Ryder McRitchie – Vice President-Investor Relations Clayton H. Woitas – Interim President and Chief Executive Officer Sherri Brillon – Executive Vice President and Chief Financial Officer Michael G.

McAllister – Executive Vice President-Encana Corporation and President-Canadian Division Jeff Wojahn – Executive Vice President and President-USA Division Bob Grant – Executive Vice President-Corporate Development, EH&S and Reserves Eric Marsh – Executive Vice President-Encana Corporation and Senior Vice President-USA Division

Andrew Potter – CIBC World Markets, Inc. Greg Pardy – RBC Capital Markets Brian A.

Singer – Goldman Sachs & Co. Matthew Portillo – Tudor, Pickering, Holt & Co.

Mark J. Polak – Scotiabank Bob Brackett – Bernstein Research Robert Bellinski – Morningstar, Inc.

Ross Payne – Wells Fargo Securities, LLC

Thank you, operator, and welcome everyone to our discussion of Encana’s first quarter results for 2013. Before we get started, I must refer you to the advisory regarding forward-looking statements contained in the news release, as well as the advisory on Page 39 of Encana’s Annual Information Form dated February 21, 2013, the latter of which is available on SEDAR.

In particular, I’d like to draw your attention to the material factors and assumptions in those advisories. Encana reports its financial results in U.S.

dollars and U.S. protocol.

Accordingly, any reference to dollars, reserves, resources, or production information in this call will be in U.S. dollars and after-royalties, unless otherwise noted.

Assuming you’ve all had a chance to read our news release, we will keep our prepared remarks brief and to the point in order to allow time for questions. The agenda for our call this morning, we will begin with Clayton Woitas, Encana's interim President and CEO, discussing the Company's first quarter highlights.

Sherri Brillon, our Chief Financial Officer, will then discuss our first quarter financial results. We'll then finish with Mike McAllister, President for the Canadian Division, and Jeff Wojahn, President for the USA Division, discussing the first quarter divisional operating results.

I will now turn the call over to Clayton Woitas, Encana's interim President and CEO.

Thank you, Ryder, and thank you everyone for joining us today. During the first quarter of 2013, Encana made significant progress in advancing its portfolio of oil and liquid rich natural gas plays.

We achieved 48% increase in our liquids production volumes compared to the first quarter of last year. The impact of organic liquids production growth as well as increased liquids extraction for midstream facilities positions us well to achieve our 2013 guidance averaging between 50,000 barrels to 60,000 barrels per day.

The expecting doubling of our liquids production in 2013 is primarily driven from well known industry established commercial areas such as the DJ Basin, U.S. Rockies and the Alberta Deep Basin.

Oil growth on an annualized average basis will be driven by plays including the DJ Basin with an expected year-over-year increase of roughly 2,000 barrels per day and the Peace River Arch with an expected oil growth of about 3,000 barrels per day. The increase in annual average natural gas liquid volumes over 2012 is expected to come primarily from associated natural gas growth in the Peace River Arch, which will add approximately 4,000 barrels per day, Bighorn, which will add about 3,000 barrels per day, the DJ Basin, which will add about 3,000 barrels per day, and US Rockies, which will about 3,000 barrels per day.

At this time, only minimal volumes have been assumed in our guidance targets from our portfolio of emerging plays. Let me stress that doesn’t mean we are disappointed with the results of our valuation program.

We are just taking a measured and conservative approach to accounting for contribution from these plays. With each of our emerging plays, we have specific targets or goals we are striving to meet before declaring the play commercial.

Such targets include expected rates of return in excess of 20% and demonstrated predictability around well performance and costs. Our teams have prudent commerciality in our core land position in plays such as the DJ Basin, the oil opportunities in our Clearwater business unit, and most recently the San Juan.

Accordingly, we are more active in these areas. The Tuscaloosa Marine Shale is also nearing commercial threshold and we hope to provide you with an update on the status later in the year or possibly in 2014, depending on the timing of bringing on our latest wells.

Proving a commercial success for our emerging plays is one of the main goals for this year, and we intend to do so while preserving the financial strength and flexibility of the company. We plan to provide additional well results from various emerging plays throughout the year.

Our first priority for 2013 is profitability and ensure – ensuring we continue to run on a sustainable basis. While we are adding diversity to our commodity and cash flow mix, Encana is first and foremost a natural gas company and we are striving to regain our reputation as the lowest cost and most efficient developer of natural gas.

Encana already has low cost structures in many of its plays, but the status quo is not an option. While we cannot control the prices for natural gas, we can exert discipline on our costs, thereby increasing our margins without depending on a sustained natural gas price recovery.

We believe that we can bring in between $100 million and $150 million in G&A and indirect operating cost reductions in the next couple of years, and over time, we expect to see an additional 10% improvement in our companywide average capital and operating efficiency numbers. To that end, during the first quarter, we made significant progress in identifying areas where we can reduce costs.

I will now turn the call over to Sherri.

Thanks, Clayton, good morning, everyone. I’ll first touch on our financial performance in the quarter and then provide some details in our cost improvement initiatives that Clayton mentioned.

In the first quarter, Encana generated cash flow of about $580 million or about $0.79 per share and operating earnings of about $180 million or $0.24 per share. Cash flow was supported by our commodity price hedging program and we remain on track to achieve our guidance cash flow target of $2.3 billion to $2.5 billion based on commodity price assumption of 375 per Mcf for NYMEX natural gas and $95 per barrel for WTI oil.

Encana maintained its strong liquidity position through the quarter with a period end balance of about $2.9 billion in cash and cash equivalents. The upfront proceeds received from the joint venture transactions that we executed in 2012 have provided us with the financial resources needed to bridge the gap between our 2013 capital spending plus an upcoming $500 million debt maturity this October relative to our forecasted cash flow for the year.

We continue to target about $0.5 billion to $1 billion in proceeds for net divestitures in 2013, and expect to end the year with cash and cash equivalents of roughly $1.5 billion to $2 billion. In addition, we have about $5 billion of undrawn bank lines committed until 2015, so we have tremendous financial flexibility.

The news release highlights the additions we made to our hedging position during the quarter. Of note, we now have about 1.5 billion cubic feet per day of expected 2014 natural gas production hedged at an average price of $4.19 per Mcf.

We are comfortable with having roughly half of next year’s expected natural gas volume hedged as it provides us with greater certainty for our 2014 cash flow generation, and this in turn gives us greater confidence in our ability to fund next year’s capital program. During the quarter, we closed the sale of our 30% interest in the Kitimat LNG export terminal.

Encana’s primary driver in entering the Kitimat project was to support and facilitate natural gas demand for Western Canada, and we are very pleased with Chevron’s entry into the project because their global LNG expertise significantly increases the viability of that project. The transaction included our interest in the Kitimat facility, undeveloped land in Horn River, the Pacific Trail Pipelines and gas processing commitments.

Net proceeds from the sale are included in the net A&D line in net capital investment summary in the supplemental materials. Because of the complexity of the transaction, we have agreed with our partners not to disclose the specific details including the total proceeds we’ve received.

As Clayton mentioned, we are actively looking for ways to reduce costs, improve efficiencies, straighten cash flows and ensure sustainability of our business. We are focused on leveraging technology and technical expertise across our business, improving our processes, concentrating on the highest quality opportunity and maximizing our margins.

Included in this, we have agreed across the corporation that we will manage attrition through internal placement as much as possible, rebalance workloads retain only critical consultants and contractor and review travel and expense policy. Each operating division has prepared specific initiatives and efficiencies to drive further cost improvement.

We are targeting to achieve some of these cost structure improvements within the next 12 months, and we expect our efforts to begin impacting the company’s financial results towards the second half of the year. I’ll now turn the call over to Mike McAllister.

Thanks, Sherri, and good morning. First quarter saw strong performance from the Canadian Division with average natural gas production of 1,422 million cubic feet per day, and average liquids production of 24,000 barrels per day.

Natural gas production was down slightly compared to the first quarter of 2012 above 5%, while liquids production was approximately 25% higher than the first quarter of 2012. We expect our liquids production to increase by about 70% year-over-year in the Canadian Division.

We continue to see strong results from the Duvernay during the quarter as the results for our most recent well came in well above expectations. After 30 days on production, it is producing roughly 1,400 barrels per day of field condensate and 4 million cubic feet per day of natural gas.

Field condensate yields from Encana’s wells across the play are top quartile, ranging from 45 barrels to 350 barrels per million cubic feet. We currently have three rigs running in the play, two in Kaybob and one in Willesden Green.

Our confidence in the play continues to increase and we are successfully transferring knowledge and our technical expertise from our Horn River operations in the Duvernay as both plays share significant or shall I say similar rock characteristics. We also continue to advance our oil opportunities in the Clearwater Business Unit by drilling 26 net oil wells during the quarter.

We expect to have 21 oil wells on production by the end of April and the total liquids production of Clearwater is expected to average 8,700 barrels per day for the year. These wells continue to demonstrate strong economics with short payout periods.

So we may consider allocating additional capital to this play later in the year. Turning now to the Peace River Arch, where we are spending a significant portion of our capital in 2013.

Our Gordondale Montney oil program in northwestern Alberta is delivering promising results, and our teams recently completed our second six-well pad. Our teams have lowered per interval completion cost by more than 60% in this play since 2011 by implementing the resource play hub development model.

We currently have two rigs active in Gordondale and expect to drill a total of 20 wells from three pad locations by year-end. We are forecasting tremendous growth from this play as liquids productions is expected to average 8,000 barrels per day, but more significantly we expect to exit the year between 13,000 barrels to 15,000 barrels per day setting us up well for 2014.

Our Pipestone Montney liquids rich development also in the Peace River Arch continues to advance with successful three-well pad completion in March. Total production from the three wells during the initial testing was about 1,000 barrels per day of field condensate.

The average interval – per interval completion cost on the pad was $210,000 or about a 30% lower than what we saw in 2011. Also during the quarter, we successfully executed our second slickwater completion on Pipestone and a well was brought on production with better than expected results at about 300 barrels per day of field condensate and 5 million cubic feet per day of liquids rich natural gas.

I would also like to note that the deep cut processing natural gas processing facilities at Musreau have been down for repairs, but have resumed operations in the past couple of days. It is not anticipated that this delay will significantly impact our ability to meet our liquid production targets for the year.

I will now turn the call over to Jeff.

Thanks, Mike. During the first quarter, the USA Division achieved strong operational results with natural gas production averaging 1,455 million cubic feet per day, and oil and NGL production volumes averaging approximately 19.5000 barrels per day.

We achieved tremendous growth from our liquids programs as total average production was approximately 90% higher than the first quarter of 2012. We expect our annualized liquids production to almost double year-over-year in the division.

We made good progress advancing most of our emerging liquids plays during the first quarter and we are now in a position to confirm the commerciality of our San Juan play. Our San Juan wells have consistently performed at or above our tight curve and we view the play as having a low capital risk.

Estimated ultimate recovery ranges are approximately 200,000 barrels to 700,000 barrels of oil equivalent. We drilled two net wells during the quarter for a total of 16 wells drilled to-date.

Our last five wells delivered 30-day initial production rates of 150 barrels to 700 barrels of oil equivalent per day with roughly 80% of the production producing from oil. Current well cost averaged $5 million to $6 million per well.

We’ve identified 150 to 300 comparable quality gross well locations so far in the core area with the potential for significantly more locations across the rest of our acreage position. We are in the process of adding to our land position and we’ll consider allocating additional capital to the play in the second half of the year.

We are currently running two rigs in the San Juan and may add an additional one rig by year end. We expect 2013 production from this play to average approximately 900 barrels of oil equivalent per day with an exit of over 1,700 barrels of oil equivalent per day.

We also continue to see good results from our DJ Niobrara play. Depending on where we are drilling, we are experiencing liquid yields of approximately 80 barrels per million cubic feet of C3-plus.

Our primary target in this play is the Niobrara formation, but we are also evaluating the Cadell, which we plan to begin testing in the second quarter. We have identified up to 500 locations accounted for both formations on our land and have secured the necessary infrastructure capacity to execute our 2013 program.

We expect the DJ Basin to contribute an average of 8,200 barrels per day of liquids for the year, an increase of approximately 5,000 barrels per day over 2012 volumes. The Tuscaloosa Marine Shale has made significant strides towards commerciality over the last quarter as well performance continues to be strong and well costs are trending down.

Goodrich Petroleum's Crosby 12H-1 well, which we have a 25% working interest in, delivered initial 30-day production rates higher than 1,200 barrels of oil equivalent per day and continues to perform above type curve expectations. This well is proving to be the best well in the trend to-date, which is very encouraging for us, because it directly offsets Encana 100% interest acreage and extends the prospectivity of our land base.

We are also pleased with the longer-term performance of most of the wells that we have drilled to-date in the play. Our TMS wells typically flow six to eight months before being placed on artificial lift and then exhibit a flattening of decline curve.

We continue to gain confidence in the reserve values with the maturity of our production information. Total well cost continued to drop from an average of approximately $20 million in the first wells we drilled in the play to our current cost of $17 million per well and we are budgeting an average cost of approximately $15 million per well for this year’s program.

We expect to further reduce these costs as we move to our larger scale resource play hub operations and once the play reaches commerciality, we expect our well cost to average roughly $13 million per well. Another positive development for the Tuscaloosa Marine Shale is the approval by the Mississippi State Legislature of a severance tax reduction.

We estimate this tax reduction effective July 1 will translate to roughly $700,000 to $800,000 of cash flow uplift on each of our TMS wells and supports our efforts to meet commerciality thresholds. I’ll now turn the call over to Clayton for closing remarks.

Thanks, Jeff. Overall, the first quarter unfolded as expected and we made significant progress in advancing many of our emerging liquids plays and saw a strong growth from our liquids portfolio.

Before closing, I like to provide a brief update on our CEO search. The selection committee, which consists of David O'Brien, Suzanne Nimocks and myself, has created a shortlist of external and internal candidates and the interviews for the position have commenced.

We plan to complete the search by the end of June and hope to have the new CEO in place as soon as possible thereafter. We are encouraged by the quality of candidates and we are confident that we will find the best possible person for the job.

In the interim, I will continue to lead the senior management team focusing on reducing our costs and investing in our highest return projects. We have a tremendous asset base and the task before us today is to develop that asset base in the most cost effective, profitable manner possible.

Thank you for joining us today. Our team is now standing by to take questions.

First a few questions on the Duvernay, and then on Gordondale. But first on the Duvernay, can you just confirm that the 1,400 barrels a day, was that just fuel liquids or does that include other NGLs as well?

And then maybe we can talk a little bit about how you’re viewing Duvernay type curve now and how that’s changed since your Investor Day?

Hi, Andrew, it’s Michael McAllister speaking here. Yeah, that was 1,400 barrels a day that was fuel condensate.

so that didn’t include any NGL recovery, which we’d see it about 60 barrels per million and I said, it was about 4 million a day of gas that well is producing. So that’s giving us, I guess even more confidence in our type curve and probably strengthening our expectations around the type curve in the Duvernay.

What would you say, I mean, what would you expect now for typical IPO to Duvernay, given what you’ve seen so far in Willesden?

Well, there’s a high degree of variability in the Duvernay when you move from the north down to the south, from Kaybob down to Willesden Green. so it’s hard to say we got a typical – where I have a typical IP that I'm going to talk about, but this well has given us significant confidence, and we have up to 600 locations in the Kaybob area.

Is it fair to say that Northern area, the Kaybob area is performing better than the south, or is it Duvernay?

Well, as I’ve mentioned before I think that we’re seeing up to 350 barrels per million in the North, and we’re about 45 barrels per million in the South in Willesden Green, so we probably safe to just leave it at that.

Sure. And just a few questions on Gordondale, maybe if you can just talk a little bit more about this.

I mean, is this, I mean, is this more of a structural play or is this more of typical resource play? And I mean, how many locations do you have in total on this play?

Well, we have identified 60. So Gordondale is a property we’ve owned for quite a while and developed vertically, now gone to horizontally.

The – this is – it’s actually not a – I wouldn’t characterize it as a structural play, it’s a deep basin play, where we’re seeing oil trapped down dip from the gas, and I think we have a pretty good understanding what’s going on there, but I’ll save that for another day.

Okay, that’s good. Thanks.

Hi, thanks, good afternoon. I just want to hit you with three quick ones.

First, could you just give us an update on Panuke as to whether that’s still slated to come on at mid-year? Second, just this is a question for Sherri, didn’t anticipate a cash tax recovery in the first quarter, but I am wondering if you can just steer us towards what you are thinking as cash tax wise in the 2013?

Then the last thing is just around the composition of your U.S. oil and NGLs in the first quarter.

So just wondering if you can shed any light on that in terms of how much NGLs are now accounting for and how we should be thinking about that going forward? And the last thing was just around the OpEx number in the U.S., I am wondering if that was just sort of a blip that your unit operating costs should decline during the balance of the year.

Sorry, that’s a lot of questions, but try to get them out.

Hi, there, Greg, it’s Mike McAllister, I’ll try the first one. Regarding Panuke, so we are still sticking with the guidance from Single Buoy Moorings, from SBM, in terms of this being on in the first half of 2013.

The – with respect to progress on the platform, 51 of 75 systems have been handed over from construction to operations, so therefore been accepted by operations, and we’ve filled the [sales] [ph] gas line from the platform so as to shore with buyback gas. So we are getting ready for start up, but we are still sticking with the owner and operator of that platform, SBM’s guidance being mid-year.

Okay. Thanks for that.

I’ll turn over to Sherri now.

Hi, Sherri Brillon. Basically, we are estimating a cash tax recovery for the year and it will be in the range of about something maybe $50 million to $100 million.

It will depend on the divestitures and joint venture transactions and any changes in our cash flow estimates that we made in 2013.

Okay, great. Thanks for that.

Thanks.

Greg, it’s Jeff Wojahn. I was very confused in writing your questions down.

Sorry, yeah, sorry, Jeff.

There was a question about the U.S. OpEx, there was a small prior period adjustment that affected our operating cost, but our outlook for the year for our operating cost is inline and actually trending below our guidance.

So I think we're in pretty good shape.

Okay. And then just the last question was on the – just the composition, what threw us a little bit was – were just the realizations on the U.S.

oil and liquids side?

I wasn't quite sure what your specific question was?

So, the question there is what would be the breakdown between or in the – just in the U.S., between oil and then NGLs and then I’m curious as to how much room things like butanes and ethanes and so forth are now occupying in the stream?

Okay. Our oil production budget for the year is in the 12,000 barrel range.

Okay.

Okay. If you got it for the year, great.

If not, I can get it offline.

Yeah, let’s get it to you.

Okay, thanks very much all.

Thank you, good morning. Going back to Gordondale, you highlighted six wells – six-well pads producing about 7,000 barrels a day in the quarter.

And I think on the call earlier, you mentioned 20 wells to be drilled this year at an exit rate of 13,000 barrels to 15,000 barrels a day, can you just talk about the context of the six-well pad and the well performance there versus the well performance that you expect on average from the wells that remain to be drilled through the rest of the year?

Hi, Brian, it’s Mike McAllister here. Yeah, so that six-well pad, it’s the two six-pad, it’s just come on-stream this week with the 10-day test of that pad when we added the wells together we didn’t test them all at the same time was 7,000 barrels a day on average when we add them up in aggregate.

We are basically drilling into the same part of the pool with our next 20 wells and we would expect to see similar results.

I guess, if you would expect to see similar results, is there anything on the working interest side or on the decline rate side I mean, certainly, if you get 1,000 barrel a day wells, it would seem like 13,000 barrels to 15,000 barrels a day would be conservative, or is there anything up going on in terms of getting to that exit rate?

Well, it is basically facility tie-ins we’re having to build an additional battery. And so we’re basically looking at these wells coming on towards the end of the year.

but it’s really timing of tie-in that would be affecting that.

Okay, that’s great. I think you mentioned that, I just want to confirm you have 60 locations that remain now, so would that mean 40 for the following two years after the 20 drilled this year?

Yep, that’s correct. yeah.

Okay, great. And then my second question is with regard to CapEx, you mentioned in your earlier comments, the potential to allocate a bit more capital potentially to Duvernay and to the San Juan, do you think about that in the context of a reallocation of capital from elsewhere, or would that be an incremental CapEx as you go forward versus your current guidance?

And I guess in that context, can you just talk about how the Haynesville fits into that given higher gas prices here?

Hi, it’s Sherri Brillon. Right now, we’re focused on our capital program as it stands.

We’ve been very focused on maintaining our capital discipline and driving down our costs. We are looking at our emerging play and we will be going through our full portfolio review midyear, just to see how our programs are proceeding.

We think it’s really important not to overcapitalize some of these emerging plays, but some are going to work and some won’t. So you want to make sure that we’re approaching it quite cautiously measured and we will be using a milestone approach as we look at the pace and consider reallocation and perhaps, additional funding in the event that we’ve demonstrated success.

It’s really important not to overshoot our capital program in light of the fact that our cash flow is still running less than our capital budget. and so we will be very cautious relative to any additional capital being put forward.

In the Haynesville where you are going to monitor the results from the initial wells that we’re drilling and we’ll take that into consideration as we review our portfolio.

Thank you.

Thanks.

Good afternoon. just a few questions from me, in regards to your Haynesville drilling campaign; could you give us an idea on how we should think about acceleration and potentially, how you view returns on the play in a 450 gas [saved]?

Hi, it’s Sherri Brillon. As far as looking at the Haynesville, we have a program that we’ve set for this year.

We’re not deviating at this time from that program and we’ll look to monitor the results and make an assessment around the Haynesville as we move forward.

And then just in regards to the two of your emerging plays, I think in the TMS, you had two wells, two ash wells that were in completion. Just curious if there was any update there, and then your initial thoughts on the wells you’ve completed in the Mississippian?

This is Jeff Wojahn speaking. In the TMS, we are currently in the process of bringing the two ash wells on.

But one of the wells is not on the line yet, the other one is still in, I think it’s on six or seven-day of cleanup, so really don’t have anything for you on that front.

And in this regard…

This is Eric, following up on your other question on the Mississippian, we’ve got seven wells drilled out there. All seven are on production, doing fairly well.

We’re going to get 30-day production on three out of the seven. and I think over the next 60 or 90 days, we’ll go ahead and take a better look and release that information then.

Great. and then just last question from me, in regards to your Piceance location, I think industry has started to drill some additional Mancos/Niobrara wells.

and I was curious if you could talk a little bit about kind of your past experience with drilling the Mancos and if that’s an attractive play to potentially look at, revisiting as gas prices rise here?

And I guess just a last follow-up question there. are there any technical hurdles that have to be overcome or is it just delineation of the resource that’s holding you back.

I guess, just there’s obviously been quite a few wells talked about as of late that potentially are fairly prolific. And I’m just trying to understand a little bit better how the relative economics of the Mancos stack up against some of your other dry gas plays.

I think it would be fair to characterize the play as an emerging resource. We’re not all the technology channel just, I can’t say that word, specifically around the completion practices are still being reviewed.

the other part of it is that there is a relatively few amount of vertical well penetrations and data within the basin. It’s a very large resource and its infancy being developed, but it’s exciting to hear others drill some wells and like I said, when we have reached conclusions and we see the play as being something that could compete within our portfolio, I think you’ll hear more.

Thank you very much.

Good morning, guys. A couple of questions, first one just one of you provide an update on current status of Deep Panuke?

And then second, after the first quarter, now you’re about two-thirds away I guess to the low-end of your target range for net divestitures. just wondering on what’s still outstanding that you’re working on?

Are you still looking at JVs for the emerging liquids plays in the U.S. like the TMS and Collingwood and so on?

Hi, Mark, it’s Mike McAllister here. As I mentioned with Deep Panuke, we’re still sticking with the guidance from SBM to be a midyear startup.

With respect to current status, we have 51 of 75 systems that have been handed over from construction to operations on the platform, and we feel the sales line would buyback gas. so we’re getting ready for start up.

I’ll turn it over to Bob Grant for the second question.

Hi, Mark, this is Bob Grant. Encana is continuously in the marketplace, so we have a variety of divestiture and joint venture opportunities that we are progressing.

We do have a modest net divestiture target of $500 million to $1 billion for 2013, and we are primarily targeting those companies pursuing LNG exports from North America. So in Canada, we have the joint venture opportunities associated with our Cutbank Ridge, Montney, our Bighorn and so Peace River Arch properties.

And in the U.S. we are marketing joint ventures in our Haynesville gas properties.

We are also marketing opportunities in our emerging oil plays such as the Tuscaloosa Marine Shale, the Eaglebine and Mississippian Lime plays. These are all ongoing processes, and we'll announce transactions when they're concluded.

I'd say bottom line is, we are well on our way to meeting guidance of $500 million to $1 billion this year.

Okay. Thank you.

I had a question on the CEO search. I see that you're looking at internal and external candidates.

What would cause you to favor an external candidate?

Hi, it’s Clayton Woitas here. I don't believe there is any favoritism either externally or internally.

We spent a lot of time and interview time and we will go with the best possible candidate to fill that role. So there is no favoritism in or out.

And then a question on the San Juan, you’ve been talking previously around $4 million well cost, I hear it’s crept up to five or six, what’s driving that cost increase?

Yeah, this is Jeff Wojahn. We’ve previously talked about target type curve and target capital cost and those targets remain in place.

Right now we are doing a fair amount of delineation and kind of one-off drilling without scale. And as we move forward with the play and, I guess, optimize our supply chain and move to a resource play hub strategy, then I think it’s fair to say that we will move from a $5 million to $6 million capital cost range to a $4 million to $5 million capital cost range.

Great. And I guess the last, how many pounds of sand or propane and how many gallons of water were in that last TMS well that you talked about earlier?

Yeah, this is Jeff. We’ve been doing two things in the TMS, one thing is to look at what we call a gel hybrid frac jobs in the Anderson wells and the most recent Goodridge Crosby wells are examples of those wells.

And those wells have IPs, 30-day IPs over 1,000 barrels of oil equivalent per day, which we’re quite satisfied with. Most recently in the ash wells that we referred to earlier, we are looking at slickwater completion technology, so a little different technology.

And we are looking at 150,000 pounds to 200,000 pounds of sand per cluster and upwards of 400,000 barrels of water that has been placed in those wells.

400,000 barrels of water per cluster or?

No, per well.

Per well. Okay, thanks.

Hey, thanks for taking my question everybody. I assume that one of the primary drivers of the lower cost structure for the company would be the combination of growth in gas production Canada with the more favorable royalty structure.

I was just wondering, do you have an estimate of what gas price could eliminate that royalty cost advantage for the Canadian production? And what would that or how would that impact capital spend?

Hi, it’s Sherri Brillon. I don't have a price readily available that would eliminate the royalty advantage in Canada.

Actually you have to look at it in its entirety whether it being Canada or in the U.S. on a play-by-play basis as we experience different transportation and geographic cost in Canada combined with unique royalty structures, the segments we do in some of our U.S.

opportunities. So, we’ve seen reductions in – recently in our Mississippian royalty severance tax structure.

And so with that I think that as we go through and we look at all of our opportunities across the portfolio, there are different things of play besides just the royalty structure.

Okay. Fair enough.

And then my second question is kind of pertained to the Cutbank Ridge Partnership. How many of those wells drilled in 2012 are on-stream now?

And what level of inventory do you anticipate at the end of the year?

Hi, Rob, it’s Mike McAllister here. So, the inventory – and I am talking gross wells, the inventory that we have is about 4000 locations.

And this year, I don’t have the 2012 number, about 60 wells that were drilled and actually I think a good portion of those would be on by now.

Back to you…

I can give you more detail maybe more off-line, but…

Okay. That will work.

Thanks, guys.

Thanks, guys. First question is, how much of your Q1 production was hedged and at what level?

Hi Ross, this is Renee Zemljak. For the first quarter, we had approximately 1.5 Bcf hedged at a price of $4.39.

Okay. Also in the Tuscaloosa play, obviously it's early on, but it's a relatively wide range of performance on what you expect out of those wells?

Any thought of where if that's going to end up in terms of average production over time?

Ross, it’s Jeff Wojahn. Right now we are really focused on a number of milestones that we set for ourselves.

We believe that the recoveries for 7,500 foot horizontals could approach that 700,000 – 750,000 barrel EURs. There is obviously opportunity to increase that with a higher stimulation of our rock volume.

Okay. In terms of CapEx for 2013, I guess you guys are still talking $2.9 billion to $3.1 billion in E&P, what’s the total CapEx number?

Hi, it’s Clayton Woitas here, could you repeat your question, we had a little interference here.

Okay, I jump to 2013 CapEx, you guys have been talking about $2.9 billion to $3.1 billion in E&P spending, what is the total CapEx number expected for 2013, I didn’t know if there was midstream in there or?

Hi Ross, it’s Ryder McRitchie here. The total number that we have forecasted is between $3 billion and $3.2 billion.

Okay.

That’s before net divestitures of $0.5 billion to $1 billion.

Okay, perfect. And then on the San Juan play, I guess you’ve got 150 to 700 a day, any thoughts on where that may normalize over time?

We think that those rates are – the play is variable on rates and that’s one of the reasons why we’ve given a wide range, but I think that range represents where we think the potential for the plays at this time.

Okay. and then finally, on the rating agencies from Moody’s, have you guys had talks with them recently.

And do you expect to stay mid-triple stable or what are your expectations there? And I guess S&P just moved you down, but has you at stable, so they’re probably fine where they are.

Hi, it’s Sherri Brillon. We have had all of our rating agencies, DBRS, Moody’s and S&P confirm our BBB for equivalent rating within the last month or so.

We have stable outlook from DBRS, as well as from Moody’s. S&P did reduce their outlook to a negative outlook, and that was primarily driven by their outlook on natural gas prices, as well as waiting to see what our transition to liquids, how it progresses as well as for most agencies making sure that we don’t incur additional debt in order to finance the liquids transition.

Okay. Thank you very much.

Thank you.

Thank you. As a reminder, Encana’s Annual Meeting of Shareholders will be held this afternoon at 2 PM Mountain Time at Hotel Arts in Calgary.

A live audio webcast of the meeting as well as presentation slides will be available on our website. I’d like to thank everybody for joining us today and our conference call is now complete.