gentlemen. Welcome to the Baytex Energy Trust second quarter 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 Alanna. Ladies and gentlemen, while listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of the securities acts. We caution that assumption 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 projection in the forward-looking statements.

There is no representation by Baytex that actual results achieved during the forecast period will be the same in all whole or in part as those forecast. I will now turn our 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 2009 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.

The second quarter was another strong operating quarter and our results were very closely in line with our guidance. We achieved production of approximately 40,400 BOE per day in Q2 as compared to guidance of 40,000 BOE per day.

E&D CapEx in the quarter in the quarter was CAD30 million which is about 18% of our annual budget for 2009. We also had acquisition CapEx of CAD2 million for a small producing property acquisition in the Lloydminster area.

Production by product was also closely in line with our earlier guidance. Production of light oil was approximately 7100 barrels per day, basically flat with Q1. Although we have not been investing much in natural gas, gas production did increase to about 60 million cubic feet per day in Q2 from 55 million cubic feet per day in Q1, primarily due to some pipeline work we completed at the end of coupon and the tie-in of wells after April 1.

Our light oil and gas production was aided by continued strong performance from the Burmis properties acquired last year which again produced approximately 3600 BOE per day. Our heavy oil production performance continued to be strong with production averaging about 23,300 barrels per day in the second quarter, again basically flat with Q1.

Heavy oil pricing continues to be strong due to significantly narrower heavy oil differentials, which Derek will discuss in more detail later in the call. Current market prices for heavy oil are around CAD60 per barrel at the wellhead in the Lloyd area and heavy oil drilling projects in that region have recycle ratios of about four, making them among the best investments in the North American oil and gas industry.

We're currently drilling our 20-well second-half 2009 program in the Lloyd area. Production in Seal remained very strong, averaging 4600 barrels per day. Recycle ratios at Seal are even higher than at the Lloyd area. We resumed drilling at Seal at the end of Q2 and we anticipate adding about 12 horizontal producing wells during the second half of 2009.

At the end of July, we closed the acquisition of predominately heavy oil assets in the southern part of our Lloydminster operating area. In this acquisition, we added approximately 3000 BOE per day of production and by our internal estimates, around 10 million barrels of oil equivalent of proved plus probable reserves.

Based on a May 1 effective date, our acquisition cost was CAD93 million. Cash flow from the acquired properties was approximately CAD7.6 million for the three-month period between our effective date and closing date on July 30.

Adjusting for the cash flow in that interim period, our cash price for the properties was CAD86 million. We believe the acquisition will be accretive to all of our relevant per unit metrics such as production, reserves, and cash flow per unit.

We financed this acquisition by drawing on our revolving credit facility. Yet as Derek will discuss in a minute, our liquidity, financial flexibility and credit metrics remain extraordinarily strong.

Operationally, the properties are a natural fit with our existing Lloyd area operating infrastructure. For the longer term, we see a number of high return investment opportunities in the acquired properties including both cold and thermal heavy oil development. Post closing of the acquisition, we're adjusting our production guidance to 42,000 BOE per day for Q3 and 43,000 BOE per day for Q4.

CapEx guidance for 2009 is being adjusted to one CAD165 million for E&D activities, up from CAD150 million previously primarily due to projects on the acquired properties. We continue to budget CAD10 million for deferred acquisition payments for our North Dakota properties. I will now ask Derek to discuss our Q2 financial results.

Thanks Tony. The second quarter of 2009 marked some early signs of a recovering global economy, with oil prices and particularly heavy oil prices strengthening significantly and with selective reopening of the equity and credit markets. Baytex has benefited from both of these improvements and during the second quarter, significantly improved our financial strength and enhanced our financial ability to profitably manage our business through the current recessionary cycle.

Second-quarter cash flow increased 46% over Q1 to CAD86.7 million driven largely by improving oil prices. The average price for [WTI] for the quarter was $59.51 a barrel, an increase of 48% from the Q1 average of $42.98.

Heavy oil differentials continued to narrow on the back of tightened heavy supply and increased investment in transportation and refining capacity. The Q2 differentials averaged 13% of WTI as compared to 22% in the first quarter and 18% in Q2 of 2008.

Our Q2 heavy oil wellhead price of $51.19 per barrel was 42% higher than a Q1 average of $36.11. and very comparable to our light oil Q2 average of $54.28 a barrel. Partially offsetting the benefit of improved oil prices, our realized natural gas wellhead price declined by 29% to average $3.85 an MCF. With over 75% of our production being liquids [weighted], Baytex is substantially less exposed to weaker natural gas prices than many of our competitors.

While the weakening US dollar has contributed to the improvement in WTI, it does mitigate some of the benefit of the improved oil pricing for Canadian producers. The Q2 average exchange rate of 1.167 reflected an approximate 7% deterioration of the US dollar over Q1 and the trend has continued into Q3.

Baytex has taken significant steps to protect its future cash flows from further US dollar weakness both through the natural hedge which results from maintaining a significant portion of our debt not denominated in USD and through a very significant program where we have forward sold approximately $13 million per month for the balance of '09 at weighted average rates of 1.22 and approximately $14 million a month through 2010 at average rates of 1.23.

Additional Forex hedging is embedded in our [ACO-based] natural gas hedges. These contracts will provide significant currency protection to our cash flow over the near-term.

During the second quarter we completed a bought deal equity financing issuing 7.9 million units for net proceeds of CAD109 million. We applied the net proceeds of this issue to pay down our credit facilities.

The weakening of the USD relative to the Canadian dollar allowed us to book an unrealized FX gain on our US dollar denominated debt. Combined, these resulted in the total debt reduction of approximately CAD150 million since the end of Q1.

With the recent increase in our credit facility, we ended the quarter with over CAD320 million of undrawn credit facility and a total monetary debt to cash flow ratio of 1.2 times on a 12 month trailing basis. These very strong financial metrics position us to take advantage of the acquisition market as evidenced by the heavy oil acquisition which Tony referred to earlier.

Our Q2 payout ratio of 38% net of reinvested dividends or 44% before reinvested dividends reflects our objective to deliver meaningful income level to our unitholders but also to preserve our corporate financial strength. The market seems to appreciate this approach as our year-to-date total return of 64.6% puts us at the top of our peer group so far for 2009.

While we do not typically offer cash flow guidance, we would point out that based on the current commodity price strip buoyed by the tighter heavy oil differentials and including the cash flow contribution from the recently acquired properties, Baytex is on course to deliver the second-best annual cash flow in its history behind only our 2008 results. I will now ask Tony to provide his concluding remarks.

Thanks Derek. Both the oil industry and the general economic environment have continued to improve since our last conference call in May. At the same time, the natural gas pricing environment remains very challenging and uncertain.

In part because our primary expertise is in oil production, and in part because we've had a more positive market view toward oil and for natural gas, we have consciously positioned Baytex to be a very oil weighted company. In fact in Q2, 87% of our revenues came from heavy and light oil.

We are particularly fortunate to have nearly two-thirds of our Q2 revenue come from heavy oil, a product that has recently come into its own with respect to heavy light differentials. Our recent Saskatchewan acquisition is consistent with our confidence in heavy oil and our focus on value accretion in every investment decisions we make.

We've also been consistent in stressing conservative financial management and a sustainable distribution policy. Our strong credit metrics following the acquisition and our low payout ratio are the result of this conservative, sustainable approach.

Year to date we've achieved the highest total market return in our peer group. While we are honored by the market's assessment, we remain respectful of the uncertainty and fragility of the current economic recovery and of the volatility in energy prices.

We at Baytex pledge to stick to our value oriented philosophy and to do all that we can do successfully steer through the remainder of this part of the economic cycle. Ladies and gentlemen, thank you for your attention. We are open for your questions.

(Operator Instructions) Gordon Tait, BMO Capital Markets.

A couple of questions on your -- just on your heavy oil split. How much heavy oil production are you getting out of the Lloydminster area right now?

It would be about -- well with the -- part of the acquisition, about 19,000 barrels a day. With the acquisition, about 21,000 barrels a day.

And then what is your expectation for heavy light oil differentials sort of for the next 12 months? I mean they've narrowed so much. Do you see that continuing? Are you able to take advantage of that?

Our expectation is that we are going to most likely continue to have strong heavy oil dips. There's three real drivers I think for that and all three are probably going to remain in place.

The first is that we have adequate transportation capacity now out of Canada to move our heavy oil into the markets that can use it, particularly those in the US. And in fact that transportation capacity is continuing to expand.

Secondly we have had an expansion of demand from US refiners who have reconfigured a number of their refineries run heavy oil. And finally on the supply side, the sources of supply for the US heavy oil refiners have historically primarily been Mexico and Venezuela.

Mexican production has declined significantly already. Venezuelan production is down some. I don't think there is very good prospect for either of those countries actually to turn around their production profile soon.

So we have got demand, we have got that demand not being met by the traditional supply and we have adequate transportation. So those are the drivers of the lower dips and we just don't see any particular reason for those to change anytime soon.

Now with all those positive things said, I think it's very difficult to make a prediction of the numerical level of this over any period. And so I wouldn't be surprised to see them fluctuate. But I would be surprised to see them go back to the levels that existed prior to say 2007 and earlier which would be about double the current dips.

All right, thanks.

Brad Borggard, CIBC.

Just a quick question. Can you comment a little bit on the [timing] of the wells in North Dakota in your Bakken/Three Forks play and maybe a little bit in terms of color on the results you've seen on wells that have been multi-frac'd so far? Then if I could ask a second question I just -- some color on -- the operating costs this quarter were a fair bit lower than they have been recently. I was just wondering for some color on what your kind of expectations are (inaudible)

Okay, start with the Bakken/Three Forks program in North Dakota. First question that Brad had was regarding the timing of that.

After a seven-month hiatus where we were not drilling due really to lower oil prices which extended from around Christmas of last year into early July, after that hiatus we have picked up drilling. We started with a redrill of a vertical well that we have turned into a horizontal well, not yet completed because we just finished the drilling and casing phase of that well.

And then will be drilling at a pace of probably one well every 35 days or so for the remainder of the year. That will give us time this year to drill about four more wells.

It's going to take a bit of time to complete those so none of them are going to be on production at least for the next -- I would say the next month or so. After that, we will start to get some contribution from those wells.

Results to date I think actually have been quite encouraging. The current program with the results that are in place from the drilling that we did last year is certainly economic at current prices. In fact, we do think that we are going to over time get a lot better results both on the cost side and on the production side just as this play moves up the learning curve.

I think our latest statistic, if we take the wells that we finished last year, show IP's, first month rates of about 220 barrels a day and it's a little bit difficult project the EUR's, probably between 215 MBO and maybe as high from the current set of wells of 260 MBO for the average of the wells done in last year's program. And again, I do think that the results are going to improve further as we continue to mature that program.

I think the most number of fracas that we actually ended up getting into one of those wells last year was about six. We are targeting 11 for the well that we just -- the vertical well that we just redrilled.

We actually think we can improve quite a bit on the fracturing design. We are operating the wells in this phase of the project than the drilling and completion phase. So we do think we are going to get improvements in productivity even from this economic level that we have today.

Furthermore I would expect some reduction in cost levels. We're drilling the wells faster and certainly services prices are -- services costs are way down. So versus what we would've predicted to be CAD4.5 million a well drilled, completed and equipped in last year's phase; we would expect something lower than that out of the wells that we are currently drilling.

On OpEx, I think the questions were the reasons for the reduction and what would we predict for the remainder of the year. The reasons for the reduction in OpEx were on the heavy side actually largely driven by the decline in the energy complex.

We used a lot of fuel in the production process for propane and natural gas, gasoline, diesel. And so when those prices decline or OpEx declines, that was probably responsible for about half the decrease that we saw. There's also been a reduction in services costs.

We were helped a little bit on the light oil and natural gas side by the addition of the Burmis properties which were lower cost. So, roughly I would say once we take into account the new properties that we've acquired, they're going to be a little bit higher OpEx than the base that we have in the heavy oil area. I would guess that we probably have perhaps an CAD11.25 OpEx for the year would be a reasonable prediction.

There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Marino.

Thank you again for participating in our conference call. We look forward to our next discussion in November following the release of our third-quarter results.

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