Ovintiv Inc. (OVV) Q1 2008 Earnings Report, Transcript and Summary

Good day ladies and gentlemen, and thank you for standing by. Welcome to EnCana Corporation's First 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]. Members of the investment community will have the opportunity to ask questions first. At the conclusion of that session, members of the media may then ask questions. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of EnCana Corporation. If anyone has any difficulties hearing the conference, please press star-zero for operator assistance. I would now like to turn the conference call over to Mr. Paul Gagne, Vice President of Investor Relations, EnCana. Please go ahead, sir.

Thank you, Operator, and welcome everyone, to our discussion of EnCana's first 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 also 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 financial results in U.S dollars and operating results according to U.S protocols, which means that production volumes and reserve amounts are reported on an after-royalties basis. Accordingly, any references to dollars, reserves or production information in this call will be in U.S dollars and U.S protocols, unless otherwise noted. Randy Eresman will start off with an overview of our results, and then turn the call over to Mike Graham, Executive Vice-President and President, Canadian Foothills Division, to provide further highlights of some of our Canadian key gas resource plays. Brian Ferguson, Executive Vice-President and Chief Financial Officer, will then discuss our 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. Today's call will highlight our performance in the first quarter of 2008, and I think you'll agree that we are off to a great start. We are just over three months into the year and we’re on our way to meeting or potentially exceeding many of our guidance measures. Natural gas and oil production were both up year-over-year driven by our growth of our key resource plays. Our current gas production of about 3.8 billion cubic feet per day is ahead of our full year guidance and our outlook for the remainder of the year is very promising. Cash flow and operating earnings in the quarter were better than expected fueled primarily by our production growth and also by strong commodity prices. With cash flow exceeding expectations and in line capitalwith guidance, we’re likely to generate more free cash flow than we budgeted for. Now, it’s free cash flow that can be redirected toward a combination of debt repayments and additional share purchases under our Normal Course Issuer Bid. Days outstanding results continue to illustrate the strength of our asset portfolio and our disciplined approach to its development. Our performance during the quarter provides yet another data point for the track record of our sustainable low-risk resource play strategy. We are now the largest producer of natural gas in North America. And we've assembled a very strong portfolio of unconventional assets with leading positions in many of the highest performance gas plays throughout the continent. Although all of our key resource plays have performed well, East Texas demonstrated exceptional year-over-year growth of 165%. This reflects the doubling of our Deep Bossier ownership position at Amoruso late last year to 100%, and the exceptional performance of the wells that we've drilled so far. The average 30-day initial production rates of the five Deep Bossier wells brought on stream in the first quarter exceeded 25 million cubic feet per day, with one well reaching rates as high as 60 million cubic feet per day. Overall, our performance is meeting or exceeding our expectations and provides further support, I believe for the long-term potential of this play. We focus our reporting and discussions on our established key resource plays, but we also have a number of emerging opportunities which add further depth to our established portfolio. Shale Gas is a very hot topic in North America, and I am proud to say that we have a significant presence in several emerging Shale Gas plays throughout the continent. In the U.S alone we have more than 1 million net acres in this play type. We have been actively evaluating the potential for the last two years and expect to drill several wells on number of these plays throughout the year. Mike Graham will discuss early-life Canadian shale play, the Devonian Age Shale at Horn River Northeast British Columbia in a few moments. On the other side of the portfolio we've designated the Weyburn oil field in Saskatchewan as a key resource play. Weyburn is one of the most visited and studied oil fields in North America and has caught the attention of the world as a great example of a business and technology driven projects that improves oil recovery while permanently storing carbon dioxide, a greenhouse gas. In our integrated oil business, we are upstream in-situ SAGD projects at Foster Creek and Christina Lake, as well as our downstream projects at Wood River and Bodger continue to move forward as planned. This business venture between ConocoPhillips and EnCana has reduced the risk associated with heavy oil price differentials and a commitment of capital for the development of our upstream assets. The end results we believe is the lowest costs, highest return in-situ SAGD projects in the industry. I would now like to turn the call over to Mike Graham, our Executive Vice-President and President of Canadian Foothills Division to comment on the performance of some of our Canadian gas assets.

Thanks, Randy, good morning, everyone. As you saw in our release this morning, performance of our Canadian gas resource plays was solid in the quarter. Growth from our BC and Alberta resource plays were strong including 34% from Bighorn, 19% from coalbed methane, and 17% from Cutbank Ridge. This growth has offset the natural decline from our Shallow Gas and conventional Canadian properties to hold our Canadian gas production flat over the first quarter of last year. While we did experience some freeze off in Alberta and British Columbia associated with the extremely cold weather in January and February of this year, the impact will not be material to our 2008 guidance. Our current natural gas production is strong for both the Canadian Foothills and the company as a whole. And we are confident that we will meet our full year guidance for natural gas production. Looking at British Columbia, activity remained strong. At our Cutbank Ridge play in the Northeast part of the province, we continued to be pleased with the overall results. More specifically, our teams are very excited by the results of our Montney wells, now producing more than 120 million cubic feet per day. Our land holdings include about 240,000 net acres over the core of this play and around 550,000 net acres in total making EnCana by far the largest landholder on this prolific gas play. We have drilled 13 horizontal wells in the Montney formation in the first quarter of 2008, averaging 1,600 meters in the horizontal length we've completed 8 to 10 fracs per well giving us a initial production rate of between 5 and 10 million cubic feet per day. In 2008, we plan to drill more than 50 wells targeting in this formation. We believe that our assets at Cutbank Ridge have a potential to grow to between 0.5 and 1 billion cubic feet per day in the next five to 10 years. Another exciting high potential play in the Canadian Foothills division is the Horn River shale play. Granted this play is in the early stages of development, but, it is a large virtually untapped natural gas resource, which is generating a lot of industry excitement. Our land position of more than 216,000 net acres, which we began acquiring as early as 2003, covers what we believe to be the thickest, most prospective part of the shale. We are partnered with Apache on most of our land in this play and as of the end of the first quarter, we have drilled nine wells and have five wells on production. The three wells drilled in the first part of this year have tested at very good rates. These wells are now tied in and are on permanent production. We are encouraged by what we have seen so far, and expect to be able to provide additional information on the commercial potential of this play in the upcoming month. Again, it is still in the early stages and significant investments in development and infrastructure will be needed to move this play forward, but so far so god. With respect to services in the first quarter, costs were relatively flat in North America with some pressure created by price increases to steel, fuel, and fabricated equipments. There is some evidence of cost increases related to these items for the second quarter in the balance of 2008. But, we are working to mitigate these effects through early commitments for materials and longer term agreements for services. Our inflation outlook for the year remains at zero in Canada, upto 5% in the U.S, and between 5% to 10% in integrated oil. Now, earlier this month, the Alberta government made an announcement to address some of the unintended consequences of changes to the royalty regime in the province. While we will not be making any changes to our 2008 plans, as a result of the government's announcements, these changes are expected to make the Alberta deep basin more competitive within EnCana's portfolio. We are working with the Alberta Department of Energy to clarify the changes and continue to analyze the effect that these changes could have on EnCana's programs beyond 2008. Overall, the Canadian Foothills division is on track to meet guidance provided for 2008. We are excited by the potential that we see from the emerging plays in our portfolio, and are pleased with the performance of all of our key resource plays. I will now turn the call over to Brian Ferguson, our Chief Financial Officer who will discuss our financial results in more detail.

Thanks, Mike. Good morning, everyone. EnCana had an excellent quarter. From a corporate perspective you saw us double our dividend $0.40 per share for the quarter. We purchased 4.6 million shares at an average price of $66.80. And we also established a dividend reinvestment program for our common shares. Cash flow was very strong, driven by our increased gas and liquids production and higher commodity price. EnCana achieved cash flow of $2.4 billion or $3.17 per share diluted. That's up 41% compared to the same quarter in 2007. This puts us in a great position to meet our guidance for the year. In terms of operating cash flow, our integrated oil assets continued to deliver strong results. On a combined upstream and downstream basis, our integrated oil business generated operating cash flow of $170 million in the quarter. This is an increase of 6% over the last year and a reflection of a strong performance of the upstream part of the business, so far in 2008. Despite reduced margins in the refining business, we are on track to achieve our full year guidance of $900 million from our integrated oil business. Our cash flow performance was accompanied by strong operating earnings of about $1 billion in the quarter or $1.39 per share diluted, a year-over-year increase of 28%. As with cash flow this increase reflects higher production and increased commodity pricing, plus their impact and operating earnings was partially offset by increases in DD&A and long-term incentive. Now let's look specifically at our costs in the first quarter. This is a good news, bad new story. Combined, our operating and administrative costs came in at the $1.53 per thousand cubic feet, which is slightly above our guidance estimate for the full year. The good news is that the reason that this is up is because $0.30 of the $1.53 is driven by the increase in our share price as we basically accrue and expense our long-term incentive costs each quarter. If we exclude the impact related to the increase in our share price, we would be below our full year guidance. The run up of the Canadian dollar relative to the U.S dollar in 2007 during the first quarter continues to impact our results. Year-over-year we have seen 17% increase in average exchange rate. For the year, we budgeted the Canadian dollar to be at parity, this is expected and has held true during the first quarter. We have a natural hedge against the increase from the Canadian dollars, we've got about two-thirds of our long-term debt denominated in U.S dollars. With respect to hedging commodity prices, in the early part of 2008, as we all know gas prices strengthened due to a colder-than-average winter in the northern hemisphere, which is continuing in Calgary today as we see. We currently have about 40% of our expected gas production hedged at $8.04 per 1000 cubic feet. It is important to note that current gas prices greatly exceed our 2008 guidance estimate of 750 NYMEX. For each $1 increase in NYMEX, including the impact of hedges, we add about the $375 million after-tax to our cash flow. That equates to an additional free cash flow of about $1 billion for just the rising gas prices at today's strip. Free cash flow that can be allocated to the debt repayment or additional share purchases as Randy indicated. Our balance sheet remains strong. Net debt-to-EBITDA finished the quarter at 1.3 times. Net debt-to-cap at March 31st was 38% which is up about 3% from the... end of 2007. This was due essentially completely to the unrealized mark-to-market losses on the risk management instrument. We expect that both of these ratios will be at the lower-end of our managed range by the end of the year. Following a strong first quarter, we are on track for another great year financially. I will turn the call back to Randy.

Thank you very much Brian. Our results in the first quarter of 2008 and in fact our results for the past several quarters have been very positive. As Brian said, with one quarter of results behind us, it is pretty clear that the year is off to a great start. This consistent and strong performance is a credit to our strategy and to our teams operating across entire EnCana. We continue to demonstrate what we believe to be industry leading performance and the development of unconventional natural gas and in-situ oil recovery. We believe the strengths, sustainability and profitability of our approach to these businesses is becoming clear and better recognized by both industry and investors. We remain focused on a sustainable phase of long-term production growth, capital discipline, and the return of excess cash to shareholders through an ongoing program of share purchases and potential dividend increases. We are comfortable with our pace of developments and the resulting production growth, and flexibility that it provides in allocating capital. Our spending in production growth plans are consistent with our strategy of executing with excellence and generating sustainable growth. Thank you for joining us today. And our teams are now ready to take your questions. Question And Answer

Thank you. [Operator Instructions]. We will now begin question-and-answer session and go to the first caller. Our first question will be from Brian Singer of Goldman Sachs.

Thank you. Good morning.

Hi, Brian.

When you look at the combination of the natural gas strip with the improved results you are seeing in the Montney, Amoruso fields particular, how do you think about the value proposition in buying back stock and increasing dividend with free cash flow versus increasing activity levels. Is there a scenario where you would increase your activity levels and budgeted 2008 as opposed to just looking ahead to 2009?

Well Brian, we've answered this question, I guess the same over and over again. We think we’ve found the right balance in the combination of the sustainable growth strategy, and the use of share buybacks rather than chasing production goals. And we kind of feel that any incremental cash we’d be generating this year in excess of our expectations, we will be targeting some of that for additional share buyback this year, partially reducing debt. But it's a long time before the year is going to be complete and at this point we are still uncertain. As we plan for next year, we will think about the size of the program that we feel that we can undertake comfortably and we will target that pace of growth. We will reallocate capital across our portfolio where we believe the best returns are. So, it may be that the Amoruso property gets more of an allocation over the Montney. We are just at very early stages of doing that today.

Would you need a people reallocation as well or if you want to just allocate capital to drill more wells in some of these regions, it really is just a capital decision?

I think we are... we have got a pretty stable base of personnel and although we do move them to some degree where the activity levels are the highest. I wouldn't say that would be a substantial part of our plan.

Sorry I keep asking the questions, but I know that every time I think asked this gas prices are about $1 or $2 higher that last time. My last question is with regards to the BC shale, the Horn River play, you mentioned the road that you built and just general infrastructure-related issues, can you elaborate on that and the over what period of time do you think we will start to see more... actual real meaningful growth in production based on some of the infrastructure concerns that have been expressed there?

Yes Bryan, Mike Graham here with Canadian Foothills Division. We did extend what we call, it’s actually, we call it the proper road [ph] up in the Northeast DC and we've put it right into the heart of the Horn River like it ran to the Devonian Age Shale. So we can conduct activity year round there and to-date, we drilled three, Apache actually operated those wells and you have seen the results from those, they have been on for about three weeks now, and are currently producing in the order of 3 to 5 million cubic feet a day per well. We are going to drill another four wells that EnCana operates. We have drilled actually about three of those right now and we should have some results in the second quarter. So it does look very promising. There is a tremendous amount of natural gas in the basin. It is a pervasive gas system throughout. So after this year, obviously we are going to see the results of these next four wells but we are very encouraged by what we are seeing to-date and like Randy said, we will look at capital allocation for next year. But we can start to ramp this play up hopefully very soon after we see the results in 2008.

What do you think you could actually... what you think is the reasonable number of wells you could drill per year based on seasonal infrastructure-related issues?

Well Bryan probably anywhere in the order of 50 to 100 wells per year, similar to what we are doing in the Montney or in in the deep basin in Alberta, somewhere in that order.

Thank you.

Thanks Bryan.

Thank you. Our next question will now come from Brian Dutton of Credit Suisse. Please go ahead.

Yes good morning. Randy your wellhead price realizations in the U.S seem to be particularly strong. Just wondering if you could comment on the drivers behind that and what should we be expecting on a go-forward basis?

Okay, we’re going to have Bill Oliver take a crack at that one. Bill Oliver - Executive Vice-President, Business Development & President, Midstream & Marketing Division: Good morning Brian. A couple of reasons; we have a higher than NYMEX price in the U.S and that was we did under accrue in the fourth quarter of '07. So you saw some bookings there in the first quarter. The other thing that we do, we do sell some de-gas into the market which gives the marketing people some flexibility and as you expect in a rising market, we did better than indexed in the first quarter. And thirdly, obviously, the Rockies bases has tightened in with Rockies Express coming on, and we do have more gas now being sold in the Deep Bossier and the Houston ship channel which is quite favorable, in terms of basis as well. So adding all those things up it did result in a very good net back for the company in the first quarter.

If you could, I guess back out the under accrual from the fourth quarter, and say some of the de-gas trading, could you give us what might be a normalized price differential you might expect on a go-forward basis relative to NYMEX?

Yes, we’ll have... it will be, I think, generally weighted to the indexes depending on our basis hedges. Otherwise you should just assume we are going to be subject to indexes... index prices that we sell at. But as I say, our prices will be getting higher with more volumes coming out of our East Texas play.

Okay, thanks a lot.

Thank you. And our next question will now come from Ross Payne of Wachovia. Please go ahead.

Hey guys good quarter. How big is the share repurchase program currently?

Our current program, we are targeting 1% to 3%, and I think we did just about 0.5% in the first quarter.

Okay. Also if you could talk about your view on heavy oil differentials, what you see for the remainder of the year?

I will turn it over to John Brannan. John Brannan - Executive Vice-President & President, Integrated Oil Division: Yes currently the heavy oil differentials have been very strong in favor of the upstream side of it. But we expect those in long term to range somewhere around 30%.

Okay and last, can you opine a little bit more on the Weyburn play and anything you see from a P&L standpoint related to a CO2 sequestration? Don T. Swystun - Executive Vice-President & President, Canadian Plains Division: Yes I will take that, Don Swystun from the Plains Division. Yes I think we are going to be looking at about in the range of 13,000, 14,000 barrels a day net to EnCana. We are going to additional carbon-di-oxide patent roll outs, about 8 more patents being developed in this year. We are also looking to add some additional recycle compressor there, as well on a go-forward basis and we still have considerable number of additional patents to develop. I think we are about half way developing Weyburn to this point. So there is considerable more sequestration on a go-forward basis. We put only about 10 million tons of CO2 to this point and potentially, we could go to at least 30 million tons with full development out there. And of course with financial recovery, the benefit is the win-win, where we can get approximately almost up to 50% recovery there.

Where is the CO2 coming from? Don T. Swystun - Executive Vice-President & President, Canadian Plains Division: It comes from North Dakota. Dakota Gasification Company.

Okay. Great that's it from me guys. Thanks.

Okay thanks Ross.

Thank you. Our next question will now come from Mark Gilman of Benchmark. Please go ahead.

Hi guys, good morning. I would like to follow up if I could, just on the Weyburn question. Can we quote any numbers in terms of the incremental resource potential at the Weyburn. I guess I am a little confused as to whether it's being designated as a resource play just on sequestration or whether there is further upside than what I previously thought was a mature project?

It is in fact a mature project. Obviously we have been developing Weyburn for decades, through water-fluid program initially now through CO2 injection. What we look for on a go-forward basis with more carbon dioxide injection and patent development. I think even though it's material we think we can keep production steady, to slightly increasing from the 14,000 barrels a day we are right now for still another quite a few number of years on a go-forward basis.

We are high on the recovery rate right now.

Coming in above the 40% range.

Okay Randy I believe, in your opening comments and also on the release, you made reference to acreage positions and promising exploratory results, in other North American shale plays. I know you talked about the Horn River, were there any other plays that you were specifically talking about? Can you put any particular numbers in terms of acreage positions on such other plays?

I am going to have Jeff Wojahn, responsible for our USA Division, provide a little bit more insight. But we are in a lot of these plays still building acreage positions. So we are trying not to be too specific on results in those areas. There are other areas which you can comment on, where we have largely captured the plays, and really just working through the technical details now. But as I mentioned, we have in the U.S alone about a million net acres in shale plays. So it's a very substantial position. Over to you, Jeff. Jeff Wojahn - Executive Vice-President & President, USA Region: Good morning Mark. You know I can comment a little bit on some of the plays which we have talked about in the past. In the U.S, it is very much a year of evaluation for gas shales and I’ll go down the list, and some of these place you may be already aware of. In the Piceance Basin, we believe the Niabrara has potential over about 400,000 acre area. This is a zone that we have done some vertical testing on, but we are now going to proceed to drilling some horizontals this year. We have about 400,000 acres over a prospective area, on our 900,000 acres plus in the Piceance Basin. So you don't hear much of industry talking about it and the reason why, is because own it. But we are talking about it now, so you will hear more about that play when we have some more results. The Pearsall play, the Pearsall Shale in the Maverick Basin is an area of current activity. We have a joint venture partnership with TXCO. We plan to drill three wells this year. We have one well completed and it's producing gas right now. More to come there, we’ve 167,000 net acres on that play. Of course, the Delaware Barnett Shale play we are partners, joint venture partners with Chesapeake. We have a little bit under 300,000, 287,000 net acres on that play and we are working our way through a nine-well commitment program, as we speak there. And we have some interesting early results there as well. And of course the Barnett Shale is one of our key resource plays, we have about 150,000 net acres on that play. As Randy mentioned, we also have some plays that we are not going to talk about today. Above and beyond the ones I mentioned, but even just adding up to the ones that I have just talked about, I think you can get yourself to a million net acres.

Jeff thanks. One more if I could for Mike Graham; Mike, regarding the 500 to 1 billion a day long-term potential for the Montney, are you still thinking in terms of well spacing four to eight wells a section to achieve that?

Mike here. It will definitely be somewhere in that order. We have kind of the combination of the upper Montney and lower Montney and we think we may need to drill up to sort of four wells for both the upper and the lower Montney. Well rates in the Montney are very... have been very consistent between 5 and 10 million cubic feet a day. We have only developed about 10 sections out of our 375 core sections or so. We have got a tremendous amount of development to be done there yet and right now we are producing about a 120 million cubic a day out of the Montney. There is tremendous gas in place in the Montney up to in the order of 100 bcf per section. So we may actually take a spacing down a little further, if time goes on and see what our ultimate recovery will be there. We are probably north of 50% on the recovery factor out of the Montney at this shale. So it actually has a little bit better permeability than the shales.

Mike did you mean four wells each for the upper and lower. Or four total?

No I am saying four each like you may put in 8 wells a section where you do have the upper and lower Montney at present.

They are not present everywhere, so there will be some areas where we can have four in each and some will just be the lower Montney.

That's right.

Great. Thanks very much.

Thank you. Our next question will now come from Stephen Caulderwood of Raymond James.

Randy I am pleased to see you widening the definition of a resource play by including Weyburn. But I want to ask you about East Texas; you highlighted the drilling success at Deep Bossier with one well producing at 60 million a day. Could you just remind us what kind of play this is? Some potential investors may be confusing it with the new Hansville shale play which I think exists on your last but is not producing.

Okay Steve, we also believe that our Deep Bossier play at Amaruso redefines what a resource play can be. When we started looking for these play types a number of years ago we never really imagined that we will be able to tie into prolific plays like this, we’re also area of [ph}--. I’m going to give Jeff Wojahn an opportunity to talk little bit more about the results here because his team has really been responsible for making it happen.

Sure.Thank you. Jeff Wojahn - Executive Vice-President & President, USA Region: Talking about our East Texas position in more detail, obviously our key land position in that play is related to... what we call Amaruso fields which is Deep Bossier 15,000 to 17,000 foot wells. And we've talked a little bit about the results from that play. We, in November, announced the acquisition of our partner Leor and now we have a 100% working interesting in the play. For this year, our focus is primarily to drill what we call the core area of the play, the sweet spot area of the play. And we believed at the time of the acquisition that we would be able to drill high rate wells and so far through the first quarter, we have been doing just that. And we have been very encouraged from our subsurface modeling on what we see. We are integrating the three seismic into our results and the reservoir is behaving the way that we had hoped it will behave, which is very encouraging. As far as future plans of the Deep Bossier, we just completed a treating plant… treating facility for 100 million a day of gas capacity in September. We have another milestone of expanding that plant to additional 200 million a day. We have 450 million a day treating capacity today with the goal of exiting this year at 750 million cubic feet per day. So it clearly is our key resource play and our anchor in the East Texas area. And I think you are going to continue to see good results from that play as we develop it further.

Steve, to answer part of your questions, the Bossier itself is a very area-extensive shale across Texas and Louisiana. I think it goes all the way to Florida. It is a Jurassic Age shale which in certain locations such as the Amoruso fields, there are build ups of sand that have been maintained in a very over pressured environment and that's where we are getting these very prolific wells. These are wells that we drilled to the depth of about 17,000 feet and have pressures in the order of 15000 PSI or greater. So, very, very over pressured allowing it to contain the great deal of... great quantity of gas and deal produce and at great rates because the porosity and permeability has been preserved in the sands at this depth. So it is quite an amazing environment to produce from.

And how many sweet spots might exist like the East Texas portion?

Well we hope that it will be more. The sweet spot that we have in Amoruso field is obviously our key activity today. But I should mention to you that we are planning on drilling three or four exploratory wells on the trends. We are the largest land owner on the so called the Deep Bossier trend where we have about a 170,000 acres in this year, in the second half of the year we will be testing some of the other features that our team has identified.

The challenge and the opportunity for us… and this is an area where we are spending the greatest of amount of our exploration dollars in the company. But the challenge is that the play could extend over an area of 1000 square miles, that's 1000 square miles of 1000 miles in length and it's going to be a challenge to find additional locations where same opportunity sets up.

Thanks a lot.

Thank you. And our next question will now come from Gil Yang of Citi. Please go ahead?

Hi everyone. Could you... it sounds like your interest or your optimism about some of these new shales has increased. Can you comment on whether or not that's just sort of just purely based on the prices being where they are or have there been some technological or just sort of learning breakthroughs in any of the areas that have gotten you more optimistic?

I think it’s mostly based on the results that we have gotten recently, applying the newest technology out there, technology that's been developed on the Barnett Shale play and then seems to be working very well in what we call brittle shales.

Okay, and are there... you've spent the last couple of years farming out a lot of that acreage. Is there any sense at this point given what you've learned and high commodity prices that may be too far in that direction and maybe you should have kept some more of that in-house?

I think from what we have achieved today, our farm out programs have largely achieved their objectives by bringing in third-party money and additional technology from other companies, and basically reducing our overall risk because you always hear about the winning ones, but there is a lot of time that we go after things that don't turn out so well. So it's really about our risk management strategy. We are very fortunate to recognize the potential of lot of these unconventional play types early and went out and grabbed an extensive amount of land without conducting the farm-out program. We likely couldn't have been able to hold our land ourselves or we may have found ourselves in a situation where we compromise other elements of our program.

Could you just compare the Horn River basin, the economics to what you’ve got at the Piceance and maybe draw any parallels between the improvements that you are seeing in Piceance versus what you might see in Horn River?

Both Jeff and Mike can crack it out. Jeff Wojahn - Executive Vice-President & President, USA Region: Jeff Wojahn here I'll jump in Gil. You know those are great questions and that's exactly what we are going to try to get to is within our portfolio of gas shale plays is to get real data on [indiscernible] and capital profiles so that we can start to compare them and how they compete in their portfolio, but at this time as Mike had said earlier we are just in the testing and infancy point of understanding the opportunities. But as we get more statistics and we drill more wells, I think it will be something that we will highlight.

Do you envision that ultimately the Horn River would be sort of the pad development program given that it’s hard to build permanent roads all whether access roads to every location?

Mike Graham here with Canadian Foothills Division. I guess that is… it's very early in play and we are really trying to get our hedge around… I mean the Horn River we had one horizontal well on for just over a year and we are encouraged by the results from the well we didn't really talk about results in that well. But the number that EOG talked about and the rates that they've talked about kind of confirmed all we are thinking. We have a good rate like I say 3 to 5 million cubic feet a day out of those. Obviously it is remote, it’s up sort of Muskega [ph] North ECC and we are looking to drill a year round like we do up there in Greater Sierra. We currently have six rigs running around Jean Marie up there. So overall, the costs are quite expensive right now drilling these horizontal wells in the remote area. But we would all go to paddrilling similar to what they are doing in the Barnett Shale. We use lot of technology, our Texas teams help us out a tremendous amount in Canada. So we’re looking at the pad to date, upto 20 wells on a per pad. So we can bring our cost down by just about any of these resource plays, when we get into them early, you will see our cost drop 20%, 30% for several years, so it should be no different in the Horn River basin. We think we can probably get our cost in the area where we drilled the Montney or its similar depth, and we're going to drill similar horizontal length as well so that will be our target.

Okay. Thank you very much.

Thank you. Our next question will now come from Baptist Malino [ph] of FirstEnergy Capital Corp.

Gentlemen, can you give us an idea, we could see obviously oil prices rocketing here, we are now through $218, what kind of price realizations are you getting on in the mediums and heavies these days in terms of absolute terms and what kind of discount percentages are we seeing, let's say over the month of April now?

All right. Bill go over and dig into that information right now. [indiscernible]

No, everybody else asked all the rest.

Okay. John Brannan will have the actual results for the bitumen that we produce.. John Brannan - Executive Vice-President & President, Integrated Oil Division: For the quarter I think our number is somewhere around $59 on a fuel price obviously that's extremely high from what we have gotten in the past.

I can give you some prices too Martin for Suffield, we were getting about $67 a barrel, and Weyburn it was about $85 a barrel for the quarter and then Pelican Lake it was about $71 for the quarter.

Anything else?

I have got the heavy old numbers. So, John, for the Cristina Lake it was… for the quarter about $57, and Foster Creek about $60 for the quarter for the fuel price.

Do you have any insight in terms of what has happened in the last couple of weeks?

I miss that.

Bill do you have any insight in terms of what's happened in the last couple of weeks there, have we stayed in those same kind of percentage terms or has it tightened or loosen sense?

I think there has been some tightening in the differentials and that is with some turnarounds, Martin that including ourselves coal and some materials versus being some concern obviously about volumes and then we are moving into the paving season so we are at a real good differential for heavy oil this quarter at this time.

Great. Thank you, guys.

Thank you. Our next question will now come from David Tameron of Wachovia. Please go ahead.

Thanks. Good morning. Question to Jeff. You mentioned that most of the wells that were drilled that came out the higher fuel rates and Amoruso were in the core which you also mentioned in the press release, two wells got approvedat the northern end. Can you just can you just talk a little bit more about that? Jeff Wojahn - Executive Vice-President & President, USA Region: Sure. You know previously if you have seen have our material, and we've talked about the acquisition. We've talked about the Laxson and Barney Ann wells which were two of the top five wells drilled in North America over the last period of time and those wells are located on the south-end of the field, kind of south central part of the field. We drilled the Mclean A2A well here this last quarter, which is on the north western end of the field and it has been producing in excess of 60 million a day. So, I think the point is that we have a distribution specially across the field of high rate wells rather than just in one spot, which bodes well for future upside as we continue to infill the field.

All right. And have you drilled anything in Madison yet, or has it all been in Robertson? Jeff Wojahn - Executive Vice-President & President, USA Region: Are you referring to Amoruso field?

Yes, yes, I am sorry as far as the counties. Jeff Wojahn - Executive Vice-President & President, USA Region: Yes, I am not sure about the boundaries.

Okay. Jeff Wojahn - Executive Vice-President & President, USA Region: I apologize on that.

No, no it's fine. And one more question on East Texas and then one on the Barnett, but in East Texas when the acquisition was announced, I believe the metrics you guys threw out were somewhere between 10 Bcf a day per EURs and about 10 million to drill, are those still... what are your current well costs running at, are those still good numbers for the EUR? Jeff Wojahn - Executive Vice-President & President, USA Region: No, we talked about 10 Bcf EUR per wells, the wells we drilled to-date have been actually right in that range maybe a little bit higher, our well costs for the quarter average 9.1 million, below our $10 million estimate. So, we made good progress on our cost structures.

Okay. Jeff Wojahn - Executive Vice-President & President, USA Region: EUR seems to be in line and the reservoir is behaving as we expected.

Okay, good. And then one more question, looking at the Barnett, in the Fort Worth Barnett, it looks like your well count went up in the quarter versus third and fourth, I think you drilled 21 wells what was in the table, your production… looks like it’s flattening out, is there anything to read into that or can you talk a little bit about that?

I wouldn't read into it, I think we are very pleased with the Forth Worth program. We continue to see efficiency gains of 20% to 30% with our fit-for-purpose rigs, and the asset continues to perform, you know, I'll call it second quartile asset, it was in our U.S portfolio. So, we are very pleased with it and we are making good progress and I think you will continue to see it as a strong performer in our portfolio.

Okay. So it sounds like it's more of a timing issue and hooking up the oil?

Exactly, it's the timing issue.

All right. Thanks.

Thank you. And our next question will now come from Ben Dell of Bernstein. Please go ahead. Ben Dell - Sanford C. Bernstein & Company: Hi, guys. I had a couple of follow-up questions, one on the CO2 front… obviously there is a lot of stay up around the oilsands about the potential to CO2 striping and the use of the CO2 after that. Have you taken any time to look into that, do you have a view as to where the industry will go and what sort of participation you would have in that?

We are certainly studying it right now and ourselves and as part of industry groups, the idea of the capture of CO2 and what cost where it can be possibly used for. But I am going to turn it over Gerry Protti to give you an update of what’s going on in the industry? Gerry Protti - Executive Vice-President, Corporate Relations, and President, Offshore & International Division: Hi Ben, Gerry Protti. We are participating in a number of groups. We have... for example, we have provided the input to the carbon capture task force that the federal government announced. I suspect we will be involved in the provinces sequestration council. We are involved with Enbridge on the Saline Aquifer Injection Project . Clearly we are in a position at EnCana with the experience that we have garnered at Weyburn not obviously in capture but in the transport and sequestration of CO2 to really assess these alternatives over the longer term. I think things are still in the very early stages in terms of oil sands, the federal government has come out with some more information in terms of how they see the regulation unfold and I note that in 2018 they talk about starting to roll out captured technologies. So we are going to stay involved. I think we have got a lot of expertise and we will be involved with our industry colleagues in the discussions. Ben Dell - Sanford C. Bernstein & Company: And, do you have a feel today to what sort of carbon price retrofit in capture would make sense. I know in Europe they talked about $40 a ton as being some sort of threshold number?

Yes, there is quiet a wide range in terms of the capture, depending upon the source whether it is a high purity source like that coming out of the fertilizer plants or the hydrogen plants, in upgraders refineries. And so the range can be from that number to a much higher number, if you are looking at low-purity sources like fuel gas streams out of coal-fired power plants. In that area, the technology hasn't really been commercially developed. So it depends very much on the source. Ben Dell - Sanford C. Bernstein & Company: Okay great, and a second question. You haven’t said much today about sort of European onshore gas. I understand you have looked at that before. Is that... can you give us an update of where your thinking is on that obviously with gas from volume declining and the European market getting tight so that seems to be an increasingly attractive opportunity?

Yes we have looked at opportunities. We've drilled a couple of wells as you know Ben, in France. We did not find commercial quantities of natural gas in those projects and we are leading to a process of divestment in those assets. We did look at Romania and assessed the opportunity for an unconventional gas play, but we determined that there wasn't one feasible and we are not pursuing any further Eastern European gas plays at this time.

Sort of have our hands full in North America right now. We really have an abundance of early-life plays. Ben Dell - Sanford C. Bernstein & Company: Okay and just one last quick question; can you give us some background to what was the big driver of the increase in SG&A on a year-on-year and quarter-on-quarter basis?

Yeah I will draw out for you some ...

Ben, the single biggest increase in fact, I think the only increase is the mark-to-market on our LTIs. We expense them as the stock price goes up and that accounted for $0.17

For our long term...

Of $0.38 in the quarter. Ben Dell - Sanford C. Bernstein & Company: Great. Thank you.

Thank you. And our next question will now come from Harry Lapiere [ph] of Lehman Brothers. Please go ahead.

Hi guys, it’s another follow-up question on the CO2 at Weyburn. I don't know if you have provided this data before, but I am just curious on an operating cost basis, I don't even know if this is really the proper way to look at it, but if you have operating cost there broken out in terms of the actual cash cost of the sequestration and relative to the production you have at Weyburn? Don T. Swystun - Executive Vice-President & President, Canadian Plains Division: Hi, this is Don Swystun from Plains Division. Particularly, we don't break out the specific cost on just the sequestration portion. Obviously it's enhanced recovery project and one has to do is just operating the wells there. So if you are looking at certainly around $11 a barrel roughly kind of OpEx, we do obviously pay for the CO2 as well from North Dakota for injection.

Okay, thanks.

Thank you, we are now moving on to the question from members of the media. First question will come from David Frey of Aspen Daily News.

Hi, could you just cast a little more shift of emphasis for 2008 from the… your Piceance basin property to Texas property like Deep Bossier and sounds like also from Jonah Field and your Wyoming properties? And Jeff can talk a little bit about how you are managing your U.S portfolio? Jeff Wojahn - Executive Vice-President & President, USA Region: Sure, Dave this is Jeff Wojahn. We have been keeping as far as capital programs, more or less steady in the $500 million range for the last several years. So, I wouldn’t say that we have lost our appetite for the Piceance Basin at all, I we also mentioned that more recently we announced a joint venture partnership with Delta Petroleum for a $400 million four-year commitment as well. So, the Piceance Basin remains the core activity area for us, a core property for us. I think the Texas properties have been more independent. I really don't see one trading off on the other. I see the Texas property as an addition to activity. Clearly we have seen a very strong regulatory environment, strong economic environment and strong resource potential in our East Texas, so properties that we highlighted earlier and hence it has been a very attractive investment for EnCana.

It's fair to say though that the... we have certainly a greater price sensitivity for economic purposes in the Piceance Basin and then several other plays. So as commodity prices… our belief in longer term higher commodity prices go, there is a likelihood of a larger longer-term investment.

Is that because of pipeline access problems?

You know the Piceance Basin is a remote access area and generally a high cost basin, supply basin. When we look at intense study it is an area with very significant hydrocarbon content capability and a 100s of trillions of cubic feet of gas. But it's high cost and in a sense it's a disadvantage because of pipeline and remoteness over areas like Texas.

Is this a response to the proposed regulations by governmental regulators in the oil and gas industry?

No. Right now the Colorado Oil and Gas Commission is reviewing or rebuilding the rule making. We’re not an active participant in that rule-making process and obviously we are concerned about the impacts of that new rule-making may have on delays and increase in cost structures for our industry. And that could make the opportunity less competitive within our portfolio.

But it sounds like… largely what's driving it is just your optimism about the Deep Bossier play?

Well obviously we have had great results in Texas. I think from a Colorado point of view it’s imperative to stay or for any regulatory body understands that our industry will gravitate to the lowest cost structures and obviously if there's some impediments to that then those will be factored into our investment decisions.

And I guess my last question is it sounds like there is not a whole lot that you were able to say about it right now, but can you talk a little bit about your oil Shale plants in the Piceance Basin and what your holdings are there?

We do have a holding area in the North Parachute Ranch. We have no current activities or plants on the oil shales.

Okay, earlier in the call you were talking about the some plans for further testing in the 2008 in the Piceance Basin?

Yes that is the gas prospect in the Niobrara shales.

Okay, thank you very much.

Thank you.

Thank you, at this time we have no other questions registered. So I would like to turn the meeting over to Mr. Eresman.

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

Thank you sir. Ladies and gentlemen, this does conclude the conference call for today. Once again thank you for participating and at this time, we ask that you pleas disconnect your lines. Have yourselves a great day.