Obsidian Energy Ltd (OBE) 2005 Q4 法說會逐字稿

Welcome to the Penn West Energy Trust fourth quarter results conference call. [OPERATOR INSTRUCTIONS] I would like to remind everyone that this conference call is being recorded on Tuesday, February 28, 2006, at 11:00 a.m. Eastern time. I will now turn the call over to Mr. William Andrew, President and CEO. Please go ahead, sir.

Thank you and good morning. With me in Calgary this morning are Dave Middleton, our Executive Vice President and Chief Operating Officer; as well as Todd Takeyasu, who is our Vice President of finance; and other members of our management team at Penn West Energy Trust. I'd like to welcome everyone who's listening today on the teleconference, or who are wired interest our webcast. Over the past several months, we've had the pleasure of speaking to a number of unit holders both on the retail and institutional side, and I'd encourage any unit holder with questions or concerns regarding Penn West Energy Trust to please contact us on the web. Our website is www.Pennwest.com. Or via the telephone.

This conference call will review or 2005 fourth-quarter results and provide an update on recent activities at Penn West Energy Trust. Following the review we'd be pleased to answer any questions. During the presentation, we will use Canadian dollars and a 6 to 1 ratio for conversion of barrels-to-oil equivalent unless stated otherwise.

Results for the fourth quarter of 2005 represent Penn West Energy Trust's second full quarter since inception. For comparative purposes we'll be looking back to the fourth of 2004 as a benchmark for this quarter, although results are not directly comparable because we began business as an energy trust at the end of May, 2005. In the fourth quarter of 2005, gross revenues were $554.5 million. The resulting cash flow was $332.6 million. That was an increase of 40% over our performance in the fourth quarter of 2004. On a per-unit basis, cash flow for the third -- for the fourth quarter of 2005 was $2.03 diluted. For the full year, cash flow was $1.185 billion. That was an increase of 37% over 2004. Net income for the fourth quarter of 2005 was $241 million. That's an increase of 251% over the fourth quarter of 2004. On a per-unit basis, net income for the fourth quarter of 2005 was $1.46 diluted. For the year, in total, net income was $577.2 million. That's an increase of 112% over 2004.

In the fourth quarter of 2005, the Trust distributed $143.6 million to unit holders. This distribution represents approximately 60% of our net income for the quarter. Effective March 15, 2006, per unit, per month distributions will increase to $0.34, and that's a 30% increase in per unit distribution since we commenced operations in the middle of 2005. The fourth quarter 2005 light oil and natural gas liquids production averaged 33,227 barrels per day. Eventual heavy oil production averaged 18,726 barrels per day. For a total liquid volume of 51,953 barrels per day.

Average natural gas production for the fourth quarter was 277.5 million cubic feet per day. A total production for the fourth quarter of 2005 averaged 99,205 barrels of oil equivalent per day. That's a decrease of 1/2 of 1% from the third quarter of 2005 production of 99,803 barrels of oil equivalent. And I think it's a good time to point out that during the quarter we sold approximately 1,800 BOE per day of production, most of which was gas. That's why if you look at where we were forecast versus actual, we're a little behind where the Street was on gas. And that reflects the sales that we made in the fourth quarter.

The fourth quarter 2005 natural gas prices averaged 11.66 per Mcf and light oil and natural gas liquids prices averaged 64.28 per barrel. Eventual heavy oil prices averaged 34.95 per barrel in the fourth quarter. Overall, commodity prices averaged 61.38 per barrel of oil equivalent. That's up 5% from what we realized in the third quarter of 2005. Operating costs for the fourth quarter of 2005 were 9.44 per barrel of oil equivalent. This represents an 3.5% increase over the previous quarter. The result of higher service costs and increased natural gas compression costs.

We've -- I'll note here that we've grown our percentage of liquids production to total production over the quarter to almost 53%. Of the liquids, approximately 64% consists of light oil and natural gas liquids. Light conventional oil fields under secondary recovery generally have higher than industry average lifting costs, however, the production commands premium price. Penn West Energy Trust is well positioned through ownership in many of the large light oil fields in Canada. This ownership position does absorb industrywide operating cost escalation and still maintain very strong operating cost net backs. Our net backs for the fourth quarter of 2005 were 39.42 per barrel of oil equivalent. That's up 1.5% from the third quarter of 2005. The oil equivalent net back includes an average light oil and liquid net back of 37.65 per barrel. Average conventional heavy oil net back of 19.64 per barrel and an average natural gas net back of $8.12 per Mcf.

Capital expenditures in 2005 totaled $456.7 million. That's down by about $409 million from the $866 million at last year. And it should be noted that our capital expenditures for the fourth quarter totaled only $6.3 million. So we had a very modest quarter in terms of expenditures. At year end 2005, Penn West Energy Trust had proven plus probable oil reserves of 357.1 million barrels of oil equivalent. That includes 290.5 million barrels of proven oil equivalent. Based on our fourth quarter average rates and using proven plus probable reserves, our reserve life index at year end 2005 was approximately 10 years. And we'd note that 84% of our proven reserves are classified as proved producing. Which is the top category for a reserve classification.

Refining, development, and acquisition costs in 2005 averaged $17.17 per barrel of proved plus probable oil equivalent. This was an improvement over 2004, but if you -- if you take a little harder look at the year itself, it's interesting to see where the number landed. Prior to conversion to a trust and after conversion to a trust. And we haven't narrowed it down to the penny but roughly you can take about a $3.50 or $4 range on either side of that number. So as a trust, we believe that our finding cost was running between $13.50 and $14 per barrel. As an E&P company it was closer to $21 a barrel.

At the $17.17 obviously we're not pleased with that. We're going to continue to work on that. I talked about the number that where we feel it is since conversion to a trust. Our capital efficiency since conversion is running at 25,000 of producing barrels. I believe that shows that we're moving to finding development costs that will be comparable or better than the average of our peer group.

Penn West Energy Trust has $1.22 billion credit in operating facility. The revolving bank facility is with a syndicate of banks and has a three-year term. Bank debt at the end of the fourth quarter of 2005 totaled 542 million. That compares with $778 million in the third quarter. Based on commodity prices of $58 U.S. per barrel of WIT crude oil, and 8.75 Canadian per Mcf of natural gas at the Field Gate, an average production range of 94,000 to 98,000 barrels of oil equivalent per day, we are forecasting cash flow to be in the order of 1 billion to $1.1 billion in 2006. The 2006 capital program calls for expenditures of between 400 and $500 million. That will fund approximately 300 net wells. Using a distribution of $0.34 per unit, per month in the mid point of our cash flow, forecasts yield about a 60% payout ratio for the Trust.

Current production rates are within guidance. We are producing -- depending on the week between 97 and 98,000 barrels of oil equivalent per tollway. Penn West has an active hedging program to increase the assurance of future cash flow to fund distributions and capital program expenditures. That provides effective downside protection, as well. If 20,000 barrels per day of crude oil hedged through the end of 2006 on collars with floors averaging 47, 50 US per barrel WTI and a ceiling averaging approximately $68 U.S. per barrel WTI.

Currently we have 111 million cubic feet per day of natural gas hedged for the first quarter of 2006. Again, that's on a collar with a floor of 882 per Mcf and a ceiling of 1660 per Mcf. For the second and third quarters 2006, we've hedged 97 million cubic feet per day using collars with a floor of $9 per Mcf and a ceiling of $16.09 per Mcf. Full details of some crude that we've hedged through 2007, smaller volumes, and smaller volumes of gas in the fourth quarter are available on our website.

Going forward, we'll continue to concentrate on field operations, development project, and enhancing capital efficiencies in all areas of our business. Work in the first quarter of 2006 has focused on optimization at the field operations level, northern gas development, and horizontal in field drilling for oil. We continue to direct significant effort at monetizing our extensive land base through farmouts, dispositions, and joint ventures. Since the conversion we've placed a high priority on becoming the most aggressive land dealer in the industry. And to date we've complete farmouts totaling 600,000 net acres.

In addition to noncore property rationalization and conventional exploration and development activities, we're continuing to work on the implementation of our strategy of replacing our existing reserve base over the next 10 to 15 years. By implementing enhanced recovery techniques on our light oil pools including Pembina and Swan Hills. Projects provide opportunity to markedly improve the productivity, recovery, and operating efficiency of the pools by utilizing large volumes of greenhouse gas in the form of carbon dioxide. These projects demonstrate that we can efficiently reduce emissions while at the same time increasing the producing life and ultimate recovery of conventional oil reserves.

Our Canada CO2 project which is a joint effort or pilot project which is a joint project of the government of Canada and the government of Alberta and Penn West Energy Trust has been operating for a year, and we're very encouraged by results to date, including CO2 containment, reservoir pressure increase, and improvement in productivity. Our Peace River Oil Sands project has the potential, we feel, to redefine our business. The initial commercial phase of development at Seal will see us increase oil production to between 4,000 and 5,000 barrels per day by year end.

We've got over 200,000 net acres at Seal, and we believe this area has a potential to add multiple millions of barrels of reserves and very strong production additions with good capital efficiency utilizing primary production techniques. And that's an important distinction we want to make about the Peace River Oil Sands Project is that production commences immediately. The wells are drilled in a conventional manner, horizontally. The oil that's produced is produced with a pump. And goes right into the pipeline. It's then blended with light oil. And processed. So there will be certainly on this project up the road as we move towards thermal, there will be very significant capital expenditures, but we feel as we move this production up over the next five or six years that basically the costs that are going to be involved are very -- there's very little difference to a conventional oil operation. And I think that's a distinction to make on some of the other oil sands projects where you're required to have four or five years of lead time before you see your first barrel.

The other thing I just want to talk about for a second, there's a little more explanation in our annual report and a little bit in our MD&A. That's on the environmental side. We're doing things a little bit differently at Penn West Energy Trust in that we will be budgeting between 20 and $30 million a year on environmental work. To basically reclamation work that's required and abandonment work that's required on suspended wells. In doing this, and we're doing this rather than having a reclamation fund because, quite frankly, the amount that we've targeted to spend per year is equal to the amount that a lot of companies have in their reclamation funds. And we want to be -- we want to build this energy trust into one that has concern for the environment. And we're going to show that by making the necessary capital expenditures to work with our stakeholders in the Company. Thank you, and I'll turn it over to the operator. We'd be pleased to answer any questions that you have.

Thank you. [OPERATOR INSTRUCTIONS] Your first question comes from Jack Bitner, a private investor. Please go ahead.

Yes. I see that under the reconciliation of cash flow distributions, as you mentioned of about 60%, 66% for the seven-month period and 63% for the last quarter, is the Trust required to pay the balance of that to bring the distribution to 100% of income, which I think is mentioned on the page before? And if so, when would that be paid?

Well, I'll turn that our to our CFO, Todd.

Well, the percentage of distribution -- distributions as a percentage of net income to us is an important gauge that to the extent that your distributions are less than your net income, you're really providing a return on capital to your investors. Whereas the general thinking is that if you distribute in excess of your net income, then you're tending to grind the capital of the investor. But the Trust is required only to distribute enough such that it has no taxable income. There's a difference in the -- between the tax income and the net income for book purposes.

I see.

Thanks.

[OPERATOR INSTRUCTIONS] Your next question comes from Kurt Willis of McDep Associates. Please go ahead.

Good morning, Mr. Andrew. Can you tell me if there's any progress on your plans for listing in the U.S.?

We're moving toward it. We have started the process for being compliant in terms of our systems and controls. Our initial projection coming out of the gate last June was that it would take about 18 months, and we feel that we're on target with that. So I would anticipate that we'll be getting close by the end of the year.

Thanks.

Thanks.

Your next question comes from Christina Lopez of Tristone Capital. Please go ahead.

Hi, Bill. With additional heavy oil expected from Seal and just your conventional heavy, as well, have you looked at any sort of refining arrangements or deals with refiners in the US or potentially Canada?

We've been talking to both existing refiners and planned upgraders and refiners. We haven't -- we haven't formalized or finalized anything yet, but we are in discussions with them.

Excellent, thank you.

Obviously, that's something that we'll want to do because of the amount of volume that we anticipate over the next 10 to 15 years.

Thank you so much.

Your next question comes from Roger Serin of TD Securities. Please go ahead.

Bill, I wonder if you could give me some color on the Seal production today in terms of dips and operating costs.

Sure. It's -- Bill it's not a very wonderful project to operate at the current time because we're producing -- basically an experimental project, and it will be that way until about mid year. We're producing to single oil factories, we're trucking everything out to get the -- basically the upgraded and blended, and that involves loading and unloading twice. We're looking at operating costs right now of around $16 a barrel. At current heavy oil price we're making a little bit of money but not a lot. We've committed to participate in a major battery up there. We've also committed on a -- on a sales gas pipeline that will take oil out and basically eliminate some of that two and three-step process that we're going through right now. So we're targeting -- we're targeting production costs for this crude of less than $10 and probably in the 7 to $8-per-barrel range.

Differentials, I mean, that's just something you live with. Those with some gray hair will realize that January, February, March, and April are not usually very robust times for moving heavy oil. And -- one thing we are encouraged about is the fact that although the differential has widened, it hasn't -- I guess it hasn't taken off maybe as much as some of us has expected. So we're confident, very confident going forward that two things will happen. One is that we're going to improve our operating efficiencies by tying the wells into a battery that we own. And a sales pipeline that will get us blended. Secondly, as we move forward on the project over the next four or five years, we'll be participating in refinery and upgrading capacity and that will significantly change the product price that we see.

Thanks, Bill.

Mr. Andrew, there are no further questions at this time. Please continue.

I'd like to thank everybody for listening this morning. If you have any questions, give me a call. In my absence, please feel free to call Dave Middleton. My direct line is 403-777-2502. Dave's direct line is 403-777-3301. Thank you very much.

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating. Please disconnect your lines.