Obsidian Energy Ltd (OBE) 2005 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Penn West Petroleum Ltd. first-quarter results conference call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. (Operator Instructions). I would like to remind everyone that this conference call is being recorded on Wednesday, May 11, 2005, at 11 AM Eastern Time. I will now turn the conference over to Mr. William Andrew, President. Please go ahead, sir.

Thank you very much, and welcome, everybody, on the teleconference, as well as those that are listening on our Web site. Our Web site is www.PennWest.com.

This morning in Calgary, I'm joined by several of our officers, including Dave Middleton, who is our Senior Vice President of Production; Don Rae, our Senior VP of Exploration; Gerry Elms, our Vice President of Finance and Corporate Secretary; Thane Jensen is our Vice President of Exploitation (ph); Bryan Clarke, Vice President of Corporate Development; Phil Reist, Vice President and Controller; and Christian Kang is our Manager of Marketing.

The purpose of the conference call is to review our 2005 first-quarter results and also to provide an update on recent activities at Penn West. And I'll also talk briefly about the upcoming conversion -- proposed conversion to a trust. Following this review, we would be pleased to answer your questions.

During the presentation, we will be using Canadian dollars and a 6-to-1 ratio for conversion to barrels of oil equivalent. First, let's talk about the results for the recently concluded first quarter of 2005.

The first quarter provided challenges from an operational point of view due to the severe weather early in the quarter and the very mild weather in the latter part of the quarter. As a result of timing concerns, primarily due to the weather, we curtailed our first-quarter drilling and development programs with total expenditures $201.7 million. This represented about 75% of our original planned first-quarter budget and compares with expenditures in the first quarter of 2004 of $447.6 million. In hindsight, we feel that our decision to downsize the first-quarter activities was the right decision in that we avoided a finish-at-all-costs type of mentality that can lead to poor long-term value creation.

During the first quarter of 2005, Penn West drilled a total of 141 net wells, with 90 being successful as natural gas wells, and 44 oil wells. This compared to 180 net wells drilled in the first quarter of 2004. We drilled 41 wells in our northern and Peace River Arch core areas, focusing primarily on natural gas and development. 12 wells in the central area focused on light oil development and 89 wells in the plains and Southern Saskatchewan core area focused mainly on development, but also on exploration for light oil, as well as heavy oil, primarily with a modest amount of shallow gas.

Additionally, we began to be much more focused on our program of farming out lands that do not fit into our medium-term development plan. In the first quarter of 2005, operators who farmed into Penn West drilled a total of 45 wells. That's almost three times the number of wells that were drilled in the first quarter of 2004 by operators who farmed into us.

The first quarter of 2005 average daily light oil, conventional heavy oil and natural gas liquids production volumes increased by 4% compared to the first quarter of 2004. Our light oil and natural gas liquids production averaged 34,219 barrels per day. Conventional heavy oil production averaged 18,943 barrels per day. That's a total of -- in excess of 53,000 barrels of liquids per day. Average natural gas production was 289.1 million cubic feet per day, and that's down about 7% from 2004.

Total production for the first quarter averaged 101 -- 343,000 (ph) barrels of oil equivalent per day. That's a decrease of approximately 2% over the first quarter of 2004. Due to our decision to reduce first-quarter capital expenditures, we reduced our bank debt at the end of the first quarter of 2005 to $511 million. That's a 31% reduction from the 737 million in bank debt that we had at the end of the first quarter of '04.

With the exception of conventional heavy oil, commodity prices were higher in the first quarter of 2005 than they were in the first quarter of 2004. Natural gas prices averaged 685 per Mcf. That's up 7% over the same period last year. Light oil and natural gas liquids prices averaged $56 per barrel. That's up 36% over the first quarter of 2004. Conventional heavy oil prices were $28.06 in the first quarter of 2005. That's a decrease of 2% compared to the same period last year, and that's, I think as many or all of you know, that's primarily due to the increasing differentials. Overall commodity prices averaged 43.70 per barrel of oil equivalent. That's up 15% from 38.10 per barrel of oil equivalent in the first quarter of 2004.

With higher commodity prices in the first quarter, gross revenues increased by 17%, compared with the same period last year, rising from $346.1 million to $405.3 million. Operating costs for the first quarter of 2005 were 8.51 per barrel of oil equivalent, and that compares with 7.65 per barrel of oil equivalent in the first quarter of 2004. The increase is primarily attributed to the increase in the proportion of crude oil in our production mix and also within that, the increase of more mature heavy oil properties, primarily from acquisitions last year.

We also have been impacted on operating costs by increases in cost of service and energy, and of course, the tremendous industry demand in Alberta on the many projects that are ongoing, and that is very much stressing the labor market in Alberta.

A significant portion of the Company's liquids production is light oil. This commands a premium price, and therefore the Company is well-positioned to absorb operating cost increases and still maintain very high netbacks. Our netbacks for the first quarter of 2005 -- and that includes a minor hedging impact -- were $27.97 per barrel of oil equivalent. That's a 26% increase over the netbacks incurred last year. These were comprised of an average light oil and liquids netbacks of 33.50 per barrel, average conventional heavy oil netback of 14.89 per barrel and average natural gas netback of $4.86 per thousand cubic feet.

Now we will move from the volumes and then we'll get down to the real numbers, and that's cash flow and net income. Cash flow from operations for the first quarter of 2005 reached $260.1 million. That's a 44% increase over the same period last year. Cash flow includes 63 million in realized foreign exchange gains on the conversion of a portion of the Company's outstanding U.S.-denominated debt. That's been offset by an increase in estimate of our cash tax payable to $40 million from $10 million in the same period of 2004. On a per-share basis, cash flow for the quarter was $4.73 per diluted share. That's an increase of 42% over the first quarter of 2004.

Net income for the first quarter increased 10% to 600 -- $66.9 million. That's up from $61 million in the first quarter of 2004. On a first diluted share basis, net income was $1.22. That's up from $1.12 last year. The first quarter, we recorded hedging gains. The hedging gains are on our natural gas collar and they amounted to $7 million.

We had no hedges in place for our liquids production in the first quarter. Thus, we captured the full impact of strong crude oil prices. Currently, we do not have any natural gas or crude oil hedges in place. On the power side, we have an average of approximately 50 megawatt-hours hedged over the next three years, and that's at an average price of just under $45. Current spot in Alberta is running about $70, so we're doing reasonably well on that hedge.

April 11, 2005, the Company announced the receipt of a satisfactory advanced income tax ruling in respect to its proposed plan of arrangement to convert the Company to an energy income trust. On May 6, an information circular and proxy statement for the May 27, 2005, annual and special meeting of security holders was mailed to all shareholders containing the proposed plan of arrangement. And I'll take this opportunity to remind shareholders to review the information circular in detail, to read the -- notably the proxy statement, to vote, and also there are instructions for any of you that are holding share certificates on how to convert them to trust units.

If the plan is approved at the meeting, and if certain regulatory approvals are obtained, the Company will convert into an energy income trust effective May 31, 2005. Going forward and following conversion into an energy trust, we're continuing a strong focus in field operations and development. Our predominant business model will emphasize exploitation and development activities. We intend to retain sufficient cash flow to fund an internal capital program of projects, including enhanced light oil recovery, conventional heavy oil development and shallow and medium gas -- natural gas development opportunities.

And by now, most of you will have noted that there will be some changes going forward into an energy trust in terms of directors, and that our Chairman, Murray Edwards, along with Nabih Faris and Denis Russell, have decided not to put their names forward for election as directors of Penn West.

I'd like to take this opportunity on behalf of the employees to thank particularly Murray and also Nabih and Denis for their strong guidance as we've built Penn West from a micro oil company to the strong 100,000-barrel-a-day enterprise that exists today. I've also had the opportunity to work with Murray Edwards over the past 13 years, and if there's one thing I've learned from him, it's not to spend too much time in backward reflection, but rather to think ahead and to brace for the future and to work hard to build future value.

To that end, we're ready for the new challenges that come with building Penn West into the biggest and most efficient energy trust in Canada. Joining me in making this a reality will be David Middleton, who becomes our new Chief Operating Officer, and also the staff and management of Penn West, who have contributed their innovation, knowledge and just plain old-fashioned hard work to build Penn West to where it is today. We've also had to endure 14 months in the twilight zone, and as a result, I know are chomping at the bit with an opportunity to get going again under Penn West Energy Trust.

I'd like to thank you, and we'd be pleased to answer any questions. And we now ask the operator to take questions.

(Operator Instructions). Bryan Denton, UBS.

I'm sorry, this is an accounting question. But I was just wondering if you could help me on the cash flow side here -- how we go from a $1.5 million charge on the P&L for the FX translation to a $64.5 million item on the cash flow statement.

I'll flip you over to Gerry, our VP of Finance, on that one.

Brian, obviously as you go through the unrealized gain and the realized gain, it seems very -- our U.S. position was pretty stagnant throughout the period. But the change on the exchange rates on the total position, that's because we had a small loss on the exchange. But then, because we realize some, some get into realized and then there's an unrealized loss and a realized gain, and then two in the -- net of the realized gain and the unrealized loss ends up in the total position of the U.S.-denominated position on the change of exchange rate between the two period ends.

So you are showing me a net on one of the -- on the income statement, are you?

On the income statement there would be a small charge.

Maybe we can pursue this further off-line. Thank you.

Keith Trauner, Fairholme Capital.

A quick question with respect to hedging. The Company had hedged in prior periods, and given current liquids prices, and kind of it seems like an awfully attractive opportunity to lock in some cash flow for some period of time on a portion of the production, especially as an income trust now. Is there any reason why you are not hedging at this point?

I think we're just following the market. Undoubtedly, as an energy trust, obviously the primary consideration is the unit holders and their receipt of the distributions on a monthly basis, and then to keep those distributions as consistent and as uniform as possible. To that end, it will be prudent to engage in a hedging policy to lock in as many of the numbers as we can. So, going forward, we will be hedging. Currently, we're quite bullish in the long term, both on oil and natural gas. However, as I say, that may not prevent us from doing hedges.

Yes, I guess, as a follow-up, it just seems like at current levels, locking in prices could virtually guarantee a significant portion of value comes out.

Absolutely, absolutely. And that's certainly something that we will look at as we do the conversion into a trust.

Chris Steel, Tristone Capital.

I just wanted to look at the farmout activity in the first quarter. It's a fairly dramatic jump-up. What's been happening internally? Is there now sort of a business group that is managing a farmout process, and about how many wells a year do you expect to farm out?

We've been doing it under the conventional model. So the primary direction with regard to farmouts has come from Don. Don has done a wonderful job with his staff over the past 13 years of managing our land. Left unattended, with almost 6 million acres of land, you would be looking at about 1.5 million acres that would expire every year. In reality, our expirees are generally a small percentage of that amount of land, and that's because of Don and his staff's diligence in controlling the land. So what he's done this year is that -- other years we would've tackled with the drill bit. And this year, recognizing where we were in the process and where we were on the likelihood of converting to an energy trust, we concentrated much more on farmouts of the land. We're going to do that on an increasing basis. My intention is to set up a business development group that would include as part of its asset group -- some of whom will be focused strictly at farmout opportunities. But you're going to see that increase probably exponentially over the next few years.

And just one more question. I just wanted to clarify in the press release today, it says that -- and I mean, maybe it's a bit of a moot point, but cash taxes as a going concern E&P Company for the year of 150 to 170 million, is that right?

Right, yes.

Sorry?

Yes, that's correct.

Stephen Calderwood, Raymond James.

I wonder if it's time or if it's possible to elaborate or update us on the plans to expand the CO2 flood in Permbina Cardium. How would you do that potentially under a trust?

Sure. I'd love to do that. Firstly, this has been Bryan Clarke's baby since inception about three years ago, when we got going with it. Currently, our pilot is underway. We're starting to see some response. We're starting to see, I believe, some reasonable response. And we're working very much on the front end, but I feel that we're the most advanced of any of the energy companies in Canada with regard to the use of CO2 to enhance oil recovery and also with CO2 sequestering. As I've said before, I don't think it's -- I don't believe it's going to be a tough sell with a successful pilot -- with a commercial arrangement on the supply and transportation of CO2. I don't believe that that's going to be a problem, either, to distribute more units within the trust or to finance the capital that's necessary to do this project. So we would either do it by extra units or we would do it by bank financing or we would do it by a combination of both. But we've been excited about this project for three years. There's certainly nothing to dampen our excitement right now. We feel we're pushing towards the end here. And we're looking forward to commercial production from the Permbina field latter part of 2008, early 2009.

David All, DLA Analytics.

Some of the questions have been asked, but could you tell us a couple of things? What's going on -- your gas production is down pretty steeply year-over-year. Is this a result of the curtailed drilling program that you had in the first quarter? Second, could you give us some -- are you going to be running any forecast information for production and cash flow for the year?

We won't be providing anything at this time until we lock in the distribution number, and that will dictate how much capital that we have to expend on our project. So we'll do that shortly after conversion to a trust. The gas is -- I mean, it's a tough -- gas is a fairly tough business in western Canada. So if you don't have the land and opportunity where you can go in and really drill it up with extensive infill drilling, which is -- in reality, most of the companies that are adding gas production are doing it from existing fields and from infill wells on existing fields. Our production adds over the past six or seven years prior to the last couple of years have all come from exploration and all come from brand-new fields and brand-new gas. And I think as with any company, sometimes you hit a flat period. And we hit a flat period the last two years, particularly in gas.

This has been offset in my mind by the tremendous success that we've had with heavy oil and somewhat with some of our light oil exploration activities in Southwest Saskatchewan, particularly. So, yes, it's been disappointing from the gas point of view, but it's also the nature of the business, that you're going to hit some flat spots, particularly when your focus for growth on gas has been exploration rather than pure development and drilling more holes in the same field.

Going forward, we do have some opportunity, particularly in shallow gas, to do some drilling. We've been -- as I pointed out in the last conference call, I don't think any others company in Canada, probably in North America, has worked under the burden that we have over the past two years, where we've had to approximately 1.5 million acres of our prime gas development land that's been sterilized because of a conflict that we've had with the First Nations Group up in Northern Alberta. We feel that we're -- as I said in the last conference call, we feel that we're very, very much in a better position on that land right now due to a recent court ruling that basically sided with the work that we had done to consult with the First Nations and to get on the land. We have --conservatively, we would have 700 or 800 locations on that shallow gas up in Northern Alberta, and I believe that over the past two years that would have significantly impacted our gas. But that's hindsight, and hindsight is usually not worth a lot.

Can I ask you a couple more questions, please? Could you tell us a little bit about your farm-in program and how successful it's been? Are you -- I assume your people are farming in particularly 1% of an interest and you're being carried, or what (multiple speakers).

They are generally -- they're sort of all over the place, but it's generally a two-for-one deal or a straight nonconvertible override deal. They've been -- I'd say they've been as successful as industry. Obviously, we like all the people who are active on our land to be very successful because it means we are successful as well. So I would say that -- I would term the 45 wells as sort of -- with normal industry statistics, there's been some good gas wells, there's been some oil wells and there's been some dry holes. And it's just a matter of building that, particularly cash flow from our farmout activity up. And I think that's -- it's about one thing that I look forward to in the trust. It's a way of securing some additional cash for distribution outside the normal conventional sort of envelope.

Can I have two more questions here? One, would you add -- would you consider going out and adding more acreage for farm-in prospects or for exploratory prospects? And could you tell us if there's been any progress on the Seal prospect -- the Seal heavy oil field?

Sure. Right now, we've got about six times -- as an energy trust, we will have about six times more land than any other energy trust. I don't see us adding a whole lot. Certainly, we have always been a Company that doesn't appreciate it very much when somebody comes in and posts land beside us. So we would be aggressive in that regard. We would also be aggressive to protect plays that we have. But I believe that Don and his crew have done a tremendous job to get us the land position that we have today, so we intend to get it worked.

The Seal prospect is one that was really being impacted by two things. One is the differential in heavy oil, and two are some of the difficulties with weather in the first quarter and continuing a little bit into the second quarter. We've had a tough time getting the oil out of Seal, and when we did get it out, we had a tough time realizing any value. So as a result, we've had up to 1000 barrels a day shut-in in that prospect throughout the first quarter. My feeling is that through the latter part of the summer and going on into next winter that we will be getting back in there, doing some more drilling. The other thing that we obviously have to do is have control of our product and our product sales, and we do that by having our own battery, having our own transportation, and we will be looking at that this winter as well.

We've got a wonderful land position up there. We've had some people that are probably a little more active on press releases than we are. We've had extensive discussion about plays. I think if you look at the area, you'll find generally that our land is in very close proximity to recent discoveries, that we will be actively working that land. We've got some 30-odd development horizontal locations that are currently on the books and ready to go. So it's just a matter of trying to work on the differential. We don't have a lot of control about -- on that, but we obviously feel that the differential will narrow, allow us to get some reasonable return. And that point, we would move to get back into Seal again. I think the important thing to remember is that these are long-term oil sands leases. So you're not held by the same time constraints that you would be on a conventional lease, which is normally five years. On these, they are 15 years.

Roger Serin, TD Newcrest Securities.

I'm wondering if, on the basis of your $0.23 to $0.26 on the distribution and assuming a 60% payout ratio, you could give me a range in terms of production and pricing assumptions on that.

We'll be giving that to everybody very shortly after the conversion. But I will be providing that.

Is it consistent with your fourth-quarter guidance on the pricing side, at least?

Yes, very much so. We've used -- you know, to get to the $0.23 to $0.26, we've used a range of prices. I think those of you that know us reasonably well would appreciate the fact that we are not going to take the most aggressive price and stance as we go forward. We're going to try to lock in a distribution that's achievable, so that there are no surprises for the unit holders.

(Operator Instructions). John McLear, Ken Fund Management (ph).

Two questions. Firstly, in your outlook comments, the phrase, we will distribute up to 60% of cash flow appears. Previously I think you were using the phrase, approximately 60%. Could you comment on what the inference is? And secondly (multiple speakers).

No inference, I think is the choice of vocabulary.

John McLear So, no inference meant?

No.

Okay, secondly, in light of Mr. Edwards' decision not to continue on the Board, who is slated to be the Chairman or lead director?

That will be John Brussa.

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

I would like to thank everybody for joining us and then certainly the many employees that are listening out there, as well as the shareholders and those of you that will listen on our webcast. Thank you very much and we will see you at the annual meeting on the 27th of May.

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