Obsidian Energy Ltd (OBE) 2006 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Penn West Energy Trust second-quarter results conference call. At this time, all participants are in 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 Tuesday, August 15th of 2006.

At this time, I would like to turn the conference over to the President and Chief Executive Officer of Penn West Energy Trust, William Andrew. Please go ahead.

Good morning and welcome, everyone, to the Penn West Energy Trust teleconference and webcast. As introduced, my name is Bill Andrew, and I'm the President of the Penn West Energy Trust. With me in Calgary this morning are Dave Middleton, who is our Chief Operating Officer; Thane Jensen, our Senior Vice President of Exploration and Development; Todd Takeyasu, our Chief Financial Officer; and William Tang Kong, our Senior Vice President of Corporate Development. We have other key members of our management team and also some of our investor relations staff in the room with us this morning.

Before we start, I would like to express my sincere condolences on behalf of Penn West to the family, friends and associates of Audrey Clark, who was part of our Port Saint John operations team. Audrey recently lost her battle with cancer and passed from this life. Our thoughts are with her loved ones.

Since we last talked, since I last talked to many of you, we have completed the conversion of Penn West Energy Trust into -- Petrofund Energy Trust units into Penn West Energy Trust units and have made a special distribution to Petrofund Energy Trust unitholders as per our plant arrangement. On June 22nd, 2006, we listed Penn West Energy Trust on the New York Stock Exchange to broaden and to strengthen our investor base.

Immediately following court approval of the plan of arrangement, we physically integrated our combined house and field staff. We have also integrated our systems and are moving forward now as one entity. The effort of all our staff in working to accomplish the smooth integration is very much appreciated.

As a result of the merger, we have promoted Todd Takeyasu to Chief Financial Officer and William Tang Kong to Senior Vice President of Corporate Development, in recognition of their continuing contribution to the success of our Company. Additionally, we have added three new directors, Jim Allard, Jeff Errico and Frank Potter, to our board.

I know there were some concerns from Petrofund's Energy Trust unitholders on the speed of the conversion and the allocation of the special distribution. I would like to thank you for your patience and for your understanding through this process, and I went through with some of you -- and I know our investor relations group did as well, attempted to assist you with the conversion and any questions that you had about the conversion of the special distribution.

We do, of course, appreciate any and all questions and feedback from our unitholders. If you have a question, please do not hesitate to contact us at our Internet address, which is www.PennWest.com, or by telephone or by letter or by facsimile. We trade on the New York Stock Exchange under the symbol PWE, and on the Toronto stock exchange under the symbol PWT.UN.

The purpose of this conference call is to review our 2006 second-quarter results and to provide an update on recent activities of Penn West Energy Trust. Following this review, we'll open the line for questions.

Since the plan of arrangement to merge Petrofund Energy Trust and Penn West Energy Trust became effective after the end of the quarter, the second-quarter numbers do not include any production, revenue or reserves from Petrofund. Our balance sheet and our forward projections show the inclusion of Petrofund in what we include as the debt and production and revenue after the merger date.

During this conference call, we will use Canadian dollars unless otherwise stated in a 6 to 1 ratio for conversion of gas to barrels of oil equivalent. Results for the second quarter of 2006 also represent Penn West Energy Trust's first full year as a reporting entity, and we're pleased to announce that.

For comparative purposes, we will be using the second quarter of 2005 as a benchmark for this quarter. The quarters are not directly comparable, as Penn West was operating as an exploration and production company in the second quarter in 2005, prior to us converting to a trust mid 2005.

In the second quarter of 2006, our daily production averaged 93,242 barrels of oil equivalent per day; that's a 7% decrease from the second quarter of 2005. Average daily production consisted of 29,974 barrels per day of light oil and natural gas liquids, 18,625 barrels per day of conventional heavy oil and 268 million cubic feet per day of natural gas.

Average production for the quarter was inside our target production range. However, it was on the lower end of projections.

Early in the quarter, due to weaker than anticipated gas prices and resulting lower miscible hydrocarbon costs, we opted to accelerate our new miscible plus pattern at South Swan Hills, and we accelerated that some six months earlier than planned.

We believe that the long-term benefit resulting from aggressive expansion of our enhanced recovery project at South enhanced recovery project itself Swan Hills at South Swan Hills is worth the minor short-term production shortfall that we are currently facing.

Additionally, we experienced delays constructing facilities at Seal to accommodate oil from our new wells into the Peace River oil sands play. We estimate that the net negative impact result on our second quarter was approximately 2000 barrels of oil equivalent per day.

Currently, our production is averaging approximately 133,000 barrels of oil equivalent per day, and that includes approximately 70,500 barrels of oil and natural gas liquids, and 375 million cubic feet per day of natural gas. We have a balanced average daily production that consists of 53% oil and liquids and 47% natural gas. We expect that our ratio will shift slightly more towards oil as we ramp up Seal production and bring on our second and third quarter oil development projects through the rest of the year.

On an overall basis during the second quarter, we drilled a total of 27 net wells in all areas, resulting in 21 oil wells and five net gas wells. Currently, our conventional drilling is focused on oil development in southwestern Saskatchewan and in southeastern Alberta. Many of the details you can get on our website of where we are drilling.

In the second quarter of 2006, natural gas prices averaged $6.14 per Mcf. That was down 17% from the second quarter of 2005.

Light oil and natural gas liquids prices averaged $71.96 per barrel; that's a 22% increase over the second quarter of 2005. Conventional heavy oil prices were $52.85 per barrel. That's an increase of 69% compared with the second quarter of 2005. Overall commodity prices for the second quarter of 2006 averaged $51.33 per barrel of oil equivalent; that's up 10% from $46.66 per barrel in the second quarter of 2005.

Gross revenues for the quarter were $452.5 million; that's an increase of 7% over the $424.2 million in revenue realized in the second quarter of 2005.

Cash flow was $264.7 million in the second quarter. That's up 3% from the second quarter of 2005. Cash flow per unit was $1.56 diluted in the second quarter of 2006, and that's up 5% over the second quarter of 2005.

Net income for the second quarter of 2006 totaled $220.5 million; that's an increase of 269% from the second quarter of 2005. I should emphasize that a portion of the net income improvement included future income tax recoveries due to changes in income tax provisions with the federal government and also with the provincial governments of Alberta and Saskatchewan. Net income per unit was $1.31 diluted in the second quarter of 2006.

Operating costs for the second quarter averaged $10.26 per barrel of oil equivalent. This represents a 15% increase over operating costs in the second quarter of 2005. Part of this increase is directly attributable to the quarter-over-quarter production rates. As our production rate comes off a little bit, we still maintain some fixed costs; so there's pressure on the cost per unit. We are also experiencing cost pressures associated with a continued very robust industry activity in western Canada.

Over 60% of the trust liquids production consists of light oil and natural gas that command a premium price and are produced from pools that have a long reserve life. As such, the trust is well positioned to absorb industry-wide operating cost escalation and still maintain very strong operating net backs.

Our net backs for the second quarter of 2006 were $33.38 per barrel of oil equivalent; that's up 15% from the second quarter of 2005.

On an individual commodity basis, our net backs averaged $43.56 per barrel of light oil and natural gas liquids, $32.86 per barrel of heavy oil and $4.46 per Mcf of natural gas. We note during the second quarter 2006 the heavy oil differentials continued to narrow as we moved into peak summer asphalt season and continued to experience strong demand for heavy feedstock.

Capital expenditures for the quarter were $105.8 million. That compares almost exactly with at the second quarter of 2005; we spent about $100 million in that quarter.

Capital spending in the quarter represented approximately 40% of our cash flow. This is very much in line with our capital budget forecast.

Cash distributions in the second quarter of 2006 totaled $167.4 million. That accounted for approximately 63% of cash flow. Our current distribution is $0.34 Canadian per unit per month, payable on the 15th of the month following the calculation of the distribution. So if you -- you will receive July's distribution in and around today, which is about the 15th of August.

Our capital program for the second quarter of 2006 was funded almost exclusively by internally generated cash flow. The merger with Petrofund and the assumption of their debt increased our total debt at the end of the second quarter to $1.37 billion. Based on our forecast cash flow -- and this is a pro forma cash flow for 2006 -- this debt level is well inside our long-term comfort zone.

Penn West also has an active hedging program to increase the assurance of future cash flow to fund distributions and capital program expenditures while providing some downside protection. Currently in 2006, we're behind on our oil hedges, but we're well ahead on our natural gas hedges. In total, to date, we have seen a gain from our hedge position. However, that position will come more into balance as our natural gas hedges unwind in the third and fourth quarter and as we continue to have quite robust oil prices.

For information detailing our hedging program, you can go to our website, again, www.PennWest.com.

Our estimate on capital efficiency as a trust over the first two quarters of 2006 was approximately $28,000 per barrel per day of production added. So we feel we're doing quite well by that measure.

Going forward, we are continuing to concentrate on field optimization and development projects that deliver capital efficiency that will drive the trust forward. We're continuing in our efforts to monetize our extensive land base through farmout sales and joint ventures. We continue to see strong interest in our lands, and we plan to extend this process until as much as the surplus acreage as possible is monetized through farmouts or dispositions.

In addition to non-core property rationalization and conventional exploration and development activities, we are continuing to work outside the box. Our strategy to acquire light oil pools and enhance production and recoverable reserves was bolstered through the merger with Petrofund. As a result of the merger, Penn West Energy Trust acquired interest in two major Canadian CO2 enhanced recovery projects at Midale and Weyburn, and Saskatchewan, as well as additional working interests in the Pembina area.

In the second quarter, we began developing two new CO2 flood patterns in our [Jothrie] project and initiated injection on the new pattern at South Swan Hills. We're moving forward aggressively with plans for CO2 capture and transmission to provide feedstock for future enhanced recovery projects at several of our large light oil pools in central Alberta, the most notable of which is the largest light oil pool in Canada, the Pembina Cardium.

Work at the Pembina CO2 pilot project has been ongoing, as is work to finalize rooting for a CO2 line that will connect our capture facility with the Pembina and Swan Hills area.

We should also note that we're following with great interest the efforts of others to utilize CO2 for enhanced recovering in areas where we have interests, including Red Water and certain nonoperated Pembina properties. We remain very confident in the financial viability of this technology and on the positive impact of utilizing Green Hills gas to increase production from and extend the economic life of light oil reservoirs.

As mentioned earlier, the acquisition of Petrofund led to a renewal in our pursuit of coalbed methane in western Canada. During the third quarter, we are drilling our first horizontal CVM well at Swan Hills and are continuing to develop a CVM potential of the Three Hills area of Alberta. From an exploration perspective, we're pursuing CVM plays, notably south of Calgary, in the [Harrington] area and also in eastern Alberta.

It's fairly natural for investors to point to current gas prices and question the decision to work on CVM. However, we believe it's very prudent to keep a balanced portfolio of projects, including a number that are based on what we call outside-the-box making.

We're actively exploring and developing our Peace River oil sands block, focusing on our Seal Oil Sands development project at Seal Main, as well as their Phase 2 and 3 exploratory blocks at Seal Cadotte and Seal North.

During the quarter, and very early in the quarter, actually, primarily in first quarter, we completed our winter horizontal program. However, we did experience some fairly severe delays in getting the production on. As we talked about in the last conference call, we're moving towards central Bantry with outlying satellites and piping everything in. And we just didn't execute properly enough in the quarter, and as a result, we had approximately 2000 to 3000 barrels per day of new oil production behind pipe at the end of the quarter. We're working like everything to get everything on, and we're working towards our production target of 4000 to 5000 barrels per day by year end.

The information gathered from our new drills at Seal North and Cadotte combined with information from previously drilled lands lead us to calculate there's an ultimate surprise of some 7 billion barrels of oil in place underlying our lands in Peace River. I'll note that the lands we're talking about are only the ones that have sufficient well control, where we can map them. This map area will cover approximately 40% to 50% of our total oil sands lease in the Peace River block, and we're going to be working on exploration on a lot of the unexplored block over the next few years.

We believe from what we have seen so far that the project will be very extensive, both in size and in scope. We're very encouraged by the results to date. We're actively working to develop the area, but we're taking into account the social and ecological concerns of the stakeholders, including the First Nations and the need to develop the area using sound planning, that takes into account not only the present but also the future.

Our outlook for 2006 is very positive. The merger with Petrofund will drive production for the second half of 2006 to average forecast somewhere between 131 and 135,000 barrels of oil equivalent per day. Based on projected product prices of $72 U.S. per barrel of oil, WTI, and $8 Canadian per 1000 cubic feet of gas, we forecast cash flow for the second half of 2006 to be between $800 million and $900 million from the merged entity.

Based on this forecast and on actual results for Penn West Energy Trust to date, we forecast cash flow for 2006 of between $1.3 billion and $1.4 billion. On an annualized cash flow basis, pro forma, the cash flow would have been in excess of $1.6 billion.

In the second quarter, we physically merged the office and field staff of Penn West and Petrofund. As many of you may have heard, the labor market in western Canada, particularly in Alberta, is very competitive. But the good news is that we're seeing an influx of skilled and unskilled workers to the West. These workers are helping to ease the shortfall by filling vacancy and also using the pressure that is currently imposed on our workforce.

Recognizing that we're working with a reduced staff count after the merger, I would like to take this opportunity to thank our staff for their efforts and their focus in keeping Penn West on an even keel through the merger and the integration.

In closing, it seems that a fair amount of time in these conference calls is spent on the numbers, which we admit are very critical to gauging the financial success of any company. I wanted to devote some time to areas that receive less attention but are equally important to our Company and to its long-term viability and vitality. At Penn West Energy Trust, we place a premium on increasing our employees' and contractors' training and awareness on workplace health and safety, working in concert with industry stakeholders to minimize social and ecological impacts from our activities and on reducing future environmental liability. We believe that focusing current capital and effort on proper planning, maintenance, site restoration and an aggressive workplace safety program will minimize not only current impacts but also future impacts on the health of our staff, on the health and well-being of the communities that surround our projects and on the ecology in general.

In the second quarter of 2006, Penn West Energy Trust received the Work Safe Alberta 2005 Best Safety Performer award. This award is given to less than 3% of the companies that operate in Alberta. And this award and others that Penn West has received for safety and environmental stewardship demonstrate the commitment of our staff and the management and our directors to our focus on safety and the environment.

I would like to (technical difficulty) and we would be pleased to answer any questions that you may have.

(OPERATOR INSTRUCTIONS). William Lacey with FirstEnergy.

Just a couple of quick questions. You talked about your capital efficiency sitting around $28,000. Obviously, you had a bunch of interruptions in the second quarter, plant turnarounds, what have you. What do you think sort of going forward your run rate is going to be around?

I think that's where it will be. I think rather than letting it flux all over the place, we're looking at what we added, where our production should be and what that number will be. So that, in the long run, we're targeting to be in the $25,000 to $30,000 per barrel range.

And the decline sitting behind that? Where are those sitting these days?

We're running about 17% right now.

As far as production is concerned, I don't know if I heard you correctly or not. But in the second half, I think you said 131,000 to 135,000 BOE's a day. As far as exit rates are concerned, obviously that [much of heavy] is going to be tied into second half of the year. Should we be looking for something around 135,000?

You should, and that would depend on how fast we can get our Seal oil tied in, in the third and fourth quarter wells that we're drilling, plus some of our other projects. I think, to give you a range, we would look somewhere toward 135,000, but I have to give you a range between 134,000 and 135,000, on exit.

As far as Seal, you have obviously framed out a pretty huge resource potential up there with 6, 7 billion barrels. What is the longer-term development plans for Seal? I know you've outlined 20,000 barrels within another five years, six years. But what sort of larger scale investments do you foresee to have to do that level of production?

Basically, when we talk about the move to 20,000 barrels a day, that is coming primarily from our Seal Main property, which would encompass about a township of land, so about 36 sections of land, as well as some development on Seal Cadotte, which lies to northwest of our Seal Main project. That leaves Seal North as an area which we just started developing. It leaves a tremendous amount of land in between those projects and also a very significant amount of land, primarily to the north and to the east of the Seal project.

It's interesting; that area we got into and started getting very aggressive on land acquisition about a year and a half ago, and continued through the latter part of last year and early this year. Certainly, the team was adamant that we pursue that, from a geological point of view. We're seeing, certainly, in recent land sales, we're seeing very increased activity in that area, very high bids. So that is lending some credence to what we feel is the potential of the area.

So basically, the 20,000 is coming from land that have got pretty good drilling into them right now. We expect that there will be more added to that as we develop Seal North, as we develop some of the unexplored land at Seal. Then still the big question is, how much is there to the northeast of Seal, and our large block there? When we talk about production and estimates, we're talking about primary production. So, as people know, with Seal we're seeing API gravity in the order -- from 10.5 to about 11.5 degrees API. We're seeing viscosity that is sufficiently decent that we're able to pump the wells using a aggressive cavity pump and lift the oil to surface. So we're talking only primary production. We have set up a lot of our wells for tertiary production or for enhanced recovery through steam injection. So a lot of them won't have to be redrilled. The trade-off is that you lose a little bit on initial production. You gain because you don't have to redrill wells.

So we're pretty excited about the area. We're going to move towards this winter and into next year, we're going to look at what impact it would have on the reservoir to inject some steam into it. As you know, there has been work done to the north by Shell, but we like to do our own work and just see where we sit on enhanced recovery as far as what we would ultimately get out of the area. It's not without the realm of possibility to take a number like 20,000 and put a pretty good multiple on it.

What are the IP rates that you're seeing on the most recent drills up at Seal?

I'll give you the range in Seal. The peak production that we have seen in the area from all wells, including competitor wells, would be between 150 and 200 barrels per day. Those would be essentially in wells that are completed without liners, so just open hole completions. We're seeing, on our wells, rates between 50 and about 120 barrels per day. Our feeling is that if we were to drill the wells without liners and allow them to produce open hole, that we would see rates that are about 50% higher than that.

Just going over to Pembina quickly, can you give a little bit more color as to sort of the current field response on CO2, what you're seeing?

Sure. I think anybody that has followed Pembina will know that it's a very extensive resource. The zone itself, well very extensive, has fairly low permeability. In other words, the ability of oil to move through the rock is hampered a little bit; it doesn't -- it's not quite like water going through a hose. We expected that when we started our CO2 push, in March of last year, we expected that our leadtime to get a good response would be somewhere between 18 and 24 months. So we're not quite at that point. The good news, and it's very good news, is the fact that we've got excellent containment on CO2.

We have got wells that have gone from no oil production to a point where they are producing oil and they are increasing in oil production. We have increased the injection of CO2. One of the concerns we had was how much CO2 could the reservoir rock take without pressuring up the facilities and equipment that's used to get the CO2 into the rock. So we have been able to up the rates by 25% without -- with very minimal impact on our surface pressure and on our well pressure.

So the forecast that we have -- and forecasts are not worth a heck of a lot until you get actual results. But we're following basically where we forecast with them. So the only caution I would use there is that we're looking at an 18 to 24-month period.

But I'll tell you what, if we were at a point in this where we are now some 14 or 15 months into the injection, we would not be going through the trouble of doing line routing, getting surveying done, spacing, getting our planning done to get a pipeline plant in place and in front of people within the next month or so. We wouldn't be doing that if we didn't see good results.

Jonathan Fleming, Sprott Securities.

With respect to your recently completed assessment of the Seal play, can you comment on the recovery factors you expect, both under conventional and/or potentially waterflood or thermal methods?

We're using varied recoveries, somewhere between about 3% to 5% on primary. Thermal -- I think, to be conservative, we were talking somewhere around 20%. I've seen other numbers that use a figure of 40% to 50%.

Can you give us any kind of guidance on the operating costs that you expect at Seal as well as current operating costs at Seal?

Current operating costs at Seal are terrible because we're having to pump everything into a tank and truck it all around the countryside to try and get it processed.

Once we get all of our lines finally finished and hooked into our satellites and main battery, we're expecting that operating costs will be in the $7 to $8 range. That's very comparable to the operating costs that we're seeing in Eastern Alberta and southwestern Saskatchewan on heavy oil.

Kurt Wulff, McDep Associates.

Thank you for that update on Seal; it's a story that is getting better. My questions probably may be a little too far ahead. Have you been giving any thought yet to what your strategy might be for upgrading the heavy oil and realizing the most value out of it eventually?

Yes, we have, in fact. We've been talking to a number of firms, and we've been talking a little bit to some of our neighbors.

Shell, for example?

I think, in the near term, we would probably point more towards the pipeline capacity out of the area, so that if we can get increased amount of pipeline capacity that will connect us into sort of the backbone of the light oil system, I think those that know Alberta know that there is fairly extensive light oil pipelines going up through the Swan Hills area and West in towards Valley View and Sturgeon Lake and then also north up towards Red Water and Nisku and Nipisi and some of those fields. So I think to the extent that we can get the heavy crude out, move it into the light system where we can do some blending and then move it on into the refineries, I think that will be the first thing that we look at and we are looking at.

Secondly, I think it's very possible that you're going to see upgraders built in the area, particularly when you look at the amount of competition that we have right now in one particular area of Alberta, in Fort McMurray, for labor, it makes long-term sense that we would spread some of that activity around a little bit and perhaps look at an upgrader in the Peace River area.

Thanks.

(OPERATOR INSTRUCTIONS). Roger Serin, TD Newcrest.

You farmed out a fair amount of land, but your number of wells drilled in the second quarter year over year are basically flat. I'm wondering if we can expect to see an increase in the number of wells drilled on a farmout basis going forward and when that might kick in?

I think we'll see a real impact of that through the winter. I think primarily one of the large farmouts we did that involved over 100,000 acres was in northern Alberta. The company that farmed in on it is Apache. They just started their work last winter and their plan is to get much more aggressive this year with it.

As well, we did a fairly extensive farmout in the Pembina area on the Nisku Play. That is -- they are finally getting to the point, the operators there, where they finished their consultation with the public and they are working on getting the wells drilled. So we expect to see some start there.

The other ones are just basically plugging along, and we expect that there will be good activity through the rest of the year on them.

In terms of any production volumes, then, it's probably fair to say it's really Q2 of '07 before much happens?

Yes. I think, as I've tried to explain or talk to people when we have been out on the road with some of our shareholders, unitholders, basically, the way we looked at it was we looked at what we have on developed land in Penn West. If we take almost an equivalent amount of land to our developed land and put it out to industry and put it out to a variety of companies, then they explore it fairly aggressively. With success, that would lead to development and then to more intensive development. If you look at that process, sort of like starting an oil company up from the time you have got an idea to the time where you are really rolling and are doing your development work, you are usually looking at a couple-three years. So we expected that it would be a little bit of lag, but we also expect that once we get fully functional with activity on our farmout lands that we would start to see a fairly decent revenue stream coming from our overrides.

I've got one other question on your credit facilities. You have got a temporary line and your existing line. You are obviously renegotiating a combined facility. Would it be fair to expect the combination of those is about what you would expect to get from a revised facility?

It would be, ballpark, that area, something like 1.9, in that range, we think, is a good size for us at this point. Indications to date are that that will not be any problem of any sort for us to put in place. (multiple speakers) take out the bridge.

The syndicate we're putting together right now is about somewhere $1.9 billion to $2 billion.

Brian Ector with Scotia Capital.

Just wondering, with the Petrofund merger now behind you, if you have any anticipated divestitures or property rationalization and potentially the magnitude or timing of that?

We do, and William is sitting right beside me, William Tang Kong. I think, as many of you know, William has been leading the effort on divestiture of our land, and he will lead the effort on acquisition and divestiture in the Company. We're looking at a couple of ideas. One is probably one or two smaller packages where we would test the waters. Those would be fairly quick timing. And we would look at a more limited distribution in Calgary, to see if there's any interest. Based on the success of that -- and we think it would be successful -- we would probably follow with a little bit larger package.

The divestiture is not really a case of having to pay down debt at all. We're very comfortable with our debt position, but it's just -- there is an opportunity in Calgary right now to wiggle our assets around a little bit, because what we're potentially looking at is maybe divesting some of our more exploratory assets in the north and taking the money and then procuring some assets in southern and central Alberta, that are more attuned to the long-term life of the trust.

So basically we're not talking about drastically reducing the size of the trust; we are more talking about trying to get to the right assets in the Company.

(OPERATOR INSTRUCTIONS). Roger Serin.

Does that exit rate include, then, potential dispositions?

No, because, as I say, anything that we would plan for this year would be small. We've got a couple of small acquisitions that we're working on as well. So no; we're looking at it outside of any acquisition or dispositions. We don't forecast any significant impact.

James [Stevenson] from The Canada Press.

Yes, Bill, when you mentioned potentially seeing an upgrader up in the Peace area, is that just thinking of your competitors? Or is that something that you are actively looking at?

I'm thinking about the whole picture up there, and certainly, the -- we have got some very aggressive competitors in the area who have made a statement recently with their purchase of assets. I expect between us and some of the other competitors in the area and Shell that there would be a move as we start to develop the oil stands up there, that there would be a move to reduce cost. Part of the way to reduce cost is to invest in facilities to upgrade the heavy crude. So I would say it's a little better than a thought, but it certainly not a -- there's not a plan of action right now.

Calimborn Kinard, who is a Private Investor.

I was just going to, do you foresee any changes to payouts to individual investors over the next six to nine months?

We continue to look at our distribution, as I said. I talk about, in the conference earlier, we spent about 40% of our cash flow in the second quarter. We paid out just a little bit over 60%. That was the number when we had converted the trust last year, we talked about roughly a 60% payout ratio. So I would say, at this particular moment in time, that we're pretty content with the distribution that we have. However, I will caution that on both sides. One is that our distribution is based on commodity prices. So, as commodity prices increase and decrease, there's some pressure on our distribution either to move it upwards or to move it downwards. If we did get into a period where we had lower than current commodity prices, I think our initial look at it would be to maintain distribution for some time and see where the commodity prices were headed.

Same thing, if we get into -- let's say, as we go towards winter, that gas prices strengthen and oil prices stay where they are, then we're going to be in a situation where our revenue increases, our cash flow increases. And the last thing we want to do in the trust is become taxable within the operating company. So I think it's very possible that a couple of the alternatives that you would have would be, one, to look at increase in distribution. Second would be to look at a special distribution.

So we're watching it all the time. We do a calculation on a monthly basis. We have a pretty good meeting of the minds about where our distribution should be on a monthly basis, and we try to make the best guess that we can on our forecasting and see where our cash flow is going to be. That's a roundabout answer, but it's the best I can do.

Thank you. And management, at this time, we have no additional questions in the queue, and I will turn the presentation over to you for any closing remarks.

I would just like to thank everybody, and I would like to just reemphasize the appreciation that we have for the unitholders, particularly the unitholders of Petrofund and their patience in the conversion. It was a bit of a long process, but having to go through that many unitholders, get the units converted from Petrofund to Penn West and then getting the special distribution, particularly in the case of a lot of our U.S. investors and getting it converted to U.S. funds and out and into the accounts -- I thought we did the best we could. We could probably do it better, and next time, we will. But I do appreciate your patience, and I thank you for listening in this morning.

Ladies and gentlemen, at this time, we will conclude today's teleconference presentation. We thank you for your participation on the program. At this time, you may now disconnect, and please have a pleasant day.