Paul Gagne - VP of IR Randy Eresman - President and CEO Jeff Wojahn - EVP and President of USARegion Brian Ferguson - EVP and CFO John Brannan - EVP and President of Integrated OilsandsDivision Don Swystun - EVP and President of Canadian Plains Division

Mark Gilman - The Benchmark Company Brian Singer - Goldman Sachs Stephen Calderwood - Raymond James John Herrlin - Merrill Lynch Stephen Beck - Jefferies & Company

Thank you, operator, and welcome everyone to our discussionof EnCana's third quarter results. Before we get started, I must refer you tothe advisory on forward-looking statements contained in the news release, aswell as in the advisory on page 1 of EnCana's Annual Information Form datedFebruary 23rd, 2007, the latter of which is available on SEDAR.

I'd like todraw your attention, in particular, to material factors and assumptions inthose advisories. In addition, I want to remind everyone that EnCana reportsits financial results in US dollars and operating results according to USprotocols, which means that production volumes and reserve amounts are reportedon an after-royalties basis.

Accordingly, any reference to dollars reserves orproduction information in this call will be in US dollars and US protocols,unless otherwise noted. Randy Eresman will start off with an overview of our results,and then turn the call over to Jeff Wojahn, President of our US Division, toprovide further highlights of some of our USkey gas projects.

Brian Ferguson, Chief Financial Officer, will then discuss inmore detail our financial performance. Following some closing remarks fromRandy, our leadership team will be available for questions.

I will now turn the call over to Randy Eresman, Presidentand CEO.

Thank you, Paul, and thank you everyone for joining ustoday. As you saw on our news release this morning, EnCana iscontinuing to perform very well with strong third quarter results.

In short,production and cash flow are now expected to modestly exceed our full yeartargets and inflationary pressures are beginning to ease, strong performance inan environment in which the NYMEX price for natural gas dropped 6% from thesame quarter last year. The benefits associated with EnCana's disciplined resource playapproach and business model are now more clearly reflected in our financialresults.

I believe that our performance is the result of the deliberate actionswe've taken over the last several years to transition the company into aleading integrated producer of unconventional natural gas and in-situ oilsands,a company with a unique, low risk sustainable growth profile. Now let's look at how the strategy is paying off byreviewing some of the highlights from our third quarter.

First, our bottomlineperformance was solid. Driven by strong refining margins, positive natural gashedges, and increased gas production, cash flow increased to approximately $2.2billion or $2.93 per share diluted.

That's up 27% on a per share basis comparedto the third quarter of 2006. In part, this is due to the share purchases wemade under our Normal Course Issuer Bid program.

Operating earnings of approximately $960 million or $1.27per share diluted are down 3% on a per share basis compared to the same quarterlast year. As well during the quarter, we generated approximately $640 millionin free cash flow.

As a result, EnCana's free cash flow for the first ninemonths of the year totals $2.3 billion. A major highlight has been our upstream execution.

Naturalgas production averaged 3.6 billion cubic feet per day. That's up 8% from thethird quarter of 2006.

For the first nine months, natural gas production hasaveraged 3.5 billion cubic feet per day, an increase of almost 5% from the sameperiod in 2006, and slightly ahead of our expectations for the year. Our capital spending was about $1.6 billion.

And for theyear, capital spending remains below budget, largely due to lower than expectedinflationary pressures across most of North America andimproved efficiencies in many of our operations. Now, with respect to production growth, I'll first focus onnatural gas.

EnCana's third quarter natural gas was driven by a 15%year-over-year increase in production from our key gas resource plays,primarily Jonah, East Texas, Bighorn and Cutbank Ridge. We're currentlyproducing 3.6 billion cubic feet per day and we're on track to exceedproduction guidance for the year.

We'll likely achieve closer to a 4% growth innatural gas production as opposed to our original 3% plan. Our Canadian based natural gas production was solid againthis quarter.

Several of our key resource plays experienced significantproduction gains in the quarter, most notably Cutbank Ridge and Bighorn. Production from Cutbank Ridge in the deep basin of British Columbia has seen thegreatest year-over-year growth of all of our natural gas plays in ourportfolio.

Production averaged about 245 million cubic feet per day for thequarter. That's up 47% compared to the third quarter of 2006.

This tremendousgrowth is the result of continued drilling success from the Cadomin zone, alongwith an increasing contribution from both the Montney and Doig formations. Our Bighorn play, which covers almost 700,000 acres in thedeep basin of Alberta,also experienced strong year-over-year natural gas production growth of 32%.Production growth is primarily attributable to improved execution through multi-wellpads and increased efficiencies realized by managing our production throughEnCana zone plants that we expanded in 2006, that's Kakwa, Resthaven and Wild River.

Well results have also been very encouraging. Typically, weexpect to cover reserves greater than 3 billion cubic feet per well, and thesewells are drilled to an average depth of 11,000 feet.

Overall, for Canadiangas, our outlook for the last quarter of 2007 remains positive. We're on trackto complete our full year drilling program as planned.

Our integrated oilsands business, once again, had verystrong financial results in the quarter. In the upstream portion of thebusiness, production from Foster Creek and Christina Lake was up 33% over the thirdquarter of last year on a gross basis, as shown in our news release.

This was largely a result of the completion of Phase 1C atFoster Creek at the beginning of 2007, which allows us to ramp up plantproduction capacity to 60,000 barrels per day on a gross basis. Constructionfor phases 1D and E at Foster Creek and 1B at Christina Lake are all well underway and areexpected to add on 100% basis about 72,000 barrels per day of additionalcapacity in varying stages over the next two years.

On the downstream side, average realized crack spreadsduring the quarter exceeded our budgeted range of $11 to $12 per barrel. As aresult, the downstream portion of the integrated oilsands business continued togenerate strong margins in the third quarter and contributed over $340 millionof pre-tax cash flow.

Regional and local market factors often have an impact onrefining crack spreads. And as such, our two refineries are located in marketswhich are influenced by the US Mid Continent and Chicago 321 crack spreads,which have been strong relative to US Gulf Coast and NYMEX crack spreads.

On the quarter, the entire integrated oilsands businesscontributed about $410 million to EnCana's pre-tax cash flow. Year-to-date pre-taxcash flow from this business, upstream and downstream, totals over $1 billion,representing about a 14% of EnCana's total pre-tax cash flow.

Currently, 321crack spreads have softened to some degree, mainly due to normal lower seasonalproduct demands. We're currently working with ConocoPhillips to provideupdated schedules and costs for the next stages of our upstream and downstreammajor expansion projects.

We expect to be in a position to make an announcementon those projects in conjunction with regulatory approvals in the comingmonths. Another recent highlight relates to our deep Panuke offshoregas project.

We've received regulatory approval from the Canadaand Nova Scotia Offshore Petroleum Board to develop deep Panuke. As we noted inour news release, EnCana's Board of Directors sanctioned the project locatedoffshore Nova Scotia.

We'll nowmove forward with our development plans. Over the next few weeks, we'll be awarding contracts on the projectswith major elements, including the production field center contract.

Based oncurrent projections, first gas from the project is targeted to come on streamin 2010. The project is expected to produce between 200 million to 300 millioncubic feet per day of natural gas, and our share of the capital investment inthe project is expected to be about $550 million.

Further details of ourcapital program for 2008 will be provided before yearend. I'd now like to turn the call over to Jeff Wojahn, who willgive us an update on the USAdivision.

Over to you, Jeff.

Thanks, Randy. The USAdivision continues to have a great year.

Our total gas production this quarteraveraged almost 1.4 billion cubic feet per day, up 16% from the same period in2006. For the first nine months, production averaged 1.3 billion cubic feet perday, which exceeds our full year guidance of 1.25 billion cubic feet per day.

This growth was driven by our four key resource plays; JonahField, the Piceance Basin,East Texas and Fort Worth areas. Iprovided an update on all four of these plays during the second quarterconference call.

Today, I'll focus on some recent events that have impacted ourUS operations. First, Jonah, which has been a great success story for usthis year.

Production in the third quarter averaged close to 590 million cubicfeet per day, about 30% higher than the comparable quarter in 2006 and wellahead of our full year guidance. This strong performance has been largelydriven by two things.

As we noted last quarter, the first improvement has been theturnaround we've seen on the completion side, which has resulted in an improvedinitial production rates, averaging 3.5 million cubic feet per day. The secondand most recent impact has been the strong response we've seen from theaddition of new field compression, and even stronger response than we hadexpected.

After the first phase of new compression was completed thissummer, field pressures dropped from about 600 PSI to about 425 PSI. Due to thestrong production response that we've seen from the gathering system pressuredrop, we've increased our annual guidance for Jonah by 10% to 550 million cubicfeet per day for the year.

A second phase of new field compression is scheduled to comeonline in the second quarter of 2008, after which we anticipate field pressureswill drop even further to about 300 PSI, and we should see additionalproduction response. With the addition of new compression, we expect somevolatility in our quarterly production before things settle out towards themiddle of 2008.

The second area I'd like to highlight is the Mid Continent.East Texas has experienced the greatest year-over-year growth in the USdivision, with average production in the quarter of about 144 million cubicfeet per day, up 36% from the same period in 2006. This growth was driven by excellent overall results from theAmoruso Field in the Deep Bossier play where we plan to operate and areoperating a seven rig drilling program for the remainder of the year.

We havebeen delining our land base and acquiring additional 3D seismic, which willhelp us to identify and optimize drilling locations. Another area that I'd like to touch on today is the Columbia River Basin.

As mentioned in thenews release, EnCana has concluded its participation in the three wellexpiration program in the Columbia River Basin. Commercial quantities of natural gas havenot been discovered.

While the potential for continued exploration remains,EnCana has no immediate plans to participate in additional drilling. Becausethis is a non-core play for EnCana, any future activities on EnCana's acreageposition will likely be funded by third-party capital through farm-out stylearrangements.

Overall for the USdivision, capital spending and operating costs remain in line with expectationsfor the quarter. For the USas a whole, industry activity levels remain high, but we are not experiencingthe same frenzied pace of prior years.

In some areas, like East Texas and Fort Worth, service providers have responded to the demandfor services, by bringing in new equipment that has helped to ease costpressures. In summary, strong production growth, disciplined capitalspending, and operating cost management, along with lower than expectedindustry inflation, combined to generate very strong financial results for the USAdivision.

I will now turn the call over to Brian Ferguson, our ChiefFinancial Officer, who will discuss our financial results in more detail.

Thanks, Jeff. Hello, everyone.

In the quarter, cash flow exceeded total capital investment,which we define as free cash flow, by more than $640 million. Both operatingand net earnings were strong, but down year-over-year.

Our natural gas price realization benefited from our pricerisk management strategies once again. We continued our industry leading costperformance.

And we purchased more of our own shares, completing our target to purchase5% during calendar 2007. For the quarter, cash flow was $2.93 per share diluted, up27%.

As Randy noted, strong gas production growth and strong crack spreads inour new downstream business, which generated downstream pre-tax cash flow forthe third quarter of $344 million, were key contributors to our beating the Streetestimates this quarter. Total operating earnings of $961 million for the thirdquarter are down 3% on a per share diluted basis compared to 2006.

Last year, our2006 operating earnings were pushed out by $255 million after-tax gain on thesale of a portion of our Brazilasset. Net earnings for the third quarter of 2007 were $934 millionor $1.24 per share diluted, which is down about $425 million compared to 2006.This decrease is largely attributable to unrealized mark-to-market losses of$69 million after-tax on our hedge program compared with unrealized gains of $285million after-tax in the same quarter of 2006, as well as the gain last year onthe Brazilsale.

I want to point out that a current total unrealized hedgeposition at September 30 was in the money by over $750 million pre-tax. On the cost side, we continue to see an easing of inflationacross the industry, with the exception of labor and energy related costs.

In Canada,excluding the oilsands, we've experienced inflation toward the lower end of ourpreviously forecast range of 0% to 5%. In the US,activity remains high, as Jeff noted.

However, inflation has moderated in someregions. So we now expect it to be in the 3 to 5% range overall.

As a result of efficiency gains, such as the increased useof fit-for-purpose rigs, we are tracking closer to the bottom end of therespective inflation ranges. We currently have about 65 fit-for-purpose rigs inour fleet.

That represents about 70% of our total contracted fleet. Theefficiencies gained from improved cycle times or reduced downtime will continueto be a positive influence on our cost structure.

Quarterly operating and administrative costs were bothbetter than guidance, and together averaged $1.01 per 1,000 cubic feetequivalent, unchanged from last year. For the first nine months, operating andadmin costs have averaged $1.12, tracking below our annual guidance of $1.20.

Capital spending for continuing operations for the quarterwas $1.6 billion. For the first nine months, capital investment of $4.2 billionis lower than we expected for the same reasons that we highlighted lastquarter.

And those, just to reiterate them, were; first, an extended spring breakup,which effected our ability to complete our planned billing program in the veryfirst quarter; second, reduced drilling costs related to the fit-for-purposerigs currently operating in our fleet; and third, improved operatingefficiencies, such as reduced downtime waiting for third-party services. We areon target to complete our capital program as planned for the year.

In the first three quarters of the year, we have generatedapproximately $2.3 billion in free cash flow. In addition, we've receivedproceeds from divestitures totaling approximately $500 million.

We have usedabout $2 billion of that to purchase shares and paid dividends of approximately$450 million so far this year. Our balance sheet remains very strong.

Our net debtincreased slightly in the quarter. However, net debt to cap was down slightlyfrom the prior quarter to 27%, and is unchanged from yearend.

Net debt toEBITDA finished the quarter at 0.8 times on a trailing 12-month basis. Lookingforward for the remainder of 2007, I expect that these ratios will remain at orbelow the low end of our managed ranges.

On the price risk management front, EnCana's gas hedgingprogram has been successful in providing protection and stability throughperiods of fluctuating prices. For example, in the third quarter, our realizedhedging gains added $1.65 per 1,000 cubic feet for gas prices.

For the remainder of 2007, we have limited commodity pricerisk by hedging a significant portion of our forecast gas volume at an averageprice of $8.80 per 1,000 cubic feet and 100% of our expected 2007 US Rockiesbasis exposure, using a combination of downstream transportation, and basishedges. The news release and financial notes indicate our hedgingposition as of the end of the third quarter.

Since then, we have added to ournatural gas hedge position. We currently have hedges in place on approximately1.1 billion cubic feet per day of 2008 gas volumes at an average price of about$8.30 per Mcf.

We will continue to look for opportunities to add to thisposition in 2008. As I noted earlier, we've completed our planned NCIB programfor 2007, having reached the top end of our targeted range, which was topurchase 3% to 5% of our shares outstanding during calendar 2007.

In summary, our financial and operating results areexceeding market expectations. We expect that trend to continue.

Given thegrowth in our key resource plays and performance of our new downstreamdivision, we expect to be at or slightly above the top end of our cash flowguidance for the year. Now back to Randy for some final comments.

All right. Thank you much, Brian.

Before I make my concluding remarks about the quarter, I'dlike to briefly comment on the public policy matter that is unfolding beforeus. As you are likely aware, the government of Albertais in the midst of a comprehensive review of the provinces oil and natural gasroyalty structure.

Further information concerning the government's planneddirection is expected to be released later today. Until we've had sufficienttime to review the details, we will not be providing any comments on the impactto EnCana, and we won't be providing any further comment relating to theroyalty review during today's Q&A session.

Our strategy remains very focused on North America, on unconventional gas, and integrated oilsands, and weare well positioned to deliver on our results on or ahead of target for 2007.We also know that the year's not over yet and there are a number of externalfactors that can influence our results. Looking at the gas market, we've entered the final months of2007 in a very similar situation to last year.

Storage inventory levels arerelatively unchanged. Drilling in the US Rockies and Texashas remained at strong levels, and continued mild temperatures in Europehave allowed additional L&G supply to make its way to North America, offsetting the declining Canadian supply, all of whichhas contributed to a softening of natural gas prices.

In the short-term, it comes down to whether, when, and towhat extent we see colder temperatures, particularly in the traditional higherdemand regions. Then, depending on North American demand, if temperatures in Europereturn to normal, less L&G will be available to make its way here.

So weexpect gas prices to be volatile over the coming months. Longer term, we remain bullish on natural gas.

Based oncurrent prices and a decrease in industry activity levels, we expect Canadianproduction will continue to fall. Numerous studies suggest that the industryneeds sustained prices higher than what we are currently seeing to bring on newproduction.

The high level of US drilling activity has only barely beenable to keep up with recent declines. Since 2001, the USrig count has almost doubled, increasing from 800 to over 1,400 currentlyactive this year, yet US gas supply is still below 2001 levels.

For the comingmonths and future years, EnCana is well positioned to thrive. In the short-term, as Brian said, we've taken steps to limitsome of our downside risk with hedges on commodity prices and basisdifferentials.

I believe that a disciplined, low risk, technology focusedcompany like EnCana can perform well through a variety of market conditions, asour financial results over the past few quarters have demonstrated. As always, we are focusing on optimizing the factors thatare within our control and minimizing our exposure to risk for those that wecannot.

Success for us in 2007 and beyond means excellence in execution anddelivering on our potential and we continue to work towards these goals. Ourresults so far this year have been very positive, a credit to our teams, ourassets and our strategy.

Thank you very much for joining us today. My team is nowready to take your questions related to our financial and operating results.

Randy, Jeff, Brian, good afternoon. Couple things I wantedto run down, if I could, probably more in Jeff's portfolio.

I wonder: Jeff, ifyou could spend a minute or two on activity in the Maverick Basin? And, in particular: whatyour expectations might be regarding the Pearsall Shale, pursuant to which therecent farm-out was into play?

Secondly, vis-à-vis Jonah, the release talks about improvedfrac to stimulation response, and was wondering: if you might be able toclarify that in terms of whether there are changes in the type of fracs beingemployed? Or: whether that better response is associated just with differentreservoir sections?

Thanks.

Randy, it's Jeff Wojahn here. I'll start off with the Maverick Basin.

We have been interested oractive in pursuing the Pearsall play. We recently developed a joint venturepartnership with TXCO to drill several wells, up to three wells, depending onthe success, up to 11 wells over a period of time, to evaluate and see if the PearsallShale will be the next Barnett Shale play.

Geologically, it looks strong. It has every indication ofbeing a fine play.

We're just starting to undergo that program, and I think inthe not too distant future, we'll be drilling the first well of that jointventure partnership. In regards to Jonah, the results in Jonah have been two-fold.One was the change in our fluid composition of our frac program that weundertook late last year.

That improved our IPs by a little less than 1 milliona day on average for our wells, about 2.5 million to 3.5 million cubic feet aday. Subsequent to that and more recently, we have, or morecorrectly, our midstream partner, Enterprise,has been undergoing the expansion of the Bridger compression station.

A couplefactors with that expansion, one, obviously, as I mentioned, we're dropping thepressure that our wells see, and we've dropped our pressure down about 425 PSI. That Bridger compression station also is completelydedicated to Jonah.

So we don't get backed out or we don't see the effect ofincreased volumes coming from the Pinedale, and that has helped stabilizeoperating pressures within the Jonah Field. So the combination of those twofactors has really helped Jonah perform well this year.

Jeff, if I could just follow up for a sec, it seems a littlebit unusual to put a farm-out in place with respect to a play that you're stillin the evaluative stage of, particularly if there is some degree of enthusiasm,as I thought was the case associated with the well results that were reported,I guess, it was probably about a month or so ago. Why the farm-out?

Well, I think earlier in the year we talked about the strategythat EnCana would be employing in the USdivision about attracting $450 million, target of $450 million towards third-partyjoint venture. And the Pearsall Shale is one of those ventures.

The idea there is that we have 27 million acre land basinand 10-year inventory of drilling already established in our company. So whenwe look at acquisitions or exploration opportunities, we're really not thatinterested in adding to our current portfolio or 11th year, it's difficult tounderstand the value of those propositions.

For that reason, those explorationprojects have a hard time competing for capital against EnCana's inventory. So, we've really taken the strategy of bringing jointventure partners, technology partners and that can unlock some of theexploration potential that we have within our portfolio.

Thanks, Jeff.

Thank you.

Thanks. Following up on Jonah: has there been any change atall to where you see ultimate spacing as a result of any of the improvements?And: does the rate improvement may get any more bullish on recovery rates?

Or:are you still looking at the same amount of unbooked potential?

Brian, its Jeff Wojahn. Jonah Field, you may know wecompleted the EIS process, I guess, a little over a year ago, today, where weapplied for 10-acre spacing and, in fact, 5-acre spacing in some cases.

We havea number of 5-acre spacing pilots, 3 in the field that are currently producing.And we're really looking at those pilots to accelerate our understanding of thereservoir. We also have a very large reservoir simulation, where we input themost recent data in and provide a predictability model.

Our current plan is to obviously drill spacing down at10-acre spacing. In some cases, on the down definitive space of the field, we'reactually drilling 20-acre spacing.

So, we really haven't made a decision onwhether we're going to advance beyond the 10-acre or the 20. We don't have tomake that decision for several more years, because we have an inventory aheadof us of 10-acre and 20-acre spacing.

And, obviously, the fine results we're seeingtoday will provide us indication of whether we'll go there. In regards to recovery factor, I think we had modeledcompression as part of the field development in the past.

We were surprised, asI mentioned, in regards to the effect. We're actually delighted.

That would bethe proper words in regards to the response that we've seen in the wells. We'llinput that into our model.

And I think it's fair to say that we look forward toseeing the compression expansion project completed next year and to see theresults that that may give us. Obviously, that's going to give us more clues onthe ultimate compression required for the field and full field development.

That's great. And Randy, a couple of questions for you.

Justgiven the ability to show free cash flow, exceed guidance and your bullish viewon commodity prices, I guess: a) how are you thinking about growth relative tothe level of spending in '08; and b) should we expect you to look at theacquisition market a bit more than you have in the past couple of years?

Okay. Thanks, Brian, for your question.

We are in positionof generating significant amount of free cash flow and we're going to continueto balance the program that we had of a more moderated level of productiongrowth in our natural gas program. Our oilsands program will effectively bewhat it is because those are long-term developments, as you know.

And we will continue to take some of the excess cash flowback to buy back additional shares as we are putting our Normal Course IssuerBid program back in place again. We think that in this market condition thereis going to be some opportunities to do some acquisitions, but we're going tobe very focused on only doing those in areas which are part of our existingoperations, and plays that we know very well.

Great. Thank you.

Thanks, Brian.

Yes, thank you. If I could start with a question on theoilsands growth, I wonder: if you were disappointed with the pace ofdevelopment in Foster Creek, the expansion of unit at Foster Creek?

And, youmentioned another three expansions, two at Foster Creek and one at Christina Lake, over the next two years toadd 72,000: do you think then you can keep a better pace going forward? Or: doyou think it's going to be as challenging as it has been?

Okay. I'm going to pass that over to John Brannan to answer.

I think as far as our pace of development at Foster Creekand Christina Lakegoes, we are happy and comfortable with that. A little bit of our productionshortfall so far this year have been associated with operational issues as webring those new phases into production.

But, overall, we're very happy with theperformance of the reservoir. The two projects that we have at Foster Creek, they're each30,000 barrels projects, the 1D and 1E, essentially on time and on schedule.

Andwe plan on bringing those on sometime next year and we'll reap the benefits ofthat production late in 2008 and into 2009. At Christina lake, we've got about 12,000 barrel a dayexpansion there that should take that field up to about 18,000 barrels.

Thatexpansion will be finished late this year. We'll start steaming wellsassociated with that and receive some of the benefits in 2008, but the fullbenefits in 2009.

Excellent. If I could ask one more question on pushing thegas production, obviously, the relative ease of attaining better than 3%, andthis is more or less a question for Randy: would you characterize thatexceeding your expectations as sort of onetime successes that you've had,particularly in the US?Or: do you think this is a normal result of having a lower target that shouldincrease our positive bias to your growth going forward?

We set our targets based on the expectations that our teamsbuild up. And really a lot of the incremental gas production we got this yearwas a result of Jonah outperforming our expectations.

And it appears that itmay be set up to outperform again next year, but that's hard to say that we'dbe able to continue that on. We are having a tremendous amount of positive results in alot of our key resource plays, as you can see by going through the details ofour release.

Overall, things are performing very well and we're managing ourcosts very well. So basically the model is working extremely well.

Now, in the longer term: does that mean that we'd increaseour overall gas production target? We're very comfortable in that sort of 5%range and complimenting our growth with share buyback and it seems to besomething that's working well.

We've communicated it to our teams very well andthey are performing very well. So, things are actually going quite good rightnow.

Thanks.

Yeah. Hi.

I think I have a variety of questions for Jeff andalso Randy. With respect to Jonah, your sequential well count from secondquarter to third was down 26%, but production was up 65 million a day or 12%.You mentioned earlier on the call that you were getting better uplift becauseof lower gathering system pressures, but you also said you had bettercompletion.

So: if you had to kind of break it down, how much of thevolume gains were completion related? How much was the gathering system related?And: whether any other wells that were, perhaps, behind pipe and not connected?

All right. Jeff will answer that.

Hi, John, Jeff Wojahn. You bring up all kinds of differentpoints here for me to talk about.

So, thank you. I think the first comment youtalked about was the sequential ordering or the cumulative scheduling of ourwells.

And one of the great things that we saw in Jonah Field this year wasimproved performance in our fit-for-purpose drilling, which led to lower cycletime and faster rate of drilling. So, I think, what we realized is we probably had more rigsthan required to meet the program that we had originally designed, and wetapered off on a couple rigs and, basically, focused on increasing the rigcounts in our new fit-for-purpose equipment.

So, that strategy has worked verywell and we've been able to stay within our capital discipline and our overallcost structures very well. In regards to where the production has come from, and welook at our base wedge from our capital program versus the completion program,I would say about 60% of the gains that we've seen have been from increasedIPs, or initial productivity of our wells drilling about 40% from thecompression project.

Okay. Thank you.

And the same thing with the shallow gas in Canada,you drilled about 360 more wells, but production was down. Do you have a lot ofbehind pipe on the shallow gas stuff?

I think it's for both Don, and maybe Mike on the CBM side.

Hi there, John. Yeah.

On the shallow gas side, we were downin Q3 some degree on production, but that's because in Q2 we had a very wetseason and we didn't get as many wells as we wanted to expect. Q4 will have similardrilling rates to Q3 at that level.

Okay. But you had 360 more wells spud.

so I was justwondering why the volumes were lower. That's okay.

Well, you won't see…

That's timing related.

Yeah. It's more of a timing issue, so you won't see it untilthe fourth quarter.

Okay. So you do have behind pipe.

Yes.

Okay. One for Brian with respect to hedging.

$499 million ofpre-tax gains is pretty large. Did you close out any of the contracts earlygiven the volatility of prices?

Or: did you just let them run their course?

I'm going to answer that question, John. We've taken thepractice of leaving all of our positions in place.

We don't trade around them.

Okay. Great!

And last one on refining: is it possible, goingforward, that maybe you can disclose some more information? We file a comp andwe can't get their actual results from the USto jive, but we don't get refinery specific information.

Yeah. That would be the difficulty, John.

We're reportingbased on our share of two refineries versus, I don't think they separate theirentire portfolio.

They don't. But, you did a lot better than their average.

Andso, I was wondering can you….

I think that probably reflects the region that theserefineries are in, as we talked about the three-to-one crack spreads in thesort of Mid Continent area, the Chicago area, we're quitea bit better than Gulf Coast.

No doubt. Thank you.

Thank you, John.

Hi, thank you. My first question, I guess, I'd like to focuson the Barnett.

I noticed that the number of net wells that were drilled felloff sequentially. I was wondering: if, maybe, you could elaborate a little more,or provide some discussion on your experiences in Q3, regarding rig count andactivities and expectations going forward?

Stephen, its Jeff Wojahn. The same effect that we saw atJonah Field is the same thing that we saw on the Barnett.

We originally hadanticipated drilling six or seven rigs program throughout the year to meet ourproduction in capital guidance on the Fort Worthplay. But what we found was that we were drilling the wells muchmore cost effectively in lowered cycle times than we had anticipated, and wereally saw 25% to 30% improvements in our drilling times with our fit-for-purposerigs.

So we adjusted our rig counts. We modified those down to about fiveactive rigs today and slowed down our well count.

So the program was a littlebit more skewed to the second quarter than the Q3 basically because we werestewarding within our capital discipline as the year goes on. With that said, we've enjoyed about an 18% cost reductionyear-to-date.

We expect to maintain five rigs in Q4, drill 86 gross wells intotal for the year. So, I've been very pleased with the results of thisprogram.

We've had excellent results by the team, a lot of focus, and we'vedemonstrated that we've got a good line position in the Barnett Shale and agood growth area for us in the future.

Jeff, just wondering, I was looking at the sequential growthin terms of production. Q2 is 124 versus Q3, 128.

Is there production behindpipe or what can we expect in Q4?

Well, I expect to see this type of volume growth that we'veexhibited. I don't have the breakdown in front of me of the quarter-to-quarter.I can get back to you on that, but I expect the team to be within theirguidance for the play.

And, as I mentioned, this is one of our higher growthareas. But really it's a function of timing and scheduling rather than results.The results have been excellent.

Okay. Can you tell me what, what your average well cost isin the Barnett now?

Yeah, I'm just digging that out for you right now. I'll goover the quick things.

Production guidance, capital guidance of $285 millionand 70 wells, and we're a little bit ahead of that right now. I'll have to getback to you on the cost per well.

Okay, great. Thank you.