Good day ladies and gentlemen and thank you for standing by. Welcome to EnCana Corporation’s first quarter 2009 financial and operating results. As a remainder 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). I would now like to turn the conference call over to Mr. Paul Gagne, Vice President of Investor Relations. Please go ahead, sir.

Welcome everyone to our discussion of EnCana’s first quarter 2009 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 one of EnCana’s annual information form dated February 20, 2009, the latter of which is available on SEDAR. I’d 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. protocol, 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 U.S. dollars and U.S. protocols unless otherwise noted. Randall Eresman will start off with highlights of our operating results, and then turn the call over to Brian Ferguson, EnCana’s CFO, who will discuss EnCana’s financial performance. Following some closing comments from Randy, our leadership team will then be ready for questions. I will now turn the call over to Randy Eresman, President and CEO.

Thanks Paul, and thank you everyone and good morning. Today’s conference call will highlight our strong performance in the first quarter of 2009, period of continued uncertainty in the global markets and a time when commodity prices were at their lowest levels since the second quarter of 2004. In spite these difficult times, we had a solid start to the year both operationally and financially. This reflects the great execution by our teams and the impact of our risk management program. Today’s results continue to illustrate the strength of our resource play portfolio, our disciplined approach to its development and the flexibility of our resource play model. These characteristics give us the ability to manage our pace of development and allows to maintain an appropriate level of activity in uncertain economic environments. Overall, our first quarter gas and liquids production increased by about 3% compared to the same period in 2008. Natural gas volumes increased by about 4% in the quarter to about 3.9 billion cubic feet per day. In addition, our overall production was higher than our first quarter expectations primarily due to price sensitivity of the royalty rates in Alberta, which are reduced at lower prices and increased when prices go higher. Before any price related royalty impacts, we expect our 2009 production to remain flat compared to 2008, which was our original target for the year. The key resource plays continue to perform very well. Now first looking at gas in East Texas, first quarter production grew by almost 50% compared to the same period in 2008. This increase was largely attributable to continued strong well performance in our Deep Bossier play. We completed eight wells in the first quarter, which had 30 day initial production rates averaging more than 19 million cubic feet per day. In…

Thanks Randy. Good morning everyone. EnCana posted another solid quarter during a very chaotic time in global markets. During the first quarter 2009, we saw declines in the average price on NYMEX where natural gas and WTI of about 39% and 50% respectively compared to the same period in 2008. Despite this, we have achieved cash flow of $1.9 billion or $2.59 per share diluted, which is down about 18% compared to the same quarter last year, a relatively small drop considering the sizeable decrease in commodity prices. Our hedging program was a key contributor to this result, supported by the strong operating result that Randy discussed, and the impact of the declining Canadian dollar. We began the year with two-thirds of our expected natural gas production hedged from January through October at an average natural gas price of $9.13 per 1000 cubic feet. The impact of the realized financial hedging on all of our products in the first quarter of 2009 was $2.55 per 1000 cubic feet equivalent. Our hedging regions are with a diversified group of approximately 25 different counter parties with high investment grade credit rating. As we’ve done in previous years, we will look for opportunities throughout the year, but we will have the ability to place hedges on a portion of our gas production for the upcoming year. Our intent is to provide an increased level of certainty to our cash flow so that we can efficiently manage our capital programs, while continuing to have the ability to pay a stable dividend to shareholders. Randy already spoke to some of the operational highlights in our integrated oil division. I’ll now take a moment to highlight the division’s financial performance. In spite WTI averaging about $43 a barrel this quarter, our Foster Creek and Christina Lake…

As we all look forward to the remainder of 2009 and into 2010, we see the potential for continued commodity price weakness. Accordingly, we’ve been conducting extensive reviews of our capital program looking for opportunities to increase flexibility by adjusting investments and examining how best to sustain value creation and profitable operations in the event of continued low commodity prices. Our results in the first quarter of 2009 were very positive and I believe that operationally and financially we are off to a great start. This consistent and strong performance is a credit to our teams across EnCana. With our resiliencies in one of the most difficult economic environments in recent memory continues to highlight the underlying strength of our business model and our focus on maintaining financial flexibility. Thank you for joining us today, and then our team is now here and ready to take your questions.

(Operator Instructions) Your first question comes from Mark Gilman - Benchmark Company. Mark Gilman – Benchmark Company: I was wondering if you could give me a bit of an update on the number of remaining identified drilling locations, which have been established in three of the plays, Cutbank and Montney in particular, Jonah and then also how many further locations you have identified in the Amoruso Field in East Texas.

I’ll turn that question over to Mike Graham to start with for Cutbank Ridge and then Jeff will follow in for the other two plays.

Hi Mark. Mike Graham here. In the Montney for 2009, we actually planned to drill about 60 wells is what we planned. We drilled about 15 wells to date and results have been in a very encouraging and the Montney is right on track and then performing very well, probably one of the top quartile plays in our portfolio. The other thing is just sort of on the potential, we have a tremendous land position somewhere in the order of 500,000 plus acres and we plan to drill sort of four to eight wells per square mile. So when you add it up, we have got a tremendous inventory in the thousands of wells that could be drilled out here in the Montney and right now we are drilling let’s say about 60 wells a year, so a big, big inventory going forward

And the Montney is responding to exactly same technology that we are using in the shale plays basically the long-reach horizontal wells with multiple fracture stimulation treatments.

Yes. It’s actually a self solenoid, and not a shale so it’s sort of a turbine, but a very big tremendous gap in plays and we do horizontal technology drill 1600 to 2000 meters long and put about eight fracs per well in there.

Jeff, do you want to follow in on Jonah and East Texas?

Sure. In Jonah Field, this year we’re planning on drilling 115 wells for the year. At the current pace of development, I anticipate that we’d have a remaining inventory of three to five years based on 10 acre and in some cases lower than 10 acre drilling. In East Texas, specifically Amoruso Field, they are planning to drill 30 to 35 wells area for this year and we have a 10 year inventory behind that in the greater Amoruso area, and one other thing that we’re focusing right now is working specifically in the Amoruso Field and the results you have seen are just in that component of the field.

Your next question comes from Gil Yang - Citigroup.

Hi, two quick questions. Just wanted to reconfirm your guidance, I think February 12 still stands, and it's based on no royalty changes based on low prices?

Yes. At this point in time, we haven’t changed any of our guidance for the year. You can see that there is a possibility that we will be tracking lower on both capital and operating and G&A. We just want to give it another quarter so before we really, I think that would put changes to the numbers.

But you’d assume that you don’t have the benefit of the lower royalty rates in that guidance, right?

Yes, it does assume that we had slightly higher prices in our original guidance. Right now, our production as you can tell is tracking higher with the royalty adjustment. Our plan for the years to keep more or less flat with 2008, a little unsure how that’s going to actually transpire as the year progresses, but I think it will be close.

So it sounds like we track weaker on the CapEx, the cost reductions, the service cost reductions might offset that so you can be more on track with the volumes?

We are not off track with the volume. We are producing higher on the volume side, so the performance on the teams right now is actually quite exceptional, higher than we would have anticipated. We also have a small volume of gas shut in, so the performance operationally is quite good.

Okay. In the Piceance, your production is starting to drop a little bit and you have, I think forecast for the year is down slightly, given your comment about the Haynesville going forward, if gas prices start to rise, will the Piceance see resurgence in activity or do you think that over time the trends sort of move out of the Piceance into the other areas and develop less capital towards the Piceance over time?

I guess, the answer to the first part of your question, the Piceance is one of those areas where we have some of our gas curtailment right now. So, part of that drop is simply by our internal choice, but in the longer term, we are trying to focus on the lowest cost price in our portfolio, it’s a little difficult right now to understand what the implications of all these plays are going to be on longer term prices, but we are focused everywhere in the company in applying technology to lower our overall cost structures. When you play like the Piceance basin, we still see tremendous amount of resource potential and with future application, the evolution of technology such as we have seen in the last couple of years. We really don’t know how it’s going to go, so I wouldn’t give up on the basins.

Obviously they are little more challenged?

Today they are.

Your next question comes from Chris Theal - Tristone Capital.

A couple of questions, the first is related to Montney. The public data shows a few deeper tests this winter. I wonder if you have any color on results in the lower Montney and then secondly, the Haynesville well count looks to be doubling, and I’m just curious with that well count. Do you expect to complete and tie in all those wells or you not have any [inaudible] issues for the balance of 2009?

Okay. Mike first.

Yes, in the Montney, we are kind of expanding our program and we are drilling a little bit further left on our land position. We have drilled one well, we haven’t completed it yet, and we spotted another well on the west side and we do have quite a bit of lower Montney right in the core of said area, and the results have been encouraging on our lower Montney stuff. So, things are going tremendously well in the Montney and we are very pleased with the well performance there. Jeff

Hi Chris, it’s Jeff Wojahn. In regards to the Haynesville, there is a lot of things going on right now. Obviously the strategy to increase our well count is the confidence in the overall play and motivated by our desire to retain our lands. In Louisiana we require to drill one well per section through our title lands, and some of our original lands are now facing expiry up until 2011 period and hence we move forward with the play. With that, we also have commitment to the Gulf South $150 million a day expansion, downstream expansion and the ETC Tiger expansion mid-2011. We also committed to a short term or have the option to, I guess commit to backhaul commitments with Gulf South and short term productions meeting this year and next year, up $250 million a day, so backhauling meaning moving the gas to cartage rather than to [Perigo]. So I think the combination of transportation agreements that we’ve announced will allow us to move forward with our land retention program and also further evaluation of the play. So I don’t want to anticipate to have shut in bonds because we don’t have capacity.

So there is no strategy of drilling, but not completing wells?

You actually have to bring the wells on production in order to retain wells.

That’s right. In most cases, our leases require us to have gas producing and paying quantities.

Thanks for that clarification. If I can just ask one more, Randy you talked about gas curtailments. What’s your sense on shut-ins, basis differentials are wide in some areas. How do you see that playing out for EnCana this summer?

We do have some quantity of gas shut-in throughout the entire company. I think specifically we said we have $90 million in the quarter shut-in the US and that was primarily in areas where we didn’t have transportation, either held or over operationally affected by lack of transportation. Throughout the company, we do have a program where we’re kind of looking around and seeing where we have high variable operating costs in those kinds of scenarios. It makes sense not to rate on production that would be very expensive. You cab think of situations like when you had a well go down and you really bother spending a lot of money bringing the service rig out to get that well back on stream again. We are also looking at places in the company where it make sense not to bring them on production after they have been drilled, but we are finding that with the existing contracts we have there is very few places in the company we can actually execute on that. As Jeff just said, in order to retain the land in Haynesville we need to bring the wells on line.

Your next question comes from Richard Wyman - Canaccord Adams.

Good morning, guys. Just following up on Chris’s question with regard to Haynesville. I do have a few questions. First of all, can you comment on which parts of the portfolio had money taken away or savings deflected opportunity? Also can you comment on interest of your partners to spend in an increasing capital program, given the current markets for gas and may be just a little more clarity on the upgrade in the CapEx as it relates to accelerating the earnings or the land retention with some of this otherwise to plan for 2010 or further into the future and use moving forward?

Okay, Richard. I’ll start and then I’ll get some help from others trying to [inaudible]. Within the company we haven’t talked about this, but we do have a what we call a 10% challenge in the company and what we’re trying to do is, throughout the entire operations in the company this year we are trying to reduce our expenditures by 10% lower than we budgeted. We’ve already identified a number of these potential savings both in capital operating and general administrative costs across the company. Once we have a better sense of it, like I stand by the second quarter we’ll probably give more specifics around it. We have already found enough money and to be able to reallocate without affecting any of our production oriented programs. So we are not yet taking away from any of the wells we would have otherwise grown in support of production in support of the Haynesville expanded land retention program.

What’s the second question?

Whether partners are all on side with the increase in capital spending?

Yes, Jeff can answer that.

Yes, Richard, I think one of the things that is interesting in Haynesville is that you are seeing as of industry an increasing rig counts in that specific play. In fact, we’ve seen rig counts now, about 50 rigs in that play, which is countered to rig counts that you see in a big or huge numbers with the Rockies numbers or the North American numbers and I think that’s driven by two things. Obviously, the encouraging well results that industry has been reporting and the potential for low supply cost that many of the analysts have written research reports on, but I think a lot of it is driven also by land retention and the need again as we described before around drawing wells to maintain land. In regards to our partner participating, Shell is our major partner in play and they are participating in the increased well drilling.

And just one last question on the results so far. I guess, some of your wells might be getting old enough that the decline characteristics of turn that point of inflection into something a little more gentle than, could you comment on how you see the tight curves of these Haynesville wells looking?

I think, Richard over the last six months we’ve converged on buying large and more stable completion programs so the data set that we have of both industry and EnCana over the last six months is encouraging. I wouldn’t say it’s definitive in regards to potential outcomes for a tight curve. Right now, we are holding judgment, but I can’t say that the initial productivity rates and the pressures that we see are very strong and in line with industry reports in regards to cost, I think that’s another big component of the play. One of the things that we’ve been able to do is reduce our spud to rig release, reduce our rig moves, reduce our run time on directional tools and over the last three wells we’ve been able to reduce our wells by 30% cost in the last three wells we drilled were in that $9 million range. So, we’ve seen IPs continue to advance, IP30 rates continue to advance, our six-month IPs continue to advance. They look promising relative to a tight curve, but that’s one of the things that we need to establish over the next six month period to really nail down what our tight curve and what our commercial program will look like, but clearly costs are coming down and IPs are going up.

Your final question comes from Andrew Potter - UBS Securities. Andrew Potter – UBS: Just a question on the Horn River, I was just wondering if you could give a little bit more information on these 14 stage wells that you are testing if you’d like. What would we expect in terms of productivity and what is this due to the cost per well or I guess cost per frac segment and how did the overall economics look, I guess with these longer wells?

Yes Andrew, Mike Graham here. We have for 2009 program we drilled seven wells, and we’ve actually completed two wells. So we are going to bring on sort of our latest wells here over the next quarter if you already waited actually. We currently have three rigs running and we’ll probably run two for the remainder of the year anyway. So, like you are asking, we actually drilled the wells a little bit longer, put in bigger fracs, we think it’s a little bit more economic to do that. We trade a lot of data with our U.S. guys and it seems like the bigger the frac the more productivity you get out of them or our latest well with a 10 frac well, 30 day IP of just about 8 million cubic feet a day. It’s slightly and after about eight months on production, it’s still over $4 million cubic feet a day. So it looks like these wells may decline about 50% in the first year, which is very encouraging, and we do think by putting in bigger fracs, we’ve gone from four to six to sort of 10 stage fracs, and now we’re going to go up to 14 stage fracs. We think we’re getting a bit bigger IP and be a little bit more economic. In regard to economics, I mean we are out there kind of way up in Northeast BC. We’re working hard to bring our costs out and if we do, we think the Horn River can compete nicely in our portfolio. Andrew Potter – UBS: Yes. I think going into the year, you‘re hoping to see costs come down to somewhat to $8 million range per well, are you seeing progress towards that?

Yes. We kind of think of it on a per frac basis now, and we’re probably like over $1 million per frac if you will. I know Kevin Smith, a guy who looks after that area for CE think that we can get our cost down similar to the Monteny. In the Monteny, we’re using about 750,000 per frac, but we think we can probably bring that down to even under 700,000 per frac. So we’re hoping to be in about $0.75 million Canadian long-term in the Horn River on a per frac basis. So obviously if you have 10 fracs, that’s $7.5 million per well; 14, a little bit more than that. It’s encouraging and I can tell you, we’re tracking sort of above our tight curves in the Horn River, the wells we have on. So we’re pretty comfortable; the latest 10 frac well we think it’s going to recover north of 7 bcf. Andrew Potter – UBS: Okay. Thanks.

Ladies and gentlemen, we will now take questions from the media. (Operator Instructions) Mr. Eresman, there are no further questions at this time, please continue.

Well, thank you everyone for joining us today to review EnCana’s first quarter results.

Thank you everyone for joining us today to review EnCana’s first quarter 2009 financial and operating results. Our conference call is now complete.