Baytex Energy Corp (BTE) 2009 Q3 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Baytex Energy Trust Third Quarter Conference Call. Please be advised this call is being recorded. I would like to turn the meeting over to Mr. Derek Aylesworth, Chief Financial Officer. Please go ahead, Mr. Aylesworth.

Thank you, Donna. 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 security 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 stated are in Canadian dollars. I will now turn the call over to Tony Marino, Baytex's President and Chief Executive Officer.

Thank you, Derek. Ladies and gentlemen, thank you for participating in our conference call today to discuss our third quarter 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.

The third quarter was another strong operating quarter. We achieved production of approximately 42,600 BOE per day, a record level for Baytex and slightly more than our guidance of 42,000 BOE per day. E&D CapEx in the quarter was CAD36 million, which is about 22% of our announced budget for 2009.

We also had acquisition CapEx of CAD94 million. CAD86 million was for our Southwest Saskatchewan asset acquisition, which we closed at the end of July, with most of the remainder for deferred land acquisition payments for our North Dakota project. Production by product was also closely in line with our earlier guidance. Production of light oil was approximately 7,000 barrels per day, basically flat with Q2. Gas production of 60 million cubic feet per day was also basically flat with Q2. Although we're not investing much in natural gas projects at this time, our gas volumes were assisted by the Southwest Saskatchewan acquisition.

Our heavy oil production performance continued to be strong with production averaging over 25,500 barrels per day in the third quarter, up approximately 2,200 barrels per day over Q2. About 1,400 barrels per day of the increase was due to the Southwest Saskatchewan acquisition, with the remainder resulting from organic growth. Despite the decline in prices for WTI from last year's highs, heavy oil pricing as of today remains relatively strong due to a significant and persistent narrowing of heavy oil differentials, which Derek will discuss in more detail later in the call.

With current market prices for heavy oil around CAD65 per barrel at the wellhead in the Lloydminster area, heavy oil drilling projects in that region continue to have recycle ratios of about four, making them among the strongest projects in the North American oil and gas industry. We drilled 18 net wells in the Lloyd area in Q3 and plan at least eight more during the remainder of the year.

Production at Seal remained very strong in Q3, averaging 5,200 barrels per day. Recycle ratios at Seal are even higher than in the Lloyd area, and as a result we drilled eight wells during Q3 and plan at least four more during Q4.

At the end of July, we closed the acquisition of predominantly heavy oil assets in the southern part of our Lloydminster area operations. Production from these properties averaged 3,000 BOE per day during the remainder of the quarter. Acquisition cost was approximately CAD86 million. 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. In fact, we've identified a number of additional SAGD locations on the acquired properties that we had not expected at the time we conducted our original purchase evaluation and these will become part of our capital programs in future years.

Turning to light oil development, we advanced each of our light oil resource plays in the quarter through a combination of acquisition, development, and evaluation work. In the Bakken Three Forks project in North Dakota, we drilled two Baytex operated wells in Q3 in which we have a 0.375 interest. These horizontal wells were completed using multi-stage hydraulically fractured completions. We have production results from the first well.

Let me just take a minute to describe our convention for reporting initial production rates. We do not report 24-hour rates. Instead, we report the average rate during the peak 30-day production period. Based on this convention, the first well produced at an initial rate of 300 barrels of oil per day, which is a significant improvement from the 225 barrel per day model we have previously used for this play. The second well does not yet have sufficient to report based on this convention. We are continuing our Three Forks drilling with three more wells in Q4.

Our original agreement with our private partner in this project dating back to July '08, called for a series of deferred payments for the acquired land. The timing of the payments was dependent on the drilling pace, but would probably have stretched out into early 2011. Subsequent to the end of the third quarter, we agreed to prepay the present value of the remaining payments by mid-December of this year. The pre-pay amount is USD33.2 million, as compared to undiscounted payments of USD36 million that would have occurred under the original agreement.

The advantage of the early payment is that it allows us a higher degree of operating control sooner in the development of this project. The original agreement called for a roughly pro rata split of the operating area, based on our 0.375 working interest in the project as a whole, but only after making all of the deferred payments. The pre-pay arrangement provides for a modest expansion of our operating area and more importantly, makes the operating area available to us more than a year earlier than we otherwise would've had it.

In our Viking light oil resource play, we announced results from a well drilled in Q2. This was an unstimulated multi-lateral well drilled in Southeast Alberta. Initial rates were approximately 90 barrels of oil per day. We plan to drill up to four additional Viking wells in the fourth quarter in Southeast Alberta and Southwest Saskatchewan.

Finally, with regard to light oil resource plays, we drilled one horizontal well in the Mowry Shale in the Powder River Basin in Wyoming. The Mowry produces light oil at low rates for vertical hydraulically fractured wells in this area. We're attempting to increase productivity by using a horizontal well with multiple fracture stimulations. Completion of this well will occur in Q4, so we have no results to report yet.

With respect to guidance for Q4, we project production of approximately 42,500 to 43,000 BOE/D. E&D CapEx for 2009 is projected to be 165 million. Including the pre-pay for North Dakota, we project 133 million in acquisition spending for the year. We are currently working on our capital plan and budget for 2010, which we will present to our Board for approval and expect to announce in early December.

I'll now ask Derek to discuss our Q3 financial highlights.

Thank you, Tony. From a finance perspective, the highlight of the third quarter of 2009 was the refinancing of our balance sheet. We issued CAD150 million of senior unsecured debentures at a 9.15% coupon and a seven-year term into the emerging Canadian high yield market. This issue was extremely well received and in addition to providing us with a lower cost of borrowing than we would have expected had we issued into the more traditional U.S. market, the transaction confirms an additional new source of future financing for Baytex. Proceeds of this issue were used to partially fund the redemption of our outstanding USD180 million senior subordinated notes.

Upon the redemption of those U.S. notes, Baytex realized a cumulative foreign exchange gain of CAD51 million. As the commodities which we sell are predominantly nominated in U.S. dollars, over the term of the now retired U.S. notes, we have enjoyed the natural hedge which U.S. dollar denominated debt provides. In order to maintain that natural hedge, at the time of redemption of those notes, we converted an equivalent amount of our bank borrowings from Canadian to U.S. dollars maintaining this natural currency hedge.

Finally, we entered into a series of interest rate swaps with the result that our interest rate exposure is floating for the next two years and the large majority of our exposure is fixed for years three to five forward, locking in relatively low costs of borrowing and limiting our exposure to increases in future interest rates.

Finishing up with the balance sheet, you'll note from our press release this morning that the strong financial position of Baytex allowed us to finance a third quarter acquisition of the Saskatchewan properties entirely with a draw on our credit facilities, therefore eliminating the exposure to any equity dilution. At the end of the third quarter, Baytex maintained a very healthy and flexible balance sheet with over CAD200 million in available undrawn credit facilities, and we had a quarter end total debt position which represented approximately 15% of our enterprise value.

Funds from operations for the third quarter was CAD88.8 million, a 2% increase over the previous quarter. Third quarter results were net of a non-recurring expense item of 3.4 million related to the issuance of the senior unsecured debentures. Per our accounting policy, costs related to the issuance of financial instruments are expensed in the period in which they are incurred. Absent the conservative accounting treatment for this financing item, our third quarter funds from operations would have been 92.2 million, which is a 6% increase over Q2.

Our financial results were again supported by strengthening oil prices as the benchmark WTI averaged 68.18 per barrel in Q3, a 15% increase over the second quarter pricing. For Canadian producers, the impact of this improvement was mitigated by the further erosion in the quarter of the U.S. dollar relative to the Canadian dollar. Baytex has taken steps to protect its cash flow from the weakening U.S. dollar, both through maintaining a significant portion of debt in U.S. dollars and through a series of currency hedges, which have locked in the sale of significant amounts of U.S. dollars at beneficial rates relative to the current spot exchange rate.

The heavy oil differential continues to reflect strong demand for heavy oil compared to light oil, with the Q3 differential for Western Canadian select averaging 15% of WTI. The future continues to look positive for sustained low differentials with continued third--continuing investment in third party refining and transportation infrastructure highlighted by the coming opening of the Keystone pipeline. The fundamental drivers of sustained low differentials have allowed us to recently enter into a series of forward sales agreements, which have locked in a heavy oil blend price at Hardisty of over CAD68 per barrel on a portion of our volumes. It's worth noting that this price is about CAD11 per barrel higher than we received for our Q3 heavy oil sales, which obviously bodes very well for our 2010 cash generating capacity.

We are hedging our differential exposure with a combination of fixed dollar forward sales contracts and percentage differential deals with the result that in combination we have effectively recreated the relationship between WTI and the differential which has existed for 2009. In aggregate, we have hedged our differential exposure on approximately 37% of our projected 2010 heavy oil sales volumes.

I will now ask Tony to provide his concluding remarks.

Thank you, Derek. The general economic environment appears to have improved to some degree since our last conference call in August. Oil pricing, though partially offset by a stronger Canadian dollar, has certainly improved. Natural gas pricing continues to be relatively weak as compared to oil. Because we've held a more positive market view toward oil than toward gas, we consciously continue to position Baytex to be very oil weighted. In fact, in Q3, 90% of our revenues came from heavy and light oil. We further positioned Baytex to be even less exposed to weak gas pricing and also to the weaker U.S. dollar through our gas and ForEx hedges.

We're particularly fortunate to have approximately 70% of our Q3 revenue come from heavy oil, a product that has recently come into its own with respect to heavy/light differentials. As Derek pointed out, we have locked in a significant percentage of our differential exposure for 2010 at approximately current market differentials.

We're pleased and honored that the capital markets, both debt and equity have been very receptive to Baytex during 2009. Our long term debt issue in Canada was something of a trailblazer for Canadian non-investment grade energy issuers and our total equity return has been 105% this year, assuming reinvestment of distributions. We've been consistent in stressing conservative financial management and a sustainable income policy. And we continue to advance our long term development projects in both heavy and light oil to maintain product mix balance within the complex of crude oil products.

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

Thank you. (Operator Instructions.) The first question is from [Robert DeRush], Private Investor. Please go ahead.

In North Dakota and the Bakken on the wells that you drilled, what was the lateral length and the number of frac spaces?

On the last well--the well that we reported there, the first that we operated, we pumped nine stages into a mile-long lateral, 640, as it's called there, referring to the well diagonally covering a 640-acre or one square mile spacing unit.

And the cost of the well?

Well, the first one was actually a redrill of a vertical well that we just cut a window in and drilled a lateral. And I think that that one came in at about CAD2.7 million. Probably the indicated cost on a grassroots well corresponding to that would be about, oh, CAD3.8 or CAD3.9 million drilled, complete, and equipped cost. The second well that we drilled we spent CAD4.5 million drilled, complete, and equipped.

And how many acres net and gross do you have in the play?

It is approximately 265,000 gross and we have a 0.375 interest. So that's, oh, 90,000 or 95,000 acres.

Okay, thank you.

Thank you. The next question is from [Raymond Widmer], Private Investor. Please go ahead.

May you--or could you comment on your Saskatchewan thermal project in the Kerrobert area?

Are you referring to the SAGD?

No, the THAI project.

Oh, okay. Well, THAI is a--the THAI project is operated by Petrobank. It's in the northern part of the same Waseca Sparky channel that our SAGD is, in the southern part of the same heavy oil deposit. The THAI project involves two well pairs - a horizontal producer, a vertical injector. And it's a variation on in situ combustion whereby the fuel to heat up the oil comes from the oil that is in the reservoir itself. Petrobank is the operator and Baytex's involvement is as a 50% working interest partner. Under the terms of that project, Baytex's capital exposure is limited to CAD5 million, which money was spent in Q3, I guess, and Q4 of this year. So that is the--that's the status of the project. Petrobank has related that the air injection is in progress, that they believe they have combustion ongoing, and the two horizontal production wells are on production currently at low rates, I guess awaiting response from the fire flood project.

But you're deferring to Petrobank to report on any early production?

Well, I'm sure that we'll be notified through our regular joint interest dealings with Petrobank of the production levels. But I don't know that there's any notable production to report right now.

Thank you.

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

Thank you, Donna. Thank you, again, for your participation in our conference call. We look forward to our next discussion at our Q4 and year end call in March.

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