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EnCana Corp. (NYSE:ECA)

Q3 2007 Earnings Call

October 25, 2007 1:00 pm ET


Paul Gagne - VP of IR

Randy Eresman - President and CEO

Jeff Wojahn - EVP and President of USA Region

Brian Ferguson - EVP and CFO

John Brannan - EVP and President of Integrated Oilsands Division

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


Welcome to EnCana Corporation's third quarter financial and operating results conference call. (Operator Instructions)

I would now like to turn the conference over to Mr. Paul Gagne, Vice President of Investor Relations, EnCana. Please go ahead, Mr. Gagne.

Paul Gagne

Thank you, operator, and welcome everyone to our discussion of EnCana's third quarter results. Before we get started, I must refer you to the advisory on forward-looking statements contained in the news release, as well as in the advisory on page 1 of EnCana's Annual Information Form dated February 23rd, 2007, the latter of which is available on SEDAR. I'd like to draw your attention, in particular, to material factors and assumptions in those advisories.

In addition, I want to remind everyone that EnCana reports its financial results in US dollars and operating results according to US 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 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, to provide further highlights of some of our US key gas projects. Brian Ferguson, Chief Financial Officer, will then discuss in more detail our financial performance. Following some closing remarks from Randy, our leadership team will be available for questions.

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

Randy Eresman

Thank you, Paul, and thank you everyone for joining us today.

As you saw on our news release this morning, EnCana is continuing to perform very well with strong third quarter results. In short, production and cash flow are now expected to modestly exceed our full year targets and inflationary pressures are beginning to ease, strong performance in an environment in which the NYMEX price for natural gas dropped 6% from the same quarter last year.

The benefits associated with EnCana's disciplined resource play approach and business model are now more clearly reflected in our financial results. I believe that our performance is the result of the deliberate actions we've taken over the last several years to transition the company into a leading 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 by reviewing some of the highlights from our third quarter. First, our bottomline performance was solid. Driven by strong refining margins, positive natural gas hedges, and increased gas production, cash flow increased to approximately $2.2 billion or $2.93 per share diluted. That's up 27% on a per share basis compared to the third quarter of 2006. In part, this is due to the share purchases we made under our Normal Course Issuer Bid program.

Operating earnings of approximately $960 million or $1.27 per share diluted are down 3% on a per share basis compared to the same quarter last year. As well during the quarter, we generated approximately $640 million in free cash flow. As a result, EnCana's free cash flow for the first nine months of the year totals $2.3 billion.

A major highlight has been our upstream execution. Natural gas production averaged 3.6 billion cubic feet per day. That's up 8% from the third quarter of 2006. For the first nine months, natural gas production has averaged 3.5 billion cubic feet per day, an increase of almost 5% from the same period in 2006, and slightly ahead of our expectations for the year.

Our capital spending was about $1.6 billion. And for the year, capital spending remains below budget, largely due to lower than expected inflationary pressures across most of North America and improved efficiencies in many of our operations.

Now, with respect to production growth, I'll first focus on natural 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 currently producing 3.6 billion cubic feet per day and we're on track to exceed production guidance for the year. We'll likely achieve closer to a 4% growth in natural gas production as opposed to our original 3% plan.

Our Canadian based natural gas production was solid again this quarter. Several of our key resource plays experienced significant production gains in the quarter, most notably Cutbank Ridge and Bighorn.

Production from Cutbank Ridge in the deep basin of British Columbia has seen the greatest year-over-year growth of all of our natural gas plays in our portfolio. Production averaged about 245 million cubic feet per day for the quarter. That's up 47% compared to the third quarter of 2006. This tremendous growth is the result of continued drilling success from the Cadomin zone, along with an increasing contribution from both the Montney and Doig formations.

Our Bighorn play, which covers almost 700,000 acres in the deep 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-well pads and increased efficiencies realized by managing our production through EnCana zone plants that we expanded in 2006, that's Kakwa, Resthaven and Wild River.

Well results have also been very encouraging. Typically, we expect to cover reserves greater than 3 billion cubic feet per well, and these wells are drilled to an average depth of 11,000 feet. Overall, for Canadian gas, our outlook for the last quarter of 2007 remains positive. We're on track to complete our full year drilling program as planned.

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

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

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

Regional and local market factors often have an impact on refining crack spreads. And as such, our two refineries are located in markets which 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 business contributed about $410 million to EnCana's pre-tax cash flow. Year-to-date pre-tax cash flow from this business, upstream and downstream, totals over $1 billion, representing about a 14% of EnCana's total pre-tax cash flow. Currently, 321 crack spreads have softened to some degree, mainly due to normal lower seasonal product demands.

We're currently working with ConocoPhillips to provide updated schedules and costs for the next stages of our upstream and downstream major expansion projects. We expect to be in a position to make an announcement on those projects in conjunction with regulatory approvals in the coming months.

Another recent highlight relates to our deep Panuke offshore gas project. We've received regulatory approval from the Canada and Nova Scotia Offshore Petroleum Board to develop deep Panuke. As we noted in our news release, EnCana's Board of Directors sanctioned the project located offshore Nova Scotia. We'll now move forward with our development plans.

Over the next few weeks, we'll be awarding contracts on the projects with major elements, including the production field center contract. Based on current projections, first gas from the project is targeted to come on stream in 2010. The project is expected to produce between 200 million to 300 million cubic feet per day of natural gas, and our share of the capital investment in the project is expected to be about $550 million. Further details of our capital program for 2008 will be provided before yearend.

I'd now like to turn the call over to Jeff Wojahn, who will give us an update on the USA division. Over to you, Jeff.

Jeff Wojahn

Thanks, Randy. The USA division continues to have a great year. Our total gas production this quarter averaged almost 1.4 billion cubic feet per day, up 16% from the same period in 2006. For the first nine months, production averaged 1.3 billion cubic feet per day, which exceeds our full year guidance of 1.25 billion cubic feet per day.

This growth was driven by our four key resource plays; Jonah Field, the Piceance Basin, East Texas and Fort Worth areas. I provided an update on all four of these plays during the second quarter conference call. Today, I'll focus on some recent events that have impacted our US operations.

First, Jonah, which has been a great success story for us this year. Production in the third quarter averaged close to 590 million cubic feet per day, about 30% higher than the comparable quarter in 2006 and well ahead of our full year guidance. This strong performance has been largely driven by two things.

As we noted last quarter, the first improvement has been the turnaround we've seen on the completion side, which has resulted in an improved initial production rates, averaging 3.5 million cubic feet per day. The second and most recent impact has been the strong response we've seen from the addition of new field compression, and even stronger response than we had expected.

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

A second phase of new field compression is scheduled to come online in the second quarter of 2008, after which we anticipate field pressures will drop even further to about 300 PSI, and we should see additional production response. With the addition of new compression, we expect some volatility in our quarterly production before things settle out towards the middle 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 US division, with average production in the quarter of about 144 million cubic feet per day, up 36% from the same period in 2006.

This growth was driven by excellent overall results from the Amoruso Field in the Deep Bossier play where we plan to operate and are operating a seven rig drilling program for the remainder of the year. We have been delining our land base and acquiring additional 3D seismic, which will help 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 the news release, EnCana has concluded its participation in the three well expiration program in the Columbia River Basin. Commercial quantities of natural gas have not been discovered.

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

Overall for the US division, capital spending and operating costs remain in line with expectations for the quarter. For the US as a whole, industry activity levels remain high, but we are not experiencing the same frenzied pace of prior years. In some areas, like East Texas and Fort Worth, service providers have responded to the demand for services, by bringing in new equipment that has helped to ease cost pressures.

In summary, strong production growth, disciplined capital spending, and operating cost management, along with lower than expected industry inflation, combined to generate very strong financial results for the USA division.

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

Brian Ferguson

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 operating and net earnings were strong, but down year-over-year.

Our natural gas price realization benefited from our price risk management strategies once again. We continued our industry leading cost performance. And we purchased more of our own shares, completing our target to purchase 5% during calendar 2007.

For the quarter, cash flow was $2.93 per share diluted, up 27%. As Randy noted, strong gas production growth and strong crack spreads in our new downstream business, which generated downstream pre-tax cash flow for the third quarter of $344 million, were key contributors to our beating the Street estimates this quarter.

Total operating earnings of $961 million for the third quarter are down 3% on a per share diluted basis compared to 2006. Last year, our 2006 operating earnings were pushed out by $255 million after-tax gain on the sale of a portion of our Brazil asset.

Net earnings for the third quarter of 2007 were $934 million or $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 $285 million after-tax in the same quarter of 2006, as well as the gain last year on the Brazil sale.

I want to point out that a current total unrealized hedge position at September 30 was in the money by over $750 million pre-tax.

On the cost side, we continue to see an easing of inflation across 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 our previously forecast range of 0% to 5%. In the US, activity remains high, as Jeff noted. However, inflation has moderated in some regions. So we now expect it to be in the 3 to 5% range overall.

As a result of efficiency gains, such as the increased use of fit-for-purpose rigs, we are tracking closer to the bottom end of the respective inflation ranges. We currently have about 65 fit-for-purpose rigs in our fleet. That represents about 70% of our total contracted fleet. The efficiencies gained from improved cycle times or reduced downtime will continue to be a positive influence on our cost structure.

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

Capital spending for continuing operations for the quarter was $1.6 billion. For the first nine months, capital investment of $4.2 billion is lower than we expected for the same reasons that we highlighted last quarter. And those, just to reiterate them, were; first, an extended spring breakup, which effected our ability to complete our planned billing program in the very first quarter; second, reduced drilling costs related to the fit-for-purpose rigs currently operating in our fleet; and third, improved operating efficiencies, such as reduced downtime waiting for third-party services. We are on target to complete our capital program as planned for the year.

In the first three quarters of the year, we have generated approximately $2.3 billion in free cash flow. In addition, we've received proceeds from divestitures totaling approximately $500 million. We have used about $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 debt increased slightly in the quarter. However, net debt to cap was down slightly from the prior quarter to 27%, and is unchanged from yearend. Net debt to EBITDA finished the quarter at 0.8 times on a trailing 12-month basis. Looking forward for the remainder of 2007, I expect that these ratios will remain at or below the low end of our managed ranges.

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

For the remainder of 2007, we have limited commodity price risk by hedging a significant portion of our forecast gas volume at an average price of $8.80 per 1,000 cubic feet and 100% of our expected 2007 US Rockies basis exposure, using a combination of downstream transportation, and basis hedges.

The news release and financial notes indicate our hedging position as of the end of the third quarter. Since then, we have added to our natural gas hedge position. We currently have hedges in place on approximately 1.1 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 this position in 2008.

As I noted earlier, we've completed our planned NCIB program for 2007, having reached the top end of our targeted range, which was to purchase 3% to 5% of our shares outstanding during calendar 2007.

In summary, our financial and operating results are exceeding market expectations. We expect that trend to continue. Given the growth in our key resource plays and performance of our new downstream division, we expect to be at or slightly above the top end of our cash flow guidance for the year.

Now back to Randy for some final comments.

Randy Eresman

All right. Thank you much, Brian.

Before I make my concluding remarks about the quarter, I'd like to briefly comment on the public policy matter that is unfolding before us. As you are likely aware, the government of Alberta is in the midst of a comprehensive review of the provinces oil and natural gas royalty structure.

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

Our strategy remains very focused on North America, on unconventional gas, and integrated oilsands, and we are 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 external factors that can influence our results.

Looking at the gas market, we've entered the final months of 2007 in a very similar situation to last year. Storage inventory levels are relatively unchanged. Drilling in the US Rockies and Texas has remained at strong levels, and continued mild temperatures in Europe have allowed additional L&G supply to make its way to North America, offsetting the declining Canadian supply, all of which has contributed to a softening of natural gas prices.

In the short-term, it comes down to whether, when, and to what extent we see colder temperatures, particularly in the traditional higher demand regions. Then, depending on North American demand, if temperatures in Europe return to normal, less L&G will be available to make its way here. So we expect gas prices to be volatile over the coming months.

Longer term, we remain bullish on natural gas. Based on current prices and a decrease in industry activity levels, we expect Canadian production will continue to fall. Numerous studies suggest that the industry needs sustained prices higher than what we are currently seeing to bring on new production.

The high level of US drilling activity has only barely been able to keep up with recent declines. Since 2001, the US rig count has almost doubled, increasing from 800 to over 1,400 currently active this year, yet US gas supply is still below 2001 levels. For the coming months and future years, EnCana is well positioned to thrive.

In the short-term, as Brian said, we've taken steps to limit some of our downside risk with hedges on commodity prices and basis differentials. I believe that a disciplined, low risk, technology focused company like EnCana can perform well through a variety of market conditions, as our financial results over the past few quarters have demonstrated.

As always, we are focusing on optimizing the factors that are within our control and minimizing our exposure to risk for those that we cannot. Success for us in 2007 and beyond means excellence in execution and delivering on our potential and we continue to work towards these goals. Our results so far this year have been very positive, a credit to our teams, our assets and our strategy.

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

Question-and-Answer Session


(Operator Instructions)

Your first question comes from Mark Gilman with The Benchmark Company. Please go ahead.

Mark Gilman - The Benchmark Company

Randy, Jeff, Brian, good afternoon. Couple things I wanted to run down, if I could, probably more in Jeff's portfolio. I wonder: Jeff, if you could spend a minute or two on activity in the Maverick Basin? And, in particular: what your expectations might be regarding the Pearsall Shale, pursuant to which the recent farm-out was into play?

Secondly, vis-à-vis Jonah, the release talks about improved frac to stimulation response, and was wondering: if you might be able to clarify that in terms of whether there are changes in the type of fracs being employed? Or: whether that better response is associated just with different reservoir sections? Thanks.

Jeff Wojahn

Randy, it's Jeff Wojahn here. I'll start off with the Maverick Basin. We have been interested or active in pursuing the Pearsall play. We recently developed a joint venture partnership with TXCO to drill several wells, up to three wells, depending on the success, up to 11 wells over a period of time, to evaluate and see if the Pearsall Shale will be the next Barnett Shale play.

Geologically, it looks strong. It has every indication of being a fine play. We're just starting to undergo that program, and I think in the not too distant future, we'll be drilling the first well of that joint venture 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 we undertook late last year. That improved our IPs by a little less than 1 million a day on average for our wells, about 2.5 million to 3.5 million cubic feet a day.

Subsequent to that and more recently, we have, or more correctly, our midstream partner, Enterprise, has been undergoing the expansion of the Bridger compression station. A couple factors with that expansion, one, obviously, as I mentioned, we're dropping the pressure that our wells see, and we've dropped our pressure down about 425 PSI.

That Bridger compression station also is completely dedicated to Jonah. So we don't get backed out or we don't see the effect of increased volumes coming from the Pinedale, and that has helped stabilize operating pressures within the Jonah Field. So the combination of those two factors has really helped Jonah perform well this year.

Mark Gilman - The Benchmark Company

Jeff, if I could just follow up for a sec, it seems a little bit unusual to put a farm-out in place with respect to a play that you're still in 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?

Jeff Wojahn

Well, I think earlier in the year we talked about the strategy that EnCana would be employing in the US division about attracting $450 million, target of $450 million towards third-party joint venture. And the Pearsall Shale is one of those ventures.

The idea there is that we have 27 million acre land basin and 10-year inventory of drilling already established in our company. So when we look at acquisitions or exploration opportunities, we're really not that interested in adding to our current portfolio or 11th year, it's difficult to understand the value of those propositions. For that reason, those exploration projects have a hard time competing for capital against EnCana's inventory.

So, we've really taken the strategy of bringing joint venture partners, technology partners and that can unlock some of the exploration potential that we have within our portfolio.

Mark Gilman - The Benchmark Company

Thanks, Jeff.

Jeff Wojahn

Thank you.


Thank you. Your next question comes from Brian Singer with Goldman Sachs. Please go ahead.

Brian Singer - Goldman Sachs

Thanks. Following up on Jonah: has there been any change at all 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?

Jeff Wojahn

Brian, its Jeff Wojahn. Jonah Field, you may know we completed the EIS process, I guess, a little over a year ago, today, where we applied for 10-acre spacing and, in fact, 5-acre spacing in some cases. We have a 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 the reservoir. We also have a very large reservoir simulation, where we input the most recent data in and provide a predictability model.

Our current plan is to obviously drill spacing down at 10-acre spacing. In some cases, on the down definitive space of the field, we're actually drilling 20-acre spacing. So, we really haven't made a decision on whether we're going to advance beyond the 10-acre or the 20. We don't have to make that decision for several more years, because we have an inventory ahead of us of 10-acre and 20-acre spacing. And, obviously, the fine results we're seeing today will provide us indication of whether we'll go there.

In regards to recovery factor, I think we had modeled compression as part of the field development in the past. We were surprised, as I mentioned, in regards to the effect. We're actually delighted. That would be the proper words in regards to the response that we've seen in the wells. We'll input that into our model. And I think it's fair to say that we look forward to seeing the compression expansion project completed next year and to see the results that that may give us. Obviously, that's going to give us more clues on the ultimate compression required for the field and full field development.

Brian Singer - Goldman Sachs

That's great. And Randy, a couple of questions for you. Just given the ability to show free cash flow, exceed guidance and your bullish view on commodity prices, I guess: a) how are you thinking about growth relative to the level of spending in '08; and b) should we expect you to look at the acquisition market a bit more than you have in the past couple of years?

Randy Eresman

Okay. Thanks, Brian, for your question. We are in position of generating significant amount of free cash flow and we're going to continue to balance the program that we had of a more moderated level of production growth in our natural gas program. Our oilsands program will effectively be what it is because those are long-term developments, as you know.

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

Brian Singer - Goldman Sachs

Great. Thank you.

Randy Eresman

Thanks, Brian.


Thank you. Your next question comes from Stephen Calderwood of Raymond James. Please go ahead.

Stephen Calderwood - Raymond James

Yes, thank you. If I could start with a question on the oilsands growth, I wonder: if you were disappointed with the pace of development in Foster Creek, the expansion of unit at Foster Creek? And, you mentioned another three expansions, two at Foster Creek and one at Christina Lake, over the next two years to add 72,000: do you think then you can keep a better pace going forward? Or: do you think it's going to be as challenging as it has been?

Randy Eresman

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

John Brannan

I think as far as our pace of development at Foster Creek and Christina Lake goes, we are happy and comfortable with that. A little bit of our production shortfall so far this year have been associated with operational issues as we bring those new phases into production. But, overall, we're very happy with the performance of the reservoir.

The two projects that we have at Foster Creek, they're each 30,000 barrels projects, the 1D and 1E, essentially on time and on schedule. And we plan on bringing those on sometime next year and we'll reap the benefits of that production late in 2008 and into 2009.

At Christina lake, we've got about 12,000 barrel a day expansion there that should take that field up to about 18,000 barrels. That expansion will be finished late this year. We'll start steaming wells associated with that and receive some of the benefits in 2008, but the full benefits in 2009.

Stephen Calderwood - Raymond James

Excellent. If I could ask one more question on pushing the gas production, obviously, the relative ease of attaining better than 3%, and this is more or less a question for Randy: would you characterize that exceeding 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 should increase our positive bias to your growth going forward?

Randy Eresman

We set our targets based on the expectations that our teams build up. And really a lot of the incremental gas production we got this year was a result of Jonah outperforming our expectations. And it appears that it may be set up to outperform again next year, but that's hard to say that we'd be able to continue that on.

We are having a tremendous amount of positive results in a lot of our key resource plays, as you can see by going through the details of our release. Overall, things are performing very well and we're managing our costs very well. So basically the model is working extremely well.

Now, in the longer term: does that mean that we'd increase our 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 be something that's working well. We've communicated it to our teams very well and they are performing very well. So, things are actually going quite good right now.

Stephen Calderwood - Raymond James



Thank you. Your next question comes from John Herrlin, Merrill Lynch. Please go ahead.

John Herrlin - Merrill Lynch

Yeah. Hi. I think I have a variety of questions for Jeff and also Randy. With respect to Jonah, your sequential well count from second quarter 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 because of lower gathering system pressures, but you also said you had better completion.

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

Randy Eresman

All right. Jeff will answer that.

Jeff Wojahn

Hi, John, Jeff Wojahn. You bring up all kinds of different points here for me to talk about. So, thank you. I think the first comment you talked about was the sequential ordering or the cumulative scheduling of our wells. And one of the great things that we saw in Jonah Field this year was improved performance in our fit-for-purpose drilling, which led to lower cycle time and faster rate of drilling.

So, I think, what we realized is we probably had more rigs than required to meet the program that we had originally designed, and we tapered off on a couple rigs and, basically, focused on increasing the rig counts in our new fit-for-purpose equipment. So, that strategy has worked very well and we've been able to stay within our capital discipline and our overall cost structures very well.

In regards to where the production has come from, and we look 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 increased IPs, or initial productivity of our wells drilling about 40% from the compression project.

John Herrlin - Merrill Lynch

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 of behind pipe on the shallow gas stuff?

Randy Eresman

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

Don Swystun

Hi there, John. Yeah. On the shallow gas side, we were down in Q3 some degree on production, but that's because in Q2 we had a very wet season and we didn't get as many wells as we wanted to expect. Q4 will have similar drilling rates to Q3 at that level.

John Herrlin - Merrill Lynch

Okay. But you had 360 more wells spud. so I was just wondering why the volumes were lower. That's okay.

Don Swystun

Well, you won't see…

Randy Eresman

That's timing related.

Don Swystun

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

John Herrlin - Merrill Lynch

Okay. So you do have behind pipe.

Don Swystun


John Herrlin - Merrill Lynch

Okay. One for Brian with respect to hedging. $499 million of pre-tax gains is pretty large. Did you close out any of the contracts early given the volatility of prices? Or: did you just let them run their course?

Jeff Wojahn

I'm going to answer that question, John. We've taken the practice of leaving all of our positions in place. We don't trade around them.

John Herrlin - Merrill Lynch

Okay. Great! And last one on refining: is it possible, going forward, that maybe you can disclose some more information? We file a comp and we can't get their actual results from the US to jive, but we don't get refinery specific information.

Randy Eresman

Yeah. That would be the difficulty, John. We're reporting based on our share of two refineries versus, I don't think they separate their entire portfolio.

John Herrlin - Merrill Lynch

They don't. But, you did a lot better than their average. And so, I was wondering can you….

Randy Eresman

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

John Herrlin - Merrill Lynch

No doubt. Thank you.

Randy Eresman

Thank you, John.


Thank you. Your next question comes from Stephen Beck, Jefferies & Company. Please go ahead.

Stephen Beck - Jefferies & Company

Hi, thank you. My first question, I guess, I'd like to focus on the Barnett. I noticed that the number of net wells that were drilled fell off sequentially. I was wondering: if, maybe, you could elaborate a little more, or provide some discussion on your experiences in Q3, regarding rig count and activities and expectations going forward?

Jeff Wojahn

Stephen, its Jeff Wojahn. The same effect that we saw at Jonah Field is the same thing that we saw on the Barnett. We originally had anticipated drilling six or seven rigs program throughout the year to meet our production in capital guidance on the Fort Worth play.

But what we found was that we were drilling the wells much more cost effectively in lowered cycle times than we had anticipated, and we really saw 25% to 30% improvements in our drilling times with our fit-for-purpose rigs. So we adjusted our rig counts. We modified those down to about five active rigs today and slowed down our well count. So the program was a little bit more skewed to the second quarter than the Q3 basically because we were stewarding within our capital discipline as the year goes on.

With that said, we've enjoyed about an 18% cost reduction year-to-date. We expect to maintain five rigs in Q4, drill 86 gross wells in total for the year. So, I've been very pleased with the results of this program. We've had excellent results by the team, a lot of focus, and we've demonstrated that we've got a good line position in the Barnett Shale and a good growth area for us in the future.

Stephen Beck - Jefferies & Company

Jeff, just wondering, I was looking at the sequential growth in terms of production. Q2 is 124 versus Q3, 128. Is there production behind pipe or what can we expect in Q4?

Jeff Wojahn

Well, I expect to see this type of volume growth that we've exhibited. 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 their guidance for the play. And, as I mentioned, this is one of our higher growth areas. But really it's a function of timing and scheduling rather than results. The results have been excellent.

Stephen Beck - Jefferies & Company

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

Jeff Wojahn

Yeah, I'm just digging that out for you right now. I'll go over the quick things. Production guidance, capital guidance of $285 million and 70 wells, and we're a little bit ahead of that right now. I'll have to get back to you on the cost per well.

Stephen Beck - Jefferies & Company

Okay, great. Thank you.


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Source: EnCana Corporation Q3 2007 Earnings Call Transcript
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