Ryder McRitchie - Vice President of Investor Relations Randall K. Eresman - Chief Executive officer, President and Director Sherri A. Brillon - Chief Financial officer and Executive Vice-President Jeff E. Wojahn - Executive Vice President and President of USA Division Eric D. Marsh - Executive Vice President and Senior Vice President of USA Division Renee E. Zemljak - Executive Vice President of Midstream, Marketing & Fundamentals William A. Stevenson - Chief Accounting officer and Executive Vice-President

Greg M. Pardy - RBC Capital Markets, LLC, Research Division Andrew Potter - CIBC World Markets Inc., Research Division George Toriola - UBS Investment Bank, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Robert Bellinski - Morningstar Inc., Research Division Philip R. Skolnick - Canaccord Genuity, Research Division S. Ross Payne - Wells Fargo Securities, LLC, Research Division

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Encana Corporation's Second Quarter 2012 Conference Call. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Encana Corporation. I would now like to turn the call over to Mr. Ryder McRitchie, Vice President of Investor Relations. Please go ahead, Mr. McRitchie.

Thank you, operator, and welcome everyone to our discussion of Encana's second quarter results for 2012. 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 39 of Encana's Annual Information Form dated February 23, 2012, 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. 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. In addition, in the first quarter of 2012, Encana adopted U.S. Generally Accepted Accounting Principles for financial reporting purposes, referred to as U.S. GAAP throughout this call. In 2011, the company prepared its financial statements in accordance with International Financial Reporting Standards referred to as IFRS. The adoption of U.S. GAAP has not had an impact on the company's operations, strategic decisions or cash flow. Full year 2011 and 2010 reconciliations between IFRS and U.S. GAAP are available in Note 27 to the company's annual consolidated financial statements prepared in accordance with IFRS. In addition, the company has also prepared supplemental U.S. GAAP financial information, including Encana's 2011 annual consolidated financial statements and selected 2011 quarterly financial information, which is available on the company's website at www.encana.com. Today, Randy Eresman, Encana's President and CEO, will speak to some highlights for the quarter and provide an update on Encana's outlook for the remainder of 2012 and into 2013. At the end of the prepared remarks, our leadership team will be available for questions. I will now turn the call over to Randy Eresman, Encana's President and CEO.

Thank you, Ryder, and thank you, everyone, for joining us today. On the financial side, during the second quarter of 2012, Encana continued to generate solid cash flow despite further downward pressure on NYMEX natural gas prices, which averaged $2.22 per million BTU, down over $2 from the same period in 2011. Encana's cash flow for the quarter was about $800 million supported by our strong risk management program and remains on track to meet our guidance for the year. With respect to production, second quarter natural gas volumes of 2.8 billion cubic feet per day. In the Canadian division volumes were primarily -- were lower primarily due to shut-in production and divestitures, which were partially offset by our successful drilling programs at Bighorn and in the Peace River Arch area. USA division, volumes were lower primarily due to shut-ins and curtailed production, divestitures and natural declines, partially offset by our successful drilling programs in the Piceance and Jonah. The majority of our activities in the Rockies are supported by historical joint venture arrangements. Average oil and NGL -- average oil and natural gas liquid production volumes of about 28,000 barrels per day for the quarter increased by about 4,000 barrels per day from the same period in 2011. The increase in liquids production volumes was primarily due to increased royalty interest volumes and successful drilling programs in our Peace River Arch area. We estimated that natural gas liquid volumes would have been about 5,000 barrels per day higher had the deep cut portion of the Musreau plant not been down for repairs during the quarter. The third-party midstream plants is expected to be back online by the end of July. We recently provided a comprehensive operational update at our Investor Day held at the end of June. As such,…

[Operator Instructions] Your first question comes from the line of Greg Pardy with RBC Capital Markets.

I think, Randy, you addressed most of what I was going to ask, but I did want to query just on where Sherri's expecting cash taxes to roll out this year and then secondly, as you move into 2013, will you continue to have a nice tax shelter and so forth as you move forward?

It's Sherri Brillon. Encana is currently estimating that income tax recovery for the year of approximately $300 million, including the transactions that closed as of June 30. The assets will then be impacted by our future divestitures and transactions and any other changes as they relate to the cash flow for year end and we'll update it -- as we go through the quarters. For next year, I had indicated at Investor Day, we were thinking of a cash tax of about $100 million, and so we are basically well positioned going into next year relative to our tax, cash tax position.

Your next question comes from the line of Andrew Potter with CIBC.

Just one quick question first, just on the investigation. I know you won't answer anything specifically but in terms -- I think you're really kind of wondering if there's any color in terms of timing like is this investigation like maybe go on for months or are we talking next year? Just any color like that and then also just wanted to confirm whether or not the Michigan lands are still in the U.S. package or whether those have been taken out. And then I have a few other questions after that unrelated to the investigation.

Okay. Andrew, we do have to reiterate that we are not in a position to provide any further updates regarding the Michigan matter at this time. However, I can confirm that we have taken the Michigan assets out of the U.S. liquids package.

Okay. And then just moving on, just a question in general, on the emerging liquids plays in the U.S. What are typical land tenures on a lot of these plays, like I'm just being very general here, but I've mean, like what are typical wells per section and over how long of a time period typically would you have to drill to hold lands?

All right. I have Jeff Wojahn and Eric Marsh tag team on this one.

Yes, the tenures on most of the U.S. are usually 3 plus 2 or a total of 5. Sometimes you have 3 years and then you have a kicker, and you can extend it for another 2 years. So the Mississippian and the TMS are 3 plus 2s, typically, occasionally, some 5-year leases, as well. But I think in Michigan -- or in the San Juans, it's a bit different than that, I would guess.

Yes. And federal land, there's also the opportunity to build units. In those cases, the land can be held for a much longer period of time

And how many wells is it typically on the nonfederal lands you haven't drilled on like to hold the section for instance?

On nonfederal lands, one well typically will hold the lease, Andrew.

Okay. And then the last question, just on NGL. I mean, you've done a good job laying out like all the deep cut growth and stuff in Alberta. Was there -- is there any opportunity for NGLs in the U.S. Rockies portfolio beyond what you're doing right now?

So, Jeff, could you talk about NGL growth potential in the U.S. Rockies region or anywhere else?

Oh, okay. Yes, I'm sorry, Andrew. I couldn't hear your question well. That's one of the areas that we're exploring right now is the natural gas liquids growth potential in the Rockies. Clearly, we have natural gas liquids opportunities in the DJ Basin where we're currently conducting a program there. Jonah [ph] field as well has about 10 barrels per million of condensate plus the upside around natural gas liquids in the Piceance basin also has natural gas liquids opportunities. So there's a number of objectives around that. We're evaluating that further, and I think we'll have more guidance around that as we kind of firm up our 2013 plans.

So that would be kind of incremental to what you've laid out there already, I guess.

Yes, Andrew, it's fair to say that a lot of our gas in the Rockies is relatively high Btu content gas. Some of the contract arrangements that we have in place today need to be modified in order for us to capture that gas, and we're working on that. So that's what's Jeff is referring to.

Your next question comes from the line of George Toriola with UBS.

The question is around the Cutbank Ridge assets, the 10% package that you have. Can you go through the rationale for that? What's the basis for wanting to sell 10% here? Is it just to raise cash? Is there some other sort of strategic reasoning that you have here?

Yes, George. It is primarily to raise cash in the short run but when we originally marketed our Cutbank Ridge partnership assets, we were looking for up to a 50% interest in those assets to be taken by a partner. Mitsubishi elected to take a 40% interest and so since we've gone through all of the work of assembling the asset packages, it's a relatively easy package for us to put out and continue to market. And we've effectively done that at this point in time really looking for the future.

Okay. And to the extent that you're able to do that, you don't foresee any difficulties in sort of operating the asset or just getting an agreement between more than 2 parties going forward?

No, we don't. We've structured it in a way that it'll work for us.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Looking at the NGLs for the quarter with the 5,000 barrels a day or so that you had due to outages, are those back on now? And I guess, should we expect for the third quarter that, that oil production would be north of, I guess, the improvement on NGL pressure will be north of the combined kind of 33,000 looking at the 28,000 from the second quarter and adding 5,000. Can you just talk a little bit about the trajectory of oil plus NGLs between now and the end of the year?

Brian, as we said, we're likely to bring on the Musreau facility by the end of July, at least that's the plan for now. And it would add an incremental 5,000 barrels per day. Generally we're in growth mode. So, I think you can do the math, but I think you've probably done it well.

Yes, okay. And then on the natural gas side if we look at what fell quarter-on-quarter, can you talk to how much of that was due more to your own decisions to shut things in versus natural declines versus asset sales?

We -- quarter-over-quarter, I may not have that number specific, but I can say from quarter-to-quarter, if we're saying first quarter to second quarter of this year, we did shut in about 500 million a day in the second quarter, shut in or curtailed in different ways. So that's the major difference between first and second quarter. And it would also reflect the major difference between last year and this year. Although we did say coming into the year that due to less capital investment in our dry gas plays that our overall production for the year on natural gas would be down about 7%. So there would be some component of that although, I do expect it to be more later in the year as that comes into play.

And then lastly, can you just give us any updated status on Kitimat, and whether some of the additional deals that we've seen both on the upstream side in terms of corporate acquisitions and then also within the additional LNG plant discussions, whether you see any increased competition or any reason for why we should expect a kind of any delays there in terms of getting supply contract signed.

Yes, I think it's all positive. Everything you hear about investments in Canada, investments in LNG is all positive for North America in natural gas. I think that there's generally a positive environment about LNG on the West Coast Canada, and I continue to believe that we will eventually have our project proceed.

Great. Are you still expecting that by year end?

We're really subject to the market itself, and we defer to our partner to provide the direction on that.

Brian, it's Ryder McRitchie. I just want to give you a little bit more clarification, our Q1 volumes did include about 100 million a day of shut-in impact in that. So the difference from Q1 to Q2 is an additional -- it went from 100 to 500 in Q2.

Your next question comes from the line of Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: A question on the shut in, and what price or under what logic do those shut-ins come back into the market?

Okay, I'll have Renee Zemljak our Head of the Marketing and Fundamentals provide some color on that.

Sure. This is Renee. With regards to our curtailed volumes, there's a combination of things that we would consider before bringing volumes back on. I will say that we're very encouraged with the recent increase in prices that we've seen, but we'd like to see that the increase in the prices be more stable before we actually bring the volumes back on. And then, in addition to just considering prices, we have to consider stakeholders that are directly involved with our curtailments, as well as our field operations. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: And then a related question. I see on the natural gas contracts, you picked up some options on NYMEX collars without any notional volumes or an average price. Were you hedging in the quarter?

We did actually put into place a very small amount of collars in the quarter. The volume and the value of them was pretty immaterial. So we just didn't provide the information. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: And then I guess the final follow-up. On the impairments, what were the oil and gas properties that failed the ceiling test?

Bill Stevenson will provide some color on that.

With the ceiling test on the quarter, it's done on a country-by-country basis. So basically we have Canada and the U.S., and we had $0.6 billion impairment in Canada. We have $1.1 billion in the U.S. So it's not done on a property by property basis.

Your next question comes from the line of Robert Bellinski with Morningstar.

I was interested to hear your thoughts on NGL prices going into 2013 as you ramp up production, as well as the potential to hedge NGLs and move some of the uncertainty from 2013 cash flows.

Okay, Renee will provide some color around that as well.

Okay. With regards to our view on NGL pricing for 2013, we do believe that between now and probably 2015 as it relates to ethane, the market's going to be in the fairly tight situation. So we're expecting to see relatively volatile prices for ethane. That being said, the majority of Encana's ethane is sold under long-term contracts at prices that are significantly higher than where the current market is today. With regards to propane, we think that the current level of really weak prices in propane will actually recover as we go into the winter, as winter demand picks up, as well as the exports that are expected to come into service by the end of this year. So in the longer term, including 2013, we think propane prices will return to more historical levels, which is about 55% of WTI and longer term, probably past 2015, we think ethane prices will return to closer to 30% to WTI.

Okay. And then just one more, I certainly appreciate the thinking behind the higher gas prices down the road, it's a thesis we share as well. But just to play devil's advocate, what could Encana do operationally to lower its supply cost to levels more in line with the natural gas prices we're seeing today just in case we're all wrong?

Well, what we will continue to do is invest in just our highest return plays, and so if we had a continued environment of lower natural gas prices, we would just reduce our capital investment in natural gas plays until the market comes back into balance.

[Operator Instructions] Your next question comes from the line of Philip Skolnick with Canaccord Genuity.

You've had pretty big hedging gains year-to-date, and your hedges fall off next year a lot. So if you don't get the JV and asset sales proceeds that you're expecting to get, how do we think about the production guidance that you laid out for next year, given there could be a big cash flow CapEx gap there?

It will really depend on what natural gas prices are in the market next year and...

If they're flattish?

If they're flat for this year? I would expect that we would substantially reduce our dry gas program. We will probably even have to reduce our liquids program as would virtually every other gas producer in the market -- or sorry, our programs with investment, new investment in natural gas liquids would also have to be reduced, depending on what liquids prices were, of course, and what liquid volumes were, of course.

So what kind of spending would you need to keep production flat?

As we've said before, the combination -- it's kind of a unique year for Encana because we do have our new project coming on late in the year and that has a potential, at full capacity to add about 300 million cubic feet per day of production. We also have a significant amount of curtailments that are, curtailments and shut-in this year that we had initially projected would be back on stream sometime next year. So we have a lot of volume upticks that would offset our natural declines. So I don't think it would have a really material impact on production in 2013 versus 2012. And we said that it would be around 3 Bcf per day. I don't think if we took a significant amount of capital investment out of our 2013 program that it would materially impact 2013. It would start having pretty significant impacts on 2014, though.

Okay. And then, the final one. Any -- sorry, debt covenants associated with the impairments. Do you have any further impairments the coming quarters?

Have Sherri Brillon.

No, I don't think there will be any covenants that are breached or approached as a result of any further impairments.

Your next question comes from the line of Ross Payne with Wells Fargo.

Touching on hedges just one more time. The last data point I had was around 17% hedged for 2013. Is that roughly where you are today or what's the update?

That's accurate. We have not put any significant hedges on the last quarter.

Okay. The second question I've got, it sounded like you were selling some liquids-rich assets in Texas. How do you think about that given that you're trying to push more towards liquids? Is it just to bring in a JV there? Is this a direct sale?

Yes, both our -- in Texas, we've got our Eaglebine assets are part of a JV package, and our expectation is that between a combination of upfront capital and the carry component on that play, it will help us move those plays, that play, and a couple of other plays, the Tuscaloosa marine shale and our Mississippi and Lime play to commercialization at a faster pace and at a lower cost for Encana. During the period of time where you have relatively high cost in the early days of the play. So it's really to help us get to commercialization at a faster pace, and we believe that we have the substantial enough position in these plays that by reducing it by a small component, it could be anywhere from 30% to 50% because 50% wouldn't be considered a small component but by reducing it to that amount, we still have lots left over for ourselves to provide a substantial amount of potential liquids drilled over time.

Okay, and also with the increased CapEx budget for 2013, how are the rating agencies looking at that? Currently, you're stable by both. It looks like you will have to have some asset sales here to bridge the gap, but how comfortable are they with your 2013 plan?

Well, I guess at this point, at this time, what we've said to the rating agencies is that that's a preliminary expectation for spending in 2013, but we would not spend at that level unless we are able to first bring in additional cash receipts through either divestitures or upfront cash payments on joint ventures.

At this time, we have completed the question-and-answer session, and we'll turn the call back to Mr. Ryder McRitchie.

Thank you, everybody, for joining us today. Our conference call is now complete.

This concludes today's conference call. You may now disconnect.