Obsidian Energy Ltd (OBE) 2005 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Penn West Energy Trust third quarter 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. (OPERATOR INSTRUCTIONS).

I would like to remind everyone that this conference call is being recorded on Wednesday, November 9, 2005 at 11 AM Eastern. And we'll now turn the conference over to Mr. William Andrew, President. Please go ahead, Sir.

Thank you and good morning. I would like to welcome you to Penn West Energy Trust conference call and webcast. With me in Calgary this morning are Dave Middleton -- he is our Executive Vice President and Chief Operating Officer; Thane Jensen, who is our Senior Vice President. Thane looks after the day-to-day operations of the Company in terms of exploration, development, and servicing; Todd Takeyasu, who is our Vice President of Finance; and then other members of our team, including William (indiscernible).

On behalf of the employees and directors of the Trust I would like to thank everyone who is listening via teleconference and those who are wired into our webcast.

Over the past few months, as a Trust and as we have converted to a Trust, we have had the pleasure of speaking to numerous unit holders, both retail and institutional. I encourage any unit holder with questions or concerns regarding Penn West Energy Trust to please contact us on the Web. Our Web address is www.pennwest.com or via telephone and the telephone numbers are readily available on either via the Web or in the phone book.

Before I begin, I'd like to send sincere condolences from everyone at Penn West Energy Trust to the family and friends of Glenn Lee, who was taken from us in a tragic accident on November 2nd. Our thoughts and prayer are with Tammy and Glenn's family at this time.

In this conference call, we will review our 2005 third quarter results and provide an update on recent activities for Penn West Energy Trust. Following this review we will be pleased to answer any questions that you may have.

During the presentation we will use Canadian dollars and a 6 to 1 ratio for conversion to barrels of oil equivalent.

Results for the third quarter of 2005 represent Penn West Energy Trust's first full quarter as a recording entity. For comparative purposes, we will be looking back to the second quarter of 2005 as a benchmark for this quarter, although we will make occasional reference to year-over-year comparisons. Results are not directly comparable because we reorganized from an oil and gas exploration company into an energy trust at the end of May 2005.

The third quarter of 2005, gross revenues were $535 million. Resulting cash flow was $335 million which was an increase of 30% over our second quarter this year and an increase of 42% over our performance in the third quarter of 2004 on Penn West as an exploration company.

On a per unit basis, cash flow for the third quarter 2005 was $2.04 per unit. Net income for the third quarter of 2005 was $210 million. That's an increase of 252% over the second quarter of 2005, also represents an increase of 173% over our performance in the third quarter 2004 -- again, when Penn West was an exploration company.

On a per unit basis, net income for the third quarter of 2005 was $1.27 per unit.

In the third quarter, light oil and natural gas liquids production averaged 33,101 barrels per day. Conventional heavy oil production averaged 18,533 barrels per day for a grand total of 51,634 barrels per day of oil and natural gas liquid.

Average daily natural gas production for the third quarter was 289 million cubic feet per day. Total production for the third quarter of 2005 averaged 99,802 barrels of oil equivalent per day. That is approximately equal to a production of the second quarter 2005. I think it's a testament, a real testament to the efforts of our employees at production for the quarter held up to the level of the last quarter.

That is in spite of wet weather that hampered both well servicing and trucking operations. And I think we should also recognize that we had a number of scheduled maintenance shutdowns in the third quarter.

In the third quarter 2005, natural gas prices averaged $8.88 grams (ph) depth. That is up 20% from the prior quarter.

Light oil and natural gas liquids prices averaged $70.94 per barrel. That is a 20% increase over the second quarter of 2005. Conventional heavy oil prices averaged $48.60 per barrel in the third quarter, an increase of 56% compared to the prior quarter.

Overall commodity prices averaged $58.27 per barrel of oil equivalent. That is up 25% from $46.66 from the second quarter.

Operating costs in the third quarter of 2005 were $9.11 per barrel of oil equivalent. This represents a 2% increase over the previous quarter. Operating costs increased over 2004 levels due to higher energy and fuel costs, planned facility maintenance projects, an increase in natural gas compression costs and lower production.

Higher industry activity in commodity prices also influenced operating costs by increasing demand for services increasing input costs. resulting in higher industry service rates. We're increasing our efforts to improve operating efficiency and to cut operating expenses in response to the external cost pressures facing the industry.

I believe it is important to note we have grown our ratio of oil production at Penn West over the past three years and in excess of 64% of the Trust liquid production consists of light oil and natural gas liquids.

While light conventional oil fields under secondary coverage generally have higher than industry average lifting costs they also produce light oil that commands a premium price. These long life oilfields positioned the Trust to absorb industry wide operating cost escalations and still maintain very strong operating net back.

Our net backs for the third quarter of 2005 were $38.80 per barrel of oil equivalent. That is up 31% from the last quarter, and up a full 62% this time last year.

These are comprised of an average light oil and liquid net back of $45.68 per barrel, and average conventional heavy oil net back of $31.89 per barrel, and average natural gas net back of $6.12 per MCF. And you'll note in our release the net backs from light crude oil sales were up 111% year-over-year.

Capital expenditures for the first nine months of 2005 are down 186.2 million or 29% from last year. Capital expenditures to date are 450 million, including 86 million spent on property acquisitions and 364 million spent on development and other activities.

On converting to a trust, Penn West entered into a $1.22 billion credit and operating facility. This 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 in credit. However, an increase in bank loan in the third quarter was required to pay the income tax bill related to the tax conversion.

Bank debt at the end of the third quarter totaled $770 million as compared with 573 million a year ago. Based on revenue and expenditure forecasts for the fourth quarter of 2005, we expect year end bank debt to be approximately $550 million.

Using commodity prices of $61.00 WTI for crude oil and US$12.00 for MCF natural gas for the remainder of 2005, we are forecasting cash flow to be on the order of $1.2 billion for 2005. That is after-tax.

(indiscernible) combined capital expenditures for 2005 both as an exploration production company and as an income trust are forecast to be between 450 and $500 million. That will fund approximately 400 to 450 net wells. We think about 450 right now.

Forecast average 2005 production will be approximately 100,000 barrels of oil equivalent per day to the range between 99 and 101,000 barrels of oil equivalent per day.

Capital expenditures since conversion have been approximately 40% of forecast cash flow, Trust unit distributions and debt management accounting for the remainder -- remaining 60% of cash flow. Third quarter monthly cash distributions totaling $127.3 million or $0.26 per Trust unit per month were paid to unit holders of record in each of July, August and September. Following a review of asset performance, capital requirements and commodity prices were Trust approved a 19% increase in monthly distribution, effective with the October 2005 distribution.

This increases monthly distributions to unit holders from $0.26 to $0.31 per unit. On an annualized basis, distributions are now set at $3.72 per unit per year.

Penn West has an active hedging program to increase the assurance of future cash flow to fund distributions and capital program expenditures, while providing effective downside protection. With 20,000 barrels per day of crude oil hedge to the end of 2006 on collars as far as averaging approximately 4750 per barrel WTI and ceilings averaging approximately $68 per barrel WTI.

Currently, we have 75 billion cubic feet per day of natural gas hedged for the fourth quarter of 2005 and 111 million cubic feet per day of natural gas hedged using collars, for the first part of 2006, using collars with a floor of 882 per MCF and a ceiling of 1660 per MCF. A full detail with our hedging program are available on our website.

When we converted to a Trust group we were left -- we faced a multiple of challenges. Several of the key directives in management with the exploration company opted to leave on conversion as well as a number of our staff. We faced this potentially negative occurrence by looking the situation square in the face and by working to build a strong operating company for the Trust.

We believe we are well on our way towards our goal of a better, more efficient operating company. We've added new directors who bring strong operations, financial, and business knowledge to the Trust. There is a major reorganization of our management and technical staff to stress teamwork, communication, and ingenuity.

As is evidenced by our performance in the third quarter, we are on our way and will continue to drive the Trust toward superior unit holder value.

Going forward, we will continue to concentrate on our field operations, development projects and enhancing capital efficiencies in all areas of our business. Work in the fourth quarter is focused on optimization of field operations. (indiscernible) gas developments and horizontal infill drilling.

Detailed initial property reviews have been completed on our core areas and we are continuing development plans to actively and efficiently work the potential of areas.

We will continue to direct significant effort at monetizing our extensive land base through (indiscernible), disposition, and joint ventures. Since the conversion, we've placed the high priority on becoming the most aggressive land dealer in the industry. Today we cite confidentiality agreements with numerous companies and we have completed and are completing farm out and joint venture deals.

A number of the completed agreements and proposals in progress include large area, multiwall commitments with plants who are aggressive (indiscernible) drilling to begin on our land before year end. Additionally, a number of the completed and pending transactions provide unit holders with interest and growth-oriented exploration companies.

In addition to noncore property rationalization and convention exploration and development activities, we are continue to work on the implementation of our Pembina CO2 enhanced recovery project. This project provides an opportunity for us to markedly improve the productivity, recovery, and operating efficiency of the Pembina Cardium pool, utilizing large volumes of industrial wave caps in the form of carbon dioxide.

The project that has been recognized as leading-edge by government regulators in the industry demonstrates that we can efficiently reduce emissions while at the same time increasing the ultimate recovery of conventional oil reserves.

We have seen positive results from pilot project wells and we have made market progress in securing a supplier for carbon dioxide. We have also begun the initial commercial phase of developments in our Seal Oil Sands project near Peace River, Alberta. We believe that this area has the potential to add multiple millions of barrels of reserves and strong production additions with very good capital efficiencies.

By the end of 2006, we expect to add an additional 50 horizontal wells on our first phase of development of (indiscernible) significantly increased production. We see this first phase as a baby step for being up and running at full speed in an area with multiple potential projects spread over an extensive inventory of land.

Penn West Energy Trust is committed to develop new projects in the area, following up on exploration activity that we have undertaken over the past two years. We will also continue with a strong exploration effort in the area.

We are looking forward to 2006 and an effort to improve capital budget to target the expenditures between 400 and $500 million. In developing the budget we opted to start from the ground floor after conversion. As a result, we feel that we have developed a good balance slate of projects that will continue to strengthen the Trust and continue to improve efficiencies to focus not only on short- and medium-term development opportunities that also an effort to improve operating efficiencies to provide added securities to our reserves inventory, and to develop large-scale and enhance recovery in Oil Sands projects.

Based on capital expenditures, the 400 to $500 million forecast 2006 prices of US$58 per barrel WTI and 875 for MCF of natural gas, using a production range between 90,000 and 100,000 barrels of oil equivalent per day we anticipate cash flow to be in the range of $900 million and $1.1 billion next year.

Before I conclude I'd like to provide some comments for our unit holders on the actions of the government of Canada regarding income trust. As you know, Penn West sought and received an advanced tax ruling from revenue Canada prior to conversion to an income trust. We believe that any action undertaken by the government of Canada should take into focus full consideration many positive impacts with income trust.

In the energy sector, the growth of the income trust sector has sparked parallel and strong activity in junior exploration companies. We are taking up the challenge of growing our conventional reserves of oil and natural gas. This activity is reflected in record rig utilization, (indiscernible) rig activity. And the very strong employment market in western Canada is providing opportunities, directly and indirectly to all regions of our country and all Canadians.

We urge unit holders to contact their MP and tell them in your words what kind of investment opportunity income trusts provide for Canadians in all walks of life. Thank you. We would be pleased to answer any questions you may have.

+++ q-and-a.

(OPERATOR INSTRUCTIONS) William Lacey from FirstEnergy.

Bill, I was wondering if you could talk a little bit more specifically about the CO2 test wells? How that performance has been to date as well as maybe some milestones over the next year that investors should be looking for on this program?

We have been injecting CO2 since about mid-February. We are in the process of increasing the size we are pumping on, on most of the wells out there. There has been great response from the wells. We have not seen any premature breakthrough CO2. We have seen good and strong pressure support. And we have seen good and strong adds of oil on the pilot project. We are very pleased with how the private pilot project is going.

In terms of benchmarks over the next year, one of them obviously what was to secure a long-term supply of carbon dioxide and as has been the case in the past three quarters, we are limited by confidentiality agreements. But I will say that we are very very much advanced on that front.

The next step will be to secure regulatory approval for two phases. One would be to capture CO2 and that would involve some equipment. The second would be pipeline coming into the Pembian (ph) area and that would involved regulatory approval and licensing as well as engineering and design. And the third would be to get the first phase of our project ready and approved by the regulatory bodies.

We'd look to push through that in 2006. We'd look to start construction in mid-2007. And we'd look to start up on the project in 2008.

Just as far as more day to day stuff, you did talk about the weather and that in the third quarter. What do you behind pipelines volumes look like these days?

That's always a tough one to look at. We -- most of the behind pipe has been in the tank rather than behind pipe. It has just been a matter of getting to the well and getting the oil out. I think what we have seen is that we anticipated that we need a certain amount of capital to maintain production or to stem production declines. And what we have seen in the third quarter is that we have improved the efficiency of operations to the point where we were able to keep the production relatively flat even though we absorbed some losses on production, due to weather.

But I would think, roughly, that at any given time during the quarter, we had up to 1000 barrels a day that was either shut in or just not getting moved and we are moving that out of the system now.

Can you talk about the reinvestment efficiency improving? Where do you think you're at these days?

That is a good question. We know exactly where we're at. Right now we are at about $25,500 dollars per producing barrel.

That's a pretty marked improvement.

And we will see -- monitor through the fourth quarter and go from there. As we've stated before, our intention was to push that capital efficiency down to levels where we wanted to be the leader among the trust and capital efficiencies.

Gordon Tait from BMO Nesbitt Burns.

Just following up on your -- on the longer-term projects. How much capital or how much in your budget will be committed to Seal and to that Pembian CO2 recovery project, say, in '06?

We have got -- in 2006 we've committed almost $50 million to the three projects. The bulk would go to Seal, the second large amount would go to Pembina and then we would have a smaller amount going to a coalbed methane project that is underway in the Swan Hills area. Of that 50, we'd be looking at roughly half to two-thirds of it going to Seal.

Just on your farmouts I notice you indicated 88 wells drilled. Are you in a position where you are receiving net production revenues off of those?

Not yet.

Not yet. Okay.

Although there may -- I would think that is probably and then, again, we have -- you got caught in this case of life before and after the conversion. We did start on a fairly modest program of monetizing our lands prior to converting to the Trust. Some of those wells, some of those areas would be seeing a little bit of production come through but we've -- we've taken quantum steps since conversion on what we're doing on trying to monetize our land.

So our feeling is that you'll start to see some significant additions in cash flow, as we move into the third and fourth quarter next year, that will allow for pretty strong winter drilling program on farmed outlands.

So what do you think you could -- what proportion of your cash flow are you thinking? 5 to 10% to come from --?

We think that -- we think ultimately that these lands will add or override any working interest derived from farmout would account for about 15% of our cash flow.

Just, lastly, of course cost pressures all cost trending up. Is this quarter you think a good benchmark for where all costs might be going forward?

No. I think we are -- I think we are really kind of turning it around in terms of where we are focusing our attention. We basically taken the old Company and given it a great big shake and seeing a lot more bottoms up ideas coming, a lot more involvement of our field staff in looking at operating cost, and budgeting, and planning and looking at projects that would add documentation and efficiency to us.

So I'm confident that we are going to work to trend, instead of trending upwards in operating costs, we're going to try to hold and hopefully push it back and that is in the safe. I think, as you know, a very very heavy push in the opposite direction on service costs. There's a tremendous increase in all areas on service costs and we are pushing against that.

Roger Serin from TD Securities.

I have got a few questions for you. On the Seal side, what are you getting in times of net backs from Seal right now?

I will turned that over to my marketing man, Christian Tange (ph) .

Currently our last quarter here like in Q3 was approximately $20 to $30 per barrel and that is before royalties and operating costs. That's a field price.

And op cost would be 13, 14 bucks.

Probably 5-ish -- 5 to $10 somewhere in there.

Plus trucking?

Yes.

Another question on the farmout, Bill, (technical difficulty) talk about you had a program for a little over a million acres that you were looking to farm out. Can you give us a sense as to where you are at? Have you farmed out a third, a half, a quarter when you talk about getting some activities in the Q3, Q4 next year?

We find that somewhere between 15 and 20% of that million acres right now, we have got two fairly large deals that we are working on. One, which would represent about another close to 100,000 net acres. We have got another one that should be about 50,000 net acres. And then a whole bunch of smaller potential farmouts that they are in various stages.

So, if you add that all are you looking to maybe get deals on half of it in a reasonable timeframe?

We are looking at -- I think there's -- I think you cite the number I talked about was 300,000 acres we got -- those are ones that basically committed or very close. We've also got several deals. One which is much larger than the total of the deals that we have done so far and it involves about 600,000 net acres. So it would -- that one alone would take us up to the million.

And when you talked about looking to 50% of cash flow I got the sense that was on a run rate as you moved out a couple years from now?

Yes you can't expect that in the next quarter.

A couple of other questions. On the property sales, post the quarter can you give us a breakdown in terms of oil and gas split whether there was some undeveloped lands that went with that and what general area it was? Is it specific to one?

Property sales were primarily in what we call the North and they were primarily natural gas and the volumes that were involved would be around 1300 BOE a day. Again mostly gas so convert that back.

A couple of other questions. On the staffing side is it tough in Calgary to get people? Are you having to put in year-end bonuses? Are there changes to your composition plans beyond the normal Trust programs you have in place?

I don't think so. I think when we are going about the performance review right now, and I think those that got committed to this thing with the trucks and those that have come on board the Trust have worked pretty damn hard in the last five or six months to get this thing going.

So I'm positive that our bonus program will reflect that. We've seen good improvement on our capital efficiency. As I said before, we've been very pleased with the fact that our production has remained flat, in spite of some of the challenge that we face in the quarter, primarily due to weather.

But no, we -- I would anticipate just that, yes, we are going to get some decent bonuses this year. In terms of our salary administration, basically, we will as part of it, we look at what the other trusts are paying and we want it to be competitive. We want -- we have a goal in mind to be the best Trust that there is. In order to do that you have to have the best people. So I think part of that is compensation.

Does that translate into a bit of a bump in the fourth quarter under the on the G&A side then, Bill?

I think, possibly, yes. I guess what we're looking for on the other side I talked about earlier but with improved capital efficiency, hopefully, we have less expenditure, with approved operating efficiency. Hopefully, we haven't got the pressures that we have incurred on operating costs. So I think it is just a balance. Right now as you know our G&A levels are quite low.

One last question and I get about the same capital efficiency you got. What do you translate that in terms of F&D cost for the year?

We sort of generally put the pen to paper but I'm not going to commit to a number right now. I think we are looking reasonable for the year.

It is going to be an interesting exercise as we go through with the reserves because we've pushed a number of areas to flatten out or trend towards flattening out our decline curves. That should impact -- that should impact very positively besides what we are finding with the net (ph) . So I will -- next quarter I'll try to give you a little better response to that.

Good quarter. Thank you very much.

Ryan Schaefer. Sprott Securities.

Good morning. Your slide show says current production is 100,050 BOE a day. Is that after the 1300 BOE a day property sale?

That is about midway. It includes some of the property sales, not all. We will probably be down in the fourth quarter, we think to about 99,000 barrels a day.

And should we expect more asset sales or are you pretty done with that program?

I think it keys on -- as I talked about that large deal where we've got roughly 700,000 net acres and a very strong commitment on oil, that one goes forward we will probably slow it down. But I don't -- I don't really want to slow the momentum down there. Particularly with regard to raw land. But yes, I think we have slowed down on sales of production but know we haven't slowed down on raw land.

Some of them, too -- I know you understand this, Ryan, that sometimes when you are looking to do a deal on a property there has to be an inclusion of some production. It depends on negotiations but I don't anticipate that there would be a lot of sale. Of production.

The last question is you mentioned that in some cases you have taken an equity investment and another entity. Can you give us more details on that?

No. I'll leave it to the other entities to announce it. But we have, as part of what we're doing, we have done a completed deal where there -- a portion of the payment wasn't in the form of stock in a publicly traded junior. And we are contemplating on working on deals where we would get the same type of structure.

I think it's just, I believe it is good for all parties. I don't -- by the same token we're not making it a large part of the deal, so generally our limit on that would be somewhere between 10%, 20% of the deal. It JUST provides us with some flexibility and certainly what we're trying to do is be able to work with the juniors in (indiscernible) and give them the ability to go out and find oil and gas and part of it, in some circumstances, involves payment through share capital.

Bruce Wescott from William Johns.

(technical difficulty) questions. Just from a business planning point of view, strategically, what are you thinking about daily productions over the next several years? Currently like at 100,000 a day. Do you think that would rise over time?

(technical difficulty) should lead to a reduction in production over time. The factors that would work to level production or increase production would be the ability to do acquisition and, secondly, the impact of the two major projects that we have underway, one being the Pembina Oil Sands or the Pembina -- we have two projects in the Seal Oil Sands project.

In a perfect world, where we just have the conventional assets of the Company and we did not go forward to do any more acquisitions then, obviously, the production has got to go down.

Talking about the Pembina field, can you talk a little bit about your ultimate recovery (indiscernible) of CO2 injected wells versus where they are now? If everything worked according to your plan?

We have done a tremendous amount of lab work and we are following up right now with field work. There has been some field work done before but based on what we've seen in some of the older work that was done and in some of our lab work, you are going to get very significant recovery. We have been much more modest in what we're using to build our model.

To date production has been in the low 20s, around 20 or recovery has been around 22, 23% of the reserves in place. Again, depending on what you use as a reserve and place number but about 1.5 million barrels have been recovered to date.

We are confident that -- that should be billion barrels instead of million. We are confident there's another billion barrels out there to be recovered under CO2.

So you can double, you can double your percentage reserves in place?

We think pretty close to double it.

What is daily Pembina production now?

It's about 12,000 barrels a day from the Cardium right now.

If everything goes according to your plan, what could daily production grow to over time? Say, five years?

I think we would look to -- we are looking toward at least doubling and quite probably tripling production from the area.

That's a pretty big increase.

Yes.

Your financing plans, assuming you don't get much of a change in commodity prices here, do you need to sell debt equity?

I think -- obviously we are looking at, depending again how much of a piece of the pipeline we take out on a first phase of Pembina we'd be looking at somewhere between, what, $200 roughly $250 million and maybe up to as much as 350 or $400 million.

Our feeling right now is that we could handle that just as a bank line. As we move forward with that phase and then depending on how much more aggressively we get at Seal I think there is a potential to look for some equity.

What is current Seal production?

Current Seal production is about 1500 barrels per day. And we are looking to take that up over 5000 barrels a day next year.

What is your current annual depletion rate?

Right now, we were running about 19%. We think we are running a little less than 18% right now.

In the 4 to 500 million of CapEx, is that all development CapEx? Or is there any exploration?

Yes, we were still doing some exploration. In fact I routinely go around and talk to the geologists and tell them that we are still going to keep up with ideas and then keep up with the projects that we do have. We still have an exploration budget. The other portions of it, where we may be a little bit different from a lot of the Trust is that we have got a budget next year of almost $30 million on environmental work and reclamation. And we also have (indiscernible) amount allocated (technical difficulty) and (indiscernible)

What percentage of your 4 to 500 million of CapEx would you call exploration-related?

Probably less than 5%.

Bob Hartley from Union Securities.

Just a quick follow-up on the Pembina field. What do you estimate as the total recovery -- recoverable reserves from Pembina with the enhancement? And how will the project affect the present reserve life index of that particular reserve?

Good question. We are anticipating that we would see ultimately recovery from the field of upwards of 3 billion barrels.

And how will that -- how is that going to change the reserve life compared to how you have it now?

I don't think it will change it a heck a lot because basically what you're doing is if you look at how the 1.5 billion barrels have been taken out to date, the wells -- still when it came on, as is the case with a lot of fields that are producing a primary recovery and this one had basically a solution gas driving as its primary mechanism. So it came on with a quite high flush rate so we would anticipate the same type of flush rate as we pushed forward with CO2.

Then as we get into the project you are left with lower rates but longer life. So I don't see it impacting the ROI of the project that much.

One short last question. When do you expect the pipeline to be onstream and contributing?

We are hoping that -- as I said, we're hoping towards the latter part of 2008. We would be putting CO2 into the ground.

Ryan Schaefer, Sprott Securities.

Bill, can you give us a sense of the timing for the CapEx on Pembina? The 250 to 350 million, that you said units you might spend in phase 1? What the timeframe of that would be?

2007 and 2008. And I wouldn't (ph) think probably after 60% in 2007 and the rest in '08.

(OPERATOR INSTRUCTIONS). Bruce Wescott from Williams Jones.

Other Pembina holders of acreage include Exxon, etc. Is there a right of first refusal for you on any asset sales out of the Pembina field? And would you contemplate taking that down?

I won't answer the question specifically other than to say that, yes, we have the right of first refusal on a lot of the assets that are held by others in the area.

In terms of the economics you are seeing out of what you are studying with what you have now, if you were to move forward with a purchase there, is that a debt or equity finance situation?

Yes. I think if you look at where we expect bank debt to be at the end of the year. I talked about, roughly, 550 to 600 million in bank debt at the end of the year. Our line right now is over $1 billion so that leaves us with a fair amount of flexibility.

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

I would just like to wrap it up by thanking everyone that was online today and also listening to the webcast today or in the future. As we said earlier if you have any questions either on the Web, there is the ability to direct a question by e-mail or pick up the phone and give me a call or one of our staff and we will try our best to answer you. Thank you.

Ladies and gentlemen, this concludes the conference call for today.