Obsidian Energy Ltd (OBE) 2002 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Penn West Petroleum, Ltd. Fourth Quarter and 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 that time for you to queue up for questions. If anyone has any difficulties hearing the conference, please press star, zero for operator assistance at any time. I would like to remind everyone that this conference is being recorded, and I will now turn the conference over to William Andrew, President. Please go ahead, sir.

Thank you very much. My name's Bill Andrew and I'm the President of Penn West Petroleum. With me today in Calgary, we got several of our officers: Don Rae, who is the Senior Vice-President of Exploration: Dale Miller, who's our Vice-President of Engineering and Operations; and Dave Middleton, who's our Vice-President of Production. Standing in for Gerry Elms, who's our Vice-President of Finance, is Todd Takeyasu, and he's Penn West's Treasurer. And unfortunately, Bryan Clake, who many of you know, who looks after our Marketing and also our Investor Relations, had a family emergency that came up and he's out of town. But our thoughts and prayer are with him today.

The purpose of this conference call is to review our 2002 results and to provide an update on recent activities with Penn West. Following this review, we would be pleased to answer any questions that you might have, or at least make our best effort to try and answer them. And during the presentation, we'll be using Canadian dollars and also six to one conversion ratio onto barrels of oil equivalent.

During 2002, Penn West achieved two important milestones. The first is that we completed 10 years of operations under the new management team at Penn West; we've been together since late 1992. The past decade has been confirmed the strength of our business plan; it's also demonstrated our commitment to financial discipline. Second important milestone was achieved in the third quarter of 2002, when our production surpassed the 100,000 barrels of oil equivalents per day mark.

During 2002, we generated record production results. For the year, average daily crude oil and natural gas liquids volumes increased by 13 percent, and average daily natural gas volumes increased by one percent. In the fourth quarter of 2002, our oil and natural gas liquids production averaged 47,273 barrels per day; natural gas production averaged 373 million cubic feet per day. Our exit rate for production was approximately 104,600 BOE per day. Currently, we're producing approximately 320 million cubic feet per day of natural gas and 47,000 barrels per day of crude oil and natural gas liquids.

Commodity prices were stronger in the fourth quarter of 2002. The natural gas prices averaging 526 per mcf, and that's up from 313 per mcf in the fourth quarter of 2001. Oil and natural gas liquid prices were also up, averaging 3566 per barrel in the first quarter, and that's up from 2358 per barrel realized in the fourth quarter of 2001. Weaker prices in the first half of 2002 impacted revenues with a year-over-year decrease of eight percent. But I think, as all of you know, prices did strengthen considerably in the latter part of 2002. As a result, fourth quarter revenues increased by 69 percent to 318 million, and that's up from 188 million in the fourth quarter of 2001.

Our operating costs in 2002 increased to 581 per barrel of oil equivalent. and that compares with $5.05 per barrel of oil equivalent in 2001. Parts of this change are - increase in operating costs attributed to our increased focus on light oil enhanced recovery and a higher weighting of crude oil in our production mix. Also, on the other side, those of you that have the detail on our press release will notice that our gas operating costs were up for the year as well. And that just reflects the tightening supply fundamentals for natural gas in North America and the resulting optimization work that we did in the year to try and keep as much volume on as we could. And the operating cost increases have been more than offset by strengthening natural gas prices and also crude oil prices.

For the year, operating costs represented 21 percent of our revenues. We generated an after tax return on equity of 13.2 percent in 2002, and that reflects the ongoing focus that the company has on cost control and on value creation. We anticipate that we will have a return in equity in the range of 15 to 18 percent in 2003.

Cash flow from operation for the fourth quarter of 2002 were $153 million, and that's a 98 percent increase over the fourth quarter of 2001. For the year, cash flow decreased by 24 percent to $463 million from our record of 613 million in 2001. That's due primarily to weaker natural gas prices and also due to the increase in operating costs.

Net income for the fourth quarter was up by 193 percent to $61.9 million. For the year, net income was 158.4 million, and that compares to 245 million in 2001. Our cash taxes for the year totaled 82 million, and that's an increase of $25 million - or increased from 25 million in 2001.

2003, we're forecasting cash taxes to be in the range of where they were in 2002 and our finite range is in about the 60 to $80 million level. Capital expenditures for 2002 totaled $573 million. That included 343 million on our exploration and developments in western Canada and another 230 million spent on acquisitions, most of that money was spent in the latter half of the year on the acquisition side.

During 2002, we drilled 197 net natural gas wells and 96 net oil wells. Approximately two thirds of acquisition spending was allocated to acquire a major property at South Swan Hills (ph). Most of the remainder was spent on our fourth quarter acquisition of assets in southwestern Saskatchewan and Alberta.

During 2002, we increased proven reserves by 3.7 percent, and that's to 360.8 million barrels of oil equivalent; that's up from 347.8 million barrels of oil equivalent in 2001. The first quarter of 2002 - and just to tell you where we - how we got to our reserve numbers or where we are today - we did scale down our gas exploration program in the first, 2002. And that was as a result of deciding to back down on our gas budget late in 2001 when prices were really starting to get soft. And as a result of the decrease in activity in the first quarter, we were unable to maintain our year-end 2002 gas reserves at the level of one year ago.

Year-end 2002, we have proven gas reserves of 897 bcf. That's a decrease of six percent from the gas reserves booked at year-end 2001. One thing that we did do during the year was that we cut our ratio of proven undeveloped gas reserves - I think as many of you will recognize - to proven gas reserves to 17.3 percent from the 19.7 percent booked in 2001. Proven reserves of crude oil natural gas liquids increased by 11 percent year-over-year to 211.3 million barrels, and that's up from 189.6 million barrels booked at year-end 2001.

2002, our finding and development costs were 1163 per barrel proven. That's an increase of 15 percent over 2001 and it reflects three things. Three things are the money that was spent to tie in the reserves of proven undeveloped gas, an increase in land and seismic budgets on the year - we increased our land budget significantly in 2002 to take advantage of the lower than normal land prices - and also reflect the increased cost of finding and developing particularly gas reserves in north America and in the area that we concentrate on for a lot of our gas in the northern part of Alberta and British Columbia.

Our net backs for the year were 1617 per BOE. For 2003, we're forecasting the net backs will increase to in excess of $20 per BOE. During 2002, we continue to build our inventory of world class assets. As I mentioned before, we did require operatorship of a hydrocarbon missile flood in the area of South Swan Hills (ph). With our growing proficiency in enhanced oil recovery, we do believe that there are many remaining opportunities for additional EOR projects in our land base - in our project base. And speaking about land, we now have land base in western Canada that covers almost 4.3 million net acres of unexplored land. And our land stretches from southern Saskatchewan and southern Alberta, where we primarily focus on heavy oil, and we got a secondary focus on shallow gas up through the west central Alberta and the Penbina Field is our primary focus on light oil and un-enhanced recovery and tertiary recovery, and then on up into the Peace River Arch and northern Alberta and northern British Columbia were our primary focuses for the exploration and development of new gas.

End of 2002, our bank debt was $598 million. That was an increase of 42 million from our bank debt of 556 million at year-end 2001. And as many of you know over the past three years, we funded our growth largely through internally generated cash flow. As a result, we have a very strong balance sheet with a debt to 2002 cash flow ratio of 1.3 to one.

Looking forward into this year, for 2003, we're targeting capital spending of between 550 and $650 million. We are through our first quarter of spending, which accounts for roughly 45 percent of our total for the year. And that focused on exploration and development, primarily of natural gas in the northern area. Secondarily in the first quarter, we did continue with our work in central Alberta in light oil and on heavy oil in the Plains. We also have continued on the cold methane (ph) development front and also on enhanced recovery, and we continued a very active program of gathering information on exploratory lands, both with seismic and with wildcat wells.

For the rest of the year, we are concentrating in two areas primarily. One is the Central area, and that's a continuation of our work on the Penbina Cardia (ph). We will be drilling infills (ph) and extension wells in the main fields, and we will also be continuing to implement secondary recovery in that field. Second area that will have a heavy concentration during the rest of 2003 will be our Plains areas. There are two primary targets there. One is heavy oil. The heavy oil will be mostly in southwestern Saskatchewan in and around our Hoosier (ph) plate and Dena Marson (ph), and that will be our bulk of our heavy oil drilling. On the natural gas side, we've got a large development project planned for the Esther Compier (ph) area and will continue with our shallow gas work at Wainwright. And we continue to launch a significant exoration (ph) program for natural gas into southwest Saskatchewan.

Based on prices of $27 per barrel WTI and $6 per mcf, a Canadian plant (ph) gate (ph), we're forecasting cash flow of 670 to 710 million in 2003. That's what we're anticipating that our entire capital program will be funded through during the generated cash flow. And since we expect that the cash flow will exceed our capital expenditures, we have put through a normal course, issuer bid to purchase up to five percent of our outstanding shares and we are pursuing that at the present time.

In terms of our hedging, we have 100 million cubic feet of natural gas that are hedged for the first quarter of 2003, so there's about another 10 or 11 days left on that one. We also have additional 14 million cubic feet of natural gas that we've hedged for the period April through October of 2003. And that hedge is on a collar; 680 is the floor and 1010 is the ceiling. And I'll step back a second. All of our hedges are on collars.

In terms of our - the oil side, approximately 42 percent of our liquids production is hedged through the first half 2003, and we have no hedges in place for the second half of the year. The average price of the collars that we have on that oil that's hedged is a floor of $2340 US prevail WTI at a ceiling of $2910 US dollars per barrel WTI.

On the power side - and power is quite a large component of our operating costs, particularly with the oil field that we operate, we have an average of 48 megawatts per hour hedged over the next three years. The average price that we've hedged out is just under $50 per megawatt hour. If you would need more details on our hedges, the corporate presentation is on our Web site. Our Web site is is www.pennwest.com, and we've got tables that outline the hedging numbers and some of the forecast in more detail.

Going forward, and in terms of our strategy with regards to hedging - and in the absence, assuming that there's no large acquisition coming up, and we don't really foresee one in the near future - we'll continue with a modest hedging program. And that's just aimed at smoothing out some cash flow and protecting our capital spending programs. We do review our capital spending on an ongoing basis and will adjust our capital spending to respond to changing commodity price or to pursue an opportunity and primarily an acquisition.

In summary and in closing, we do believe that Penn West is a unique company in many ways. We've got a great balance between natural gas and oil that provides us with a cushion in times of weaker commodity prices. We have long life reserves and provide the flexibility to select projects based on both long-term value creation and short-term financial impact. We have been and are committed to using a technology innovation to maximize the amount of oil and gas that we can get out of our properties, particularly on the oil side with our push into enhanced recovery, both secondary and tertiary. We maintain a strong commitment to the community and to the environment.

And most importantly, and what we've promised over the past 10 years, is consistency and discipline. We have the discipline to maintain a strong balance sheet that gives us the financial strength and ability to continue to grow profitability, and we've got the consistency that we stick to our program of attaining a balance between exploration and development and leading the company with lots of projects to pursue at any time. I thank you for your time. If there's any questions, I would be pleased to take them.

Thank you. One moment please. Ladies and gentlemen, we will now conduct the 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 that they are received. If you would like to decline from the polling process, please press star, followed by the two. Please make sure you life the handset if you're using a speakerphone before pressing any keys. One moment, please, for your first question.

Your first question comes from Brian Prokop from Peters & Company.

Morning, Bill.

Hi, Brian.

A couple quick questions. Just missed the current production. Did you say 47,000 and 320 on gas? Hello?

Yes.

OK?

Brian?

I'm sorry, 320 million. Is that what you said?

Three hundred twenty million and 47,000.

OK. Great. On ...

Average decline on our gas side is about 25 percent per year. So, you know, roughly two percent a month or one percent every two weeks.

OK. And just on the reserves reconciliation - I image that will be sent out shortly here - were there any significant revisions either positive or negative? And if so, where would those have been?

No, nothing significant. Basically on the gas side, there were two main revisions. Interestingly enough, not the type of revisions that you're used to. I think the type of revisions notice past few years have been bull (ph) - would just come on production and then they end up with a write down of the reserves as reduced expectation.

In both cases, these were mature gas fields. One at Minnehik-Buck Lake, where we are experiencing - started to experience some retrograde conditions. Without getting too technical, basically, retrograde means that the gas that's in the reservoir starts to go to a liquid phase in the well water (ph), and we're presently working on that problem by working on unloading the wells. And we're hoping to return those reserves. That revision was in the order of about 10 bcfs. The other similar size revision was in a non-operated field at Tangent and just on the performance of some of the older wells. Again, they just had some wells that started to load up; in their case, it was with water. On the oil side, nothing.

OK. And last question, the share buyback that you're pursuing, do I take that to mean that you have been in the market buying, or you're planning to?

We have been in the market, Brian.

Can you give a sense of how much; i.e. how much have you purchased? I mean, obviously you can only do two percent up to the point, but have you been aggressive?

We can purchase up to two percent. We've got significantly less than that purchased right now.

OK. Thanks a lot, guys.

Your next question comes from Chris Theal from Tristone Capital. Please go ahead.

Good morning, Bill. Two questions. The first is just your current production at 320 and your gas program up north, what do you anticipate exiting the winter, post spring break up Penn West volumes being particularly on the gas side?

I would think - recognize we'll be adding our new gas starting - you know, we were completing the tie-ins right now, so we'll just be starting this weekend to add some of the volumes. The major adds will come from Wildboy in the Boyer area, and they will be participating right now somewhere between the second and third week of April when they'll be on production. So, that puts us about three weeks down the road. So basically, our 320 number will be somewhere in the range of 300 - 300 to 310 by then.

Right. And in terms of anticipated additions, you know, are you confident in averaging somewhere around that 340 level for the year.

Yes, we're pretty confident in that level.

OK. And just a second point, do you have your an estimate of your year end tax pools and a split on the components?

Yes. I've got the large numbers. The total pools are 1.4 billion. And I'll let Bob just run through the ...

We have - we have tangible capital of about 441 million; cog P (ph) of about 853 million; CDE of about 129 million; and other of about two, 2.1 million - billion, sorry. For a total of 1.424 billion.

OK. Thanks, guys.

Thank you.

Your next question comes from Mark Himes (ph) from Yorkton Securities. Please go ahead.

Good morning. Just a couple of quick questions with respect to the capital spending program in 2002. I was wondering if you go have a rough breakout of how much was gas versus oil?

All of our exploration numbers, roughly 340 million that we spent on the E&D (ph) side - on the convention E&D (ph) side - the majority of that would be aimed at gas, both from our land acquisition point of view and from our - what we did with the drill bit (ph). It would be 240 million or roughly that we spent on acquisition - sorry, 230 million we spent on acquisitions. The bulk of that was oil. I would say the split would be roughly 180 million on oil and about 50 million on gas.

All right.

And I'm breaking it that way because some of the oil properties, we classify them as oil properties, but they do produce solution gas so ...

OK.

... associated with them.

I guess based off a rough estimation of your year-end gas reserves, it looked like you only replaced about 50 percent of 2002 gas production. Yet, your drilling - your natural gas net drilling was only down about 20 percent from 2001. Are you guys starting to experience significantly lower reserve ads per well on the gas side?

The easy answer is yes, though I don't think that's necessarily the correct answer.

So, how does this bode ...

It depends on - because you're dealing with a dynamic situation. So every winter, we don't just go back to the same pin cushion and put more pins in it. We, you know - some waiters (ph) were in different parts of the north, for example in the shallow gas portion in Boyer and in through that area, significantly more wells are required to add the same type of reserves that you can add in Wildboy.

In Wildboy, we did have an active drilling program for the year, and I'll say our results were fair to good. And then, we were experiencing the same level of adds that we've experienced in other years. Some of our effort in terms of capital was spent on reducing the amount of our proven undeveloped reserves. What we're seeing, obviously in the Plains area, if you're looking at the deeper targets - if you're looking at Manville and below, we're utilizing seismic and seismic has been utilized for that purpose over the past 20 years - you're certainly not looking at first generation targets. You're looking at second or third or fourth passes over the area. So, the targets are reduced somewhat in size.

That's balanced somewhat by the fact now there's an emphasis on new targets, mostly in the shallow gas area, in through the Plains area, particularly. So, west Saskatchewan and the eastern part of Alberta that's north of - north of the normal shallow gas area.

In the northern area, which is the other area we look for gas, we're still primarily on the first pass with regard to some of our deeper work. And a when I say deeper, up there from the lower Cretaceous through the Mississippi and down into the Devonian, so you're still looking at a lot of first generation targets. As we get in with more shallow gas drilling, particularly in the Bluesky up in Boyer, you're involved with more infill and extension drilling and that delivers less reserves per well. So, on balance for last year, yes, but year-over-year, there were less per average wells drilled. That was a reflection of - just more reflection of where we drilled than what we drilled.

So, it's fair to say then that the mix is a company is going to continue to get more exposed to - or sorry, levered to liquids or crude oil and finding developments costs on the gas side or liquid contingent to rise?

I think that's a good general statement for the industry, that we have not, as an industry, seen a lot of tremendous gas adds through exploration. But that may change. I mean, there's a lot of this basin that's yet to be explored, primarily in the northern part. And there could be some - and I think there very well be some significant gas reserves up there. But based on our past history and based on the last couple of years, it looks like it's getting more expensive to drill for gas - the targets, as I said - and some of the areas are getting smaller. So, I think you can take from that that it's getting more expensive to add gas. Liquids, we've got a tremendous list of prospects on the heavy oil side to add lots of new reserves there. And then, we also believe that we can add very significant reserves of light oil. That's primarily through extension drilling, infill drilling and the real key to the light oil reserves is enhanced recovery.

Thank you.

Thank you.

Your next question comes from Robert des Rogers (ph), Private Investor. Please go ahead.

Good morning. I wonder if you can comment on the availability of CO2 for a large scale flood program.

Sure. Currently - in western Canada - currently in Alberta, there's one source of CO2, and that's the NOVA core petrochemical complex at Joffre, and we're utilizing the CO2 that's produced in that plant for our projects at Joffre. At the current time, Joffre is the only CO2 missle (ph) flood operating in Alberta.

We spent an awful lot of time on the CO2 source. There's four main sources in Alberta. The first is the NOVA system, or the pipeline system within Alberta, and just stripping CO2 out of that system, basically removing any remaining acid gas out of the pipeline gas. There are such large volumes of pipeline gas that are going through that system that there's a significant amount of CO2 available there. It is an expensive process in that, not only would you want to get the CO2 out, but you'd probably want to do something with regards to the liquids that are still entrained in the gas and really clean up gas while you were doing that.

Second place is the - are the power generating plants - coal fire generating plants that are primarily in west central Alberta, west of Edmonton. Again, a little bit of an expensive proposition because of the constituents that are in the tail gas that comes out of the generating plants related to the source of fuel which is coal.

Third, and one of the two most likely sources for CO2 and one of the two that we've been actively pursuing is the petrochemical complex in and around Edmonton and primarily to the northeast of Edmonton in Strathcona County. There is a significant amount of CO2 being emitted right now from refiners and the petrochemical complexes. What would be entailed there is putting in a tail gas equipment to recovery the CO2 and then a pipeline down into our main field, which is Penbina, the distance of the pipeline roughly 120 kilometers. And we wouldn't anticipate a problem with that. And we're working right now with a couple of the producers or the emitters in that area to basically look at the costs of putting in the tail gas line.

The fourth source of CO2, and what we believe is the second most likely, are the oil fan operators in the Fort McMurray area. Most of their equipment with regard to their upgrade is - really avail themselves to the extraction of CO2. As you know, there's been an awful lot of work done over the past years in the oil sense (ph); a lot of the equipment is quite new. It makes it easier to modify, to capture the CO2. The difficulty is to get the CO2 from Fort McMurray to Penbina. But when you look at the totals involved in terms of expenditure, you could probably build a pipeline from Penbina to Fort McMurray and do the tail gas plant along the large upgraders (ph) up there for not significantly more money than you would spend going into the Strathcona area and capturing CO2 from the refineries or petrochemicals.

We do believe there's some good sources. Basically, we have to make it work for enhanced recovery, so we have to get the price of the extraction of the CO2 to a reasonable level on our end as the main (ph) user of the CO2. What's facing the other companies, particularly the refiners and basically any of the industries that have been targeted as large emitters, is to reduce their capital costs down to where it's competitive with the price of credit for CO2 right now.

Have you worked breakeven price for oil for any of these options to be effective?

Yes. Sure, and I'll just base it off - primarily off Joffre. There would be a modest increase to put it into Penbina. But basically, the breakeven point at Joffre is in the range of 20 to $22 WTI. So, I would expect Penbina would be in that range.

Have you looked at similar to what doing bringing CO2 in from the states in a longer pipeline?

Yes. We've looked at that option. We'd much prefer to provide a Canadian solution and work with some of the heavy industries in Alberta and try and kill two birds with one stone.

Now, is there a potential credit for CO2 being put away in the oil fields?

We're still in - we're still in discussion with both levels of government, both the provincial and federal. I think there's very good opportunity for credits for CO2 that we put away.

So the 20, $22 price is not including any potential credits?

No, and I've got a - I think we should talk about the operating costs related to a CO2 project, and that's basic the operating costs that we see in Joffre. Conventional mature light oil fields operating costs are in the range of eight to $10 a barrel. When you add a missable (ph) component on that, you can get costs up to the range of 15 to $18 a barrel. We need to provide as well a little bit of return on capital for what we do, so that's how I get to the 20 to 22. And that does not - 20 to $22 does not include a significant or if any royalty components.

OK. One other question, your heavy oil, is that light enough to flow through the pipelines without anything being added or do you have to add to it?

We add - we add a little bit to some of our - average gravity on our heavy oil is about 17 degrees API. A lot of it does flow through the pipelines. We do have to - we do have to blend it with condensate (ph) when we put it into the pipeline (ph).

OK. Thank you.

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 any keys.

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

I would like to thank you all and thank you for the very good questions that we had. Our press release is out. There's more details in there. My number is on the back, and as I talked about earlier in the telecast, that Bryan Clake is away and he'll be away for a little while. So, if you want to give me a call - area code 403-277-2502. If there's a detailed financial question, Todd Takeyasu is available. Just go through our main switchboard 777-2500. Thank you very much.

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