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EnCana Corporation (NYSE:ECA)

Q2 2009 Earnings Call

July 23, 2009 1:00 pm ET

Executives

Paul Gagne - Vice President of Investor Relations

Randall Eresman - President and Chief Executive Officer

Brian Ferguson - Chief Financial Officer and Executive Vice President

Jeff Wojahn - Executive Vice President and President, USA Division

Michael Graham - Executive Vice President and President, Canadian Foothills Division

R. William Oliver - Executive Vice President, Business Development

John Brannan - Executive Vice-President and President, Integrated Oil Division

Don Swystun - Executive Vice-President and President, Canadian Plains Division

Analysts

Brian Singer - Goldman Sachs

[Brian Lavely] - Tudor, Pickering, Holt & Co.

Chris Theal - Tristone Capital

Brian Dutton - Credit Suisse

Richard Wyman - Canaccord Adams

[Bart Polla] - Scotia Capital

Martin Molyneaux - Firstenergy Capital

Mark Gilman - Benchmark

[Dan Trozo - Rice Hall James]

Shaun Polczer - The Calgary Herald

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the EnCana Corporation second quarter 2009 financial and operating results. (Operator Instructions)

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

Paul Gagne

Thank you, Operator, and welcome, everyone, to our discussion of EnCana's second quarter 2009 results.

Earlier this morning we updated our 2009 guidance document and Key Resource Play information sheets. In addition, we posted a supplemental slide package providing the highlights of today's conference call. These materials can be found in the Investor Relations section of our company website, EnCana.com.

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 20, 2009, the latter of which is available on SEDAR. I'd 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 highlights of our operating results and then turn the call over to Brian Ferguson, EnCana’s CFO, who will discuss EnCana’s financial performance. Following some closing comments from Randy, our leadership team will be then ready 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.

Today’s call will highlight our performance in the second quarter of 2009. We're now at the midpoint of the year and we're very pleased with our results to date.

Our performance is the result of many years of hard work by our teams and demonstrates the advantages associated with our resource play strategy. We've established premium land positions in many of the major North American unconventional gas fields and we hold recognized top-tier oil properties as well. Despite the current lower commodity price environment, our determined focus on costs further distinguishes us from our competitors.

Our quarterly natural gas production was on target. This was achieved through lower than

expected royalties on our Canadian production offset by volumes we chose not to bring online in both Canada and the United States. Our production would have been quite a bit higher than our guidance had we not restricted volumes by about 300 to 400 million cubic feet per day. About half of this volume could be brought on relatively quickly as it is physically shut-in, while the remainder would take more time as some additional work would be required to bring it onstream.

We’ve updated our guidance document to widen the production range to reflect the uncertainty of the current commodity price environment. We’ve also updated our capital and operating costs.

While we're spending more time scrutinizing how we manage our existing production base, we continue to move forward with the evaluation of our emerging plays.

In the Haynesville, we continue to increase our drilling program and the latest well results continue to be very positive. We plan to drill about 50 net wells this year, which will enable us to further increase our understanding of the play, evaluate our lands, and retain prospective acreages. The most recent EnCana wells were drilled at a cost of $9 million per well and, while the production from the wells are currently restricted due to midstream constraints, we estimate that they have the potential to produce between 15 and 20 million cubic feet per day against line pressure for 30 days. We continue to believe that the Haynesville will be one of the most important gas plays in the future of our company.

In the Horn River, our results have also been very encouraging. After 15 days of initial flow, our latest Horn River wells have rates in the range of 9 to 11 million cubic feet per day. The potential size and quality of this play along with its favorable royalty structure make it very competitive in the North American natural gas market. With the help of technology going forward we expect to see lower costs and improved efficiencies that could also make the Horn River one of the most important plays in our company.

We continue to develop these and other emerging plays as we believe that the current sub-$4 price levels for natural gas are not sustainable in the long term. Our current view is that the marginal supply cost for North American natural gas has been significantly reduced by the successful application of technology in plays such as the Haynesville and the Horn River.

Consequently, we have reduced our long-term NYMEX natural gas price expectation to a range of $6 - $7.

Despite this lower price expectation, EnCana will do well. Our focus on being the lowest cost producer, our active portfolio management and our dedication to high-grading our asset base will ensure that we maintain a strong operating and financial position.

The emergence of shale gas has changed the landscape for North American natural gas. The supply of natural gas is now estimated to be large enough to meet North America’s needs for more than one hundred years. We and other gas producers believe that there is an opportunity to expand the market for natural gas to displace significant quantities of coal and foreign oil to become a much larger source of clean energy for North American power generation and transportation fuel. Natural gas represents an abundant, secure, long-term supply of energy to meet North America’s needs.

We're encouraging policy makers to look at the potential for increased use of natural gas as an economic, transportation and power generation fuel as a means to reduce both U.S. dependence on foreign oil and North American greenhouse gas emissions. Compared to the current energy choices available in North America, natural gas is one of the most environmentally friendly options, and we've have started to convert several of our vehicles in our fleets at select Canadian and U.S. operations to run on natural gas.

While we're excited about the opportunity we have for natural gas, we're also confident that domestically sourced oil will continue to play an important role in the North American energy mix. In the second quarter production from oil and natural gas liquids were up 6% to 136 thousand barrels per day versus the same quarter in 2008. We saw a 65% increase in our production at Foster Creek and Christina Lake compared to the same quarter in 2008.

Improved operating performance at Foster Creek and Christina Lake, combined with the start-up of production for Foster Creek Phases D and E, contributed to our production growth in 2009.

These phases are consistent, scalable and repeatable expansions that enable us to learn from prior phases and incorporate technical advances as we expand. Since our first pilot project at Senlac in 1996, we've been able to grow our combined gross production to almost 100 thousand barrels per day from three separate project locations - Foster Creek, Christina Lake and Senlac - all while leading the industry in capital efficiencies and low operating costs.

Our superior capital efficiencies can be attributed to our low steam-to-oil ratios and our

manufacturing approach to development. Most recently, we established a module yard in Nisku, Alberta which is dedicated solely to the construction of pipe modules. Having all the components built and assembled at one offsite location has allowed us to better control the safety of the operations while improving the quality of the pipe modules and minimizing re-work and additional field costs.

We have continued to implement technologies which help lower operating costs, decrease water use, reduce land disturbance, decrease the amount of energy used, and improve oil recovery rates. These technologies include implementing wedge wells on a commercial scale at Foster Creek to capture bitumen between steam chambers with minimal additional steam injection.

We're also in the early stages of implementing a full-scale pilot of our Solvent Aided Process or SAP, as we call it, at Christina Lake which mixes a solvent such as butane with steam to help mobilize the bitumen and improve recoveries with lower energy input.

We're also continuing to evaluate low pressure SAGD along with a number of other technologies that help lower our overall environmental footprint while increasing production or recovery rates.

Overall, strong operating performance this quarter.

I'll now turn the call over to Brian Ferguson, our Chief Financial Officer, who will discuss our overall financial performance.

Brian Ferguson

Thanks, Randy. Good morning, everyone.

EnCana had another strong quarter financially. Despite a 68% decline in NYMEX gas prices and a 52% drop in WTI, we achieved cash flow per share diluted of $2.87, down 25% compared to the same quarter of 2008.

Our cash flow performance is within expectations and, as a result, we have maintained our full year cash flow guidance at between $9.50 to $11 per share. Our cash flow performance was accompanied by strong operating earnings of $1.22 per share diluted, down 38% year-over-year.

Our net earnings for the quarter of $0.32 per share were down 80%. This included realized after-tax hedging gains of $900 million in the quarter which were primarily offset by $750 million of unrealized after-tax hedging gains (sic) in the second quarter. The unrealized hedging losses are a result of marked-to-market accounting, which causes us to book gains or losses to net earnings in prior quarters and then remove the prior gains or losses when they are realized as we get the cash proceeds.

Year-to-date we've realized after-tax hedging gains of $1.6 billion. We also have in place a

strong hedge position for the balance of 2009 and into 2010. This will greatly reduce volatility in

our cash flow. Both cash flow and operating earnings beat the Street estimates.

Looking specifically at our costs in the second quarter, combined operating and admin costs were $1.15 per thousand cubic feet equivalent and below our previous full year guidance estimate of $1.40. Decreased costs were primarily due to lower long-term compensation costs, a lower U.S.-Canadian dollar exchange rate, and lower repairs, maintenance and workovers.

As Randy mentioned earlier, we adjusted our 2009 guidance. We've lowered our full year estimate for our operating and admin costs to $1.30 per thousand cubic feet equivalent.

Our balance sheet remains strong. Debt to adjusted EBITDA finished the quarter at 0.7 times.

Debt to capitalization at June 30th was 27%. On May 4th we completed a debt issue in the United States of $500 million in 10-year notes with an interest rate of 6.5%. There was a huge response to this offering and it was significantly oversubscribed. We feel that this was a great reflection of the appetite for EnCana’s debt and demonstrates the market’s confidence in EnCana’s strong financial position and our overall strategy and focus on resource plays.

Overall, our balance sheet exited the second quarter in similar fashion as we entered it. EnCana remains in a strong position and continues to employ a conservative capital structure.

Capital investment was in-line with our expectations as we have invested about $2.6 billion at the halfway point of the year. Through the first half of the year we have identified significant cost savings, prompted by a challenge to all employees and contractors working for EnCana. We challenged our teams to save 10% in capital, operating and admin costs without sacrificing cash flow. We've reached our goal by identifying savings in excess of $900 million for the year. We've taken this opportunity to redistribute some of the saved capital to other parts of our portfolio to help position us for the future. This is reflected in our updated guidance document as well. We've adjusted our guidance range to $5.5 to $6 billion dollars to reflect our current expectation for the capital program.

Some of the forecast capital reductions result from deflation. We've seen cost reductions of about 5% to 10% and an increased willingness on the part of suppliers to negotiate. For the year as a whole we expect inflation to be down significantly over 2008.

It's worth mentioning that we've seen savings of up to 25% in some areas of our operations. Labor rates, which are a significant component of overall cost, are not expected to move with the same timing or velocity as other inputs; however, labor productivity has improved.

As I mentioned, our natural gas price hedging program continues to serve us extremely well. Two-thirds of EnCana’s expected production is hedged through October at an average NYMEX equivalent price of $9.13 per thousand cubic feet. We've hedged about 2 billion cubic feet per day for the November 2009 through end of October 2010 at a NYMEX price of $6.09 per thousand cubic feet. We continue to look for opportunities to add additional hedges if the conditions are favorable. Our risk management program provides increased certainty around future cash flows and confidence for our capital spending programs.

In the second quarter we began to see some improvement in the price of crude oil. Although the year-over-year price of WTI is down more than 50%, oil prices did improve from the first quarter and the light-heavy differential narrowed. Accordingly, our Integrated Oil Division generated upstream operating cash flow of $206 million and downstream operating cash flow of $154 million this quarter, both ahead of our expectations.

The downstream component of the Division’s operating cash flow represents an increase of $95 million to $154 million as compared to $59 million in the first quarter of this year. The second quarter cash flow includes an increase of approximately $100 million related to lower purchased product costs as a result of accounting for inventory based on a first-in first-out valuation as required under Canadian GAAP. This inventory valuation methodology results in lower product charges to operations in a rising input cost environment.

The Chicago 3-2-1 crack spread, although 19% lower than the same quarter in 2008, was relatively strong in the second quarter of 2009 and averaged about $10.95 per barrel. Our realized crack spread, combined with lower operating costs as a result of reduced energy costs, were key drivers of the downstream results. Lower natural gas prices resulted in reduced variable operating costs for both the upstream and downstream segments of our business as natural gas and electricity are key cost drivers.

Overall, I am pleased with our financial performance.

I'll now turn the call back to Randy.

Randy Eresman

Thank you, Brian.

So far our non-commodity based results have been positive and in line or better than our expectations, a credit to our teams, our assets and our strategy. We continue to use our advantage of being a company with a strong diversified portfolio of low-risk, low-cost, long-life

development projects. We're focused on optimizing the factors that are within our control and

minimizing our exposure and risk for those that are not.

We strongly believe that we have premium a position in the two energy sources which hold huge

growth potential in North America - unconventional natural gas and enhanced oil. We believe

that there are enormous economic and environmental advantages to expanding the use of natural

gas in our economy and that future sources of domestic oil will need to be extracted using enhanced recovery methods with a lower impact on the environment.

We continue to keep our operations steady and consistent through this low point in commodity pricing and uncertain economic environment. However, this market allows us to showcase the strength of our business model to our shareholders, demonstrating that we can successfully withstand the most difficult economic conditions in recent memory.

Finally, I'll now take a moment to provide an update on the timing of the proposed corporate reorganization of EnCana into two independent energy companies.

We continue to believe that the underlying reasons for creating the integrated oil company Cenovus and establishing EnCana as a pure play natural gas company remain intact; however, significant uncertainty in the current economic environment continues to exist. We remain committed to maximizing value creation for our shareholders and will provide updates in the future as appropriate.

Thank you for joining us today. Our team is now ready to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

When you think about your lower long-term gas forecast of $6 to $7 combined with the improved productivity from the Horn River and Montney plays, how do you think about your own Canadian production growth in that environment as well as Canadian production, gas production, growth overall?

Randy Eresman

Corporately we've been targeting a long-term production growth for natural gas in the 4% to 6% range, the target we've had for the last number of years, and then, of course, as you know, in this environment we've slowed it down a bit.

In that environment we have a lot of plays such as our Montney, a lot of our Shell gas plays that have much lower supply costs than the bottom end of that range and can do potentially quite well. In the meantime and over the last couple of years we've been continually divesting of some of our more mature conventional assets that possibly won't be able to compete as well in that long-term environment.

So I think we're in pretty good shape to at least maintain that same target and I'm saying overall for the company, not specifically Canada or the United States, with the possibility that it could actually rise in the future as a result of having a more concentrated base in these lower-cost plays.

Brian Singer - Goldman Sachs

And do you see Canadian production overall as less competitive relative to the U.S. either within your own portfolio or, more likely, overall?

Randy Eresman

You know, it really is a play specific situation. There are and have been certain challenges historically being in Canada with a higher overall cost structure and challenges oftentimes with changes, rapid changes in exchange rates and the access to supplies and services. That situation has largely been reduced right now and we're seeing significant opportunities arise in Western Canada. The royalty structure of the Alberta government works in our favor today, so there are plays that are actually becoming more competitive compared to the U.S.

Generally, wherever you have the most concentrated resources and the lowest cost development, lowest operating cost, those are the ones that are going to be developed first in the future in this kind of a dynamic environment.

Brian Singer - Goldman Sachs

And lastly, could you provide some more color on the production that's either shut-in or uncompleted, the 300 to 400 million, of the half of it that you mentioned takes a little bit of time to come back on, at what price and how long would it take to bring back? And maybe if you could provide a U.S.-Canada split of that 300 to 400 million?

Randy Eresman

The majority of it is in the U.S. and Jeff can actually go through where the bigger chunks of gas are either shut-in or have not been brought on and the details around that.

Jeff Wojahn

In regards to the U.S., we have approximately 200 million a day shut in or curtailed and you can see when you look at our guidance relative to our KRPs or Key Resource Plays in the U.S. that you've seen a reduction from Q1 to Q2. Those reductions are related to those shut-ins or curtailments that I mentioned, the 200 million a day.

In regards to overall, when wells are shut-in or curtailed outside of swabbing operations and that's just a function of equipment and timing, we can bring on our wells fairly quickly. For instance, in East Texas, because of the high pressure environment we're talking about weeks.

In the case where swabbing operations are required or in the case where fracture stimulation operations are required - and that's beyond the shut-in or curtailed volumes that I mentioned  we're talking, you know, four week to six week timeframes.

Randy Eresman

And Mike Graham also has some shut-in in the Foothills division.

Michael Graham

Yes, but we've actually got, in the order of a little over 100 million cubic feet a day shut-in in the Canadian Foothills division right now and a lot of that is in the deep basin, a lot of it's in the Montney, places where we're 100% and there's no issues around royalties or the like.

Operator

Your next question comes from [Brian Lavely] - Tudor, Pickering, Holt & Co.

Brian Lavely - Tudor, Pickering, Holt & Co.

I just really have a follow up question on your restricted production. Can you give a comment on just that number or the backlog of wells that you actually have that are drilled but not completed?

Brian Ferguson

I don't know that we've been tracking that in inventory because we always have a lot of wells that have been drilled and not completed just sequenced in. But we have definitely in some areas slowed it down a bit. But I don't think we have been tracking that specifically.

Brian Lavely - Tudor, Pickering, Holt & Co.

Then going on to your second quarter production, first is your full year guidance and you've already kind of alluded to that. Can you just kind of comment a little on how you think about that strategy of continuing to drill but not complete wells going forward and how that may play out for the rest of the year? Because it seems like if you look at that comparison between the second quarter and full year, it seems like that there is some production coming back to the market in, say, the Jonah and East Texas areas.

Randy Eresman

You know, the natural gas market has always been volatile and always been surprising for us, so we'll wait for opportunities to bring on wells that have high initial natural decline. Wells that are just going to slow down we can turn them on and react to the market very quickly as well.

I guess we really don't know what's going to happen in the course of the next year, but I would not want them to be shut-in indefinitely.

Brian Lavely - Tudor, Pickering, Holt & Co.

Sure. So in your full year estimates then you have dialed in some curtailment in those numbers?

Randy Eresman

In our full year estimate what we've done is we've simply given a wider range for the potential outcome this year. And if the market did come back on the fall we'd be able to bring production back on to our original target and possibly even exceed it. If [the fall] market is quite low, which it kind of looks like it will be today, it's more likely we'll hit the lower end of that range.

Again, it's a pretty dynamic situation. We're seeing prices in some of our basins that have gotten pretty low.

Brian Lavely - Tudor, Pickering, Holt & Co.

And kind of along with that have you seen some improvement or to what extent have you seen improvement in the realization from the Rockies area?

Randy Eresman

Well, I think the basis differential in the Rockies has shrunk quite a bit, so that's been helpful since last year.

What other comments can you make about that, Jeff?

Jeff Wojahn

Yes, you know, I think one of the things that we saw earlier in the year is a dramatic decrease in rigs in the Rockies and with that there's a delayed reaction in regards to production drops. And we see some of the future fundamentals of the Rockies suggesting pricing in that 80% to 85% range of NYMEX. That begins to equalize the Rockies relative to potential other basins where we can continue.

But overall I would say the fundamentals in the Rockies are weak but improving.

Randy Eresman

Yes. I think the basis for companies [inaudible] the last quarter came down to about $0.66 and I know in periods in the past that was getting closer to $1, so overall it's come in with the reduced production.

Operator

Your next question comes from Chris Theal - Tristone Capital.

Chris Theal - Tristone Capital

In the press release you guys talk about the increase in Haynesville IP rates moving up to 14 intervals per well. Can you just give us sort of a barometer? What did IP rates look like on the first sort of vintage of wells relative to the IPs you're seeing on these increased frac densities?

Jeff Wojahn

We started out in the Haynesville three years ago drilling vertical wells with 1 million a day IPs or less and we have steadily increased IPs through the application of horizontal drilling, an increased in sand concentrations, water concentrations, length of wells and stages, and you know, today we're moving from eighth-stage wells to 12 to 14-stage wells. And with that what we're seeing - you know, that's about 3.5 million pounds of sand in those 12 to 14-stage wells - with that we're seeing water production profiles, higher pressures and higher rates.

So we have talked about a 6 Bcf-type curve and that really was based on kind of an 8-stage well, 3,000-foot lateral, and we're wondering if with time we can gravitate towards an upside of a 9 Bcf-type curve with 12 to 14 stages. We have limited data today - three or four wells that EnCana has - but those wells are very encouraging and have been at the top of our ranges. In fact, one well we drilled this last quarter, the Conway Harris 22 well, we actually physically flowed at over 20 million a day at 8,400 pounds flowing pressure and that was a higher-stage well with more [profit] in the core area of Red River where we've seen high rates before as well. But it's an indication that more stages, more sand, more emphasis in our fracture stimulation program will yield higher results, and so we're moving that way in the play.

Chris Theal - Tristone Capital

Any incremental thoughts on Mid-Bossier since the Q2 call?

Randy Eresman

We're currently pumping a well as we speak in the Mid-Bossier. I don't have specific results and I anticipate that there'll be some more results and comments in the Q3.

Operator

Your next question comes from Brian Dutton - Credit Suisse.

Brian Dutton - Credit Suisse

Lots of commentary's been coming in lately on the Kitimat LNG project and I was wondering what your thoughts are there in terms of the possibility of you being a supplier to that project?

R. William Oliver

The Kitimat project has always been of interest to us. In fact, I think we stimulated the idea of turning it from a re-gas into a liquefaction with some of the optimism we had in the Horn River.

What they're attempting to do right now - and we certainly support that - is to try to find a home, first of all, for the LNG, and I think you've seen some contracts for takeoffs going to go to the Asia market. The next thing they're attempting to do is get commitments by producers in terms of supplying the gas.

So given the right commercial contract and circumstances, we might entertain that, but we really believe that there's a lot of liquidity in BC and if we develop the Horn River to the extent that we think it should be there shouldn't be any problem in terms of getting enough gas into that facility.

What they really need, though, is someone to come and build physically a liquefaction plant. I think that's what they're tempted to do to match up the buyers and sellers, so anything that the industry can do to make that project go forward I think would be very positive for the natural gas industry in Canada and specifically for the Horn River.

Brian Dutton - Credit Suisse

You're probably not willing to put all your cards on the table, but what would attract you to be a supplier to the project? What kind of contract conditions?

R. William Oliver

Well, we would certainly have a contract that would equate to the other options we've got to sell our gas in Canada, so it'd have to be equivalent to some sort of [inaudible] pricing, station two pricing, something along those lines.

But it's really premature for us to talk about that because it is just very preliminary discussions on those commercial interests.

Brian Dutton - Credit Suisse

The other question is on the Western Canada gas production. You made reference in the commentaries and also in the text itself about the royalties having an impact on your reported net production.

Could you tell us what the gross production was before royalties from the first to the second quarter?

Paul Gagne

We'll get back to you after the call on that.

Operator

Your next question comes from Richard Wyman - Canaccord Adams.

Richard Wyman - Canaccord Adams

I've got a couple questions here, some to follow up on prior ones.

First of all, just for clarity on the drop in production in East Texas, was that entirely due to shut-ins or curtailments or were there other influences affecting production there?

Jeff Wojahn

That was entirely under our control.

Richard Wyman - Canaccord Adams

And then in terms of the production at Haynesville you comment on Northern Louisiana as being gross 100 million a day. I presume that's all Haynesville. How much of that would be net?

Brian Ferguson

Richard, about 100 million a day gross and about 75 million a day net.

Richard Wyman - Canaccord Adams

And a question for Mike, just to get a little update on Montney production right now and how you see that changing as the year unfolds.

Michael Graham

We're drilling about 60 wells in the Montney this year and then we're probably getting close to about 180 million cubic feet a day just out of the Montney alone.

There's probably on the order of about 15 rigs running in the play; ourselves, I think we have four or five rigs running in the play.

The Montney looks very encouraging. The costs continue to move down. We're doing our completions, frac completed, tied in, everything for on the order of less than $700,000 per interval now, so very attractive finding and development costs, sort of $1.50 range, even lower than that.

So things are continuing to progress well in the Montney and we do have a tremendous land position and we're testing some more areas on the Montney, so we're very encouraged by it.

Richard Wyman - Canaccord Adams

And with the Alberta royalties, are you moving that activity into Alberta rather than the focus to date in BC?

Michael Graham

Yes, Richard, we've looked at sort of comparable royalties across BC and Alberta and both of them are actually quite competitive and both are talking about more stimulus programs as we go, so both are doing a pretty good job there.

We do have rigs on the Alberta side as well in the area that we call Gordondale, and we like what's happening in Alberta. These couple-year incentives really help out the Montney and make it very comparable to what we're doing in British Colombia.

Richard Wyman - Canaccord Adams

And then one last question here. There was a comment in the conference call earlier about capital efficiencies in the oil sands developments. Can you just put a number on that, dollars per BUE a day and how that might relate to historical experience?

John Brannan

We've just completed at Foster Creek the D&E expansions, which were each 30,000 barrels a day. Capital efficiencies on a U.S. dollar basis around $15,000 per barrel.

At Christina Lake we are in the process of building a 40,000 barrels a day expansion there called 1C, and we're saying that that will be in the roughly $18,000 to $20,000 per flowing barrel upstream on capital efficiencies.

Richard Wyman - Canaccord Adams

And in the context of historical experience, how do those numbers compare?

John Brannan

Generally fairly flat because we're building a lot of infrastructure in those kind of things in there. We are building a little bit for the future as we go forward. We're not seeing great reductions in overall capital costs there. We are seeing some improvements in productivity on the workers. The project that I've got going right now, the 1C, that's why I gave you a range of about 20, we've [parted] for about $20,000 a barrel and we're opening we can bring it in somewhere around $18,000 or $19,000.

Operator

Your next question comes from [Bart Polla] - Scotia Capital.

Bart Polla - Scotia Capital

A question for you on SAGD operating costs. It came down quite significantly in this quarter. I was curious if that's largely just low gas prices or if you're seeing any other [break in audio] operating cost reductions there?

John Brannan

On the op costs, yes, we've definitely seen a reduction in our overall fuel gas costs because of the natural gas prices coming down, but also we've increased our volumes substantially at Foster Creek, in particular, and so on a per unit basis there's some reductions there. But I also think that we've been working with our contractors, our chemical contractors, our mechanical contractors, workovers and those things. We've actually realized some savings there.

So the biggest drop has been on natural gas prices, but the efficiencies that we're gaining by additional volumes and some contract negotiations that we've had to reduce our suppliers' costs.

Bart Polla - Scotia Capital

I guess as you're adding in 2010 hedges right now I assume you're starting to think forward to next year's budget and I'm just curious, depending how next year's pricing environment looks, how you weigh decisions in terms of capital spending cuts versus dividend cuts come later this year?

Randy Eresman

We've already put a significant number of hedges on, as we said, for 2010 and at this level we're starting to feel pretty comfortable about the amount of free cash flow that we'll be generating, so I wouldn't think that our dividend is significantly at risk at this point in time. But, of course, that is a Board decision that's made on a quarterly basis.

With respect to our capital program, we have slowed down our capital program this year to target kind of a zero percentage growth rate. I would expect that if the market continues to be as it is now that that's what you might expect for next year. Costs continue to come down, so I would think that we may be able to achieve along the line of what we're spending this year, maybe even hopefully a little bit less. But that will unfold with time and we'll put our capital program out some time in the fall for 2010 - I think we may do it as late as December this year again - and that will be significantly based on what we see for market conditions at that time.

Operator

Your next question comes from Martin Molyneaux - Firstenergy Capital.

Martin Molyneaux - Firstenergy Capital

Gentlemen, given what you just said in terms of the heavy oil projects, I guess question number one is with the low gas prices is there opportunity to push more steam into the system given the lower cost environment and potentially even lower gas prices in August and September here?

And I guess question number two is given the current oil and current natural gas prices is there any room for accelerating any of the heavy oil portfolio?

Randy Eresman

Martin, as you know, a lot of the things we do on the SAGD side are really longer-term decisions. I think we try to optimize the facilities at all times, so I doubt very much that there'd be much flexibility in terms of adding more steam. We typically don't react very much in that way.

But in our Plains business unit - our Plains Division, I mean - we are reacting where we can to shift some dollars away from the natural gas development to heavy oil development and Don Swystun can comment on what he's doing there.

Don Swystun

The most active area that we're pushing money into is right now into Suffield, particularly in that [inaudible] because of the Alberta incentives also that - adding some wells there. So we'll probably do maybe even up to 75 wells in the Suffield area. We're also looking at some additional wells, maybe in Brooks as well and some Saskatchewan opportunities that I think we'll be looking at drilling in the second half of this year.

Randy Eresman

I'm going to turn it over to John to answer the first part of the question, to either add or clarify something I said.

John Brannan

I think one of the things that we've really been focusing on in both Foster Creek, Christina Lake projects this year is really working on improving our operating efficiencies and not having any downtime. So we are looking to get as much oil as we can out of the ground. We are running our steam generators that we have and those that are built pretty much at capacity as best we can.

We have approvals, regulatory approvals, at Foster Creek for the current projects that we're bringing on and we don't have additional regulatory approvals beyond that. We have made applications for expansions for FG&H at Foster Creek.

At Christina Lake we have approvals for up to 98,000 barrels a day, regulatory approvals, and we're working with partners to sanction the 1-D here hopefully in the next quarter.

And so we're trying to progress those projects as best we can. We have not slowed down any of our developments like some of the other operators had done when the oil prices slowed down.

Martin Molyneaux - Firstenergy Capital

Just in terms of following up with that, in terms of approval processes are you noticing slowing down or speeding up in terms of those exercises given the falling away of some competitors?

John Brannan

We made our applications. We're working with the regulators to move those through as quickly as we can. I think we're working as a company to provide complete and detailed applications; that improves the process.

Martin Molyneaux - Firstenergy Capital

And the last question here: In terms of Foster Creek and Christina Lake, fabrication costs for those facilities, have you seen any, like, are they where we have been previously or have you seen some erosion in capital intensity on the future [inaudible]?

John Brannan

I think we haven't seen substantial cost reductions because a lot of the things that we bought, like steam generators and steel and those kind of things, are ordered and bought ahead of tie. We may see some reductions as we go into these future phases.

The things that I can say is that we are seeing improvements in worker productivity and we're not having the turnarounds that we had when we lost crews and stuff to other major projects in the Fort McMurray area and those kind of things.

So we're very happy with the work force and the projects that we've got going forward. We think that we're cutting some time off of them. We used to say it'd take, say, 36 months; now we're saying maybe we can do them in 30 months and those kind of things.

So ultimately when we do these new projects hopefully we'll see some improvements if the market conditions stay where they're at today.

Operator

Your next question comes from Mark Gilman - Benchmark.

Mark Gilman - Benchmark

First, Randy, Jeff, Mike, are there any physical well consequences to extensively deferring completions that ought to be taken into consideration?

Randy Eresman

We would take those into consideration before we decide to shut-in a well or not complete it.

There are some things that can happen. Jeff mentioned that some wells may require some swabbing to bring them back onstream and in that kind of a situation there's always a possibility that you will do some near well bore damage. So we try to be very careful with wells that are wet producers, not to do too many of them.

But Jeff and Mike?

Jeff Wojahn

When we look at the criteria for selecting wells, you know, one of the things that we looked at is their decline characteristics, the actual reservoir performance of the well, and, as Randy mentioned, carefully select the wells that we thought would have relatively low cost for bringing it back onstream.

But there's a lot of other considerations that we took into account - obviously, our contractual arrangements, lease arrangements with our partners; another factor that's of significant importance is well data collection. There's numerous things that are local and we've asked our teams to specifically look at each of our areas of work to identify those considerations that are costly or that we just can't do and from that we were able to develop a strategy for each of our fields.

Mark Gilman - Benchmark

Okay, if I could shift gears a little bit, John Brannan, I believe the application regarding Borealis was probably submitted, I don't know, 9 - 10 months ago if my recollection's correct. Give me an update on where things stand on that.

John Brannan

We're currently waiting for the province to come out with the top water management. We've been consulted on that, reviewing on that, but I think really that's the holdup on that application.

Mark Gilman - Benchmark

So it's still pending?

John Brannan

Still pending, that's correct.

Mark Gilman - Benchmark

And just one philosophical question, Randy or Brian, if I could, you and I guess others seem to be thinking that natural gas prices will remain weak in 2010. I'm wondering as you think about the capital budget for next year whether it will be a budget that would be predicated upon generating free cash flow in the kind of price environment that you now seem to envision?

Randy Eresman

Yes, it will. That is basically how we've been trying to operate the company for the last number of years. And so we can control the size of our capital budget, although we do, as much as possible, like to take advantage of the current market conditions for the service sector, you know, getting jobs done; we can do them quite a bit less expensively.

We see value in keeping our teams operating at a steady pace. We see value in making sure that the service sector is actually healthy in all the areas that we operate in as well.

So I wouldn't want to take it down too low. We always have an underlying target of creating free cash flow, but I'd say we could give up some of it and there's other ways to create it. So it won't be the end all, but it will be a factor in creating the budget.

Mark Gilman - Benchmark

Randy, would you agree at least on the basis of rough numbers, it frankly looks to me as if in, just to pick a number, a $5 kind of environment that there's no way in 2010, even with the hedges in place, that you could spend at a level sufficient to hold production flat.

Randy Eresman

I haven't come to that conclusion yet because it really is going to depend on the input costs, and if the commodity price, I'd say, continues to stay at that level we're likely to see a continued degradation of costs.

So I'm not there yet; I have to do more work. I'm just not there yet.

Mark Gilman - Benchmark

Okay, just one more for Jeff Wojahn. The decline I guess referenced in a previous question in East Texas in Deep Bossier, I would imagine, in particular, quarter-over-quarter, the first quarter was impressive. Should we infer that at least the variance which is well over 100 a day right there is all deferred completions?

Jeff Wojahn

Mark, it's deferred completions as well as curtailments. You know, in East Texas we have royalty owner partners and we have discussions with each of those partners in regards to their appetite for curtailment and based on that we curtail these wells. Because the Deep Bossier has unique properties that allow it to be turned on and off without very much well damage or cost associated with it, it's an ideal place for curtailment and shut-in and hence the reason why you saw the quarter-over-quarter reduction in production of about 100 million a day, about half of the division's 200 million a day of shut-ins and curtailments.

I should also mention that in East Texas we drilled or completed a half a dozen wells and their original 30 day IPs averaged over 20 million a day, so we are ahead of budget from a performance point of view, but we've made some decisions on production there.

Operator

(Operator Instructions) Your next question comes from [Dan Trozo - Rice Hall James].

Dan Trozo - Rice Hall James

I have a few questions on Haynesville. I think you mentioned earlier that you completed 15 wells or so in that area. I'm curious how many wells you expect to complete in the next 12 months and what is your long-term goal for Haynesville?

Jeff Wojahn

We earlier talked about our strategy in the Haynesville to drill and complete 50 net wells this year with a plan to drill and complete 100 net wells next year as part of our land retention strategy. So we envision over the next 30-month period to have 250 net wells as part of our land retention strategy to basically hold our leasehold position in the area.

Dan Trozo - Rice Hall James

And along those lines, what has your experience been with the use of resin-coated sand versus ceramic-coated sand, not only in Haynesville but maybe in other areas?

Jeff Wojahn

That is a factor dependant on the specific areas that we operate in the Haynesville. We have done a fair amount of experimentation on resin coated versus ceramic [prop] and because of the high confined pressures in the area I think the de facto solution that most operators have gone to is the ceramic sand.

Dan Trozo - Rice Hall James

You think it has a better long-term payback?

Jeff Wojahn

Well, we'll find out. I mean, that's one of the trials and tests that we're currently undergoing. We have pumped straight sand, we've pumped resin-coated sand, and we've pumped numerous different ceramic sand combinations, and one of our optimizations as we move towards a better understanding of the play is to identify the cost benefit of those three particular options. We haven't made a conclusion to date yet.

Dan Trozo - Rice Hall James

What is the cost significance between resin-coated and ceramic?

Jeff Wojahn

Cost-wise I think the cost for ceramic sand on a typical job is approaching $1 million and resin-coated is about half that, so there's a significant cost benefit. The issue is whether we see a type curve benefit or a difference in the decline characteristics.

Dan Trozo - Rice Hall James

I expect that this is an evaluation that's going to take a very long time to determine and will likely change significantly with time?

Jeff Wojahn

That's right. It's going to be years.

Operator

Your next question comes from Shaun Polczer - The Calgary Herald. Please go ahead.

Shaun Polczer - The Calgary Herald

I take it from Randy's comments on Horn River that [inaudible] is ready to go full commercial scale and, if so, what would that kind of a development look like in terms of wells, capital spending and production?

Randy Eresman

Okay, I wouldn't say we're going full commercial scale. We're still at a fairly early point in evaluation as to how big a development that we might ultimately see in the area. We will expect as we get more and more results in we'll start putting those plans together, but we do not have a full long-term development plan yet. It would be much too premature to develop that because we really don't know what the long-term characteristic performance of the wells are going to be.

What we've said is we are very encouraged with the results to date and we're taking a number of steps to make sure that we can bring production onstream for I guess the next couple of years.

Mike, you can say what exactly we have in front, the plans that we currently have with industry.

Michael Graham

Yes, Shaun. For this year in the Horn River we're actually going to drill somewhere on the order of about 18 net wells, which is actually up from what we said in the last quarter. We're actually drilling more wells and really completing less wells, if you will, so we're going to defer a lot of that, some of that, into 2010.

Like Randy talked about, we're very encouraged with the rates. Our last couple wells are 12 and 14 stage frac and, you know, midway through the month they're still probably producing in that 9 to 11 million range. The bigger the frac, it seems like the better the well, similar to what you'd find in any of the other shale plays as well.

Our drilling costs have come down significantly. We've gone from about 25 days to 16 days on some of our drilling. And, you know, from what we see today - like Randy said, it's very early yet; we've only had wells on about a year in this play - but our declines are relatively shallow. We're very happy with where we think our EURs are going to end up on these wells if we can get our costs in line and continue to prove this play throughout the basin it'll probably turn into one of our Key Resource Plays as we move on.

Shaun Polczer - The Calgary Herald

So how would it stack up against some of the other plays that you have in Louisiana and Texas in terms of competitiveness?

Michael Graham

Well, I can tell you right now, like it is very remote up in Northeast BC, so the cost structure is a little bit higher. Now, we do have lower royalties; the BC Crown has done a good job in [inaudible] industry. On a supply cost it's probably in at least the top half of our portfolio, somewhere on that order, but there's still room to move on the cost and then that's where we're really focusing in on, especially around the completion cost.

Randy Eresman

I think it's fair to say that the supply cost is probably at least $1 higher just because of where it's located.

Operator

There are no further questions at this time. Please consider, Mr. Gagne.

Paul Gagne

Thank you, everyone, for joining us today to review EnCana's second quarter results.

We would like to remind you that in 2009 EnCana is hosting a series of conference calls highlighting several of the company's key plays. Please mark your calendar for the next conference call, scheduled for Thursday, September 24th at 9:00 a.m. Mountain Time focusing on our Integrated Oil Division. Additional details will be available at a later date.

Our conference call is now complete.

Operator

Thank you, everyone, for joining us today to review EnCana's second quarter 2009 financial and operating results. Our conference call is now complete.

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Source: EnCana Corporation Q2 2009 Earnings Call Transcript
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