Obsidian Energy Ltd (OBE) 2003 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 the questions and answer session. Instructions will be provided at that time for you to queue up for questions. If anyone has any difficulty hearing the conference, please press "*" "0" for operator's assistance at any time. I would like to remind everyone that this conference call is being recorded. And I would now like to turn the conference over to Mr. Bill Andrew, President. Please go ahead sir.

Thank you very much. Good morning everyone, welcome to our teleconference call. The call is also available on our website. The website is www.pennwest.com. My name is Bill Andrew, and I am the president of Penn West. With me today in Calgary is the rest of the management team at Penn West. I won't introduce them. We have been introduced them before, but I may seek their advice on some answers that you may have later.

The purpose of the call is to review our 2003 first quarter result and also to provide an update on our recent activities. Following the review and the update, we will be pleased to have to answer any questions that you may have. Throughout the presentation using Canadian dollars, unless otherwise noted and our production volumes include the Crown Royalty share.

Penn West generated very good results in the first quarter of 2003. We achieved new records in first quarter liquids production, natural gas production, cash flow, and net income. During the first quarter, average daily natural gas volumes increased by 5% from the first quarter 2002, that’s from 313.3mmcf per day up to 328.2mmcf per day. Crude oil and natural gas liquids average daily volumes are up by 10% and that’s from 42,021 barrels per day up to 46,421 barrels per day. The total production in the quarter averaged 101,125boe per day that’s an increase of 7% over Q1 2002. Currently, we are producing approximately 108,000boe per day and that’s weighed about 57% to natural gas, actually a little bit over 57% to natural gas.

We achieved record financial results during the first quarter with cash flow of $230m, and earnings $136m. Cash flow per share was up 140% over the first quarter of 2002 and that’s from $1.79 per share up to 4.29 per share basic. Earnings per share increased by 425%, 48 cents per share to $2.52 per share basic. Excluding the unrealized foreign exchange gain our net income was $106m or $1.98 per share. Operating cost in the first quarter, $6.25 per boe and that’s inline with our yearly estimates, actually it is under our yearly estimate of 640 per barrel -- not continue to beat that estimate for the rest of the year. These operating costs were up from 539 per barrel equivalent to first quarter 2002. It's basically because that we have light oil enhanced recovery and higher rating in crude oil and production mix also due to the number of property that we brought in later half of 2002 that Dave Middleton and his production crew are still working on to produce operating cost, and we are succeeding in -- we will have some more good news the rest of the year on that. We generated an after-tax return on equity of 31% during the first quarter of 2003 and December would have been even higher. It included provision for unrealized foreign exchange gains. For the past decade, our average return on equity has been 16%, and we anticipate that we will beat that number in 2003. We are looking at something in excess of 18% for the year. Cash taxes for the first quarter of 2003 totaled $18m, that’s an increase from about $10.5m in the first quarter of 2002. For full year 2003, we are forecasting cash taxes worth total $60-80m.

Our net tax in first quarter was $28.31 per boe that reflected a strong natural gas price and crude oil prices. Natural gas prices increased by 131% year-over-year to 743 per mcf in the first quarter while liquids prices increased by 50% to $41.34. At the end of the first quarter of 2003, our bank debt was $544m. The majority of the bank debts approximately $340m U.S. -- is in U.S. loans. This U.S. debt positions could lead to additional exchange gains in the second quarter of 2003 and throughout 2003. We maintained a very strong balance sheet. Current debt annualized first quarter cash flow ratio was 0.601. Our capital expenditures for the first quarter of 2003 totaled $251m. The majority of that was spent on conventional exploration and development. We only spent $5m on acquisitions. Due to the strength of the acquisition market, we recently put out a package of properties -- minor properties that include approximately 3,800 barrels of oil equivalent per day and that’s been out on the street for about a week. We are looking for bids in mid June with closing through the summer.

During the first quarter, we drilled 284 wells. The success rate was 76%. I think you will notice that the success rate is down from last year where it was in excess of 80%. Basically, this is because of the type of program that we did in the first quarter. We did quite a bit of work on exploration wells and drilling in the northern area. This rate is just not as high when you do a program that’s more weighted to exploration. We did as I talked to a concentrated program on natural gas in Northern Core Area, as the main development area was our Wildboy play.

We continued to drill for light oil in central area, and we also focused on conventional heavy oil and some gas exploration on the plains. The Wildboy project is very notable example of our ability to explore core to develop natural gas, 100% working interest play that we have brought up from the grassroots, and I know many of you have followed this play over the years since we started on it. In 2002, we completed our fifth expansion phase of Wildboy and took production to over 80mcf a day. Current production with this winter’s [inaudible] tied in now is approximately 110mcf per day. And as this field is grown, over the past five years, we are one of the major producers of gas fields in Western Canada and we have got a hell of a lot more we can do in the area. We have only looked at approximately 15-20% of the land to date. We still have a lot of exploration to do, and we are confident that that will lead to a lot of development. We still have significant amount of development to do on the areas we have already delineated, but basically the work is to continue the exploration on the un-drilled portion of the block while capturing the gas reserves that we have delineated and that are in close proximity to our pipeline system.

In terms of light oil, we are pursuing the potential CO2 miscible flooding in our Central Core Area. This is a proven technology particularly in the States. Studies indicate that our Cardium oil reserves -- Cardium oil pool is as good as anything they are working on in States currently under the miscible floods. So we're very confident that the technology will work. Based on the US model a CO2 injection increases, increased recovery by more than 25% and because as Canadians are by nature very conservative. Reviewed estimates of up to 15% for incremental recovery for an average increase of 7, but we understated that number just to keep just to keep -- just to be modest I guess. Main challenge to the economically viable CO2 flood is access to a low price stock in CO2. And we're currently working with some large industrial bidders in CO2 in Alberta. In fact we have signed up confidentiality agreements with a number of companies. And for that reason I cannot go into a lot of detail on the particulars of the CO2 supply and we are continuing to build our expertise in operating miscible floods.

As you know we operate the only CO2 miscible flood in Alberta, one or two in Canada. We also operated hydrocarbon miscible floods at Saskatchewan Hills and have a significant working interest in miscible flood operation in Virginia Hill. We feel that the price is very large and comparable to projects that are being under -- otherwise projects that are being undertaken in Alberta currently in terms of finding cost per barrel and operating cost. We're also in the unique position to generate a win-win solution with the large [inaudible] involving the use of CO2 to enhance the late oil recovery. And we cannot understate the significance of this work to the increase in our reserve base. We also got a very expensive holdings to uphold that methane right primarily in the [inaudible] is about approximately 400 sections of land. I'll just update you on where we are there. We currently have 3 wells non-production from the initial round of about 8 wells that we were working on. This year we're going to continue with work on about a dozen more. We are confident now of the technology for completing these wells and also in our flexion criteria, which seems to graph in what sort of completion technique to use.

Now we are at the stage where we are delineating the commercial areas or number of commercial areas. Next phase over the next year or two we will be to start to develop these areas. The challenge with coal bed methane is to get the capital cost in line with the expectations that you have in terms of the reserves per well and the production per well. We look at it as very close similarity that the shallow gas in Southern Alberta, Southwest of Saskatchewan until we have to get our cost basically in line with those sort of costs to make it a worthwhile project.

2003 our capital spending level will be between $550m and $650m with a balance between drilling acquisitions and some new technology through coal-bed methane and CO2. We will wieght a lot of the spending to conventional exploration and development focus and we've already focused on the natural gas -- a lot of natural gas is found in Northern area. Some of the light oil will continue with the light oil through the summer. And also in the summer we will focus very much on heavy oil in the plains and also shallow natural gas in the plains area and in the Southwest Saskatchewan.

We are basing our cash flow estimates of $680m-720m in 2003 on price assumptions of 2750 US per bill WTI, 620 per mcf that's at the Plant Gate at Alberta plant -- at our plant gate and average exchange rate of 70 cents. Does this mean that the proposed capital program for 2003 will be funded entirely through internally generating cash flow? Since we expect the cash flows could exeed our capital expenditures we have initiated a Normal Course Issuer Bid, -- Issuer Bid calls for a purchase of up to 5% of the outstanding shares in 10 less to date and we purchased 406,000 shares that going to cost approximately $15.6m.

We remain very bullish on natural gas pricing and we've hedged only 14% -- 14m cubic feet per day of natural gas and that is under a collar of -- that’s 680 by 1010 for the period of April through October 2003. We are inside the bore and ceiling on that collar right now. Crude oil side we have hedges in place totaling approximately 42% of our liquids production first half of 2003. And we are unhedged currently in the second half -- for the second half of the year, although we are looking at possibly putting in some hedges for the second half of the year. The hedges that we have in place are collared and they range from floor of $23.40 per barrel U.S. to a ceiling of $29 U.S. per barrel WTI. If you want more details on the hedging, it is included in our corporate presentation which is on our website and we have tables for finding the hedge numbers and forecast in more detail. And also on the website, we have got the normal sensitivity information and also the cautionary note on some of the forward-looking statements.

Going forward in the absence of a large acquisition we will continue with the modest hedging program and excluding cash flows checking our capital spending programs. Our capital spending programs is reviewed on an ongoing basis and we can adjust that to respond to the change in commodity prices or to pursue an acquisition or acquisitions as they may evolve. In summation, we feel that Penn West is a unique company in many ways with our balance between natural gas and oil that provides us with a cushion in times of these commodity prices. We have very long life reserves and we have very shallow decline particularly on our oil property, and we feel that this is -- will lead to long-term value creation for the shareholders of Penn West. We also have a lot of good projects and we're working on that will help with short-term financial impact also for the shareholders.

The future – the future looks very bright right now and continues to look bright. We've got a lot of prospects. We got a lot of work that we do. We've got almost 5m net acres now of exploratory land that we are working on and then will continue to work on. We have been at it now for a little over 10 years. Over those 10 years, we have put our faith in our ability to generate prospects, to seize opportunities, and to maintain the levelheaded approach to business. We see more opportunities right now than we have seen at any time in the past 10 years. And for that reason we are prepared to continue to push this company on into the future. I would like to thank you and we would be pleased to answer any questions. We understand the operator will queue up the questions.

Thank you sir. One moment please. Ladies and gentleman we will now conduct the question-and-answer session. If you have a question, please press "*" "1" on our touchtone phone. You will hear a three tone prompt acknowledging your request. The questions will be pooled in the order that they are received. If you would like to decline from the pooling process, please press "*" "2". Please ensure you lift the handset if you are using a speakerphone before pressing anything. One moment please for your first question. Your first question comes from Greg Alexander from Ruin Cullet(ph) Please go ahead.

Hi Bill congratulations on the quarter. Listen I just wanted to ask you a couple of things. One, could you roughly guestimate your finding cost for the quarter?

Yes roughly it is in the – that would be in the $13 range.

Okay. And…

And we expect – we are just changing to buy land in the second quarter. So second quarter we won’t do much to help that number, but certainly through the third and the fourth quarter as we get working primarily on the plains wells and then the heavy oil wells, we'll work to keep that number in line.

Okay. If we look back some years in the future if the CO2 flooding and so forth works, but it turns out that these would be restated downward or do you think that's just the range?

I didn’t follow you – go ahead.

Well if your – if the stuff like the CO2 flooding works and various things that you may be not booking now do you think these costs might end up being restated downwards?

Yeah. There wouldn’t be any -- there wouldn’t be any impact on the current cost. But certainly with the CO2, once we've started booking [inaudible] users. We're looking at cost for the CO2 on a per barrel basis that would be less than our average finding costs last year. And certainly the infill well, infill work that we've got scheduled for areas like Pembina would be less than last year. And I think increasingly you are going to see -- we're very -- our ratio of heavy oil to light oil and our ratio of heavy oil production to the total production of the company is small, compared to a lot of our -- I guess what I'll call there, peer group with the rest of the operators in Western Canada. And so for that reason we're going to focus a little bit more on heavy oil. And my feeling is that that'll drop the finding cost down somewhat as well.

Okay, secondly the G&A and operating cost are up nicely. I just wanted if you would venture what proportion of the higher operating cost are just due to higher gas prices and so forth? And then what -- just a few words, take a moment to explain, you know, you must beefing up perhaps your overall staff on the G&A side and how your thinking about? You know what that means to the company and hopefully what you are doing there?

Yeah. Part of the G&A -- part of the G&A side is -- we still have very low G&A.

Yeah.

Certainly on a net basis i think one of the lowest, if not the lowest in Canada.

Yeah, I am not criticizing, I am just asking.

We -- part of the increase last year was in response to the fact that we did -- we have issued most of our options to date. So you look at other ways to compensate your employees and then it usually ends up being through a bonus or through an increase in salary, and that's reflected on the G&A side. We are -- we continue to staff up. We're not -- we are not hurting in any particular area as with any exploration company in North America. We are always on the lookout for a good geologist or a good geophysists or a good keen young engineer to come in at the company or a marketing person. But we are pretty well -- know we're pretty well fixed staff wise.

In terms of the operating cost themselves, continued pressure through -- we had a lot of pressure in 2002, particularly on the electrical -- cost electrical power for a lot of our fields. And that -- that is what added a very decent sized component to the operating cost. That is portion of the operating cost where -- and I can't understate this is the fact that we did purchase significant amount of oil properties in the last half of 2002. And in the market that we have today, a lot of the properties that are available need work on them and particularly need work in trying to optimize the production and also trying to reduce the operating costs. Because generally they are coming out of companies that put them on the market, because of high operating costs or lack of attention.

So we have proven that we have been good in the past that's taking all types of properties and putting the attention to them and also bringing down the operating cost, and then increasing the efficiency of the properties. So we are confident we are -- we are happy with the first quarter operating cost. As always, we are trying to reduce them but the fact that we are under budget -- we have anticipated that the op cost would be above 640 and it came as 625. So we are quite -- quite pleased with that and we are going to continue to work to reduce it.

So could you speculate what you are trying to think op cost would have been up, you know if energy prices and electric prices had been constant? You hadn't bonus to staff or--?

Yeah. We increased -- we increased electrical cost adds somewhere, I guess depending on the day somewhere between 65 cents from $1, a barrel to our op cost.

Okay. So if you -- we took the existing old projects and took out the electricity would they be up much -- like you know, would they up double digit or not?

It would be up somewhat.

Yeah, okay. Can I ask one last one? Canadian dollar -- have you -- have you -- where -- what are you thinking about that; it's gone up a lot? Do you have any hedges and--?

Yeah, we have a gain on the foreign exchange and through a hedge with a dominant Canadian dollar. And its good news and bad news, the good news side that this gain on the foreign exchange; the bad news side is the when you’re trying to market crude oil in US dollars it’s a reduction in the amount of cash that’s comes in. So, we put those numbers in their sensitivities, it’s a [inaudible] wash.

Do you have much of a hedge or -- as high from the US debt or what’s the US debt that has?

No, we've got to hedge which matches the amount of US debt.

Okay, thanks a lot.

The next question comes from Stephen Calderwood from Raymond James. Please go ahead.

Good morning, thank you for taking my questions I have a short-term question and a long-term question. In the short term, normally you have a huge ramp up in gas production in the second quarter, in order to meet your average target for the year. And this year looks like it's no different, except -- you had some lower than expected -- which had lower success rates of drilling in the Northern area, your primary gas area. And you also, I think, had shorter season, could you -- maybe expand a little bit on the difficulties that you saw this winter? And how it looks in terms of your building, your gas production for the reminder the year?

Yeah, basically on the gas, and I have always taken success numbers with a grain of salt, depends on type of wells you’re drilling -- we didn’t drill a whole lot of shallow gas. And shallow gas well is a success, whether it makes 20mcf a day or 220mcf a day. We count that -- to concentrate our development drilling more on the deeper zones, Mississippi and then below. We did, as I said, quite a bit of exploratory work. So even though our success rate is down, I say the quality of the wells that we drilled -- the quality of the development wells that we drilled look better than we have done in other years. And we didn’t lean as much on shallow gas, as we have on previous years.

Excellent, excellent. Okay and if I may, I mean I have a couple of questions related to carbon dioxide, but I’ll just ask one. In relation to the landmass that you have there at terminus A; it's, you know, 10 townships of net Penn West or lands that Penn West have an interest in over the Cardium, what percentage would you say would be appropriate for CO2 injection by growth; how much of it?

Well probably 75% of the land, the stuff that would be a little bit tougher would be -- I'll get specific to -- our area in the Pembina Cardium stretches from just north of Rocky Mountain [inaudible] to the Carrot Creek and then the Cyn Pem area. And then the areas to the North Carrot Creek and the Cyn P area have generally got a conglomerate associated with them. That would probably -- we think that would prove to be less desirable for CO2 flood, than the main body of sand that we have in our main units in the Pembina field. So the units that we have that are primarily sand without a large conglomerate component above them, would be the best suited and that would encompass about 75% of area.

Great and help me understand, I mean, I can’t get away from asking this one last question. On the timing of the pilot project for the CO2, is it more driven by the availability of CO2 in terms of having a smooth transition from a pilot to a more commercial project; or is it -- are you waiting because you have to drill more infill wells and prepare the areas for the pilot?

No, we’re -- I think it's just being said of the normal modus operandi of Penn West, we -- I look at it as much as the same as Wildboy. Wildboy, our first foray in there was the winter of 94-95, we had our first production 1998, and we just pushed it up since then. So we tend not do things that are -- I mean tend not to get over anxious when we do things. So basically what we have done at Pembina and we have had -- we made our first and a major move in the Pembina in 1999 with the acquisition of the BP Amoco assets. They need to consolidate over the next year and half and so it's really been in the last year that we have looked at the miscible flood and we, again, we've taken the steps to get up to speed, get our staff, -- get the right staff and place the company. We made some acquisitions in the late 2002, put this operative couple of other miscible flood in the Joffrey and in South Swan Hill, and basically it is taking that technology now and applying it.

So, we have gone over the past year and half, year to year and half, we’ve gone over alot of the [inaudible] studies that we were done in Pembina. Originally the field -- they looked at -- the original operative looked at [inaudible] miscible flood in the area. Not the time, there wasn’t -- there is a lot of places to drill -- the lot of places to look for oil in North America, so there wasn’t a great emphasis although the scientists where studying it. So, we have gone back and taken that information. We re-looked at the studies and sent studies to consults, to look at and compare what they think about various areas of Pembina with lot of the areas in North America. They come back with very positive indications on our pools up there and we are at the point right now where generally, you do you geological work, you do your engineering works and then you want to do your pilots and that's what we are going do this fall. So we are planning on one or two pilots in the area, possibly two. It will be done with CO2 that’s trucked in and we will be looking at the issues that are -- that face all of the operators in North America on CO2 and that's control of where the CO2 is going in your flood.

Basically, there is a type of timing you've got to breakthrough. How you are going to time your various cycle between the gas phase and the CO2 phase, the water phase in Shallow and you want to do that for about a year to two years in that time. Our partners on the other end will be putting in the infrastructure for capturing CO2 and then by then will be ready to roll and when we roll we are not going to roll on the small scale, we are going to do at big scale -- several big scale projects in the area.

Excellent Bill. Thanks a lot.

Ladies and gentlemen if you have any additional questions at this time please press "*" "1". As a reminder, if you are using a speakerphone, please lift the handsets before pressing any keys. The next question comes from Mark Heim from Yorkton Securities. Please go ahead.

Hey Bill. I was wondering if you can comment on the size of the pilot project that we would be looking at?

Yes, we probably are looking at some [inaudible] section, two sections in each one of them. Basically, we are looking at most of the areas where we operate, most of the areas. Although, lot of the areas were 100%, so right now we’re keening at two properties that we have a 100% interest in and around a section inside for each one.

And what's the typical time and response, is it basically, somewhere in 6-9 months range before you see an impact of the flood on volumes?

It’s usually under 6 months

Six months, alright. And just with respect to current production volumes, you stayed around 108,000. Is there anything behind pipe still?

No, not much. There is -- we have got some branded oil wells in Saskatchewan and they are waiting for [inaudible] on but that’s not a huge amount of volume and we got some gas wells as well as to tie on the Alberta/Saskatchewan border. I would think, you know, maybe there is 500 barrels a day, but no more than that.

Alright. How is weather going to impact like getting back into the field with essentially, you know, Lake Saskatchewan here on heavy oil program. Do you see any impacts on the potential for second half production volumes?

I don’t think so. I thing once we get going we can ramp it up pretty good, we got our rigs lined up so. Yes, I think as everyone is aware I hope they are aware that we had lot of snow here in the west -- in the southern part of Alberta and in southwest Saskatchewan, so road bans are still on. They are usually not off until the early part of June from what we are hearing that may be delayed by a week or so, but it shouldn't - as long as the weather holds you through the summer, which should be alright. One thing about Eastern operative Saskatchewan, it dries almost as fast as it gets wet so there shouldn't be a major problem. And we haven't had anything too extraordinary in the rest of Alberta. We expect fairly normal timing throughout central area.

Alright, actually one more question back to the CO2. Is there any -- have to be any capital requirements on upgrading any other production facilities with respect to CO2 or can they currently handle?

No there has to be. What we are contemplating right now is taking at very high pressure gas. One of two things, but that's to happen. One, that the pipeline system going into Pembina, will have to be very high pressured or fairly high pressure pipeline. Second thing if the pressure is little lower coming in we again have to put some additional compression to handle CO2 for injection. And also the wells that are used as injectors, you have to change the tubulars up. And we've included that in our frocast. We've been aware of that.

Alright great that’s all Bill.

Your next question comes from Greg Alexander from Ruin Cullet(ph). Please go ahead.

Hi, I thought of two more. First of all how are you feeling about the whole Kyoto type stuff these days or is it just to up in the air? And then secondly if you felt there was -- not indiscrete to talk to about how you are feeling about just whatever dewatering, has [inaudible]

Okay, on the Kyoto side obviously we are moving - as a country we are moving forward on that. That’s I think provided the impetus for us, we have always felt that we have good pools [inaudible] recovery on. It helps when there is some pressure to capture CO2 from the large emitters. We are pushing ahead with that and the Kyoto seems to be pushing ahead. I don't think there has been -- the government had some fairly strong response, but it may be in light of what's happening on a global basis, but not as much attention on the Kyoto right now as there is on the situation in Iraq, in the Middle East. On dewatering [inaudible] basically we're looking at taking the water from the CVM wells and using them in the Cardium wells for pressure maintenance.

So, very different situation in Canada and that the water is not pumped out on the surface as it is on some of the areas in the US. So, there is not the ecological concerns. Yeah I have been reading about some concerns, from the farmers and ranchers and the people in the rural areas have about taking water out of the [inaudible] from these areas. They are quite removed from any of the [inaudible] that are used or for water in Alberta. [inaudible] used for water is generally up above these [inaudible], which shouldn't be any interference to water that is used for human consumption and for animal consumption.

But you feel alright, about how the wells are - I mean the wells are dewatering as the production comes along the way?

They are pretty well on track. We are going into a bit of an unknown as an industry on dewatering the wells in Canada. We have got some information from the U.S. wells, but we don't know exactly the moment when the water will back off and the gas will really take over. The wells are performing as they do in the many bases in the States, as we take more water out the gas rate continues to slowly increase.

Okay, thanks a lot.

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

Thank you all very much. If you have any additional questions, our phone numbers are on the website. Bryan Clake is back in the saddle again. He is at 777-2510 in Calgary, area code 403. I am at 777-2502, and I am on my way to Saskatchewan in a few minutes. So, I will try and answer anything or you leave a voicemail. If not, Bryan can help you up. Thank you all very much.

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