Paul Gagne - VP, IR Randy Eresman - President and CEO Sherri Brillon - EVP, Strategic Planning and Portfolio Management Brian Ferguson - EVP and CFO Jeff Wojahn - EVP and President, USA Region Don T. Swystun - Executive Vice-President and President, Canadian Plains Division Michael McAllister - VP, the Peace Country Business Unit Gerry Protti - EVP, Corporate Relations, and President, Offshore and International Division

Brian Singer - Goldman Sachs Mark Gilman - The Benchmark Company Stephen Calderwood - Raymond James Pat Roche - Nickle's Energy Group Ian McKinnon - Bloomberg News Jon Harding - The National Post Norval Scott - The Globe and Mail David Ebner - The Globe and Mail

Thank you, operator, and welcome everyone to our discussion of EnCana's 2007 fourth quarter and year-end 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 23, 2007, the latter, 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 reference 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 Sherri Brillon, Executive Vice-President of Strategic Planning and Portfolio Management to provide further highlights on our reserve additions.

Brian Ferguson, Chief Financial Officer, will then turn over... will then discuss in more detail 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. This conference call highlights our performance in 2007, my second year as CEO.

As you saw in our new release this morning, EnCana performed very well in 2007 achieving strong overall results. It was a year in which we met or exceeded virtually all of our targets, which we believe is a reflection of the merits associated with EnCana’s strategy, execution, and our disciplined approach to the business.

During the year, we accomplished several major strategic milestones. We began the year with the completion of the transaction with ConocoPhillips that gave us 50% ownership interest in two US refineries.

It positioned us to pursue a clear, low-risk development plan for our oil resources at Foster Creek and Christina Lake. In East Texas, we solidified our position in the Deep Bossier play in the Amoruso Field with the acquisition of our partner’s interest in the area, a play that we believe will in time become one of EnCana's top resource plays.

At Jonah, we had a significant improvement in performance resulting from enhancements made to both the completion technique and to the compression and gathering system. These changes allowed us to increase production by 20% from 2006 levels, averaging about 560 million cubic feet per day for the year.

During the year, we expanded our exploration land base in and around several of our key resource plays in both Canada and United States, ensuring a steady supply of future drilling opportunities. Although we succeeded in growing at a significant pace this past year, EnCana's goal is not about being the biggest, it's about having the highest quality assets.

As such, we will continue to be disciplined in our approach to acquisitions and divestitures, always with the goal of improving the overall quality of our portfolio. Now, let's take a look...

more detailed look at our results. The news release outlines our 2007 financial and operating results for both the fourth quarter and year as a whole.

I'll focus on what I believe are the highlights. First, greater than expected natural gas production growth.

Our North American natural gas production grew 6% year-over-year, almost twice our original forecasted growth rate. This was achieved by a 14% growth from our key natural gas resource plays, most significantly Jonah, East Texas, Cutbank Ridge, and coalbed methane, more than offsetting the impact of declining production from EnCana's historical Canadian production base.

Second, very strong financial performance, driven by increased gas production, higher liquids prices, realized financial hedging gains, and very strong refining margins. EnCana achieved cash flow of $11.06 per share diluted.

That's up 29% on a per share basis compared to 2006 and again, ahead of guidance. This was accompanied by strong bottom line performance represented by operating earnings of $5.36 per share diluted, a year-over-year increase of 37%.

Third, capital discipline, capital costs and operating costs for the year were in line with our guidance. Adjusting for the foreign exchange impact that we experienced during the year, these figures are significantly better than our guidance numbers, evidence of the great strides that were made through the year driving greater efficiencies into our operations, a huge credit to our teams.

And fourth, strong resource growth, proved reserves increased 12% to about 19 trillion cubic feet of gas equivalent, and we replaced 227% of the company's 2007 production on a pro forma basis. We believe the resulting play and development cost at $1.65 per 1000 cubic feet equivalent continues to be very competitive.

More importantly, since EnCana is principally a natural gas company, our natural gas related reserve additions were also very strong, replacing 167% of production and growing proved reserves by 7%, which was all achieved at a very attractive planning and development cost of $2.40 per 1000 cubic feet. The stability of our asset base combined with strong financial performance as we reported today gives us the confidence to once again double our quarterly dividend.

On an annualized basis, this would equate to $1.60 per share. Now, focusing on gas production, EnCana's average annual production of 3.6 billion cubic feet per day, represent a growth of 6% for 2007.

Our gas development programs added over 900 million cubic feet per day of new production, offsetting average annual declines of about 22% and providing the incremental growth. We expect about 90 natural gas reserves plays will continue to lead our production growth in 2008, in which they are forecasted to grow by approximately 12%.

While all of our key resource plays have performed well, those in Texas, British Columbia, and Wyoming are expected to contribute the majority of our year-over-year growth in 2008. We are excited about the performance we've seen this past year and the future potential of regions such as Amoruso, Cutbank and Jonah.

At East Texas, we are very encouraged by our results we are seeing today. We have integrated the 3D seismic program completed last year into our geologic model, successfully targeting a number of entrant wells so far this year.

Initial production rates from these recent wells in Amoruso are currently exceeding our expectations with several individual wells testing at rates over 30 million cubic feet per day. In fact, our last ten wells have averaged over 24 million cubic feet per day.

We have also made solid progress in adding new infrastructure. Our Ridgemont [ph] facility in Texas was commissioned last week, adding an additional 80 million cubic feet per day of processing capacity.

Looking at inflation, we’ve started to see some moderation in US cost structures. We believe this has been partly driven by the impact of the credit crunch in the US on smaller E&P companies’ ability to access capital, resulting in reduced activity levels.

In addition, we are benefiting from the steps we've taken across all of our programs, both in United States and Canada. These include reduced growing costs and increased efficiencies related to the fit-for-purpose rigs currently operating in our fleet and optimizing factoring and completion programs that have driven step changes in our cycle times for some of our plays.

For 2008, we expect overall price inflation will be between zero and 5% in United States and relatively flat in Canada, excluding the upstream portion of our Integrated Oil business, which we expect will be between 5% and 10%. We believe the efficiencies we’ve built into our operations will help significantly offset these increases, getting back to the trend whereon prior to 2005 when we targeted a minimum of achieving new efficiencies each year to offset inflation.

Now despite this, some of our plays in Alberta are becoming less competitive compared to early years and compared to the rest of our portfolio, particularly emerging gas plays and those affected by the proposed changes to the deep gas royalty program. Despite relatively strong natural gas prices, we expect that the changes to the royalty regime will continue to negatively impact activity levels in Alberta.

Now, regarding industry activity, current regularization rates continue to be very high in the United States, while at the same time are very low in Canada. Corresponding to this difference in activity, we are moving some of the newer mobile rigs in our fleet out of Canada and into the US to work on our projects there.

Specifically in Alberta, we expect industry activity levels to fall off for the remainder of the year following completion of this winter's growing season. This will have a cascading impact on all industry-related activity in the province.

While this should reduced some service costs, we continue to see cost increases in labor, steel, property taxes, and energy, which we believe will more than offset any benefits in the short-term. For EnCana, we’ll continue to evaluate various supply management initiatives.

Due to the reduced level of industry activity in Alberto, we are seeing a number of positive indications that may allow us to make strategic commitments, leveraging the size and sustained activity level of our field operations. Longer-term, we believe that industry, the service sector, the Government of Alberta, and the people of Alberta will need to work together to re-establish the competitiveness of the development of Alberta's conventional oil and natural gas resources.

EnCana will play a constructive role towards that end. Coal production continues to be quite strong.

However, we have experienced some [inaudible] in Alberta and British Columbia associated with the extremely cold weather in January and February of this year. It will have a minor impact on first quarter production, but we don't expect it to have much impact on our annual targets.

We expect first quarter natural gas production to be relatively flat compared to year-end numbers, followed by gradual ramping up through the remainder of the year. Now, looking at our Integrated Oil business, it had an outstanding inaugural year, benefiting in particular from the Downstream Segment with higher than expected crack spreads.

For the year, operating cash flow from our Integrated Oil business was almost $1.3 billion compared to about $275 million in 2006. In the Upstream portion of the business, production from Foster Creek and Christina Lake steam-assisted gravity drainage projects was up about 25% over 2006 on a pro forma basis, as described in the news release.

This was largely a result of the completion of Phase IC at Foster Creek, which has increased planned capacity to 60,000 barrels per day. Construction for phases ID and IE at Foster Creek and IB at Christina Lake are all well under way.

In addition, Christina Lake Phase IC has also been approved by the EnCana and ConocoPhillips upstream partnership. In total, we expect to add about 112,000 barrels per day of additional capacity in varying stages over the next two to three years.

EnCana has a long history as a leading SAGD producer. The key element to our success has been our low steam-oil ratio.

Foster Creek and Christina Lake's overall steam-oil ratio of about 2.5 times is amongst the best of existing industry SAGD projects, and we are continually looking for new approaches or technologies to make it even better. Reducing this ratio improves both our margin and our capital cost, which in turn reduces our environmental footprint.

We've made considerable progress in reducing the environmental impacts of our projects over the last ten years and we're strongly committed to continue to make improvements in the future. Regarding overall project cost, we expect to execute our Christina Lake IC expansion of 40,000 barrels per day at a capital efficiency of approximately $19,000 per barrel per day, which is very competitive in today's cost environment.

We are also working with our partner in the Integrated Oil business to provide the updated schedule and capital cost for a major downstream expansion planned at the Wood River refinery. We expect to be in a position to make an announcement on this once regulatory approval has been obtained.

I would now like to turn the call over to Sherri Brillon, Executive Vice President of Strategic Planning and Portfolio Management, who will discuss EnCana's 2007 reserves reporting.

Thanks Randy, and good morning everyone. In 2007, EnCana added 3.6 trillion cubic feet equivalent of proved reserves.

Overall, our reserve life index remained at about 12 years. Finding and development costs were $1.65 per 1,000 cubic feet equivalent, a decrease of 17% from 2006.

EnCana’s three-year average finding and development cost is about $1.60 per 1,000 cubic feet equivalent, which we believe represents top quartile performance in our peer group and is representative of our longer-term track record. For our natural gas programs, finding and development cost were about $2.40 per 1,000 cubic feet, a decrease of 11% from 2006, again a very competitive result.

Our reserves continue to be 100% externally evaluated by independent qualified reserve evaluators, not just reviewed or audited. By commodity and by geographical region, revisions to opening balances were positive.

Substantial additions and positive revisions in Canada were largely attributable to development drilling and optimization activities in Cutbank Ridge, Bighorn, coalbed methane, and Shallow Gas with respect to natural gas, and in Christina Lake and Foster Creek with respect to crude oil. In the United States, substantial natural gas additions and positive revisions were largely attributable to development drilling and optimization activities in Jonah, Piceance, and Fort Worth.

In total, drill bit additions, that is extensions, discoveries, and revisions, are 3.4 trillion cubic feet equivalent or about 10% higher than in 2006, while the associated capital expenditures in 2007 are $5.6 billion or down approximately 8% year-over-year. Natural gas related drill bit additions of some 2 trillion cubic feet were equally split between Canada and the United States, approximately 90% of which were from our key resource plays.

While we are focused almost entirely on North America and predominantly in natural gas, our operations are diversified across the continent located within most of the major and emerging producing basins. This diversification reduces operating risk in our portfolio and exposes us to opportunities created by ourselves as well as others.

This diversification is also reflected in the average production efficiency we achieved for our natural gas portfolio of about $6300 per thousand cubic feet per day. For 2008, this figure is estimated to be about $6100 per thousand cubic feet per day.

Overall, I believe that this figure highlights the relatively low cost organic growth capability associated with our asset base. I will now turn the call over to Brian Ferguson, our Chief Financial Officer, who will discuss our financial results in more detail.

Thanks, Sherri. Good morning everyone.

I'm excited to talk to you about our excellent 2007 financial results. For the year, cash flow exceeded our budget and we beat our guidance to the market.

Operating earnings were very strong. We continued our industry leading cost performance, despite the skyrocketing Canadian dollar.

Our total price realizations benefited from our hedging strategies, increasing our overall netbacks by about $1 per thousand cubic feet equivalent for the year. Cash flow exceeded total capital investments, excluding A&D activity, by more than $2.4 billion, which was enough to fund share purchases under our normal course issuer bid of 5%, and we doubled our annual...

our quarterly dividend in 2007 to an annual amount of $0.80 per share. As Randy mentioned, we have doubled the quarterly dividend again this year.

Now, focusing on our fourth quarter, cash flow of $1.9 billion increased $173 million, primarily due to an increase in netbacks after hedging, higher volumes from upstream operations, and our new downstream division added another $180 million of operating cash flow before tax in the quarter. Operating earnings of $849 million were up a $174 million from 2006.

Increases in upstream and downstream operating results that I outlined in the cash flow were somewhat reduced by higher DD&A, which is largely due to the foreign exchange, high Canadian dollar, and a $44 million impairment of our France assets. Net earnings were $1.082 billion in the quarter, up $419 million from 2006.

In addition to the items I just mentioned, net earnings increased due to a federal tax rate recovery and a realized foreign exchange gain variance from the prior year. Offsetting the positive variance is a swing in the unrealized mark-to-market gains, reducing net earnings by about $460 million [ph] after-tax in the fourth quarter.

For the full year, one of the biggest financial challenges for us in 2007 was the run-up of the Canadian dollar relative to the U.S. dollar.

It increased reported operating cost by about $65 million in the year and reported capital by nearly $200 million in the year. Let me comment specifically about our fourth quarter cost, which were inside our guidance range.

Operating costs were $1.02 per Mcf equivalent, and that’s up $0.12. Foreign exchange added $0.12 and higher long-term incentive costs due to the appreciation in the EnCana stock price added another nickel.

If not for these, our operating cost on a per unit basis, Q4 versus Q4, would have actually been down. Administrative costs at $0.29 per Mcf equivalent were up $0.08, essentially all related to the impact of foreign exchange and higher long-term incentive cost.

For 2008, we've budgeted the Canadian dollar at parity with the U.S. dollar.

We'll see what happens. We have a natural hedge against further increases in the Canadian dollars since we have 72% of our long-term debt in U.S.

dollars at year-end. With regard to hedging, we take a proactive approach to managing the risk of commodity price changes and basis exposure.

As you've heard, our 2007 risk management program was successful in protecting us from the downside risk associated with commodity prices and basis exposure. This approach to managing topline risk allows us to lock in the early returns on our new capital investment and gives us greater certainty on our cash flow and ultimately more sustainable free cash flow.

This is clear evidence of our commitment to generate free cash flow over the long-term and return it to shareholders. As we've noted in our supplemental information, realized hedging gain on natural gas was $1.33 per thousand cubic feet equivalent for the full year, which translated into higher annual upstream revenue of approximately $1.1 billion after-tax.

For 2008, through to the end of October to the end of the gas year, we have certainty on pricing on about half of our forecast natural gas volumes. We have fixed price swaps on about 1.9 billion cubic feet per day at an average NYMEX equivalent of about $8.20 per 1,000 cubic feet.

Our dividend policy is further evidence of the commitment to the sustainability of our cash flow generation. Our Board of Directors approved the doubling of the quarterly dividend again in 2008.

On an annualized basis, this would amount to $1.60 per share and would be expected to provide one of the highest yields of our E&P peers. Last but not least, our balance sheet remains strong.

Net debt to cap at December 31 was 34%. This is an increase over 2006, largely due to the East Texas acquisition we completed in November.

Net debt to EBITDA finished the year at 1.2 times. During 2007, we undertook three public note financings and in January we completed another.

This gives EnCana tremendous financial resilience to further deterioration in US economy and a potential impact on the capital markets. Currently, we have about 80% fixed-rate debt at an average after-tax cost of less than 4%, overall an excellent year financially.

We are well positioned for another good year in 2008. I will now turn the call back to Randy.

Okay. Thank you, Brian.

As I stated earlier, our 2007 results are very positive, a credit to our strategy and to our teams across all of EnCana. I would like to take this opportunity to thank them all for a tremendous year for delivering on our goals and for the way they've represented EnCana in all the communities we conduct business.

They have done so with pride and in a professional, caring, and respectful manner. Thank you for your contributions in 2007, and I look forward to another strong year ahead.

During 2007, we continued to demonstrate what we believe to be industry-leading performance in the development of unconventional natural gas and in situ oil recovery. We believe that strength, stability, and profitability of our approach to these businesses is becoming clear and better recognized by both industry and investors.

We’re continuing to focus on a moderate, sustainable pace of growth, capital discipline and return of excess cash to shareholders during through an ongoing program of share purchases and planned dividend increases. This is our strategy, this is our business, and this is our culture.

For 2008, our operating challenge remains excellence in execution and that continues to be our focus. Overall, our shareholders should expect the same consistent and disciplined approach that we have demonstrated over the past years to continue in 2008 and into the future.

Our spending and production growth plans are consistent with our strategy of executing with excellence and generating sustainable growth. In 2008, we expect total production to average about 4.6 billion cubic feet equivalent per day, which is about a 5% increase over 2007.

Natural gas production is expected to grow by 6% year-over-year to about 3.8 billion cubic feet per day. Overall, we expect that our key resource plays will continue to drive growth with production forecast to increase by 13%.

Operationally, we are very happy with the current run rate for operations and the resulting production growth and flexibility that it provides in allocating capital. Commodity prices have been volatile, but we remain bullish on natural gas in North America.

I'm often asked how we would react to an increase in gas prices. My answer should not be a surprise.

If short-term commodity prices exceed our expected range for the year and we generate greater cash flow than forecast, we expect to use those incremental proceeds to buy back additional shares or pay down debt. f we believe that a longer-term structural change occurs in North American commodity prices and the potential exists for our margins to expand on a sustainable basis, we plan to use that additional free cash flow to increase our dividend.

This is how we believe that we can best create sustainable value for our shareholders. Thank you for joining us today.

Our team is now ready to take your questions. Question and Answer

Thank you. Good morning.

Good morning.

Randy, just following up on your last couple of sentences there, if short-term commodity prices increase, you buy back stock or pay down debt and longer term you would increase the dividend, no increase in drilling mentioned there. Can you talk to the constraints rig permitting people potentially and why you wouldn't do that even if your long-term gas price forecast increase based on your rate of return decisions?

As we’ve talked about in recent years, we believe that having a long-term sustainable growth rate at about 5% allows us the greatest amount of flexibility in our portfolio to create the largest long-term return to the shareholder, and that by using excess or free cash flow to buy back shares we'll generate a significant overall per share growth for the company. Having that level of flexibility has been a tremendous asset to the company in portfolio management in this past year, and we expect that on a going forward basis it will create many, many opportunities for us to maximize profitability from our portfolio.

If service costs do begin to tick up again, would you be prepared to lay down rigs or you would just maintain your level of activity and use the additional cash flow for drilling, without an increase in --?

If we saw the activity levels getting into the pace of growth that we saw in 2005 and 2006, we would definitely not try to chase production. We would tend to try to manage the situation as best we can and we would give up production growth for profitability in that scenario.

And then, what we have done in other hand… another situation when activity levels tend to fall as they are in Western Canada, EnCana is the company that's basically drilling right through it, taking advantage of those lower costs.

Right. I apologies if this was discussed earlier.

Costs seem to tick up a bit during the quarter, LOE, DD&A, SG&A. Could you speak to what drove that?

Yes, as Brian Ferguson pointed our, the cost increases that we saw fourth quarter over fourth quarter were primarily due to the significant run-up in the Canadian dollar against the US dollar, that had the majority impact, but then we also have long-term in the sense that we charged against operating cost and because of depreciation of the cash share price throughout the year that had a cost impact on operating costs, but when you remove those two items and compare it to 2004, you we’d actually found that our operating costs would have been down. And all of this was within in our guidance range anyways.

So it shouldn't be really unexpected.

Okay, last question. Should we expect any additional acquisition activity or should we look at your acquisition as one-time?

Brian, we don't have anything that's a major plan right now. If there were opportunities that came up throughout the year we would certainly look at them, but you would have to consider the same kind of opportunities that we've been looking for in the past.

These have been in joint operations that we know very well. And since most of the operations that EnCana has were effectively close to 100%, there aren't that many of those kind of opportunities in our portfolio.

Great, thank you.

Thank you.

Guys, good afternoon. I had a couple of things.

Randy, I just want to clarify that I heard you correctly. In terms of your comment about first quarter this year, production has been roughly comparable, I think you said to the year-ago, which would imply some fairly significant… a fairly significant decline from fourth quarter.

Is that indeed what you indicated?

No. Sorry, Mark, if I said that I didn't mean to.

We would expect it to be relatively flat from fourth quarter 2007 to first quarter. That's generally a pretty normal event in our industry.

Okay, thanks. That helps a lot.

Secondly, is it possible to give us a rough idea what the year-end '07 reserve numbers might look like under the new Alberta loyalty regime, assuming a similar price level?

No. We haven't done that yet because the regulations have not been put into...

I guess into effect yet, and there are still some changes that are likely to occur before they are finalized. We have done some preliminary assessments and the impact for us because the majority of our land-basin activity is on land that we own, pretty simple, the impact for us is not all that significant.

Okay. Finally, just one other one on the reserve picture, is it possible perhaps to give us an idea for the natural gas reserve increases, how they break down between increase and recovery rate on the one hand versus increase and in-place type assessments on the other?

I don't think we have that kind of detail just readily available. It'd be something we could provide more if you want to have a detailed discussion on a play-by-play basis outside this conference call.

Okay, Randy. Thanks very much.

Okay. Thanks, Mark.

Yes, good morning. I noticed...

well, everyone has noticed your increase in capital or sort of an operating cost in Q4. And as you mentioned, it's well within the context of your guidance.

In fact, on the gas side, it looks like your full year operating costs were about $0.03 lower than your guidance of $0.85. So I guess at least a question if I could on the future guidance, you are calling for $0.95 operating cost in 2008.

Is most of that increase in operating cost again due to foreign exchange or do you characterize certain amount of that increase due to cost inflation?

I'm going to turn that over to Brian Ferguson to get a little bit more detail on it, but there are a number of things that continue to influence operating cost. Certainly, one of them is just energy cost in general being higher.

That flows through because there is a lot of transportation related activity when it comes from operating cost. We've also seen a pretty strong uptick in property taxes in the last couple of years, and that's is having fairly significant influence, particularly in our Canadian operations.

And for some additional detail regarding FX I am going to turn it over to Brian.

Hi, Steve. The [inaudible] that we are forecasting in increase is labor component as well in 2008 versus 2007, but again the lion’s share of the increase is related to the US Canadian-dollar.

We saw it averaging about $0.93 last year in 2007 and we are forecasting $1. As I said, we will see what happens there.

Again, I would emphasize that you have to distinguish between the economic versus the reported, the actual reporting disclosure impact in our Canadian operations, because we report in US dollars we won't see quite the same impact. There is also probably a slightly higher impact from property and mineral taxes.

And that's your...

We're also forecasting our stock price to go up, so we've built that in as well.

Stephen, this is a great opportunity for me to also mention that despite the increases that we have observed in operating costs and likely industry will be exposed to the same ones. EnCana continues to have amongst the very lowest operating cost in the industry and that's a direct relationship of the unconventional resource plays that we pursue in their low cost nature.

Okay, great. If I may ask, you mentioned your recent success at drilling in the Amoruso Field, and I just wonder if you're still planning on drilling outside the core areas there?

I think you are planning on drilling a well in Louisiana?

I am going to have Jeff Wojahn, our President for US division, speak to that.

Hi, Steve. It’s Jeff.

We have plans… I think it was stated said earlier that we are going to drill three or four exploration wells on the Jurassic Trend or on the Amoruso Trend. We haven't drilled any yet or spud any, but that's our intent.

We do as you know have a very large lion position on the trend, 180,000, 190,000 acres. So we would like to get around to valuating that land, and we have some exiting prospects developed.

So as we have results I think we'll keep you posted.

Do you mean later in 2008?

In 2008, yes.

Thank you.

Thank you.

Hi. I’ve just got a couple of hopefully brief questions.

First question is your Canadian gas production is forecast to be down about 5% for this year. Can you give me a breakdown by property, how much of the decrease will occur at which property in Canada?

Okay--.

Gas production?

I'm not sure that I will be able do that right off the top of my head here, but I can generally say that in the Foothills Region, we are continuing to see some growth. It really is largely driven by our BC properties, and in our plains division, our more matured natural gas properties are in somewhat of a decline.

I’m going to turn it over to Don Swystun to elaborate on that. And Mike McAllister is here and he is sitting in for Mike Graham, he can maybe provide a little bit more color on the production changes in his division… the Foothills division.

Hi, Don Swystun for the plains. Just… obviously our biggest producing resource play is the shallow gas and we produced around 726 million a day in '07 and we are targeting right now about 675 million a day for '08.

So that's the decrease you will see.

This is Mike McAllister with the Foothills division. Our production growth will be larger in BC than in Alberta, but I think across the entire division we’ll slightly flat to a little bit increasing.

Our biggest growth areas would be in Cutbank Ridge and as well as in Greater Sierra a little bit.

And my next question is you are forecasting a 23% increase in U.S. gas production.

How much of this is due to the Bossier acquisition?

I'll turn it over to Jeff Wojahn to answer that.

Yes. Hi, Pat.

It's Jeff.

Hi, Jeff.

I would like to give you kind of a perspective of where we are and where we're going because I get this question a fair amount, but last year our production averaged for the year 1340 million cubic feet a day, where our current production is just over 15.10 million [inaudible] cubic feet a day and we are forecasting to average for the year in the 15 to 16 range. So of that 23%, we have already experienced 14% or 15% as we've gone through.

So it’s a function of a growing profile and also a function of the acquisition at Amoruso that we conducted in the fourth quarter last year. The primary growth areas for the remainder of the year will be from the East Texas area complemented by our Fort Worth program our Jonah and Piceance areas.

Thanks. And my third question was sort of tying the two together to some extent.

You mentioned… Randy, you mentioned the low rig count in Canada and the high rig count in the U.S., and I know this was happening before Alberta announced its royalty changes and it has been the case for some time. I guess we've had a slowdown here now for the past 1.5 years at least, that the U.S.

just keeps on at the same fairly rapid pace. Can you tell us a little bit about the reasons for that?

How much is due to dollar, how much is due to the other factors, can you just discuss those?

The differences as you point out that started to emerge prior to the royalty review were largely due to the Canadian dollar. If you look back four or five years, the Canadian dollar has appreciated like 40%, 50%.

So that has had a significant impact. Of course, that does increase the purchasing power to some extent of the Canadian dollar, but that takes a longer period time before it moves through.

The other impact of course has been that operating costs in Canada have been... tend to move higher because of the strong level of activity throughout all of Alberta, the construction activity and the activity related to oil sands.

Despite having a fall-off in conventional oil and gas activity, we haven't yet seen labor costs coming down to a degree that they would need to be in order to have activity pick-up significantly. And then, there are some other issues as well.

A number of the targets that Canadian companies have been chasing in the last number of years tend to be a little bit smaller in nature when we compare it to the kind of targets that we have in our U.S. activity.

So production efficiency tends to be a lot better in our U.S. operations in general.

And so that would tend to be one of the reasons why U.S. activity levels are higher than Canadian.

But then you really have to go back a little bit farther and say, part of this was definitely caused by the changes to the royalty trust, which has reduced the activity level there and then the impact that, that had subsequently on the junior sector. So a lot of things have changed.

We can't point at one individual thing. And then, the changes to...

pending changes to royalties just are one more compounding effect.

Okay, just one last question with a very quick answer. Can you give any kind of ballpark estimates when you would be able say something about BC shale gas?

We certainly have a few more wells into the play by the end of this winter's drilling season, but I'm not sure if at that point it will be enough information for us to make any significant determination. It is an early life exploration play as far as we're concerned.

Okay. Thanks very much.

Thank you.

Hi, a couple of quick questions. Randy, any size and scope on divestitures this year, after you said Leor acquisition, you would look at maybe selling up to $500 million.

I'm wondering if you've got any better clarity on that issue?

Yes. Our intention at this point in time to look at a potential disposition of $500 million worth of assets.

We've got I think about half of them already targeted for sales, the other half we're in the process of putting together packages that will be... that will come out throughout the year.

And any areas like Canada, U.S., where are you looking at selling assets?

Well, we have some reason is in both Canada and United States to sell some of our smaller and more scattered assets. I think we would consider to be non-core, due to the packages themselves could end up being quite a bit larger or smaller than that $500 million depending on how we view the market conditions and the opportunities at the time.

Okay. The other question I have, you said you're bullish on natural gas prices into '08.

Given that most people think the U.S. is heading into a recession or is in recession, I'm just wondering why you're “bullish?”

Okay. So there is a lot of reasons beyond the issue, whether or not the U.S.

is moving towards a recession. Some of those issues of course are related to Canadian supply making it into the U.S.

markets. That we expect would be off as much as 1 bcf per day over the course of the next year.

We've also seen L&G imports coming in at a much lower level that we saw during the 2006 year and that's a direct result of increased demand for L&G on a worldwide basis. But also because the switches occurred this past year where the winter in Europe tends to be...

is tending to be a lot colder than it was previously and so there is a stronger demand in Europe and higher prices. So those cargos simply are not making it here.

And then we're also seeing what appears to be a slowing in the overall production growth in the United States, at the same time that we're seeing continual increases in electrical demand. So nothing for us in the near-term suggesting anything other than a positive impact on natural gas, and sort of the proof that you have right now is the way in which natural gas storage levels have continued to drop at a fairly significant pace relative to last year and moving closer and closer to that five-year average.

So all of that is tending to have an impact on the market and people are starting to see an uptick in futures prices for natural gas.

Thank you so much for your time.

Thank you.

Good morning. Two questions please.

The first is, with this declining business climate that you're seeing in [inaudible] in Canada, I'm wondering with your opportunities that you see in the U.S. is it still strategically and financially advantageous for EnCana to be based in Canada?

Can you comment on that?

We are a Canadian headquartered company. Our head office staff are all located here, and it's quite an effective place to run our overall business.

Despite all of the other impacts that are happening in the industry, EnCana still has a very, very strong and very, very profitable production base in Canada and we see tremendous amount of opportunities for growth in unconventional natural gas place both in Alberta and in British Columbia. And we do see a long-term business with our steam-assisted gravity drainage oil recovery.

Okay. The second thing I want to ask is The Bow, the office tower.

Is that still on track? Are you still planning for a 2010, 2011 move in?

I believe so. I am going to have Gerry Protti give some color to the answer.

Hi, Jon. Yes, we're still on track.

As you know, we've got a large excavation underway and all of the planning is following the correct schedule. So we still plan to be in, in 2011.

Okay. There are...

and comment or not on this, but there are rampant rumors in Calgary Downtown that the building is not progressing as planned.

Those are not true. We are moving ahead.

Okay. Thank you.

Good morning. Randy, you mentioned that people need to work together to re-establish the competitiveness of Alberta conventional oil and gas.

I was wondering what you think actually needs to be done for that to happen?

Well, there are just a litany of issues that need to be worked through in order to make the Canadian oil and gas industry, particularly in Alberta, more profitable or profitable enough to incent the activity levels. And since it is not just one thing as I outlined before, it’s a number of different issues related to… primarily related to expectations that need to be worked through, and the more effectively that those can be worked through, the level of activity can be increased again.

Do you have any expected timeline for recovery in the sector? When will these issues might be worked through?

I think one of the issues will be with the government dealing with the unintended consequences of the changes to the royalty regime in the province, that's definitely one. There is some landowner expectations that need to be changed in the future as well, that can allow for more activity and allow for I guess an improvement in the investment climate.

Okay. Finally--?

Gerry Protti is going to add a little bit to this as well.

Okay.

Norval, Gerry Protti here. Just to add to what the issues that Randy outlined, I think one of the areas that government, stakeholders, and the industry ought to come together and discuss is changing nature of the resource base.

The conventional industry that grew this province over the last 50 years is rapidly declining and disappearing, but as Randy mentioned in the conference call, there is this huge unconventional base, be it unconventional natural gas or unconventional oil, it is an area that people don't understand as fully as they need to. The cost pressures are different, the implications the way its developed its different.

And we know that there is increasing environmental pressures and trade-offs associated with it, and the balancing of the economics of that business with those environmental expectations I think will be an area that we are going to look forward to participating in the debate with government.

Okay. One final question, do you think this sector can improve without EnCana increasing its investment in oil and gas [inaudible] going to expanded its trading in Alberta?

I guess what I am trying to get is does the sector rely on you?

I'm sorry, you really broke up and we couldn't understand your question at all.

Sorry. I guess I'm trying to ask to what extent does the recovery depend on EnCana coming back with investment into the sector?

I see. We're still a very strong investor in Western Canada and just an improvement in price will itself increase our activity levels on our key lands and lands are not affected by their current royalty structure.

But when it comes to just the general industry issues, there need to be improvements so it can be competitive with the rest of our portfolio before we substantially increase our investment. But EnCana makes up 20% roughly of the industry activity in Western Canada.

So that's a kind of influence that we could have.

Thanks very much.

Thank you.

Hi, Just two questions. On the unintended consequences, what sort of tangible result are you hoping for?

Well, I'll again turn it over to Gerry Protti.

Hi, David. I think the areas that people… the industry have identified and had discussions with government had been around the economics of deep basin… gas for drilling for deep unconventional opportunities.

So I guess on that one maybe even specifically, how would you like to see maybe the proposed royalty curve change or are there drilling breaks you're looking for or well by well or...?

Well, I don't think we can get into the specifics. I think it's a question of… the fact that the government has received input from individual companies, from cap, the trade association, and they've worked through it.

I think we're... our expectation is post election that we are going to sit down, look at areas like those deep gas drilling opportunities, maybe unconventional sources like development of various like mantle [ph] coal, deep oil opportunities.

So what we're expecting is a round of discussions, and I suspect that through the selection period the department is working through all the different alternatives and options.

I guess you are looking for… to have the royalties lowered on all those topics?

Well, I think the royalties have been increased significantly and the royalty regime… our expectation is... will reflect the costs...

the higher costs of developing those resources.

Yes. I'm not so sure they were looking for a decrease in royalty, but it certainly is important for lot of these early life players that the frond end loading of the royalty rate be less.

Longer-term, we could pay higher royalty but it's really the timing of the royalties that's important.

Okay. And then on subfields with the hearing coming up next month, how confidant are you that the company can be successful, and if it is when does drilling perhaps start?

The hearing starts in mid-March, and VIS [ph] that we prepared for that David is probably one of the most extensive environmental impact statements that any company has prepared for any C application. We're hoping that in the course of the hearing that it will be clearly demonstrated to the panel and to everyone accessing it that we are very confident that we can do that infield drilling on the NWA and do it with minimum environment impact and demonstrate kind of improvements in technology as we go through.

And then, if you're successful when would you hope to start drilling?

Next year.

Okay, great. Thank you.

Okay. Thank you, everyone for joining us today to review EnCana's fourth quarter and year-end results.

So our conference call is now complete.