Obsidian Energy Ltd (OBE) 2002 Q1 法說會逐字稿

Good morning, ladies and gentlemen, thank you for standing by. Welcome to the Penn West Petroleum first quarter 2002 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. If anyone has any difficulties hearing the conference, please press star zero for operator assistance.

I would like to advise everyone that this conference call is being recorded. I would now like to turn the conference over to Mr. William Andrew, President. Please go ahead, sir.

Good morning and thank you all for your interest in Penn West Petroleum limited. And with me today are the brave soles that made it through the traffic woes in Calgary. We had a pretty fair snow storm last night. Anyway, in the room with are Don Rae, who's our Senior Vice President of Explorations, Gerry Elms, who's the Vice President of Finance, Bryan Clake, who many of you know as our Vice President of Marketing and Investor Relations, Dale Miller our Vice President of Engineering and operations. David Middleton of our Vice President of Production and Gordon Timm, Vice President of Land.

First, this conference call is to review our 2002 first quarter results. And to provide an update on recent activity at Penn West. And for those of you who require some more specific and detailed information on Penn West, our Web site is at www.pennwest.com. Following this review, we'd be pleased to answer any questions that you may have regarding the company. And during the presentation we use Canadian dollars, and a six to ratio for conversion of natural gas to barrels of oil equivalent.

In the first quarter of 2002, crude oil and natural gas volumes increased by 17 percent and natural gas - sorry natural gas liquids volumes increased by 17 percent and natural gas volumes increased by one percent compared to the first quarter of 2001. During the first part of this year our oil and natural gas liquids production averaged 42,000 barrels per day and natural gas production averaged 313 million cubic feet per day.

Per volume prices were significantly lower in the first quarter of 2002 than in the first quarter of 2001, particularly natural gas prices. First quarter, 2001, our average price realization for natural gas was 321 per 1,000 cubic feet, down 64 percent from the 901 realized in the first quarter of 2001.

Prices for crude oil and natural gas liquids are also down compared to the first quarter of 2001, from 35.21 per barrel to 27.62 per barrel in the first quarter 2002. That was a decrease in 22 percent.

Our operating cost in the first quarter 2002 averaged 539 per DOE. That was an increase of 12 percent over the first quarter 2001. This increase was principally due to the increased ratio of oil production to GAAP production in the first quarter 2002 as compared to the year ago. And as many of you know, oil properties have a longer life than gas properties, but on the other side, the sub side they're on average more expensive to operate from gas properties.

As a result of the cumulative changes, our cash flow in the first quarter of 2002 was down by 58 percent compared to the first quarter of 2001 from 226.2 million to 94.5 million. On a per share basis, cash flow was 1.79 in the first quarter of 2002. That was down from 435 in Q1 2001. Diluted cash flow per share was 1.74 in the first quarter of 2002.

Net income reflected lower cash flow and an increase in the provision for depletion depreciation and site restoration. Net income for the first quarter of 2002 was 25.2 million. This is a 76 percent reduction compared with net income of 101 or sorry 104.2 million achieved in the first quarter of 2001. On per share basis, net income was 48 cents in the first quarter of 2002. That was down from 2.01 per share in the first quarter of 2001. Our diluted net income per share was 46 cents per share on first quarter of 2002.

Natural gas prices appear to have bottomed out. And they're exhibiting strength in the second quarter of 2002. As a result, we've increased our price forecast for 2002 to 350 - 3.50 per thousand cubic feet to an average of 3.75 per mcf. Recent prices on the forward markets would yield an average price in excess of 3.90 per mcf for the year.

An improved economic climate and supply caused crude oil prices to react positively with prices showing considerable strength in the second quarter. Based on this strength, we've increased our price forecast for the year to an average of 22.50 U.S. per barrel of WTI. That's up from an earlier forecast of 21.50 per barrel. This estimate is conservative when compared with the future's markets where WTI is averaging almost $25 U.S. for the year.

The stronger prices beginning in the second quarter of 2002 are now forecasting cash flow for the year in the range of 430 to 470 million using our price assumptions. If commodity prices were to retain their current strength cash flow from operations could approach 550 million.

Cash taxes for the first quarter 2002 totaled 10.5 million for the year 2002. We're estimating that cash taxes will be in the range of 40 to 60 million. That represents approximately 10 percent of a pre tax cash flow. For 2002, we expected capital expenditures will be in line with our cash flow from operations. This will continue our approach over the past two years where our growth has been financed strictly from internally generated cash flow.

For 2002, we're continuing to target capital spending of between 400 and 500 million, although it now appears that spending will be closer to the higher end of the range, given the favorable economic environment for heavy oil, light oil and natural gas.

At the end of the first quarter, this year, bank debt was 579 million compared with - compared to an available limit of 750 million with a syndicate of chartered banks.

We've maintained a strong balance sheet for the debt to first quarter annualized cash flow ratio of 1.5 to one. With our strong balance sheet, the potential does exist for significant spending in excess of our base budget. Our capital spending is reviewed on an ongoing basis. And is adjusted to respond to change in the commodity prices or to pursue an acquisition that makes sense.

During the first, we drove 112 net well and spent 163 million. Our capital program focused on natural gas exploration and development in an urban core area. The program included development drilling at Wildboy in British Columbia where we increase production by more than 30 million cubic feet per day.

We completed an active exploration program that has laid the foundation for our six consecutive expansion phase next winter Wildboy. In the region we targeted natural gas at Hotchkiss and Haig adding 20 million cubic feet per day of new production.

The first quarter natural gas drilling program will begin to generate production results in the second quarter this year as a the new wells are tied in and as the facility expansions are completed. Currently, we're producing approximately 350 million cubic feet per day of natural gas. And 42,000 barrels per day of oil from natural gas liquids.

In the first quarter, we completed property acquisitions valued at 25 million and we're continuing to work on other acquisition opportunities.

For the balance of 2002, we'll switch our primary focus to shallow, natural gas and conventional heavy oil in the planes area. Our efforts at will continue with a focus on light oil as well as a full bed methane. We're conducting an active exploration program including land and seismic acquisition and drilling spread over a variety of prospects.

We have not added any new hedges since our last teleconference in March. In the second quarter of 2002, we have existing hedges in approximately 50 percent of our natural gas production. That's with an average four of 310 per mcf, an average ceiling of 370 per mcf. And the third quarter, hedged volumes dropped to percent and fell through to the two percent in the fourth quarter.

On the power side, we have 20 megawatts of per hour hedge for the next three years, at an average price of $56 per megawatt.

Crude oil, with hedges totally approximately 43 percent of our liquids production in the second quarter, with an average floor of 18.50 USWTI, now a ceiling of 22.20 per barrel, WTI. Our liquids hedging drops to 21 percent in the third quarter, and to 7 percent in the fourth quarter.

Going forward, and in the absence of a large acquisition, we will continue with a modest hedging program aimed at smoothing cash flows and protecting our capital spending program.

In summary, we believe that Penn West is a unique company in many ways. We have good balance between natural gas and oil, and this provides a cushion at times of metered commodity prices. Our long-life reserves provide the flexibility to select projects based in both long-term and short term financial impact. We're committed to incorporating both technology and innovation in our quest to achieve maximum value from our properties.

We have a strong commitment to our community and to the environment. Most importantly, we have the discipline to maintain a strong balance sheet, giving Penn West the financial strength and ability to continue to grow. Thank you, and I'd be pleased to answer any questions that you may have.

Thank you, ladies and gentlemen, we will now conduct a question and answer session. If you have a question, please press the star, followed by the one, on your touchtone phone. You will hear a three tone prompt acknowledging your request. Your questions will be polled in the order they are received. If you would like to decline from the polling process, please press the star, followed by the two.

Please ensure you lift the handset, if you are using a speakerphone, before pressing any keys. One moment, please, for your first question. Your first question is from Steven Calderwood with Salomon Partners, please proceed.

Yes, thank you very much, I am -- in your annual you give a breakdown of your liquids production, in that you're dominated by lighter and medium oil. And in my forecast, I guess I have a little more oil production growth to come in 2002. So my question is twofold, can you describe the profile if your liquids production in total over the next 12 months to give me an idea about whether or not you may be interested in increasing your liquids production, especially on the heavy side. And then the summary, could you maybe give me a breakdown of what your targets are for percentage of light and medium oil versus heavy oil, going forward.

Sure, thank you. As you know, our first quarter production was 42,000 barrels. Our budgeted increases on oil would be to an average of 43,000 barrels per day by the fourth quarter of 2002. Most of that -- most of the oil there -- the oil that -- would come mostly from heavy oil in the plains area and our drilling for the year, but would also be made up with light oil. The heavy oil, we'll get to sooner in that we can get our drilling rigs out there as soon as the snow stops, whereas the light oil we tend to start our work at Drayton Valley towards the middle of July.

So, we'll have a little more impact from heavy oil than light on our . Our current makeup, our liquids, about 70 percent of our production is light oil, with an average API of 37. Twenty-two percent is heavy oil, with an average API of about 16 percent -- 16 degrees, and our NGL's are about 8 percent of our production.

Sorry. And going forward, beyond 2002 into 2003, we think we can continue to work that type of a balance, although with any further narrowing in the differential with heavy oil, we've got a tremendous amount land that's available for development drilling on the plains, and we could ramp up the amount of heavy oil production that we have by drilling more wells up there.

That's great, so that was kind of what I was getting at there. You're not overly enthusiastic about heavy oil just because of the recent narrowing. Sounds to me like you'd need a period of time -- what kind of period of time would you like to see before you really ramped up heavy oil, in terms of the differentials being around the long-term average here.

Again, it's not really a lack of enthusiasm, it's a lack -- an excess of other opportunities. We've got a tremendous land base in an essential area, particularly around Drayton Valley. We also have oil that we are developing in our north-central area, and the economics are just a little better -- long-term economics are just a little bit better on the light oil right now, and also the long-term outlook is a little bit better.

In terms of narrowing in differential, I think for the long term that we would look for an ability to have more heavy oil upgraded in western Canada, and at that point we would very aggressively pursue heavy oil drilling. In the meantime, we'll continue to drill, but just not at the pace that we could drill.

That's great, thanks a lot, Bill.

Your next question is from Dennis Lawrence with First Energy Capital, please proceed.

Hi, good morning gentlemen. A couple of questions, first Bill, you mentioned gas pricing under the current strip -- about 390 per -- I just want some clarification on that. Was that for the remainder of the year, and was that a realized price, including your hedges, or how did you come to that 390?

Well, I'll switch you over -- I'll answer it, but I could answer, but let me switch you over to Bryan Clake because...

OK.

Yes Dennis, I guess it's all of the above -- that would be our realized price, on average, for the year, net of hedging. And that would dollar CF at our plant .

OK, perfect. That's the answer I was expecting. The rest of the year, in terms of cap ex, could you give us some outlook, you know, you spent a little over 160 million Q1, sort of targeting up towards 500 million for the year. Just roughly, how would you envision that breaking down over the remaining quarters?

We see a significant amount -- the majority of that spent in the second and third quarter, probably fairly evenly. And in terms of the areas where we would spend it, the amount of money would again be fairly evenly split between the plains area and our central area.

Additionally, we've budgeted $75 million in acquisitions, and as we indicated, we spent 25 in the first quarter. We would expect to close some acquisitions in the second or third quarter.

But you would see the spending as primarily Q2, Q3, not Q3, Q4.

Primarily in Q2, Q3.

OK. Great. That's all I have, thank you.

Ladies and gentlemen, as a reminder, if there are any additional questions, please press the star, followed by the one. Your next question is from from and Company, please proceed.

Hi, Bill, it's Brian here. Quick question on, I guess, services cost. What are you finding with respect to drilling and well work-overs back to cost?

I hope you're up to pick you up. You're a little faint, Brian, I did you get you. The question was related to our experience on drilling costs now and going forward versus what they did in the past year, and also in service costs.

What we're finding for the summer is that the drilling costs are coming down somewhat, probably in the 15-20 percent range. The service cost -- it seems to be more a factor of how active the industry is, and the real impact on the services is how use the people are making of the services. When it gets very busy, you spend time waiting for services, the crews are not quite up to the snuff of when it's less active.

We probably see about a quarter -- a quarter worth of some pretty reasonable service costs, and then -- I'm very, very positive that with the way the gas price is strengthening, and the way the oil price is holding up, that many companies are in the same situation as we are, where we're looking at increased cash flows, and they're looking at opportunities to drill.

And when you drill, you service your wells, and also I expect that there will be some amount of optimization and completion work done in the second and third quarter. So we expect that services will be, again, pretty tight going into next winter, as well as drilling.

Bill, yesterday in the you mentioned about how you're, like, one of the last five here. Notably within that group, you don't have, sort of, a frontier exposure or international. Could you comment on sort of your thoughts on that and an on an acquisition basis, where you think you might be going over the next few years?

Sure. I guess to try and answer your question, we feel that we've got a very, very significant exploratory land base in western Canada. If you look at where an exploration company would like to be in the western Canadian basin it would be in the primarily northern British Columbia in the deep basin area and in northern Alberta. And we have an exploration land base in northeast BC that's second to none right now, particularly around the area and south into and some of those areas. Our land base in the deep basin trends for our central area and north central area is very strong, as well. And in addition to that, we have a lot of exploratory land in northern Alberta. And then I talked a little bit about the amount of land and opportunity that we have in the plains. So we feel going forward that we still have a great deal of work to do in western Canada.

We also are not naive enough to believe that ten years from now we'll be exclusively in western Canada. And we are making an effort to look at other basins outside western Canada. Primarily, they would be North America, South America. And I think our move would probably be into a mature situation. And those of you that follow Pen West have seen our growth in areas like the area or Drayton Valley where we've gone into a mature part of the basin and consolidated and basically tried to breathe some new life into an area. And we feel we've done that successfully. And we feel we can carry all sort of ideas into other basins internationally.

Frontier right now is I think as you know the primary frontier areas in Canada are east coast offshore and the Mackenzie Delta. Both of those areas, the land position is fairly tight. So any involvement in those areas is what would be through an acquisition. Other than that, certainly, there's a large amount of land available north of Alberta and into the territories. And as you know, a lot of it is still tied up with

Bill, on the South America and North America thing, would you be looking - you say go into a mature area - but would you be looking at assets or more of a corporate type acquisition?

I think our preference has always been to buy assets rather than a corporation. But you know, we don't - we've never wanted to put a set of blinders on that would just limit us to an asset acquisition versus a corporate acquisition. If there's a corporate acquisition that made sense and would give us the exposure where we thought we had an opportunity to grow we'd do it.

Great. Thanks a lot.

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

OK. I had three more questions that we had at the annual meeting yesterday. So that was good, anyway - four more questions. And I'd like to thank you once again for joining us. And as I said before, if there's more details that you need, they're on our web site at www.pennwest.com. And on that web site as well are my phone number and Bryan Clake's. And if anything comes up we'd be very happy to answer any questions that you have. And thank you very much.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating. I ask that you please disconnect your lines.