Obsidian Energy Ltd (OBE) 2005 Q2 法說會逐字稿

Welcome to the Penn West Energy Trust's second-quarter results conference call. At this time all participants are a listen-only mode. Following today's presentation instructions will be given for the question-and-answer session. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded today, Friday, August 5, 2005. I would now like to turn the conference over to William Andrew, President and Chief Executive Officer.

My name is Bill Andrew and I'm President and CEO of Penn West Energy Trust. With me today in Calgary is a little lighter crowd than usual. We looked around the table this week and realized that not too many people had taken any holiday; so I shooed a few people out of the office yesterday. Anyway, joining me this morning are Dave Middleton who is our Chief Operating Officer; Todd Takeyasu who is our Vice President of Finance; William Tang Kong, Vice President of Corporate Development; and Kristian Tange, our Vice President of Business Development.

On behalf of our staff, the management and directors of the Trust, I'd like to welcome any unitholders, the financial community, the media and any of the general public who are listening to our teleconference or who are wired into our webcast. Over the past month I've had the pleasure of speaking to numerous unitholders, both retail and institutional, and I encourage any unitholder with questions or other matters that require the attention of Penn West Energy Trust to please call and we'll do our best to help you.

For information on our Trust, please go to our website at www.PennWest.com. We've recently expanded our Investor Relations group to meet the needs of the Trust and we're in the process of doing the last few things, one of which is to install a couple toll-free lines for inquiries. The main purpose of this conference call is to review our 2005 second-quarter results and to provide an update on recent activities at Penn West Energy Trust. Following this review we'd be pleased to answer your questions.

During the presentation we'll use Canadian dollars and a 6 to 1 ratio for conversion to barrels of oil equivalent -- that's unless otherwise stated. As well, results for the second quarter of 2005 include two months operating as Penn West Energy -- Penn West Petroleum Ltd. and one month operating as Penn West Energy Trust. For this reason and for comparative purposes we'll be looking back to the second quarter of 2004 as a benchmark for this quarter even though we reorganized from an oil and gas exploration company to an energy trust during the last quarter and thus the results are not directly comparable.

In the second quarter of 2005 our light oil and natural gas liquids production averaged 32,011 barrels per day; conventional heavy oil production averaged 18,622 barrels per day for a total of 50,633 barrels per day. Average natural gas production for the second quarter was 296 million cubic feet per day. Total production in the second quarter of 2005 averaged almost 100,000 barrels of oil equivalent per day, 99,910 was the actual number. Production from the quarter was impacted by wet weather in western Canada, as many of you remember, particularly in the latter part of May and June and then by scheduled maintenance programs subsequent to the second quarter and production has increased to current rates of in excess of 101,000 barrels of oil equivalent per day.

Also during the quarter we entered into purchase agreements or properties that will add between 2,500 and 3,000 barrels of oil equivalent per day of production and these volumes will be added into our production after closing -- we're looking at about mid-August for the closing right now. They're not in the second-quarter numbers. In the second quarter of 2005 natural gas prices averaged $7.41 per Mcf, that's up 5% from the same period last year, and light oil and natural gas liquids prices averaged $59.05 per barrel, that's a 26% increase over the second quarter of 2004. I mentioned heavy oil prices were $31.22 in the second quarter of 2005, that's an increase of 3% over the same period last year.

Overall commodity prices averaged $46.66 per barrel of oil equivalent, that's up 12% from the $41.56 per barrel of oil equivalent in the second quarter of 2004. With higher commodity prices gross revenues in the second quarter of 2005 increased to $424 million and that's up from $390 million in 2004. Operating costs for the first half of 2005 were $8.70 per barrel; the increased operating costs were attributed to the increase in the proportion of crude oil in the Company's mix. We had been running at about a 50-50 ratio and through the first half of this year we're running about 52% crude oil, about 48% natural gas. The crude oil has higher operating costs associated with it.

Operating costs were also impacted by increases in cost of steel and energy and, I'm sure as many of you are aware, just the basic industry activity and demand for services that exists in western Canada right now. In excess of 60% of the Trust's liquids production consists of light oil and natural gas liquids. These products demand a premium price and have long reserve lives. The Trust is well positioned to absorb industrywide operating cost increases and still maintain strong operating net backs. Our net backs for the second quarter of 2005 were $29.60 per barrel of oil equivalent. These are comprised of averages like oil and liquids netback of $35.06 per barrel, average heavy oil netback of $17.57 per barrel, average natural gas netback of $5.10 per Mcf.

If you put all these things together, cash flow from operations for the second quarter of 2005 reached $257 million, that's a 22% increase in the same period in 2004. Our net income -- and bear in mind the activity that's going on in the second quarter with reorganization -- net income in the second quarter decreased from 66 million to 60 million from 2004. The cash tax provision for the first half of 2005 of 54 million was computed as if the trust conversion did not occur. The trust conversion on May 31, 2005 resulted in a short tax year that resulted in the acceleration of cash income taxes. Cash taxes payable in excess of the amount provided is considered an advancement of future tax liabilities.

Capital expenditures for the second quarter of 2005 total $99 million and that included 67 million spent on conventional exploration and development activity and $32 million spent on property acquisitions. In connection with a conversion to a trust we entered into a new -- a $1.2 billion credit and operating facility. The revolving bank facility is with a syndicate of banks and has a three-year term. Our capital program for the first six months of 2005 was funded by internally generated cash flow and by modest use of bank lines of credit. At the end of the second quarter of 2005 our bank debt was 576 million, that's up a little bit from 503 million at the end of 2004 and, again, that reflects some of the costs of restructuring here in the quarter.

Based on commodity prices of US$55 per barrel WTI for crude oil and 765 per Mcf of natural gas, we're forecasting after-tax cash flow in excess of $1 billion for 2005. The proposed combined capital expenditure for 2005 -- and that, again, five months as an E&P Company and the last seven months will be as a trust, we're looking at somewhere between $500 and $600 million. In the 2005 period prior to the conversion we paid dividends to Penn West Exploration -- paid dividends of 17.5 million. The Trust has established an initial target to distribute approximately 60% of cash flow with the remaining 40% reinvested in exploitation and development projects and also in acquisitions.

First monthly gas distribution in the amount of $42 million or $0.26 per unit was paid on July 15, 2005 to unitholders of record on June 30, 2005. On July 20, 2005 we announced the next monthly distribution of $0.26 per trust unit; that's payable on August 15, 2005, that's to unitholders of record on July 29, 2005. Based on forecast commodity prices for the remainder of the year the current distribution level represents approximately 50% of cash flow. This leaves your Trust with the ability to apply cash flow in excess of current distribution to reduce debt, to use for future acquisitions or potentially to provide a special distribution for unitholders. We are very actively tracking and modeling gas and oil futures and utilizing all available information and looking at the current level of distribution.

To increase the certainty of future cash flow to fund our distributions and capital program, the Trust hedged 20,000 barrels per day of crude oil through December 2006, so that was done on callers with an average floor price of US$47.50 per barrel WTI, an average ceiling of US$67.86 per barrel WTI.

Effective May 31, 2005 Penn West Energy Trust commenced operations as an oil and gas income trust pursuant to the plan of arrangement approved by shareholders on May 27, 2005. We've since put together a new Board of Directors and we've revitalized the management team to guide the future of the Trust. And recently, on August 3, 2005, we appointed George Bruckman, who is a very well-known independent businessman and civic leader in Calgary, to our Board of Directors. Yesterday we received good news as well from the United States Securities and Exchange Commission in that we were granted an exception under rule 12G 3.2 and this will assist unitholders in the United States in trading our units.

The next step on the process is looking at state by state clearance for Bluesky provisions. We are also in the process of putting a team together to facilitate the requirements necessary to register in the U.S. in order that we can obtain a listing in the United States. Are expecting right now the time frame necessary leading to the process to a U.S. listing is somewhere between 12 and maybe on the outside 24 months but probably 12 to 18 months would be a better estimate.

In summary, there's definitely a great buzz at Penn West Energy Trust both in the office and with our field operators. Gone is basically a year or more of uncertainty and that really, I felt, hampered our ability to perform to the best of our ability. And we've got great, great anticipation of providing high-quality investment opportunities for our unitholders. With that going forward we're continuing with a strong focus on field operations and development. In the third quarter we'll be looking at optimization -- we are looking at optimization at the field operations level. We've got shallow gas development ongoing and also horizontal infill drilling for oil.

We've begun a significant effort to utilize the value of our large land base through farm-out sales and joint ventures. To date we've signed confidentiality agreements with a variety of companies, begun the process of completing farm-out and joint venture agreements. A large number of the proposals include wide area multiwell commitments with plans for aggressive drilling on our lands commencing in the third and fourth quarters of 2005. Our teams have completed detailed property reviews for our core areas that we're moving forward to develop plans to actively and efficiently work the potential of these areas.

In addition to the conventional activities, we're continuing to work on the implementation of the enhanced recovery program on the multibillion barrel Pembina Cardium oil fields and that will utilize waste CO2 that's currently being emitted into the atmosphere by heavy industry. In terms of where we are there, we are very close to signing an agreement with a potential partner. That will see us move forward to the next level, the next step which is basically to make the project happen and we're still very, very confident that we will be looking at a commercial project -- first phase of commercial project at Pembina late 2008, early 2009.

We've also got probably the quietest oil sands project in western Canada going in the Seal area. We're moving forward really with the first phase, we've got a pilot phase ongoing right now that's producing over 1,000 barrels a day from a limited number of wells. We believe -- we certainly haven't booked any of these reserves, but we believe there's multiples of millions of barrels of reserves of oil in these very thick deposits of oil sands. We're looking at an aggressive program through the latter part of 2005 into 2006 that would see us drill somewhere between 30 and 60 wells. The project itself, the first phase of the project will provide good production additions -- also we should be able to do it at very good capital efficiency and we're confident it will lead to other phases.

Our predominant business model with the Trust is to emphasize sustainability. We intend to retain sufficient cash flow from the Trust to fund our internal program and we feel that we have a wealth of projects that will justify the expenditure of capital. With that I'd like to thank you and I'd be pleased to answer any questions that you have.

(OPERATOR INSTRUCTIONS). William Lacey, FirstEnergy Capital.

Bill, I was just wondering if you could answer a couple quick questions on the production. Specifically you mentioned the acquisition of 2,500 to 3,000 barrels affective mid-August. Can you give a little bit more on the details of that, where it is, how much you paid for it?

We'll do that on closing. But it's in our Southern area and it's basically an expansion of a southern area in Priorton (ph) and also an addition of some production near our core lands.

Is it like a breakdown of the commodities, basically oil?

Basically oil. It's basically a medium gravity oil.

Okay. As far as your guidance, you've said 98,000 to 101,000 barrels a day, is this included within that?

Yes.

Okay. Just on the operating costs, your heavy and your gas OpEx was basically in line with where you've been over the last few quarters, where the light and NGL's took a bit of a spike up. Was there anything unusual within the OpEx this quarter?

Not really. I think we just did some workovers and just did some general costs, some of them one time. As we look at the environment that we're in there's a lot of pressure on costs and we feel we can tackle a lot of it because as an E&P company I don't think we focus as much time as we will as a trust company on general field optimization. That should help on the operating cost side.

Okay. With the production you said that it is currently around 101,000 barrels a day, so what the lift in production versus Q2, is that mainly on the liquids front?

Yes.

And lastly, I guess your G&A went up a little bit here in the second quarter to make it more competitive. Is that probably a more reasonable run rate number going forward here?

That is probably -- and I think, as everyone on the other end of the phone knows, it is a very competitive environment in western Canada for (indiscernible) whether it be in the office or in the field or on projects.

Great. Thanks for the time.

Kurt Rolf (ph), Deep Associates.

I have three questions; they may be a little on the general side. I'm interested from the point of view of a U.S. investor. But the first question applies to your business. You mentioned you have 7.8 billion barrels in place in the Pembina Cardium -- that's what exists for everybody. Can you remind me what the recovery factor might be now on the proven reserves, how much that recovery factor might be boosted with CO2 recovery and what roughly proportion of those reserves do you own before royalty? The second question is how are the trusts taxed in the U.S.? And the third question is what do you think the Canadian ownership limitation picture will look like when you might be listed in the U.S. in another year or so?

I'll do one and three and then I'll turn it over to my good financial man to give a whirl at number two. In terms of Pembina, the -- there's a general argument about how much oil is in place in the pool and it's -- the (indiscernible) number is somewhere between 5.5 billion barrels and 7.8 billion barrels. Of that about 1.5 billion barrels has been recovered to date. So we're looking at a recovery of somewhere between 15% and 25% depending on which in place number you use.

We anticipate that we would get incremental recoveries of at a minimum, and the maximum is really unknown. The Company has looked at a lot of work that's been done in the U.S. where we've seen recoveries on tertiary with CO2 that equaled the recoveries on primary and secondary that were previously taken out of the ground.

Our working interest in Pembina proper runs somewhere around 35% of the field, so about a third of the field is Penn West interest. Canadian ownership right now -- or U.S. ownership in the stock we think is somewhere just under 20%, maybe about 17%. Obviously with the ability in the future to list in the U.S. there's lots of room there to move up in U.S. ownership. I'll turn it over to Todd with regard to tax for U.S. unitholders.

Generally the Trust is not subject to tax in the U.S.; however, an investor -- to the extent that they receive distributions they, for U.S. tax purposes, are qualifying dividends because we are a qualifying corporation. And I don't want to get too technical, but basically you will be on a distribution subject to a 15% withholding tax that you should get a foreign tax credit for in the United States and you will then take the low dividend rate of 15% in the U.S. So at the end of the day your effective tax rate on a Penn West distribution should be 15%.

Would any portion of the distribution be considered a return of capital?

That's yet to be determined. Our forecasts indicate that at best a modest proportion of that will be a return on capital. But we're running our forecast as if the distributions will be 100% taxable at this point in time.

Of course 15% maximum tax rate is very favorable. That's good. On the Canadian ownership question, do you think that a year from now that Canada will have 50% limits on trust ownership so we'll like that change too. That's a pretty general political question and I know you don't know what's (multiple speakers).

It's hard to read the minds of politicians.

Thanks very much for your response.

David All, DLA.

I want to follow up on a couple of question on Pembina and a little bit more about Seal. You had a pilot project you started at Pembina in April I believe. Could you tell us what progress is being made, if you had any response yet? The second, I know you announced the pipeline. When you talked about bringing in a partner are you talking about bringing a partner of the pipeline or a partner for CO2 supply? And could you tell us how you would go forward and what would be the timing for developing the pipeline network?

And also just what the current production is at Pembina and what sort of drilling you're doing there and in terms of infill wells and as far as the water foot (ph) goes? And then on Seal, I think on the last earnings call you said you had about 3,000 barrels a day of production shut-in because of pipeline constraints. Would that be -- what is the status on the pipeline construction? And then I don't believe you said what the projected output would be for the 30 to 50 wells -- the expansion you're talking about doing at Seal would be. Could you just comment a little bit more on that? I know I've given you a lot, but all of it's very interesting.

I'll try to wind my way through it. Our current production level at Pembina is about 12,000 barrels a day. The work is ongoing right now from basically a negotiation point (indiscernible) is with regard to the supply side of the CO2. And we've got -- as with any project of this type you've two or three or four things going on at once. The pipeline is well underway. As we've stated before, we would love to be a working interest partner on the CO2 spine that's being envisioned for central Alberta and that's an ongoing work in progress with a couple of levels of government and potential industry partners.

The pilot -- we commenced injection (ph) in February, everything is going very well. We're starting to see some results, but the results that we're saying from a positive point of view are the fact that we took it as part of the field to look at. We felt that that had quite a high recovery. So really probably not the most effective parts of the field to look at from the point of view of adding CO2 and tertiary recovery. What we're seeing that's very positive is we're seeing minimal if any circulation of the CO2 through the reservoir and basically any -- we're not seeing any urgent breakthrough of the CO2 so we're getting a uniform wall that's pushing oil. We are getting some incremental oil to our well bores.

Our timing for any real results we'd always hope that would take somewhere between a year and a year and a half. So we're about five months into the process right now. I would hope that at the next quarter and certainly if not the next quarter the one thereafter we should have some good announcements on the pilot.

With regard to the Seal, we've had problems with wet weather. We've had problems, as does anyone that's at the initial stages of development weather it be a conventional oil sands project or an in situ project such as this. We're currently producing, as I said, over 1,000 barrels a day. We don't have all the wells on, we've got a number of them on. On average the wells after flush would be producing somewhere between 75 in 125 barrels per day of oil. They do produce under what we call cold production so they're producing right now without the benefit of any thermal work or assist to help them flow into the well bore. Basically I think I never liked extrapolating, but with the 30 to 50 we've got planned we would assume that the sand quality is the same so we're looking at similar type results on a per well basis.

Thank you very much, Bill, appreciate that. Oh, by the way, what about the pipeline and building a pipeline to move the oil out of Seal?

We're working on a couple things right now. First up is to get a battery in place and right now we're looking -- there's a brand-new road being put into Seal, so it could very well be that in the near-term it may be almost as cost-efficient to truck it as to put the capital in for a pipeline. Those are a couple things we're looking at. And as I say, we plan to get fired up on this project in a much bigger way late in the fourth quarter and early next year.

Thank you very much, Bill.

(OPERATOR INSTRUCTIONS). Gordon Tait, BMO Nesbitt Burns.

Good morning. I was just wondering, with some of these big core projects you've got on the books, are you looking at disposing of some of your noncore assets? Do you have a disposition program in place as well?

William Tang Kong is in here with us today. I guess in order to give me something to do and certainly William doesn't need any more to do, but our principal -- part of our principal tasks are on the acquisition and divestiture and we are looking at both. And as I've said to our employees here and certainly discussed at the Board level and talked a little bit about in public -- is the fact that we're looking for a model in the Company that's got good sustainability.

We feel that some of our asset which we built up as we were growing an exploration -- or an E&P company would be -- are more suited for that realm. I think you could very well see Penn West evolve over the next six months to 18 months out of some areas and then take that capital, move it into other areas with the concentration being on longer life reserves and condensed areas of focus.

Okay. I guess you'll just announce those as you get packages?

Yes.

Just one more question on the Seal. What do you estimate the amount of capital that you will spend on that project say over the next 12 months and 24 months?

I think over the next 12 months you would probably see us spend somewhere 35 to $50 million, somewhere in the range. The next 24 months depending on success, I think it is just something you would keep going at.

You could continue to drill that many wells a year there?

Yes, it looks like a good place to add volumes and add some long life reserves and it seems to certainly be the preferred model that a lot of companies have in their pocket in western Canada.

All right, thank you.

Ryan Shay, Sprott Securities.

Good morning. You had mentioned your CapEx guidance and I just wanted to clarify that the acquisition, 2500 to 3000 BOE (ph) a day acquisition would be included in your existing CapEx guidance?

Yes, that is inside that.

The second question is you mentioned you would consider a special distribution and I was just wondering if that would be something that would be tax related or just due to the strength in commodity prices?

I just think it is something that we are looking at and you are seeing a number of the trusts do some things recently, either change distribution levels or put in a onetime special distribution or ongoing special distribution. It is just something that we are looking at with regard to commodity price. The one thing and I had been through this a little bit publicly as well, I was concerned and we were concerned coming off an E&P company and into a trust just how we would react as a company and how the staff would react and sort of where our production would level out and how things would go.

What we are seeing is we are seeing quite a bit of bounce in everybody's step the last couple of months. With that it looks like we can hold production and hold production probably better than we had originally forecast. Commodity prices are very strong right now. As I say our distribution level that we are paying at $0.26 a unit is about 50% of our cash flow. So it leaves us opportunity. That's just something that we'll review. We're just into our first quarter as a -- our full first quarter as a trust and bear with us, we'll do the best for the unitholders.

Great, thank you.

Roger Serin, TD Newcrest.

I've got three quick questions. First of all, you've added people and lost people. I wonder if you could give me an idea of where you are from a net change from a staffing point of view?

Sure. We've lost a total of 15% of the staff -- in the office. So we have about 300 people. We lost I think about 34 or 35, so that's close to 15. It's working out very well because there were people that wanted to move on or felt that the Trust world wasn't where they wanted to be. And at the end of the day now we've got people that are fully committed to making this thing a genuine success.

On the recruitment side we added three people last week; we've got offer letters out probably to another half dozen. We've got some people that are very excited about the opportunity to come work for Penn West Energy Trust. So I'm not concerned about the people at the end of the day. I'm very concerned about my employees, but I'm not concerned about the ability to attract people.

And with that you've lost a little bit more than you've gained, do you see anything that's going to impact you in the short-, medium-term operationally?

No, I think as I said, probably on the management team, we didn't take a lot of holidays in the summer, so we're keeping it together and we'll be -- I think we'll be up and rolling with a full staff complement I would envision by mid-September. By that time maybe Mr. Middleton and I will take a day off.

I'm glad you're working hard, I am too. On the undeveloped land side you have about 5.1 million acres, down from about 5.8 when you did your information circular. Is that a higher than normal loss rate? I'm just kind of wondering if there were some early expirees or whether you can give me some guidance on that?

The simple answer is that probably as part of our capital efficiency the last couple of years -- one of the large areas, we bought about 350,000 or 400,000 acres in the Shackleman (ph) play in Southwest Saskatchewan that didn't turn out very well. It didn't turn out well at all. We attempted to do a farm-out on the land, we did a farm-out on the (indiscernible) lands, a lot of it was viewed as not perspective by the industry. So we let that drop and that's a major portion.

And the last question on heavy oil difs, obviously the second quarter was a little tough. Where are you now in terms of run rate on heavy oil difs?

I'll let Kristian move in on this one.

Right now the heavy oil differentials we're seeing about $9 to $10 of Penn West heavy oil differential Bold (ph) River is about $9 to $10, that's where it's coming in at. And I'd say for Q2 it was actually a little narrower just because (indiscernible) prices were lower and we used less of it in Q2. For the year we'd say $9 to $10 off Bold River, Roger.

So that means you're going to see second half, at least at this level, similar to the second quarter on a dif basis?

Yes, we would anticipate that. (indiscernible) prices have shot up again here the last few weeks and we expect they'll probably stay high. So I would say $9 to $10 is a good estimate for rest of the year.

Thanks very much, guys.

At this time we have no further questions in queue. I would like to turn the conference back to management for any concluding comments. Please go ahead.

Thank you all very much. If there's any questions please feel free to give us a call. Thanks.

Ladies and gentlemen, that does conclude the Penn West Energy Trust second-quarter results conference call. Thank you again for your participation on today's conference and you may now disconnect.