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EnCana Corporation (NYSE:ECA)

Q3 2009 Earnings Call

November 12, 2009; 1:00 pm ET

Executives

Randy Eresman - President & Chief Executive Officer

Brian Ferguson - Chief Financial Officer & Executive Vice President

John Brannan - Executive Vice President & President - Integrated Oil Division

Mike Graham - Executive Vice President & President - Canadian Foothills Division

Jeff Wojahn - Executive Vice President & President - USA Division

Paul Gagne - Vice President of Investor Relations

Analysts

Brian Dutton - Credit Suisse

Chris Theal - Macquarie Securities

Amanda Frazer - AllNovaScotia.com

Barbara Betanski. - UBS Global Asset

Peter Ogden - National Bank

Kam Sandhar - Peters & Co.

Richard Wyman - Canaccord Financial

Ross Payne - Wells Fargo

Mark Polak - Scotia Capital

Carrie Tate - National Post

Scott Haggett - Reuters

Pat Roesch - Daily Oil Bulletin

Operator

Welcome to the EnCana Corporation’s third quarter 2009 financial and operating results and 2010 outlook. As a reminder today’s call is being recorded. At this time all participants are in a listen only mode. Following the presentation we will conduct a question-and-answer session. (Operator Instructions)

I’d now like to turn the conference over to Mr. Paul Gagne, Vice President of Investor Relations; please go ahead.

Paul Gagne

Thank you, operator and welcome everyone to our discussion of EnCana’s third quarter 2009 results and our preliminary 2010 budgets. 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 EnCana’s operating results and turn the call over to Brian Ferguson, EnCana’s CFO and Cenovus designated CEO to discuss EnCana’s financial performance as well as Cenovus 2010 preliminary budget. We’ll then turn the call back to Randy to discuss EnCana’s 2010 preliminary budget and follow with some closing comments. Afterwards 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. Today’s call we’ll highlight our performance in the third quarter of 20009 for EnCana and discuss the 2010 budgets for both the new EnCana and for Cenovus. I’d like to emphasize of these are preliminary budgets which Brian and I expect will be revised during the upcoming year as our independent business strategies mature and as we understand how the economic environment is unfolding.

Before we get into the focus of today’s call I’d like to take the opportunity to update everyone on the timing of our proposed transaction. On September 10, we announced our plans to proceed with a plan of arrangements to split EnCana into two independent energy companies.

We mailed out the information circular at the end of October and shares for both the two new companies began trading on a when issued basis last week. Shareholder vote is scheduled for November 25 and subject to shareholder and court approvals, the company expects to complete the transaction on November 30. I’m pleased to report that we’re on schedule and working diligently to insure a smooth transition over the upcoming months.

Going forward EnCana and Cenovus will strive to be among the premier producers for their respective businesses while continuing their tradition of responsible resource development. Each Company will build its future on very strong foundations of quality assets, people, and business strategies.

Now, switching to the third quarter operational results, in the third quarter we continued to see strong operational performance from our key resource plays. The lowered our operating costs, had strong well performance and improved our capital efficiencies. So, first for our gas activities, total quarterly natural gas production was about 3.6 billion cubic feet per day down 9% over the same period in 2008.

This was largely a result of our decision over the course of this year to curtail and shut-in gas volumes due to low natural gas prices, which were partially offset by lower royalties in Alberta again due to the low natural gas prices. In third quarter we curtailed or shut-in about 500 million cubic feet per day of gas production. The reductions in volumes are split about 60:40 between the United States and Canada.

The average year-to-date shut-in gas volumes are approximately 320 million cubic feet per day. Our plans are to bring these volumes on stream during the winter of 2009 and 2010. Despite these shut-in volumes our year-to-date gas production was about 3.7 billion cubic feet per day reflecting our strong operational performance and the impact of the price sensitive royalty rates.

In our emerging Horn River play we continue to work on optimizing our development plans, casting longer laterals with up to 20 frac stages per well. We’re also testing wider spacing between horizontal laterals as we continue to evolve technology and drive down costs. We’re targeting drill, complete and tie in costs of about $500,000 to$600,000 for completed interval for a total cost of $10 to $12 million per well.

Over the last year we’ve seen costs drop about 25% based on a combination of improvements in technology, economies of scale and cost deflation. In addition we’ve also had very strong well results where our recent 12 and 14 frac stage wells are achieving initial 30 day production rates of 8 to 10 million cubic feet per day. In the Haynesville play we continued our land evaluation program.

Our primary focus this year continues to be on a land retention and completion optimization. We have 250 land retention well locations which we plan to complete over the next three years, including this year. 60 wells are to be drilled in 2009 with the remainder to be split between 2010 and 2011. Like the Horn River we have a great position in this play and results to date have been very positive. Current production is 130 million cubic feet per day net-to-EnCana.

Within our cut bank ridge resource play we continue our steady development of the Montney Formation where drill complete and tie in costs have come down to about $650,000 per stage and 80% dropper interval over the last five years when we drilled vertical wells. We have tremendous development opportunities in this key resource play with over 1900 future drilling locations identified.

Now, to oil and natural gas liquids, oil and natural gas liquids production increased by 4% compared to the third quarter of 2008 to 139,000 barrels per day. This was lead by the continued growth of our Foster Creek and Christina Lake Resource plays where production increased 43% over the same period in 2008. Combined production of Foster Creek and Christina Lake has recently had over 110,000 barrels per day on a gross basis, translating to more than 55,000 barrels per day net-to-EnCana before royalties.

With current production above our target 2009 exit rate, we continue to focus on improving our industry leading operations. We’ve also had strong performance from our other enhanced oil assets such as Leyburn where production was 10% higher than in 2008. Also given higher oil prices we’ve taken the opportunity to allocate funds to high value oil opportunities in Southern Alberta and Saskatchewan.

Respect to capital year-to-date we’ve spent a total of $3.9 billion and are on track to meet our full year guidance target of $5.8 billion. We continue to see our service sector costs decrease and have realized savings of up to 30%. Overall service sector prices at the end of 2009 are forecast to be down by as much as 13% to 15% year-over-year.

I’m proud to say that our 10% challenge cost savings initiative within EnCana has saved over $1.4 billion this year versus a target of $900 million, a fantastic achievement by all our employees and contractors. We’ve reallocated some of those savings primarily to land retention and evaluations in the Haynesville.

I’ll now turn the call over to Brian Ferguson who will discuss EnCana’s overall financial performance as well as the preliminary 2010 budget for Cenovus. Afterwards I’ll follow up with a 2010 EnCana budget and some closing comments.

Brian Ferguson

Thanks, Randy. Good morning everyone. EnCana’s third quarter again posted strong financial performance anchored as Randy described by the strength of our operations. For the third quarter, natural gas prices averaged $3.11 per thousand cubic feet excluding our financial hedges representing a 64% decrease compared to the third quarter of last year while liquids prices also excluding our financial hedges averaged $57.40 per barrel, a 42% decrease compared to last year.

This price weakness was substantially mitigated by our commodity price hedges. Our realized hedging gains were $3.39 per thousand cubic feet equivalent during the quarter adding after tax cash flow of $913 million. EnCana achieved cash flow per share on a diluted basis of $2.77.

Our expected full year cash flow guidance remains unchanged at $10.10 per share on a diluted basis. What EnCana actually reports for the full year 2009 will include Cenovus for 11 months, so the full year numbers will require some interpretation for you. Our cash flow performance in the quarter was accompanied by operating earnings of $1.03 per share on a diluted basis, representing a decrease of 46% compared to the third quarter last year.

The lower comparative results in both cash flow and operating earnings generally reflect the combination of low commodity prices and the large volumes of natural gas that were shut-in or curtailed. Our quarterly net earnings were affected once again by the combined impact of realized and unrealized hedging gains and losses, which resulted in an $18 million after tax decrease to net earnings in 2009 compared to a $1.8 billion after tax increase to net earnings in the third quarter of 2008.

I believe that operating earnings are a better measure of our performance, because they remove the variability associated with the unrealized mark-to-market accounting accruals. Operating costs were $0.90 per thousand cubic feet equivalent and administrative costs were $0.36 per thousand cubic feet equivalent. The increase compared to last year is a non-cash item primarily due to a large reversal in 2008 of long term incentive costs that were previously expensed.

Looking specifically at our integrated oil assets, at Foster Creek and Christina Lake, operating cash flow was down 2% quarter-over-quarter reflecting a 37% reduction in crude oil prices which was essentially offset by the 43% gain in production. The downstream operations generated operating cash flow of $86 million compared to a loss of $96 million in the third quarter of 2008 due to higher capacity utilization and lower operating expenses.

In addition, rising crude oil prices during the quarter resulted in lower purchase product costs and higher inventory values contributing approximately $44 million to operating cash flow in the quarter for our downstream operations. All in all, solid results from our integrated oil division. EnCana’s balance sheet remains strong. Excluding Cenovus recent debt securities offering, debt to adjusted EBITDA ended the quarter at 1.1 times and debt-to-cap at September 30 was 25%.

After the arrangement becomes effective, it’s the intention of EnCana and Cenovus that the initial combined dividend for the fourth quarter of this year will be equal to EnCana’s current quarterly dividend of $0.40 per share and this will be equally apportioned between EnCana and Cenovus.

It is anticipated that the fourth quarter dividends will be payable December 31, 2009, to the respective common shareholders of record for EnCana and Cenovus as of December 21, 2009. Future dividends will be at the sole discretion of the respectable of the Directors of each of EnCana and Cenovus no dividend policy has yet been adopted by either company, overall, another strong financial performance for EnCana.

Now, let me comment on our exciting new company, Cenovus Energy. Before I start I’d like to remind you that these are as Randy said preliminary budgets for both companies which will likely be adjusted as we move through 2010. Although our budget announcement today is in U.S. dollars to allow for consistency compared with the current EnCana, it is Cenovus’ intention to move to Canadian dollar, Canadian protocol reporting by the end of the first quarter of next year.

Our strategy at Cenovus is to continue to build a premier integrated oil company. 2010 is an important stepping stone in our growth strategy. We’re making substantial investments in our integrated oil business that will see a major expansion of heavy oil refining capacity in the downstream business which will come on stream in 2011. We also expect to see production growth in 2010 of between 15% to 20% at Foster Creek and Christina Lake as we continue toward our target of 200,000 barrels per day of productive capacity net to Cenovus.

In our budget, we’ve allocated resources to assess, evaluate, and prioritize the extensive inventory of bitumen projects in our portfolio that contain an estimated 40 billion barrels of natural bitumen in place. All of this is supported by a financial strategy targeted at generating free cash flow and paying a strong dividend. The mature shallow gas and oil assets within Cenovus’ portfolio are reliable and predictable. They effectively provide an annuity like stream of cash flow that enables us to fund our growth.

In September, we locked in approximately $6 billion of bank credit facilities and long term notes that provide the financial foundation for our capital structure. The initial estimate for Cenovus’ capital spending in 2010 is a range of $2 billion to $2.3 billion. The range is based on a foreign exchange rate of between, $0.85 to $0.96 for the Canadian dollar; we’ve modeled a WTI oil price range of $65 to $85 per barrel and NYMEX gas price of $5.50 to $6.15 per thousand cubic feet.

These price assumptions were used for both EnCana’s and Cenovus’ 2010 preliminary budgets. Our enhanced oil developments at Foster Creek and Christina Lake are the focus of Cenovus’ current capital programs. Of the approximate $550 million allocated to Foster Creek and Christina Lake, over $220 million is targeted for future Christina Lake expansion at Phases C&D.

They will add to Cenovus’ growth beyond 2011 with each phase adding 40,000-barrels per day of productive capacity. Phase D is now fully sanctioned and construction is set to begin in 2010. We expect the capital efficiency for Phases C and D expansions to come in under $20,000 per flowing barrel, which would continue our tradition of being among the lowest in industry. These expansions are two more bite sized modules in our repeatable, sustainable, manufacturing process. 2010 also marks the last major spending year for the Wood River Coker and Refinery Expansion or core project.

Total downstream investment will be $700 million to $750 million. About 70% of that amount will be invested directly on the core project to substantially complete it. The core project is expected to result in improved refining margins at Wood River. The core is over 65% completed at the end of October and is expected to be on stream in 2011. Once core is complete, we estimate that the sustaining capital requirements for downstream operations will be in the range of $100 million to $150 per year net to Cenovus.

The remaining $700 million of our capital program is targeted for our enhanced oil assets at Pelican Lake waiver as well as Cenovus’ natural gas and other liquids production. These assets are expected to generate approximately $2 billion in operating cash flow. This excess operating cash flow is expected to be used in part to fund our dividend. The Cenovus executive team will be working on our standalone business plan during the first quarter of 2010, so stay tuned for more developments.

Depending on our estimates of free cash flow as we see 2010 unfold, Cenovus has also identified further short term oil opportunities in the range of $50 million to $100 million. We’ve also established a target to divest of $500 million of non-core natural gas assets, which will be redeployed to strengthen the growth of our enhanced oil portfolio. So now this is enhanced oil is operating cost are among the best and reflect a steamed oil ratio that is one of the lowest in the industry.

For Foster Creek and Christina Lake, fuel operating costs are expected to be about $4 to $4.50 per barrel, while non-fuel operating costs are forecast to be in the range of $9.75 to $10.25 per barrel and don’t forget that we are integrated economically on the cost side by virtue of our large natural gas production base, which reduces our exposure to fuel gas costs.

Our strategy, is focused on building our oil business, we’ve been endowed with some of the best enhanced oil assets in the industry supported by the financial strength of the free cash flow generated from our legacy natural gas and other oil assets.

I’ll now turn the call back to Randy to discuss the new EnCana’s 2010 budget.

Randy Eresman

Thank you, Brian. I’ll now discuss the 2010 budget plans for the new EnCana. So following the completion of the transaction, we expect EnCana to be the premier senior North American natural gas company focused on profitable growth from a strong portfolio of low cost unconventional natural gas plays. Our goal is to achieve strong long term operational and financial performance.

We’ve initially set EnCana’s 2010 capital budget at about $3.6 billion to $3.9 billion. At this level of spending, we expect to achieve production of 3.2 billion to 3.3 billion cubic feet equivalent per day, about a 9% increase above 2009 levels. We’ve chosen what we believe is a prudent and conservative investment plan that allows us to generate sufficient free cash flow, to maintain our financial strength and flexibility during this time of continued financial uncertainty.

Should commodity Markets as well as our delineation work continue to be positive, additional capital may be allocated to our new shale plays for additional land capture, retention and evaluations. The bulk of a 2010 capital is directed to growing production in our lowest supply cost plays as well as for the evaluation of our emerging plays primarily at Haynesville and Horn River. Our preliminary budget allocates $750 million and $350 million respectively to these two plays alone. Another $220 million is allocated to our Deep Panuke gas project, which is scheduled to come on stream in late 2010 or early 2011.

In the Horn River we are beginning commercial development in 2010 and we expect to continue to drive down our costs to a more competitive level within our own low cost portfolio. As I mentioned earlier, we’ve seen excellent results in our Horn River play and we expect production to grow to about 55 million cubic feet per day next year. At Haynesville, we continue to focus on land retention drilling, as well as completion optimization across our vast land holdings.

Despite this focus on land retention, our 2010 production is expected to grow to 240 million cubic feet per day and our average well costs are expected to continue to climb to about $9 million. Our coalbed methane resource play program in 2010 is currently planned with a drilling of approximately 700 wells and Capital Expenditures of $345 million, with the first half of the program prepared and ready for execution.

Our 2010 cash flow projection is expected to be in the $4 billion to $4.6 billion range, as increased production is offset by lower pricing realizations. The new EnCana will launch with significant financial flexibility. Based on our 2010 preliminary budget forecast, our debt-to-capitalization ratio will be about 32% and debt-to-adjusted-EBITDA about 1.7 times.

Our cash position post close will be in excess of $4 billion U.S. of cash, an undrawn credit facility of $4.5 billion Canadian, access to a $2.5 billion Canadian commercial paper program and strong investment grade credit ratings from three agencies and continued investor demand for our debt securities. This financial position will provide us with the flexibility to manage our portfolio of opportunities.

Now turning back to the present, we’ve continued to use financial instruments to hedge commodity prices to increase certainty of our future cash flows. As of September 30, the old EnCana had hedged about 2 billion cubic feet per day for the 2010 gas year, which runs from November 1 of 2009 to October 31 of 2010 and an average NYMEX equivalent price of $6.08 per thousand cubic feet.

EnCana also had 27,000 barrels per day of expected 2010 oil production hedged at an average fixed price of WTI $76.89 per barrel. It is our intention that hedging contracts will be allocated based upon each companies productive share once the transaction is complete. EnCana remains strong as we move closer to a split date we’re moving forward from this position of strength as we Form two independent companies.

Our key resource plays have delivered outstanding results over the years and our many emerging resource plays look very promising. We continue to demonstrate industry leading cost performance. Our netbacks are robust and supported by our risk management program. Our track record speaks for itself. We continue to deliver solid results through the volatile pricing environment experienced over the last 18 months.

Our prudent approach to our capital programs and the scalability of our resource plays has allowed us to maintain strong operating and financial results. Going forward we believe it will be even better, both companies will continue to demonstrate what we believe to be industry leading performance in the development of unconventional natural gas and enhance oil resource plays.

We believe the strength, sustainability and profitability of our approach to these businesses will ultimately be recognized by both industry investors when they are able to operate a separate and focused entity. 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 Dutton - Credit Suisse

Brian Dutton - Credit Suisse

Brian I was wondering if you could give us a little more insight into your guidance for Foster Creek and Christina Lake production in 2010. I gather that the numbers you’re showing there are net numbers, but you’re also showing an effective royalty rate, but when you gross up those numbers to get it on a gross production basis and before royalties. The guidance you’re giving for 2010 looks somewhat like the current production?

Brian Ferguson

Brian, I think we’ll let John Brannan respond to that. There’s a couple of moving parts here that explain it.

John Brannan

Yes, the guidance numbers that we have are on an NRI basis and our current production while close to 100,000 barrels a day at Foster Creek and around 15 at Christina Lake, those are kind of weekly averages, not annual averages or not monthly averages. We factor into our guidance about a 93% run time so, 7% or so down from that 100% number.

The other thing is that our capacity at Foster Creek will be 120,000 barrels a day yet we won’t reach that capacity until we have some patterns on blow down so we would expect to maybe enter the year somewhere around 95 to100 and exit the year somewhere around 106 to 110, those type of numbers on kind of a monthly basis. I hope that helps answer your question.

Brian Dutton - Credit Suisse

I think John, I might also add the royalty component.

John Brannan

Yes, the other piece is currently before payout at $65 oil, we’re about 2.2% royalties on a gross basis and at $65 with the post pay out royalties would be 27.3% on a net basis and at current rates and current volumes and current oil prices we would expect that we could go into that post pay out at about the first of June.

Brian Dutton - Credit Suisse

So on a gross basis then if you were looking at your production for 2010, can you give us a feel us to what that 42 to 44 and 7 to 7.5 would be on a gross basis through the year?

John Brannan

Yes, I think at Christina Lake, it will be somewhere around that very close to that 7 to 7.5 at Foster Creek I think I’ve calculated that to be about 51 or 52, somewhere in there, 96 at a gross basis, so taking that on the EnCana share it would be 48.

Brian Dutton - Credit Suisse

It will be a lot clearer when they start reporting and using Canadian protocol next year.

John Brannan

Using NDR protocol.

Brian Dutton - Credit Suisse

Second question is just on the tax rate for Cenovus. You’re indicating here an 18% effective tax rate in 2010. Is that a normalized rate we should be looking at on a go forward basis?

John Brannan

It I guess is reflective, yes of the split of the operations as we look forward, recognizing that the U.S. taxable income is a smaller component forecast for Cenovus.

Operator

Your next question comes from Chris Theal - Macquarie Securities.

Chris Theal - Macquarie Securities

Just a question on cash taxes and the circular you’re looking at, about a $700 million cash tax expense. Do you see that in the fourth quarter and the $500 million recovery in 2010? Is that still looking like a reasonable number?

Brian Ferguson

Yes.

Operator

Your next question comes from Amanda Frazer - AllNovaScotia.com.

Amanda Frazer - AllNovaScotia.com

I was just wondering if Deep Panuke economical what today gas prices?

Mike Graham

When you look at sort of Deep Panuke on a go forward basis, it is definitely economic in today’s gas prices if you will, and that’s based on sort of our 650 long term price.

Amanda Frazer - AllNovaScotia.com

So what price then do you need to see to make the project economical in the long term?

Mike Graham

Well like I say we run with about a 650 long term price and going forward we see Panuke very economic at this point.

Amanda Frazer - AllNovaScotia.com

There’s been talk before too that it’s a non-core asset for EnCana. So I’m just wondering I guess is EnCana looking for a buyer for the project in the long term?

Randy Eresman

The Deep Panuke project we’ve always expressed it as being the similar from all of the other projects that EnCana has been pursuing over the last number of years, our unconventional gas strategy, but we have not been actively pursuing the CLV assets. We’re comfortable keeping it in our portfolio as it is approaching production, but we’d also if the situation was right we would consider selling it as well.

Operator

Your next question comes from Barbara Betanski. - UBS Global Asset.

Barbara Betanski. - UBS Global Asset

The question is related to the divestitures that you mentioned for Cenovus of 500 million this coming year and I’m wondering if you’re planning on continuing a divestiture program over a number of years and just looking at the balance you have right now between oil and gas, whether you think that’s an optimal balance are you moving towards a more oil leverage longer term or do you want to keep those mature assets as a source of free cash flow longer term?

Brian Ferguson

Yes, we are going to be targeting about $1 billion in divestiture proceeds over the next two years. You are correct in that we intend continue to emphasize the oil opportunities inside Cenovus portfolio and expect over the next three to five years to see that if you look at it just on straight production waiting that we would be in the range of two third to three quarters oil weighted within that time period.

I would emphasize though that we do not and I certainly do not think of our growth opportunities other than those focused on our oil and our bitumen projects. As I mentioned in the call notes, we have got a tremendous amount here with the free cash flow that’s generated from our shallow gas assets and I really think of them as a financial asset, not as a production asset.

Operator

Your next question comes from Peter Ogden - National Bank.

Peter Ogden - National Bank

Just a couple of questions, just maybe building off the last question, you mentioned Cenovus wants to concentrate on its oil opportunities. Can you give some of the strategic rational behind the selling of Senlac in the quarter? Why you would have sold an oil property within Cenovus?

Randy Eresman

Peter, Senlac had very limited growth opportunities. It was a small property and we’re focusing on some very material growth opportunities on the other projects that we’ve got starting first and foremost with Foster Creek and Christina Lake and you should expect us to continue to focus on where we can have a material impact in terms of creating net present value as we go forward.

Peter Ogden - National Bank

The second question involves the refining and the guidance surrounding that. You have $100 million to $200 million in cash flow, net of the $44 million LIFO/FIFO adjustment this quarter and you do about $50 million a quarter, I would argue would be a relatively weak crack spread and a narrow heavy oil differential. What kind of heavy oil differential are you assuming next year for that cash flow and I guess, what’s your macro view on kind of the refining next year?

John Brannan

This is John Brannan. Peter, what we are looking at is differentials in that 15% to 20% range and we think that they will be in that range kind of on a longer term basis. There is a number of refinery expansions that are all going on to heavy up refineries, when there’s less crude coming out of Mexico, less crude coming out of Venezuela and less heavy coming out of OPEC.

So there’s a bigger draw and certainly pipeline capacities available to take the Canadian crude down into the Pad 2 and Pad 3 refineries. So we think for the midterm like three to five years, six years that we think those differentials will stay in that 15% to 20% range.

Peter Ogden - National Bank

Once core is on production, that $100 million to $200 million, could you hazard a guess as to where that cash flow would go given the same assumptions once core is operational?

John Brannan

I think we definitely run a number of models there, but it is substantially higher than that $100 million to $200 million.

Operator

Your next question comes from Kam Sandhar - Peters & Co.

Kam Sandhar - Peters & Co.

Just a quick question on what your spending levels are going to be looking like for the Montney and for Bighorn next year?

Randy Eresman

I’ll just let Mike Graham and Jeff Wojahn answer that question, because there’s a bit of variability in both of those depending on how commodity prices respond and how we see the economic environment turning out.

Mike Graham

Kam, you’re asking on the Montney and Bighorn. This year in the Montney, we’re actually drilling in the order of about 52 wells, what we have planned for 2009. We’re probably going to be in that similar sort of range next year. So we’re talking in the tune of about $400 million to $500 million of what we’ll be spending in the Montney.

A quick update on the Montney, similar to the Horn, we continue to drill our wells longer and putting in bigger fracs upwards of 2500 meters in some of our latest wells and we’re getting some tremendous rates out of the Montney. Some of the wells are coming on over 10 million cubic feet a day now and we do think our EURs are going up as well in the Montney.

We think we can have wells as much five to even close to 10 Bcf per well in some of our core areas in the Montney. So the Montney looks very, very attractive. We have a big, big land position somewhere in the order of 700,000 net acres in there. So we’ll spend sort of accordingly in the Montney.

Moving into Bighorn, Bighorn is what we call the Deep Basin of Alberta. We have about a thousand sections on that property and very good results again in Bighorn. We’ve decreased our capital on the well from about $5.5 million down to about $4.5 million per well, so very economic. So we’ll probably be doing somewhere in the same order in Bighorn next year as what we’ve done this year, maybe even a little bit more in the 50 to 60 well type thing, so again about $300 million to $350 million in the Deep Basin of Alberta.

Operator

Your next question comes from Richard Wyman - Canaccord Financial.

Richard Wyman - Canaccord Financial

Just a couple questions here, one follows on the last one. Could you comment on out of the Cutbank Ridge business unit? How much of the production is Montney sourced? Then the other question I have is of the capital efficiencies that you’ve achieved this year. How much permanent do you think or maybe just illusive during a period of cost deflation?

Mike Graham

Mike Graham here again. On the Montney, we have currently about 180 million cubic feet a day coming out of the Montney, somewhere in that order and obviously the big growth going forward in the Cutbank area is going to be out of the Montney, if you will and if you look at sort of deflation if you will for this year 2009, we think it’s somewhere in the 10% to 15%, maybe even up to 20% in some of the cases.

Randy alluded to it on some of his notes there that costs have come down a lot. Mike McAllister, who actually runs the business unit, thinks with can get our costs in the Montney somewhere less than 650,000 per interval and we might even get into half a million dollars per interval and time goes on and we’ve seen that in some of our latest wells. So the Montney continues to be top quartile in our portfolio.

Richard Wyman - Canaccord Financial

What about broadly over the company of the cost efficiency improvement, how much is attributed just to surplus oil field services and price competition versus operating efficiencies driving the cost down?

Mike Graham

Richard, what we do is we try to at least offset inflation each and every year with efficiencies and if you look at the fit for purpose rates the fracking technology, we seen substantial improvements in costs, like we say the Montney is down 70% to 80% over the last four or five years. We think we haven’t reached sort of the peak of that yet and we’ll get more cost efficiencies as we go forward. Inflation is probably around zero for next year and 2010 is what we’re looking at in the Canadian Foothills.

Richard Wyman - Canaccord Financial

On the Horn River budget of $350 million, how much of that’s drilling and how much of it is infrastructure facilities and stuff like that?

Mike Graham

Richard, in the Horn River like this year we drilled like I said about 21 net wells in the Horn River and again, our costs are moving down quite a bit. We’ve gone from about $3 million to about $2.5 million in drilling for our days have gone from about 30 to somewhere around 60 in days. So we’re just seeing tremendous cost efficiencies and we really do try and load level our program in the Horn River.

So this year we actually spent a lot more money just drilling wells and kind of load level. We actually only put on four wells in 2009 and that’s kind of what we’re planning for 2009. You’ve seen the results for 12 to 14 fracked wells. We’re coming on in the order of 10 million cubic feet a day. So for next year, a lot of our capital is going to be spent on completions, ourselves and our partner Apache we’re gearing up to start completing wells.

We have well pads anywhere in the order of 10 to even up close to 16 wells on a pad and we’ll just kind of load level those then and complete as we go, so drilling I would think would be similar to sort of this year and say, we’re targeting about 21 sort of net wells if you will and a little bit more on the completion side for 2010.

Richard Wyman - Canaccord Financial

I think the plant construction capital is more in the 2011 time frame?

Brian Ferguson

Yes, that’s right Randy.

Randy Eresman

So there’s significant spending on that one next year.

Operator

Your next question comes from Ross Payne - Wells Fargo.

Ross Payne - Wells Fargo

I wanted to just ask a question, How far down in terms of sales of gasses as you want to go far enrich your natural hedge, or how do you think about that?

Randy Eresman

So I think you’re talking about Cenovus, and I’ll turn that over to Brian.

Brian Ferguson

Right now in terms of our internal consumption, at current production rates at Foster Creek and Christina Lake we consume between the refineries in Foster Creek and Christina Lake about 100 million cubic feet per day and we expect that to continue to increase overtime as we continue to grow our SAGD production and that will take us up into the 200 million to 250 million cubic feet per day range.

Certainly, the divestitures that we have planned over the next couple of years, we would still have a belong natural gas production as such and again these are, I would characterize as extremely valuable assets because of the very shallow decline predictable nature of the asset and very high netbacks relative to most of the rest of the industry because of lower royalties and low operating costs so we don’t have any kind of a plan to divest of all of the assets. It’s really focusing on those that we would consider non-core that are maybe higher operating costs or the higher decline, those sorts of things in terms of how we continue to high grade portfolio as we go forward.

Operator

Your next question comes from Mark Polak - Scotia Capital.

Mark Polak - Scotia Capital

Just a question with the wider well spacing in the Horn River, I believe you’re trying 300 and 350-meters, just want to confirm that and I’m curious if you think there’s potential committee even go to maybe even go wider than that at some point and then second part of that, is that something you would look at trying out in the Haynesville or Montney or do you feel you have the spacing optimized in those other regions?

Randy Eresman

I think there’s a given opportunity for Jeff to come on line a little bit later and give you updates on the Haynesville.

Mike Graham

Yes Mark, we are definitely going to sort of wider well space and we’ve gone from about 200 which is essentially eight wells per section, we’ve increased that to 250 and some of our latest pads we’re going up to 350 even close to 400 on those. We are drilling our wells longer. We’ve gone from a thousand to 1,600 meters, our latest couple wells are out as far as 2,200 meters and so we’re a long ways on the horizontal.

We continue to look at our fracs and the tonnage, we continue to do about somewhere in the order of 200 tons per interval and we’re looking at sort of sand tonnage as well. So we have a huge inventory, like I say we have about 250,000 net acres in the Horn and we probably have a drilling inventory somewhere in the order of a couple thousand net wells just ourselves without our partner Apache.

The Horn River between the sort of the three Devonian zones, are Musquash, Otter Park and Kahlua are the easiest as we got a tremendous amount of gas in place from 150 to right up 250 plus Bcf per section, so we are doing a lot of experimenting on sort of the length of our wells, the size of our fracs, our frac spacing and I think it would be fair to say that we’re doing a lot of that in the Montney as well.

Like I talked about recently, we drilled wells as long as 2,500 meters in the Montney, and we’ve gone from four to eight and now Mike is fracking right up to as many as 14 stages per well. So this thing is moving quickly and I think Jeff will tell you the same thing in the Haynesville. We haven’t quite figured it out and really it’s driving a lot of the efficiencies. It’s driving a lot of the great well results have it be at the Horn or the Haynesville or the Montney.

Randy Eresman

So I’m going to have Jeff comment as well. Jeff is not with us today. He’s in our Denver office, so Jeff if you’re still there?

Jeff Wojahn

Yes, I am. Thanks, Randy and thanks Mark. One of the competitive advantages I think of EnCana is we have a breadth of technical knowledge that we share. In fact we just had the Horn River team down in our Texas office to talk to our folks that are working on the Haynesville and the Barnett to kind of compare notes and we do that daily, monthly, weekly, within the teams. So when you hear about 2200 meter lengths or 300 foot stages or more stages, you can be assured that our technical teams are sharing learning across the company. So that’s my first comment.

We have a high technology transfer. In regards to the Haynesville specifically, we buy and large have been eliminating the length of the wells to fit within the sections as part of our land retention strategy. So we haven’t really been doing the experimentation say that the Horn River team has been doing by drilling 2200 meter horizontals. It’s not technically something that we couldn’t do, but at this point, we’re focused on remaining within our land retention strategies.

So we’re doing other things and those things are around optimizing spacing, fracture spacing, playing with our gel loads, trying to make sure that our run time efficiencies of our pump jobs actually come off effectively, so that we don’t break equipment because of the high breakdown pressures we have in the Haynesville.

Looking at optimizing the type of profit we use, all of those kinds of things we’re experimenting with and generally what you’re seeing is a little bit higher gel loading, a little bit higher concentrations of sand, little higher concentrations of water and they’re incrementally improving the performance on a per stage basis. Like what Mike has said, we continue to evolve that and there’s no doubt in my mind that over the last 16 months, we’ve been on a rapid technological improvement around optimization of our completion programs and cost structures of these plays.

Mark Polak - Scotia Capital

Maybe just one follow-up for Mike, is it just an optimization sort of analysis in terms of a lower drilling costs versus higher fracking costs as you go for more tonnage or do you reach a practical limit of how wide you can get even with more tonnage and where you lose communication and you’re not quite filling in the space between wells?

Mike Graham

That’s exactly right Mark. We’re doing a lot of experiments just to figure out the best way to recover the most reserves we have, we can get on them and similar to the Barnett you’ve seen recoveries going from 10% to 20% to 50% recovery factor in places in the Barnett and hopefully that will be the same in the Horn River.

So like I say we’ve got a big, big inventory, and we’re just experimenting quite a bit ourselves and Apache our partner there and we’re very pleased with the results. So we are putting in bigger fracs, we’ve gone right up to 300 tons per stage and we think we’re probably appropriate in that 200 maybe even a little bit less than that and we’re just experimenting on the spacing and what kind of recovery we’re going to get up.

Operator

Your next question comes from Carrie Tate - National Post.

Carrie Tate - National Post

I’m looking at the IEA report that came out earlier this week that looks like there maybe a gap. Their prediction is there will be a gap until 2015. What would happen to EnCana if this proved correct?

Randy Eresman

We do expect that there to be, I’m not sure I want to use the word a gas glut, but we do expect that natural gas is going to be in abundance for a very long period of time. EnCana is very well positioned with as very low cost structure and exposure to significant development opportunities within many of the lowest cost plays in North America. So despite the fact that we have a lot of gas, EnCana is positioned very well to succeed in this environment. Should that gas glut, I guess deteriorate and prices improve, EnCana would do even better.

Carrie Tate - National Post

When you say that you think there will be in abundance for a very long time, how long is a very long time?

Randy Eresman

It’s really a question as to how much incremental demand is created in North America. What we know there’s determined is that the supply of natural gas in North America at current production rates appears to be in the order of 100 years in length so, that’s a very, very long time and that’s the gas availability using today’s technology, so we think with future technology growth that abundance could even in terms of time could even be higher.

We believe strongly that natural gas has a role to play in increased demand in North America both in greater use of natural gas for electrical generation and also we believe it has an opportunity to displace gasoline and diesel in the transportation sector. So it really is a question of how much opportunity is taken up in growth of new natural gas demands.

Carrie Tate - National Post

Right now when you talk about your low cost projects which ones would take priority given a continued abundance situation?

Randy Eresman

Today we have quite a few plays which are demonstrating very low cost what we call supply costs and we also see several plays that have the opportunity in the future to be among the lowest supply cost plays in North America so it’s a combination of plays that we already have and developed in our portfolio such as our Jonah play in Wyoming, our Deep Basin in Alberta, our Cutbank Ridge play in the Montney play in both Alberta and British Columbia and then we also see that the Haynesville is likely to get into the lowest cost structures as well as the Horn River eventually.

Operator

Your next question comes from Scott Haggett - Reuters.

Scott Haggett - Reuters

I’m wondering with your shut-in volumes is there a price point at which they will return as always that return of those volumes now fixed?

Brian Ferguson

We did those gas volumes when the prices we were exposed to were generally in the $3 range and our plan right now is to start bringing them back on stream and they will be brought back on stream over the course of this winter. Our expectation is that there will be some Form of correction in prices of next year, but the price we’re currently seeing in above the $5 range and its $5.5 is a strip for next year are adequate.

Scott Haggett - Reuters

Are you looking at the Marcellus at all are you planning an entry next year or in the future?

Brian Ferguson

We have been watching developments in the Marcellus play and we have a small entry position, which we hope to learn more about the play over the course of the next couple of years.

Operator

Your final question comes from Pat Roesch - Daily Oil Bulletin.

Pat Roesch - Daily Oil Bulletin

I notice you’ve dropped the use of the word oil sands it seems to me you’ve dropped the word oil sands entirely and instead you refer to your SAGD projects as enhanced oil projects. Wonder if somebody could talk about the rationale for that?

Brian Ferguson

Really what we have done as have a look at the nature of the recovery techniques that we apply and on EnCana’s bitumen production which is 100% SAGD there are assets and properties that we drill and use drilling techniques to recover the oil, which is really a Form of enhanced recovery which the industry has been focusing on for many decades and we just thought it was more representative of the nature of Cenovus assets to describe them as such so that there wasn’t any confusion about that.

Pat Roesch - Daily Oil Bulletin

That’s confusion between in-situ production and mine. Do you think that the Alberta government should follow and make a clearer distinction between in-situ production and mined oil sands?

Brian Ferguson

I think that’s we’re happy to respond to questions that relates specifically to EnCana or Cenovus that’s probably a question you should maybe direct-to-cap or to the government.

Operator

There are no further questions at this time. Please go ahead Mr. Eresman.

Randy Eresman

Okay, well, thank you everybody for joining us today for our third quarter conference call and our conference is now complete.

Operator

Thank you everyone for joining us today to review EnCana’s third quarter 2009 financial and operating results. Our conference call is now completes.

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Source: EnCana Corporation Q3 2009 Earnings Call Transcript

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