Ovintiv Inc. (OVV) Q2 2008 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to EnCana Corporation's Second Quarter 2008 Financial and Operating Results Conference Call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without express consent of EnCana Corporation. I'd like to turn the conference over to Paul Gagne, Vice President of Investor Relations EnCana. Please go ahead, Mr. Gagne.

Thank you, operator and welcome, everyone, to our discussion of EnCana's second quarter 2008 results. Before we get started, I must refer you to the advisory on forward-looking statements contained in the news release, as well as the advisory on page 1 of EnCana's annual information form dated February 22, 2008. The latter of which is available on SEDAR. I would like to draw your attention, in particular, to the material factors and assumptions in those advisories. In addition, I want to remind everyone that EnCana reports its results in US dollars and operating results according to US protocols, which means that production volumes and reserve amounts are reported on an after-royalties basis. Accordingly any reference to dollars, reserves or production information in this call will be in US dollars and US protocols unless otherwise noted. Randy Eresman will start off with highlights of our gas assets then turn the call over to Brian Ferguson, EnCana's CFO and IOCo's CEO designate to discuss the highlights of our integrated oil and shallow gas assets, as well as EnCana's financial performance. Following some closing comments from Randy, our leadership team will then be available for questions. I will now turn the call over to Randy Eresman, President and CEO.

Thank you, Paul and thank you everyone, for joining us today. In today's call, we will highlight our performance in the second quarter of '08. We are now more than halfway through the year and we are very pleased with our results to date and the course that we have mapped out for the remainder of the year. As you saw in our reported results today, we have begun the transition to create two separate high-performance companies. Brian Ferguson will comment on the changes to our segmented reporting shortly, but let's begin by talking about some of the natural gas highlights from the quarter. Total natural gas production was up 10% over the same quarter of 2007, once again driven by a 17% increase in our key resource play production. Based on the strong results to date and outlook for the remainder of the year, we have updated full year natural gas guidance to 3.85 billion cubic feet per day, an increase of 8% over full year 2007 gas production. Additionally we've made upward revisions for the production guidance for several of our key gas resource plays which have been exceeding our original expectations for the year. Our strongest area of growth in the quarter was East Texas. Despite achieving year-over-year growth of almost 130%, the expected ramp up of production is behind schedule. As such we reduced the full-year guidance for the play to 370 million cubic feet per day. Well results have been strong, and in line with our initial production expectations, however, we drilled fewer high-impact wells in the first half of the year's program than expected. We fully expect this situation to improve as we move forward through the remainder of the year. The Deep Bossier continues to be a leading near-term driver of EnCana's future production growth. Despite the delay in East Texas we are well ahead in our overall gas production, as I mentioned earlier. This should clearly illustrate the depth and strength of EnCana's unconventional assets portfolio with leading positions in many of the highest performance gas plays throughout the continent. As we've discussed previously we have assembled leading positions in three of North Americas most exciting new natural gas resource plays. Horn River and Montney in British Columbia and the Haynesville shale play in Louisiana. In the Horn River basin, EnCana has finished drilling the final four wells of its 2008 program. I'm very pleased to report that the test results from the first two of these wells averaged in excess of 5 million cubic feet per day during the first months of production. For the remainder of the year, we, along with our partner Apache plan to complete the remaining two EnCana wells, finish construction of the Culme [ph] road that provides access to our leases and begin planning for a significant increase in development activity in 2009. To the south of the Horn River, our established Montney play continues to excel. EnCana was an early mover in the Montney and was able to capture more than 500,000 acres of land at average price that's substantially lower than those being paid more recently. We're about halfway through our 2008 program and the average performance of the wells growth year-to-date has exceeded our expectations. We are currently producing more than 140 million cubic feet per day from about 70 horizontal wells. The strong production is supported by infrastructure additions such as the Steeprock expansion, which will be coming online very shortly. We continue to make progress on operational efficiencies as well. We can now complete eight fracs along the horizontal leg in four days. Now, just one year ago we were averaging only four fracs in about 20 days. Its learning's like these that add great value when we apply them across our entire unconventional gas portfolio. In the Haynesville shale play we acquired additional acreage in the quarter, bringing our position to 370,000 net acres, complimented by an additional 89,000 gross acres of mineral rights. Together with our partner, we have two rigs running in the play. Initial production from our second horizontal well averaged approximately 15 million cubic feet per day during an early two-day test. This exceeded expectations for the well. The Haynesville Shale is a very exciting emerging play with a potential to rival the quality and scope of the Barnett shale play. Capital spending was in line with expectations at the end of the second quarter, and total capital guidance remains unchanged for the year, however, given our recent shale land purchases, we have ... we expect increased activity in both our acquisitions and divesture programs for the full year. On a net basis our guidance for the year is unchanged with net proceeds estimated at about $500 million. With respect to inflation, our longer term planning has minimized our exposure to increases so far this year, but we do expect more of an impact may be felt going forward. Significant cost shifts in the second quarter impacted steel and fuels in particular with general upward pressure on many other commodities and services. Key input cost for steel such as scrap and iron ore are up between 65 and 75% in the first half of the year while fuel costs have increased approximately 50% the cost of our operations in the same period. We are starting to see increases in labor costs and tighter inventories for supplies and services. We've been mitigating some of these effects through early commitments for materials and longer-term agreements for services. We've been able to [inaudible] for very much of the impact during the first half of 2008 and do not at time see a need to revise our full year cost guidance for the year. I will now turn the call over to Brian Ferguson, our Chief Financial Officer, who will discuss our integrated oil highlights, as well as our overall financial performance.

Thanks, Randy. Good morning, everyone. I will start with a few comments on the operating performance of what will be the integrated oil company. Overall, on a year-to-date basis, we are running about 5% ahead of budget on gas production and we are right on track with liquids production. Referring to note 5 of our financial statements, you will see that our operating cash flow, both in the quarter and year-to-date is up about 20% over last year. We are achieving strong operational and financial performance. Now, on to our key resource plays for the integrated oil company. Weyburn and Pelican Lake oil volumes are tracking in line with or slightly ahead of guidance estimates for the year. At our in-situ oil operations, year-to-date oil production is slightly behind expectation, primarily due to the combined effect of an unexpected first quarter external power outage, when we had minus 40 weather, and an extended second quarter plant turn around at Foster Creek. We have been adding additional water handling equipment to improve performance at that plant. We have lowered combined Foster Creek and Christina Lake full year guidance by about 3,000 barrels per day as a result to 31,000 barrels per day net to EnCana. The expansion projects at Foster Creek and Christina Lake are proceeding on time and on budget. Foster Creek Phases 1D and 1E, which were expected to about double facility capacity to 120,000 barrels per day are more than 90% complete. We expect large increases in production as we start ramping up Phase 1D in the fourth quarter of 2008, and Phase 1E in the first quarter of 2009. We're targeting to take our 2008 exit rate, which we expect to be in the range of about 64,000 barrels per day on a gross basis, up to about 90,000 barrels per day by year-end 2009. At Christina Lake, we are steaming new wells that are Phase 1B expansion and expect to see increases in production through the remainder of 2008. Construction of Phase 1C is under way and we're working with our partner to approve Phase 1D, which in aggregate are expected to bring facility capacity to nearly 100,000 barrels per day by 2012. Christina Lake gross volumes are expected to ramp-up to exit the year at about 14,000 barrels per day. Moving to pricing now. Benchmark crudes, WTI and Western Canadian Select, were up about 90% and 120% respectively over the same quarter last year. Western Canadian Select heavy blend averaged more than $100 per barrel in the second quarter. This is unchartered territory for our industry and it helped generate some outstanding results for upstream oil business. On the downstream refining side of our business, market crack spreads were significantly lower in the second quarter compared to the same quarter 2007, but still strong compared to the five-year averages. At the Borger refinery, we realized relatively strong refining margins in large part due to the installation of a new Coker last year. At Wood River, we are proceeding with engineering and procurement on our Coker and refinery expansion, which is expected to add a 130,000 barrels per day of heavy oil processing capacity to that facility. Air permit delays are expected to impact the start of site construction for the project, and resulting in a delay of ... in the range of four to nine months from original plan. Our partner ConocoPhillips is working with regulators to resolve outstanding issues and we plan to provide details on timing and cost of this project when that air permit is grants. Our Canadian planes gas volumes averaged 856 million cubic feet per day in the quarter, which as I mentioned earlier, slightly ahead of budget. Overall, very solid performance for the new intergreated oil company. Before I discuss our financial performance, I'd like to draw your attention to some of the changes we've instituted in our financial reporting and disclosure for the quarter. In the MD&A, segmented notes and supplemental information, we've provided separate results for each of the four operating divisions: Canadian Foothills, Canadian Plains, Integrated Oil and USA. This change will hopefully help the investment community in your transition to the evaluation of the proposed reorganization of EnCana, along existing divisional lines which is expected to be complete in early 2009. We are expecting to provide additional disclosure in our information circular in mid-November. Now, on to EnCana's financial results. Cash flow was strong driven by higher netbacks after hedging and increased production. EnCana achieved cash flow per share on a diluted basis of $3.85, up 16% compared to the same quarter in 2007 and well ahead of street consensus. Our cash flow performance is exceeding expectation and as a result, we have increased our full year cash flow per share guidance to a range of $13.30 to $14.65 per share. At the midpoint, this is 26% higher than last year. Our cash flow performance was accompanied by strong operating earnings of $1.96 per share on a diluted basis, the year-over-year increase of 9%, which was also well ahead of street consensus. The increase in operating earnings reflects higher production volumes, and increased netbacks after hedging, which are partially offset by higher DD&A. Our net earnings for the quarter of $1.2 billion were down about 14% on a per share basis. Net earnings are subject to the same factors impacting operating earnings, but net earnings were also affected by an unrealized after-tax mark-to-market loss of $235 million in the quarter on our hedging program. Looking specifically at our costs in the quarter, combining operating and admin costs, came in at about $1.70 per thousand cubic feet equivalent and above our full year guidance estimate of $1.40. About $0.35 of that in the quarter is due to long-term incentive costs directly related to the increase in our share price during the second quarter, which closed June 30 at about $93 a share. We do not expect the impact to be material on the full year basis and do not plan to revise our full year operating and admin costs guidance at this time. The run up of the Canadian dollar relative to the US dollar continues to impact our results. Segment quarter average exchange rates were 9% higher than the same period last year. We have a natural hedge, however, against increases in the Canadian dollar, as we have about two-thirds of our long-term debt denominated in US dollars. Our balance sheet remains strong. Net debt-to-adjusted EBITDA finished quarter at 1.3 times. Net debt-to-cap at June 30 was about 36%, which includes the non-cash unrealized mark-to-market loss as I mentioned earlier. If you adjust for that, our net debt-to-cap comes down to about 34%. As mentioned previously, we expect to reduce net debt levels prior to year end and expect that our net debt-to-cap and net debt-to-adjusted EBITDA will be at the low end of our managed ranges. Overall, strong financial results. I will now turn the call back to Randy.

Thank you, Brian. Our results for the second quarter of 2008 and in fact our results for the past two years have been very positive. As we transition towards the tradition of two strong, independent companies, it will be business as usual and we expect that this consistent and strong performance to continue. The transition process is moving forward as planned, while the next milestones will be the mail out of the information circular to shareholders. We expect this to happen in mid-November with a shareholder vote on the transaction to follow in mid-December. We continue to demonstrate what we believe to be industry-leading performance and the development of unconventional natural gas and in situ oil. We move with the strengths sustainability and profitability of our process [ph] and these businesses will be better recognized by both industry and investors when they are able to operate as separate and focused businesses. Thank you for joining us today. Our team is now ready to take your questions. Question and Answer

[Operator Instructions]. We will now begin the question-and-answer session and go the first caller. Your first question comes from Martin Molyneaux, First Energy Capital Corp. Please go ahead.

Gentlemen, you have now come up with a new guidance for cash flow of 10 billion to 11 billion, substantially ahead of where we opened up this year. CapEx sits at about seven, so with the announcement of the split into the two companies, you guys suspended the normal course issuer bid. The stock is down $0.20 a share or so from the announcements. Would it now make sense to resume the normal course issuer bid process now?

Thanks for the question, Martin. Certainly, things are performing very well at EnCana right now. One of our biggest quirks right now is to position the company for the best possible start for the creation of the two new entities as they emerge. We're also looking at a number of other opportunities within the company, share buyback is certainly something that would appear to be very attractive at this point in time. At the same time, we are looking at the possible of acquiring additional lands in certain number of key resource plays. So we are trying to kind of looking at all of those possibilities. But the fact is that there has been a significant change in commodity prices in the last little while and we have to see how that plays out before we are too active in any one of those areas.

Fair enough. Thank you.

Thanks.

Thank you. Your next question comes from Brian Singer, Goldman Sachs. Please go ahead.

Thank you. Good morning.

Hi, Brian.

A couple of questions. First on the Haynesville, I know it's only been a few weeks here since your analyst meeting, but do you have any update on where the first Haynesville well you drilled is currently producing. Any thoughts on the decline rate profile relative to, I guess, normal unconventional gas-type of clients.

Thanks, Brian, let me turn that over to Jeff Wojahn.

Hi, Brian, it's Jeff. I haven't to be honest we looked at it, recently. We do expect that the profile… our best assumption right now is that the profile would be similar to the Barnett Shale profile. Until we get a longer history on these things, we don't know. But the well is hanging in there pretty well from what I heard from the team and I think once we get through the budget process, we will have more time on the very few limited data points that we have and we'll have a better understanding at that point.

Thanks. And secondly, there is certainly lot of volatility in natural gas prices. I was wondering, maybe both for Randy and for Brian, how one should think about Canadian capital spending and natural gas drilling in both a bullish gas environment for 2009, versus a more cautious gas environment for 2009?

I guess we are talking about 2009, we are talking about the integrated oil company, versus GasCo spending profiles. On the GasCO side, the expectation is that we will try to have a steadier program as possible with an expectation that we will increase activity in both the Montney and the Horn River Shale plays. And these plays will be, you know, robust under a very wide range of pricing. So, it's unlikely that any change in commodity price is going to materially impact what we do in those plays. And like I have said in the past, we are best served and we can do long-term planning and have steady growth in our programs and that's the way we can become most efficient and the best use of our capital. And Brian?

Yes, Brian, we are actually just starting looking at our 2009 budgets for both of the two companies. And as Randy mentioned, we've certainly learned the lessons of the past of steady pace and giving some added flexibility. Both companies and particularly in the plains variable cost and attractive F&Ds. So, whether we have high prices or low prices, I would expect our pace of drilling to not vary dramatically one way or another.

Great. Thank you.

Thank you. Your next question comes from Gil Yang, Citi Investment Research. Please go ahead.

Hi, Randy, you mentioned that the Bossier was a little bit behind schedule because of fewer high impact wells. Is that a scheduling issue or was that the wells did not perform as well as you had expected?

Yes. Its really just a… to some degree, it's still statistical. So, it's just a matter of fact that haven't did as many of the higher performance wells. We have looked at having sort of an average performance over the period and the statistics would suggest that we were a little bit behind on having the big ones. No performance issues that we detected at all in the play. We have had some development… some timing issues with respect to all of the facilities, but Jeff can tell you about that.

Yes, Gil, it's Jeff Wojahn. The biggest issue we have is forecasting of these early life resource plays and the Deep Bossier is probably the most difficult one, simply because we are not drilling that many wells. We are planning to have about 40 wells a year, nine a quarter and, this last quarter we didn't, as Randy said, hit any of the big wells. So, that caused us to be behind our mean case, but certainly well within the range of expectations. I can tell you next month, we've got three more wells that we are bringing on and, our expectation is that we're going to be bringing on about $100 million a day of gross productivity from those three wells. So, it's just a world-class asset and we expect outstanding performance from it. But, we can't kind of forecast well-to-well or quarter-to-quarter that well.

So, Jeff the three ones you are bringing on with the $100 million a day productivity, you have tested those, so you know what they are going to be producing at?

That's our expectations. We haven't tested them yet. We have good…, we have a well logs in good understanding of the settings. We are continuing to be bullish on our forecast and our team is confident that, through time, that our one bcf a day target for East Texas will be met.

Okay. The second question is, Randy, you were mentioning earlier that Montney and Horn River would not be… are very robust would not be affected by commodity price movements too much. Are there any regions where you would be more prone to pulling back activity first if commodity prices fell and to what level would gas prices be falling before you started to considering pulling back in those areas?

Most of our… well, our long-term price expectation has been around $8… $8.50 for the last couple of years and that's basically what we built our entire program on. And when we see the prices, long-term prices, our expectation dropping below that, then we'll reduce activity in some of our higher marginal cost plays. Consistent with what we have done in the past, they tend to be certain regions of the Piceance Basin that are higher costs and certain regions of the Northeastern British Columbia, Greater Sierra, those are the areas that we went to in the past to slow down activity. But the vast majority of our plays have pretty low supply costs. I think our overall portfolio something like $4.75 is the price that we require to get our cost to capital. So, you will have to fall back pretty far. And this is not… we don't react just the near term pullback. It's our fundamental… our belief in the fundamental change in natural gas prices that drive our activity.

Okay. And finally, for the new cash flow forecast, what is the outlook, the budgeted gas price, oil prices to get to that cash flow?

Well, we gave you a pretty wide range between $10 and $11 billion. The assumption is contained in the guidance document that give you the range on which we base that.

Okay. All right. Thank you.

Thanks.

Thank you. Your next question comes from Mark Friesen, TD Newcrest. Please go ahead.

Thank you. Good morning. A couple of questions to you, Brian. First of all, wearing your CFO hat, could you stratify the mark-to-market adjustments between the adjustment for the mark-to-market for the basis hedging and then the mark-to-market for the rest of the natural gas positions?

Yeah. Mark actually I don't have that level of detail handy here. We typically don't get into that level of detail largely for competitive reasons in terms of identifying specifically the basis hedge program.

Okay. Fair to say, though, that they serve to offset each other somewhat?

Yeah.

Okay. Second question for you, Brian. Wearing your new CEO hat, just directionally, what's your longer term view for both, refinery crack spreads and also for like, heavy differentials?

Well, I guess that's perhaps the preferred ... proverbial $130 question. Definitely, one of the things that I think we are ... we're certainly in a view that compared to, say, the last five years, you are going to be in a stronger crack spread market. One of the big things that's going to be very impactful for us is heading up the wood river refinery. And we saw very strong refinery margins coming out of Borger where we added additional coking capacity last year, and we certainly expect to see a material increase in the realized crack at Wood River, as we ... as we bring the new cokers on there as well. So I think my overall observation would be that certainly in our case, we expect to do better than average for the refining business because of that, and then with regard to products as well, one of the big advantages, in terms of the Wood River expansion, in our specific instance, is that we are not going to be producing any more asphalt. So, again, our percentage of premium product yield and diesel and that goes up.

Okay. And how about your light/heavy outlook?

Yeah, that's ... we were continuing to model that along historical lines which has been running around at 30%.

Do you still think of it on a percentage basis, given with the volatility of oil prices?

That's a real good question. I can ... I should probably ask you what you are thinking, Mark.

I tend to think of it more on a dollar-per-barrel basis. All right, thanks for your views, frankly.

Okay.

Thank you. Your next question comes from Mark Gilman of Benchmark. Please go ahead.

Good morning, guys. The first question, and, Jeff, I hate to belabor this but with respect to the Deep Bossier, I still don't understand, whether the reduction in the outlook is associated with maybe longer drilling times or alternately the fact that just some high-impact wells weren't scheduled in the quarter. Could you try one more time to clarify that?

Sure, Mark. We ... in the last year, we drilled three of the top five biggest initial productivity wells over a five-year period in North America in this field. So you have to put things in context. And we had ... we believe, well, there's probably some more out there and statistically, I still believe that. And so, within our mean expected case, we forecasted we would hit a couple more like the wells that we drilled last year. And we didn't hit any of those types of wells in the second quarter, and hence our averages on an IT basis and EUR basis went down. So operationally we have been performing quite well. In regards to the scheduling, actually the drill times and the completing of the wells and, we target drilling three wells and completing three wells a month. And we have been by and large on schedule. We have some minor facility issues, as Randy had mentioned. But it ... there is a wide deviation, standard deviation around the mean because of the range in the well productivities ranging from a couple million a day to $65 million a day. And so if you don't drill that $65 million a day well, it moves your quarterly results.

So we are not really scheduling high-impact wells, it's that every once in a while we get one?

And those move the averages around and how we forecast.

Okay, thanks. Let me try another one if I could. Randy, I believe you suggest that ... in your comments that the Haynesville ultimately would look comparable to the Barnett. I wonder if you could elaborate on that in terms of what specific parameters you were referencing, EURs, ITs, recovery rates. Could you just go a little bit further on that comparison in terms of what you were alluding to?

Okay. Well, with the few number of wells that were drilled in the Haynesville so far, we've seen, and some of our competitors or industry competitors, have seen initial production rates which are in the order of twice that of the ... some of the best wells ever drilled in the Barnett Shale play. So that's one indicator. In terms of ultimate recovery or gas in place, the play is deeper. It is higher pressured because of its depth, but it's also more over pressured which allows a lot more gas to be packed in. It's quite thick. And so we have initial gas in place on the play. I think in order ... on an average, Jeff ... maybe twice as much as the ... compared to the Barnett.

On a perception basis, yes.

On a perception basis. So you have got that. The ultimate recovery, that will be something we don't know yet and it will be a long time before that's determined. But given those no initial parameters ... those initial performance indicators, it's suggested that this play can significantly exceed the potential of the Barnett Shale play. Now, all that comes at a cost and the question is, are we going to be able to get the cost down into a range that makes the whole thing as economically attractive as the Barnett Shale play is? And with the early results, we again, think that that's a realistic expectation.

Okay. Just two more, if I could. Randy, you alluded to the fact that the divestiture program would be stepped up, essentially, to offset the incremental cost of the additional acreage that's being acquired. Give us any thoughts as to where you might be targeting for those additional divestments?

There's going to be a lot of mature and miscellaneous properties across our entire portfolio, both Canadian and U.S. based and likely also include some midstream type assets as well. There are ... we do have some very attractive large mature properties in Alberta, that may be on the block.

Okay, and if I could just one more. The shallow gas drilling in the quarter was at a comparatively low level, which all things being equal, I guess would suggest a pretty good step down in the third quarter volumes, unless there is a lot behind the pipe. Can you comment on that observation?

Yes, we are going to have Don Swystun tell us about that program.

Yes. Hi there, Mark. It's not that far off from what we normally do in the second quarter. It's always generally wet and we break ... we break up at that time. So it's a real difficult number to pick as to how many holes you are actually going drill in that in Q2. So I thought we did fairly well this year, compared to ... in fact, ahead of what we budgeted. So we weren't unhappy with that. And then, we do have actually a fairly strong program going to the third and fourth quarter and particularly we are looking at maybe even adding a few more wells in the fourth quarter, if things go well. Yes, there's still ... obviously we carry an inventory behind pipe for additional production and that should be coming on. You will see a bit of that. But we are, in fact, drilling less wells this year as well, total.

Thanks very much.

Thank you.

Thank you. Your next question comes from Andrew Potter, UBS.

Hi guys, just a couple of questions on the Haynesville. Just wondering what the likelihood is we'll see a ramp up in your drilling activity from the planned I guess five rigs running by this year end.

All right, Jeff will answer that again.

Hi, Andrew. We'll probably stick with our target of five rigs exiting the year. There's some logistical issues going on, but given our encouraging results that we mentioned on our last horizontal, you know, obviously we're going to ... we're going to ramp it up. And another consideration that we have is not only evaluating the play and seeing how it fits within our portfolio, but also to manage our land base and make sure that we meet our obligations to our leaseholders. So that will in the short term drive ... drive our rig count, but as far as next year, clearly we are going to be bringing our rig count above, our exit target of five. To what extent, you know that's going to be a discussion that we will have with our part of the shale. But I think it's fair to say that we are going to be planning on a more aggressive program, not only for an stratographic point of view in evaluating the reservoir but also from a commercial point of view.

Great. So we have seen some of your competitors with similar size land bases talking about 10, 15 rigs. I mean, is it possible that you would kind of end up in that range through the year?

I think it's possible, but again we haven't gone through the budget process. So, until we do that, it's premature. But, hopefully in the upcoming quarter we will be able to nail that number down a little closer.

Right and somewhat related, I guess in terms of capital allocation for '09. What is the range of outcomes in terms of capital we could see for between Horn River and Haynesville I could see the merge in plays. Is it a $1 billion of spending in '09 or is it a couple of billion dollars of spending and I guess if it is in that type of magnitude, is it all incremental or would you start think about kind of shifting away from CBM or some of these other programs to put to work towards Horn River and Haynesville?

Yes. We are considering all of those things. It is a little bit premature.

Yeah, okay. Thanks.

Thank you. Your next question comes from Richard Tullis, Capital One Southcoast.

Thank you. Couple of more questions, if I may on the Haynesville. What parish is the second horizontal well located in?

This is Jeff Wojahn. It's in Red River parish and the name is the Bowleen [ph] 1H well.

Could you ... are you able to give the cost on the first two horizontals?

You know, I don't think they are representative of the long term. They are exploratory wells, which we have done a lot of science on. They are clearly not commercial cost ranges, as what we think. I think we have a longer term contract or concept of depending on the depth and the pressures of the plays ... has different cost structures, but on long-term average, $7 to $8 million range which is in line with some of the other operator estimates for commercial well.

Okay. And how long of a lateral would that be, generally?

Well, that's an interesting comment. You know, with the two wells that we have done, like I mentioned before we've the two horizontals that we have completed, we're doing some very pragmatic things. We are trying to figure out what the optimal evaluation methodology is to see how the reservoir will perform, rather than focus on optimizing the commercial plan. But, I think the base case for all of this work is to look at a Barnett well, horizontal which are typically 2,500 to 3,500 feet with 8 to 12 stages of fracs with half a million gallons per stage and water and sand concentration. So, that's where the industry is going to start and we'll optimize around, those kind of numbers.

Okay. Of the 370,000 net acres, approximately how much is located in East Texas?

The majority of that land is in Louisiana.

Okay.

Focused around Red River parish.

Okay. And now finally, if you can, are you able to talk at all about your thoughts on how far out the play extends, particularly the core?

Given that we have been attending land auctions, I think it's premature for us to comment on the extent of the play. But probably as we move through the budget, in the upcoming quarter or two, we will have more details around them, you know where we feel the plays is going.

Okay, well thank you. That's been very helpful.

Thank you.

Thank you. Your next question comes from Mark Gilman, Benchmark. Please go ahead.

Randy, I know obviously you've got a lot of things going on but I was just wondering whether you've gotten any further along in terms of the ability to give us some idea of the impact of the '09 Alberta royalty changes?

What I will do is I'm going to turn that over to Mike Graham, and Don Swystun and John Brannan to comment on how they impact those areas. Mike?

Yeah, Mike Graham here with Canadian Foothills Division. You know, we are looking at the Alberta royalty, especially around the deep basin. Obviously, the government increased the royalty a lot based on productivity. So the better wells that you're going pay royalties right up to, sort of, 50%, and some of the good wells and it's based on price. It's based on volume as well, and then depth as well. So it's quite complicated to figure it out. But needless to say, it does hurt some of the activity in sort of the shallower part of the deep basin. We do get some relief in the deeper part of the deep basin. But we're still looking at it, and we have slowed down a little bit in 2008 in the Deep Basin in Alberta and probably not going to see a big ramp-up in 2009.

This is Don Swystun from the Plains. In the shallow gas area, there wasn't much change. In fact in some cases it's actually better from the Crown royalty perspective. But, of course, we have a huge percentage of fee lands in southern Alberta, so it doesn't impact us all that much. We do have some higher royalties going to be experienced at Pelican Lake because it falls under the standard of oilsands royalty. So that will obviously be a function of the oil prices at any one point in time in terms of how that's calculated.

And this is John Brannan. On the heavy oil assets that we have in the Integrated Oil Company, the pre-payout right now on projects is 1%. And starting January 1st, that will go on a sliding scale, again as Don said on the price of oil. Cap sized at 9% as a $120 WTI. So that would be a significant change on the royalty impact. Also long-term, after payout, it also on a sliding scale and it currently goes from, say, a capital 20%, up to the new cap will be up to 40%.

Okay, guys, thanks. Just one other one for Brian, if I could, please. The release refers to the FICO inventory impact on the results of the refining partnership. Have you been reporting on that ... I mean, that methodology since inception? Or was that something you changed to at the first of the year?

It's something that we have been following since inception in 2007. It's the difference between Canadian GAAP and US GAAP. It was more impactful in the second quarter of this year, because of the dramatic run up of prices in the quarter.

Okay. Thanks, Brian.

Thank you.

Thank you. [Operator Instructions]. Your next question comes from David Bentley, AllNovaScotia.com.

Yes. Hello. I wonder if I could ask two or three questions Atlantic Canada are focused. First of all in view of your comments on inflation, I am wondering if you could tell us if you're still expecting to bring deep [inaudible] ... on budget?

All right. Gerry Protti will talk to that.

Hi, David.

Hi, Gerry.

We're impacted like other projects are by the value of the Canadian dollar, but our expectation is still to bring the project in on budget at a cost of about $760 million capital.

Right. And we were originally sort of working here 700, I thought, Gerry. Is that my sense of that, or perhaps ...

Yeah ... and that reflects the impact of the higher exchange rate.

Yes. Yes. Okay. The extra 60 on that would be the exchange rate?

That's correct.

Yes. Okay. Good. Just wondering about the scheduling. I have been hearing that the supply industry is busy and wondering if you still expecting to be able to produce gas when you forecast in late 2010.

Yes, There's no question that everyone is busy, but our expectation is we can still bring the project in just over two year's time towards the end of 2010. We note that some of the critical long lead items are coming in nicely. We've got the pipe being deliver to Shaw and Shaw & Shaw first shipment arrived There's two more coming this year. So we are happy with the progress.

Great. Just finally, I don't know whether you can say anything about this. But we've been hearing a little bit here about unconventional gas exploration opportunities. Now, I was wondering is there any possibility that you guys have been watching this or it could at all be interested at all?

We are certainly aware that there are those who said that there might be some potential there but our focus, David, is completely on project. And we don't have any plans for either offshore or onshore activity in Nova Scotia at this time.

Great. Thanks very much, Gerry.

Thank you, David.

Thank you. [Operator Instructions]. Your next question comes from Ian McKinnon, Bloomberg News. Please go ahead.

Hi, there, my questions are for Brian. Just most of them are minor clarifications. In terms of the delay on the refinery product, you said four to nine months from the original date. Can you give me what the original date was and what we are looking at now?

Well, ... yeah John

July 1st…

We had originally anticipated starting July 1 of this year.

So now we are looking anywhere from October to next April, some where in there?

Correct.

Okay. The other question is on stock compensation, you said about $0.35 a share. Is that correct?

Yes.

And you had somewhat 53 million shares outstanding. So I get that out to a 264 million. Is that before or after tax?

Before tax.

So after tax would be what, two-thirds of that or 60%?

It's a little ... there's not a real straight forward answer to that because a portion of it is capitalized and a portion of those ...

Okay. Then hold on ... pose more simply on a net basis, how much did the stock-based compensation reduce earnings?

The actual amount was 35 after tax.

Just 35 million?

Yes. You got to remember, this is one of those theoretical calculations.

Yeah, I understand.

Mark-to market. Great.

Okay. Great. Thanks.

Thanks.

Thank you. [Operator Instructions]. There are no further questions at this time. I would like to turn the conference back to Randy Eresman. Please go ahead.

Well, thank you, everyone, for joining us today for reviewing EnCana's second quarter results. Our conference call is now concluded.

Ladies and gentlemen, this does conclude the conference call for today. You may now disconnect your line and have a great day.