Obsidian Energy Ltd (OBE) 2001 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by.

Welcome to the Penn West Petroleum LTD's fourth quarter year-end 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 the time for you to queue up the questions. If anyone has any difficulties here at the conference, please press star, zero for operator assistance.

I would like to advise everyone this conference call is being recorded.

I will now turn the conference over to Mr. William Andrew, President. Please go ahead, sir.

Thank you and good morning.

My name's Bill Andrew, I'm the president of Penn West Petroleum. With me in Calgary this morning are Don Rae who's our Senior Vice President, Gerry Elms, our Vice President of Finance, Bryan Clake, who many of you know who's our Vice President of Marketing also with Investor Relations of Penn West, Dale Miller, our Vice President of Engineering, Dave Middleton, Vice President of Operations, and Gordon Timm, Vice President of Land. And at the end of the session, there will be some questions by me. I may refer the questions to someone else. I will name them if I do that.

Purpose of this conference call is to review our 2001 results and provide an updated brief of activity at Penn West. Following the narrative portion of this call we will be pleased to answer any questions that you may have regarding the company. During the presentation, we will use Canadian dollars in the six to one ratio for conversion to barrels of oil equivalent.

Penn West is pleased to announce that we've generated record results for production, cash flow, and earnings during 2001. 2001 natural gas volumes increased by eight percent and crude oil and natural gas liquid volume increased by 20 percent. Of course, in the fourth quarter 2001, our own natural gas liquids production averaged 42,300 barrels per day. Natural gas production averaged 334 million cubic feet per day.

Although commodity prices were weak in the fourth quarter, our natural gas price for the year averaged 524 per thousand cubic feet. That was up by 11 percent from 470 per thousand in 2000. Oil and -- oil and natural gas liquid prices averaged $31.31 per barrel for the year. That was down 13 percent from $35.83 per barrel realized in 2000.

Revenues for the year increased by 13 percent and, for the first time, exceeded $1 billion. This record was achieved in spite of a 42 percent drop in fourth quarter revenues. That drop was caused by a weakness in oil and natural gas pricing. That more than offset our increased production levels.

Operating costs were up over year. The largest driver in increased operating costs or increased power costs in Alberta. For the year, our power costs were up by about 70 percent over 2000. The power cost our account for almost half of the increase in unit operating costs in 2001.

Increasing industry activity levels also drove service costs higher in 2001. And in addition, we increased our weightings in light oil and our production mix and continued to implement and recovery in the field.

These combined the facts increased our operating costs for to $5.05. Increased operating costs are offset by premium price realization for light crude and by shallow decline rates associated with our light oil property. For the year, operating costs represented only 16 percent of our revenues, reflecting the fact that our production was 59 percent in natural gas and 31 percent to light oil and natural gas liquid.

from operations in 2001 was $613 million. That was increase of nine percent over 2000 and a per share basis cash flow for the year was $11.72 basic and $11.36 diluted. Net income for the year was up by 10 percent to 425 million -- sorry -- 245 million -- glad I got that corrected -- on a per share basis net income for 2001 was 469 per share basic and 454 per share diluted.

Cash taxes for the year totaled $25.1 million. This was an increase from our initial estimates on cash taxes and that was due in part to lower interest rates than we had forecast and also due to reduction in our expiration and development program at the end of 2001. That was in response to the falling commodity prices. We also increased our weighting to acquisition expenditures in the second half of the year. And I think many of you know acquisition expenditures are viewed as lower risk in expiration and they carry lower write off rates for income tax purposes.

Capital expenditures for the year totaled $634 million. Largely included 401 million spent on conventional expiration and development and 233 million spent on acquisitions.

2001, we drilled 237 net natural gas wells and 97 oil wells for a success rate of 85 percent. The drilling program was focused on natural gas in our northern area and on crude oil in the central and plains areas.

Our acquisition spending was concentrated primarily in the second half of the year and focused on strategic acquisitions like sweet crude oil and natural gas in our core central area. These acquisitions will enhance both our area dominance and will also provide long life reserves of the company.

development costs for 2001 averaged $10.12 per on a proven basis. $9.64 per on approved plus probable basis. When we calculate these numbers, we include all of our capital spending for the year including -- as well as the normal items -- such items as line expenditure, seismic, and corporate capital.

Weak industry activity levels during the early part of 2001 lead to significant increases in costs for drilling rigs and services. In addition, we focus a significant portion of our expiration and development budget on shallow gas projects in Northern Alberta These projects historically have higher than average finding costs, but do provide long-life reserves. And while our finding and development costs of 2001 were higher than historical costs, we maintain an investment -- recycle ratio two . And this is due to our strong net backs of $19.87 per that reflects the premium nature of our natural gas and light oil production.

In 2001, we generated a return on equity of 24.9 percent for the year, again demonstrating our long-term commitment to financial discipline. During 2001, we continued to build our inventory of future growth prospects. We commenced our methane expiration and testing programs as the initial step in evaluating our extensive holdings with methane lines.

We also made the significant advances in the application of light oil enhanced recovery technology requiring the operatorship of the only carbon dioxide oil recovery project in Canada and we do believe that the application of this type of technology will increase significantly in the future as stiffer rules regarding admissions are imposed upon industry. land base in western Canada that covers some 3.4 million net acres of undeveloped land.

Our land base stretches from Northern British Columbia, Northern Alberta -- where we are aggressively pursuing new accumulation of natural gas -- through West Central Alberta -- where our focus is light oil. to re-continue to explore and develop reserves of heavy oil.

At the end of 2001, our bank debt was 556 million of the decrease of 34 million from the bank debt of 590 million recorded at the end of 2000. For the past two years, we've funded our growth entirely through internally generated cash flow. This is result strong balance sheet of a debt to 2001 cash flow ratio of .9 to one.

Currently, our production's approximately 310 million cubic feet of natural gas per day with 42,000 barrels per day of oil and natural gas liquids. As far as the future, for 2002, Penn West will target spending between 400 million and 500 million. The spending will be weighted on expiration and development focused on natural gas of the northern area, light oil in the central, heavy oil in the Plains. We will continue with our efforts in coal bed methane development and recovery technology while conducting an active expiration program spread fairly evenly over our land.

capital program for 2002 provides production growth while controlling levels of debt. In 2002, we expect power prices to be flat to down from 2001 and we expect that some of the cost pressures on industry will ease. As a result, we're forecasting operating of approximately 505 to 525 per in 2002.

Based on prices of 2150 U.S. per barrel, for oil and 350 per mcf for natural gas, forecasting cash flow of 400 to 450 million in 2002. Since our last report, we've added 70 million cubic feet of natural gas hedging for the first half of 2002. We've added another 90 million cubic feet of natural gas hedging for the second quarter.

Combining previous hedges with these new hedges, we are now -- we now have 50 percent of our natural gas production hedge in the first quarter of 2002 at an average floor of 340 per mcf an average ceiling of 350 per mcf. The second quarter, we've also had 50 percent at an average floor of 310 per mcf an average ceiling of 370 per mcf. The third quarter hedged volumes dropped to seven percent and fell further to two percent in the fourth quarter.

On the power side, we've got 20 megawatts per hour hedged in next four year -- over the next four years. That's with an average price of $56 per megawatt.

On the crude oil side, we now have hedges totally approximately 22 percent of our liquids production in the first quarter of 2002. Forty-three percent in the second quarter, 21 percent in the third quarter and seven percent in the fourth quarter.

Price in the on the crude hedges range from a floor of $18 to $19 U.S. per barrel while the ceiling is approximately $22 to per barrel. And if you want additional details on the hedges, our corporate presentation is on the web site, www.pennwest.com and it's got tables that outline hedging numbers in more detail.

Our hedging is very much weighted to the first half of 2002 and that should also mention that we don't have any hedges in place for 2003. Our corporate policy regarding hedging calls for hedging of up to a maximum of 50 percent of our production for terms of no greater than 18 months.

Going forward, in the absence of a large acquisition, we continue with a modest hedging program aimed at smoothing cash flow and protecting our capital-spending program. Our capital spending's reviewed on an ongoing basis and can be adjusted to respond to changing commodity prices or to pursue acquisition.

In summation, we believe that Penn West is a unique company in many ways. Our balancing natural gas and oil provides a cushion in times of weaker commodity prices. Our long life reserves provide the flexibility to select projects based both on long term value creation to short term financial impact.

We are committed to incorporating both technology and innovation in our quest to achieve maximum value for our -- from our properties for our shareholders. With strong commitment to community, to the environment, most importantly, we have the discipline to maintain a strong balance sheet and that will give Penn West the financial strength and ability to continue to go profitably.

I thank you for listening and if you have any questions, I would please to try and ask them now.

Thank you. One moment please. 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 touch-tone 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're using a speakerphone before pressing any keys. One moment please for your first question.

Your first question comes from from Goldman Sachs. Please proceed with your question.

Hi, Bill. Can you give us your thoughts right now on coal bed methane, how that's proceeding, and then secondly what you're seeing in terms of acquisition opportunities for you this year.

Sure, and the question was with regard to our coal bed methane and secondly on acquisition opportunities. The first part on coal bed methane, we've drilled two further wells in the first quarter. We've got the two initial wells on in terms of rates, they're -- when I spoke in New York a few weeks ago, I thought about the initial rates that we're seeing are in the order of 10 to 20 mcf per day with water and we expect that these rates will increase at least 10 fold as we -- as we remove the water.

The last two wells that we drilled are, you know, very similar in terms of the seams that we're looking for. They are quite a distance from our initial wells. When I say "quite a distance", the third well is about 10 miles distance and the fourth well is about 20 miles away from our first development. And we're just going to continue with the evaluation process. That involves drilling, coring, work on the cores, testing of the wells, and we will take it from there, but we're -- there's nothing that we've seen thus far that causes us to not like the project. We're very much going forward on this project.

Second part of it related to acquisitions and we did see a reasonable amount of products available in properties in the first quarter, as some of the large companies that made acquisitions in the last year-and-a-half are straightening up their portfolio. And we expect this to continue through 2002. In terms of pricing, absolutely. I think pricing is down from the levels of 2001 and from 2000, so we're -- I think we can achieve a little better number on what we're paying for acquisitions this year.

And Bill, just one other thing on the coal bed methane. Do you -- how many more wells do you plan to drill in 02?

Probably this year we will drill another half a dozen or so and then take it from there for next year. I know in the last year, or kind of before, what happened with the end of this year in terms of the prices going down that we were looking forward to being a little more aggressive on the coal bed methane in 2002, and basically, we just pushed that schedule back about six to 12 months. So we will continue with about a half of dozen more wells this year and then look to doing something much larger next year.

One other thing just on the the $4 to $500 million. Is that all and any acquisitions would be incremental to that or have you got an acquisitions that number?

We always put a small acquisition component, roughly 10 to 15 percent of our total budget in for acquisitions because we're constantly doing consolidation on our properties, so I think as anyone who knows the company knows that we have a lot of wells and we have a lot of properties and we tend to do an awful lot of consolidation work. And also consolidation not only on that we operate or have an interest in, but also consolidation within areas.

So we do -- we do put an amount in there. This year it's $75 million, which is roughly 15 percent of our budget.

Thanks, Bill.

The next question comes from from Brothers. Please proceed with your question.

Thanks very much. Bill, the costs look like they're in line and there's no reason to believe that there should be any adjustments. Should I -- is there any adjustments to the capital expenditures in terms of dispositions of facilities in 2001 that we need to make?

No.

OK. And some brief time ago, we had a conversation about the fact that Penn West uses two engineering firms to do their third party work. Could you just expand in this conference call, in this question period, as to what the reasons are to do with the number of and the costs associated?

Sure. When -- a little history lesson. I hope I don't bore you to death, but when we started at Penn West, we had a very small engineering firm that we inherited. We then went to, at the time, the firm of , which is now and then a switch from there to . And did our reserves for a number of years -- and Associates.

In 1999, with the acquisition of the assets from Amoco, there at the tail-end of the year when we completed the deal, in terms of timing, we just went with who had done the reserves for Amoco previously -- or previously. And we've been -- and roughly now, they do about half of the -- half of the reserves a piece and we're happy with that arrangement in that we have a tremendous amount of properties in the company.

We operate or we have an interest in some 200 plus properties and, my belief is that you get a better job done with two companies concentrating on fewer properties than bogging them down with some 200 odd properties to look at in one firm. They're both extremely competent third party engineering firms, so I do not have a problem with the arrangement and we've been very open and straightforward with our investors with -- in that regard.

One of the key questions, though, and you can only answer this notionally, but if you were to take the assets that are currently evaluated by and give them to and take the properties that are currently evaluated by and give them to , I mean obviously that would be a silly thing to do in terms of the cost of making that change, but would there be any material changes in the reserve -- proven reserves, do you think?

No. Because as part of consolidation, we -- part of our consolidation, we took a number o -- a couple of properties that -- had done and gave them to . There was no material difference. And the same is true the other way.

We acquired a property in the Plains that had evaluated, gave it to and there was no material difference. And again, our reserve committee -- independent reserve committee of the board has asked the same question of the engineers the last two years in a row and have effectively response has been that there would be no change in the way that they evaluate and there should be no change in the bottom line.

That's excellent, Bill. Thank you very much.

Thank you.

Your next question comes from from and Company. Please proceed with your question.

Hi, Bill. Just a couple of quick questions on reserves. Could we get reconciliation or continuity sent out, I guess electronically or otherwise, rather than going through it? And I just wanted to touch on any revisions, either up or down, of any significance on the properties. And then two other ones that I will let you go at. An update on your Q1 activity and then what's the cash tax forecast?

OK. And I will reserve the last one to Gerry Elms, who is our VP of Finance. Basically on the reserves there were -- there were no revisions -- no significant revisions. They would be in line with the revisions that we took last year which were very minor. There were so many questions, Bryan, I forgot the other ones. I think it's old age.

Sorry, Bill. I would like a reconciliation -- the press release ...

Oh, certainly. We can do that.

... do that, if we can ...

I got that on my desk Monday afternoon and we will have that out to you. There's no problem with that.

OK. Great. And then just a cash tax forecast because these things can bounce all around -- I will let you defer that. And just an update on activity -- the work that's been the number of wells and what you're seeing there.

Yeah. I will ...

I will let Gerry answer the question with regard to activity. In terms of the first quarter, our primary focus was the area. And the has been an extremely good project for us. We concentrated this year mostly on new leads we developed in 2001 and they were leads primarily in the Mississippi and it was some distance from our initial development development in , which was in the .

We had very, very good success this year to fall off on our expiration last year. We anticipating adding about 40 million cubic feet per day to our project and that would take our production rates up to the range of 90 to 95 million cubic feet per day of sales . And primarily the new -- the new ads are coming from the Mississippi .

In terms of size, the initial -- the initial field developed was the . It's well on its way to producing reserves -- marketable reserves markers in excess of 100 bcf and we seal up the second phase. It's not one single pool. It's several good-sized pools. We will provide reserves at least equal to the and perhaps larger. Yeah, was on the first quarter. Again, we shift our emphasis from 2001.

2001, we did an awful lot of work in shallow gas in our north to take advantage of the -- of the prices and to try and achieve some measure of quick pay out on our project costs and the . This year, we focused on primarily on carbonates -- not only in , but also in the entry of the Area in Northern Alberta.

We're well underway with developing a number of trends there, in terms of expiration and production. We will be putting the initial phase of production this year and we anticipate of about 15 million cubic feet a day from the area. The rest of the quarter, we did some work in Pembina.

We started, or continued with a little bit of a horizontal program that we've got going on a couple of our leases. Results to date look very good, but we'd like to -- we'd like to get a year or so production on the wells before we really get overwhelmed by a lot of horizontal wells. We believe that to a lot of the work that we're doing on enhanced recovery will provide additional oil from that field.

Our heavy oil area and our shallow gas area in the Plains area we get a limited amount of work in the first quarter drilling about six wells, but we will pick up the pace, somewhat, through the summer. We will be concentrating primarily on heavy oil through the summer. We've got amount of land there and my to drill some of the prospects that we have and to continue with the development in the area. And I will let Gerry go .

Hi, Brian. It -- for 2002, we're look at estimating around about 10 percent of our pre-tax cash flow. Probably around 40 to 50 million .

Thank you very much, guys.

Thank you.

Your next question comes from from Raymond James. Please proceed with your question.

Good morning, Bill. Just a couple of questions. One is, could you sort of just talk about where your current production is. I suspect it's probably not different than Q4. But could you also remind me of what kind of heavy oil you have and what percentage of your reserves are heavy oil right now?

Sure. In terms of our current production, basically, it could take a decline in our gas. It's basically just decline. We haven't added any gas yet in 2002 in terms of production. Most of our production will be coming on the end of this month and very early in April, but we're about 310 million cubic feet a day of natural gas right now and the same with our oil. Our oil drilling has been very minimal.

The start of the year, we will pick the -- pick up the pace second quarter. We're producing roughly 42,000 barrels a day right now natural gas liquid. Our heavy oil production -- when we talk heavy we -- I always like to qualify it a bit. What we call heavy oil has an average gravity of about 16 API and that type of oil in the company right now, we're currently producing about 9,000 barrels per day. In terms of percentage of the reserves -- it's less than 10 percent.

The last question is that if you had to look back into 2000 and look at your decline rates for liquids and gas and compare to where you ended the year in 2001, can you sort of give us a rough idea of how that might have changed. Because I know you're drilling more gas in that northwest area where it has probably a little higher decline rate than what you're, you know, west central area has traditionally been.

Yeah. Corporately, our decline rate has remained fairly constant at about 18 to 19 percent for the combined product. But the mix has changed somewhat and you're correct in our change from 2000 2001. We've seen our decline rate on natural gas go up from about 23 to 20 -- roughly 24-and-a-half or 25 percent.

Our decline rate on oil was a little bit over 15 percent and now it's slightly under 15 percent, so -- corporately there haven't -- there've been very little change, but on the gas side, there has been some increase as we're bringing a new gas on. That's certainly a challenge by the industry is to replace the -- replace their gas production on a daily basis plus also attempt to add gas reserves.

Thanks a lot, Bill.

Thank you.

Ladies and gentlemen, if there are any additional questions at this time, please press the star followed by the one. As a reminder, if you're using a speakerphone, please lift the handset before pressing the keys.

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

I'd just like to thank everyone and my telephone number in Calgary is area code 403-777-2502. The fellow usually travels with me and you're talking to a great deal is Bryan Clake. He's at 777-2510 in Calgary. And I'm sure if there's any questions that arise, we'd be pleased to answer them. And I will again refer you to our web site which is www.pennwest, all one word, dot-com. And there'd be more details on the Web site. Thank you very much.

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