Cenovus Energy's CEO Discusses 2013 Budget Conference (Transcript)

| About: Cenovus Energy, (CVE)

Cenovus Energy, Inc. (NYSE:CVE)

2013 Budget Conference Call

December 12, 2012; 11:00 a.m. ET


Brian Ferguson - President & Chief Executive Officer

Ivor Ruste - Executive Vice President & Chief Financial Officer

John Brannan - Executive Vice President & Chief Operating Officer

Harbir Chhina - Executive Vice President - Oil Sands

Susan Grey - Director, Investor Relations


George Toriola - UBS

Greg Pardy - RBC Capital Markets

Mike Dunn - FirstEnergy

Mark Polak - Scotiabank

David McColl - Morningstar


Good day ladies and gentlemen and thank you for standing by. Welcome to Cenovus Energy’s 2013 Budget Conference Call.

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). Please be advised that this conference call may not be recorded or rebroadcast without the expect consent of Cenovus Energy.

I would now like to turn the conference over to Susan Grey; Director, Investor Relations. Please go ahead Ms. Gray.

Susan Grey

Thank you operator and welcome to our discussion of Cenovus’s 2013 budget. In addition to this morning’s news release, we have posted guidance and a presentation package to our website. Throughout today’s conference call we will reference the midpoint of our guidance estimates unless otherwise noted. All figures are before royalties and in Canadian dollars.

First, I would like to refer you to the advisory on forward-looking information in today’s news release and associated documents. In particular, I draw your attention to the risk factors and assumptions outlining advisory and discussed further in our Annual Information form and our Quarterly Report. We also provide details on oil and gas information and non-GAAP disclosures. I encourage you to read both of these disclosures.

Our call today will begin with Brian Ferguson, President and Chief Executive Officer, discussing our oil growth strategy and our 2013 plan. Ivor Ruste, Executive Vice President and Chief Financial Officer, will then provide the details of our 2013 budget and our financial strategy. John Brannan, Executive Vice President and Chief Operating Officer, will discuss our operational expectations for 2013 and Harbir Chhina, Executive Vice President, Oil Sands will provide an emerging play and technology updates. Following some closing comments from Brian, our executive team will be available for questions. Please go ahead Brian.

Brian Ferguson

Thanks Susan. Good morning. Cenovus recently celebrated its third birthday as an independent company. We’ve accomplished a lot in our first three years and remain focused on the objectives that we first laid out in our 10-year plan back in June of 2010.

In that plan we identified opportunities to grow our oil production to 500,000 barrels per day net to Cenovus by the end of 2021. We remain committed to this oil growth strategy. Our strategy is anchored by the development of our vast oil sands resource. To be successful we must have financial strength. Our balance sheet remains strong and our conventional oil and gas assets provide great short and medium term cash flow.

Our refineries reduced the volatility of our overall cash flow and we are broadening our integration through transportation alternatives to new markets. With this strategy in mind, we have developed our plans for 2013.

Today’s budget is another step in our 10-yaer business plan. We are doing the things we set out to do and remain focused on delivering on our commitments. We are committed to the strategy we defined for you back in 2010. The only thing that has changed is that we have demonstrated we can bring SAGD projects on ahead of schedule and on budget. We expect ongoing uncertainty in global financial markets and volatility and commodity prices. As such we continue to build the flexibility into our plans to maintain financial resilience.

Before we get into the specifics of the 2013 budget, I’d like to take a moment to comment on this year. Overall I think it’s been a great year for the company and I’m pleased with the results that we have delivered. We are on pace to achieve 23% growth in our oil and liquids production as a result of strong execution from our teams.

We also completed expansions at Christina Lake and made progress on future phases at Foster Creek. We received regulatory approval for all three phases at Narrows Lake and partner sanction for phase A. We also continue to advance our emerging oil plays. Harbir is going to talk about those for you in a few moments.

Based on strong performance from our upstream operations, we believe that we will be in a position to add more than 250 million barrels of crude reserves at our Oil Sands operations in 2012. This is primarily driven by the regulatory approval and sanction at Narrows Lake. We also expect reserve growth from our conventional business as well.

For 2012 we anticipate approved finding and development costs to be in the range of $8 to $10 per barrel, which excludes changes in future development costs. We expect three year average SND to be about $6 a barrel. On the downstream side we successfully tested new heavy oil processing capacity at Wood River and increased our integration at what I think has been an opportune time.

So here is our 2012 report guard with some of the highlights that I just mentioned. Our goal is to continue to execute delivering predictable, reliable performance. I think it’s clear from the slide that we have had a very strong year. So we’ve moved through the fourth quarter; we have seen shifting market fundamentals. As such we have provided an update to our 2012 cash flow guidance to reflect these recent developments.

Most notably wider late heavy differentials and lower benchmark crude oil prices have lowered our upstream operating cash flow expectation by about $200 million. We now expect cash flow of about $3.7 billion for the year.

We had plant maintenance turn arounds at our two refineries in the fourth quarter. The turnarounds took a little bit longer than expected. We also experienced volatile feedstock costs. These things combined resulted in an additional $130 million reduction to our forecast in cash flow.

For the full year however, we continue to expect that we will exceed $1.3 billion in operating cash flow from our downstream. Refineries are now back up to full rates, which will benefit our refining performance in 2013 as cheaper feedstock purchased in the fourth quarter of this year is going to be processed through the refineries next quarter.

Given the strong returns on our downstream we are doing some tax planning, which results in a one-time cash tax expense of about $60 million, which we are booking this quarter. This relates to a restructuring of our U.S. business to reduce corporate tax in 2013 and over the longer term. It’s expected to result in some very substantial tax savings for us. Our operations continue to perform well and our production and cost guidance is right on track and we look to maintain that momentum going into 2013.

We’ve highlighted on our key 2013 milestones on this slide, so that you can measure our progress. John’s going to address these milestones in his operational overview. I believe that achieving these will continue to help grow net asset value.

I’m going to now ask Ivor Ruste to provide some of the details of our budget and to discuss our financial strategy.

Ivor Ruste

Thank you Brian and good morning everyone. As Brian noted, we are continuing to execute our 10-year plan. We are focused on maintaining our financial resiliency, especially given the volatility and uncertainty in the global markets.

Let’s take a look at the budget in a little more detail. Based on our commodity price deck, we expect total cash flow of between $3.1 billion to $4 billion. Using commodity strip pricing as of November 30, the total cash flow for 2013 would be higher than we expected 2012 cash flow.

Our capital program is focused on oil and we expect total capital expenditures of between $3.2 billion and $3.6 billion. With this budget we are continuing to invest for long term growth and grow our net asset value. About 60% of our budget capital contributes to production and cash flow growth beyond 2013.

Our balance sheet remains strong and we anticipate being at the bottom end of our target metrics at the end of the year. This provides us significant flexibility moving forward.

This next slide highlights the financial flexibility inherent in our budget. Our capital allocation is broken into three categories, the first of which is committed capital. This is approximately $2 billion in 2013 and includes investment in existing operations and those with regulatory approval in place.

Next is our dividend. In 2013 we anticipate cash flows well in excess of committed capital, allowing the board of directors to consider growing the dividend. Finally, approximately $1.4 billion of our 2013 capital is discretionary. It includes capital related to advancing emerging oil sands projects and growth capital for our conventional assets. This is the portion of our capital program that gives us flexibility.

Cenovus is an oil focused company and our strategy is to grow our oil production. Since inception our oil production growth and expanded heavy oil processing capacity has resulted in an increased proportion of cash flow from our integrated oil business. In 2013 we anticipate 90% of our overall operating cash flow will be derived from our integrated oil assets. Our natural gas will continue to act solely as a financial asset and an internal hedge on deal consumption.

Our focus continues to be on our financial resiliency and managing risks across our business. Our integrated model, scalable conventional programs and transportation portfolio, all helped to manage operational risks inherent in our business.

A strong financial position also provides flexibility in executing our plans in periods of increased volatility. The commodity hedging program protects approximately 30% of our anticipated cash flow in 2013.

We have stress tested our capital program at various pricing scenarios. Even at a WTI price of U.S. $65, we could still execute our 2013 capital program and be within our target debt ranges. However in periods of sustained weakness in commodity prices, our discretionary capital provides us the flexibility to adjust our plans.

We are committed to developing our oil resource responsibly and we take environmental considerations into our business plan. These risk management strategies gives me confidence that Cenovus will continue to deliver predictable, reliable oil growth.

I’d now like to pass the call over to John Brannan, who will provide an operations overview for 2013.

John Brannan

Thanks Ivor. I believe another great year lies ahead in 2013. Our budget is consistent with our strategy and we are continuing to move forward on the objectives we laid out in our 10-year plan.

We are continuing to focus on safe operations and we are working to increase productivity and efficiencies across those operations. We anticipate 14% oil growth in 2013, driven primarily by production additions at Christina Lake and Pelican Lake. We will continue to advance our projects through the regulatory process. We are submitting an application for an extension across the creek Phases J and Christina Lake, Phase H. We anticipate these expansion phases will take both facilities closer to that 300,000 barrel per day gross mark.

We are looking at ways to take advantage of our size and scale as a company to manage operating costs in 2013. This includes reducing drilling and completion costs, chemical usage, enhancing waste treatment processes and reducing work over frequencies.

In our 2013 guidance, operating costs are expected to be slightly higher than 2012. These increases are primarily due to higher natural gas prices, chemical usage and power prices which account for the majority of the total increases. Overall our 2013 budget assumes an average of 3% to 5% inflation in Capital and operating costs.

Our integration strategy will continue to be hopeless this year. We plan to evaluate de-bottlenecking opportunities at Wood River, support transportation alternatives, consider additional supply agreements and execute our hedging strategy.

At Foster Creek, to maintain strong execution in 2013 and continue to look at ways to optimize our plan and our processes. We will also continue the development of Foster Creek phases F, G, H. Phase F is 65% complete and we expect first production in Q3 2014. We believe our manufacturing approach, the development will allow us to add capacity at Foster Creek phases F, G and H and efficiency of approximate $25,000 per flowing barrel.

We expect Christina Lake to continue to drive production growth in 2013. Phase D is ramping up very well. Current production is approximate 85,000 barrels per day and is expected to reach design capacity of 98,000 barrels per day in the first half of 2013. Phase E is 65% complete and we now expect first steam in Q2 3013 and first oil in Q3 2013, approximately three months ahead of schedule.

With this top quality resource we continue to expect ramp-ups of expansion phases at Christina Lake to be in the six to nine month range and cost to be in the $22,000 to $25,000 for per flowing barrel range.

At Narrows Lake we are moving to the next stage of development flowing partner sanction of phase A. Initial ground work is already underway and commencement of facility construction is expected in the fall. Narrows Lake will be our third construction management team and we are saving this team from our existing Foster Creek and Christina Lake construction management teams.

As we had previous discussed, costs are slightly higher for this Greenfield project, where new infrastructure and SAP related capital is required. However we expect to continue to deliver these projects at capital efficiencies well below industry averages. Our initial estimate for capital cost efficiencies at Narrows Lake is $28,000 to $32,000 per flowing barrel. We expect to have first oil from Narrows Lake phase A in 2017.

So on to our conventional oil portfolio, it continues to generate significant short term cash flow, as well as provide near to medium term growth opportunities. The details of our program are illustrated here. In 2013 we expect to continue to direct resources to light oil opportunities in Alberta, where we have had good results and hold a competitive cost advantage with our fee lands.

Our natural gas assets which are managed as a financial asset are expected to generate operating cash flow in excess of capital invested of over $400 million. This cash flow will be reinvested into our oil growth portfolio.

Pelican Lake. Pelican Lake represents one of these growth opportunities, one of the growth opportunities within our conventional portfolio. We continue to run the four rigs on our infield drilling and polymer flood program.

Results in 2012 were slightly behind expectations as reduced operating pressures during infield drilling resulted in lower than expected production rates on existing wells. However production from the new wells is coming on as expected and we are slowly seeing production rates returning to normal from the existing wells as operating pressures as restored.

We are expecting higher operating costs at Pelican Lake in 2013, the majority of that increase, about 70% relates to increased polymer use. In 2013 we will commence construction of an additional oil battery which will add about 30,000 barrels per day of processing capacity to support our current growth plans of reaching 55,000 barrels per day.

Our refining assets continue to demonstrate the benefits of integration, with another outstanding year in 2012. Spending of $100 million to $125 million net to Cenovus will be dedicated to operating and maintaining the facilities. We anticipate operating cash flow of about $1.1 billion to $1.7 billion, generating significant operating cash flow in excess of capital.

Our refineries are strategically located to take advantage of discounted crude

feedstock, including Canadian heavy crude and our own Christina Dilbet Blend. We continued discussions with our partner about debottlenecking opportunities at Wood River.

In addition to our integration strategy, we also take an active approach to managing our exposure to wider light-heavy differentials. As we just talked about, our heavy oil processing capacity at Wood River and Borger allows us to offset weaker upstream pricing and net-backs by using discounted feedstock. This provides a direct offset for light-heavy differentials.

We also mitigate our exposure to volatility and the light-heavy differentials to the use of hedging, transportation commitments and marketing arrangements. Some examples of this include, WCS hedges that lock in a light-heavy differential, from service to the west cost for 11,500 barrels per day via the Trans Mountain pipeline gets us access to tidewater pricing, any long term agreement with the crude oil end uses that we have signed in the third quarter. Over 90% of our exposure to wider light heavy differentials is mitigated in 2013.

Lastly, we continue to emphasize the importance of the portfolio approach to transportation and marketing. In 2013 we will continue to support major pipeline initiatives to a variety of markets. Specifically are supportive of pipelines to the U.S. Gulf Coast and the West cost of Canada. We will be looking at the east cost projects to determine how each make may fit into our marketing strategy.

The confidence in our plan over the next decade allows us to make long term agreements and commitments to new pipelines or to arrange further supply agreements. Diversification of markets and customer base is a key benefit to our portfolio approach.

We have also provided some flexibility on the transportation side. We are currently railing approximate 6,000 barrels per day of light oil and look to expand that to about 10,000 barrels per day in 2013. This helps us to reach markets not currently available to us by pipeline.

With regards to condensate, we continue to secure our supply from multiple sources and are working to ensure long term sources of additional supply.

With that, I’ll pas it over to Harbir, who will provide an update on emerging oil sands projects and technologies.

Harbir Chhina

Thanks John. John’s already discussed the operations at Foster, Christina and Narrows. Now I’d like to give you an update on emerging plays and an update on the technologies that we are working on.

Starting with the Grand Rapids, we have our second well that’s been steaming for the last few months. We just made first production in the New Year. Similar to the first well, this is one of the longest wells that we’ve drilled in the oil sands, about 1,200 meters. So far it’s performing really well and the steam is getting distributed along the full length of the well.

We expect lower production in the Grand Rapids because of the difference in reservoir quality compared to the McMurray. This reservoir has lower saturations and slightly lower thickness and despite that we expect good economics, we expect to see peak rates of about 600 barrels per day and steam well ratios of about 3 to 3.5.

We are expecting to receive regulatory approval in the Grand Rapids by the first quarter of 2013. We’ve already got our SIRs and we are answering those and those should be submitted in early January, everything is going really well.

In Telephone Lake, the dewatering test is doing really well. We are producing about 50,000 barrels a day of water. We are injecting about three quarters of a million a day of air and our disposal is going well, production is going well, injection is going well. So we are doing a lot of 4D seismic just to make sure everything is working just the way our models predicted and this project will have a pretty good comfort level within the next 12 months.

Based on our private work to-date and the result of the strat wells, we are very pleased with this reservoir. We think it has an ultimate potential of Telephone Lake of about 300,000 barrels per day.

Finally on the strat wells, we’ll continue to maintain our portfolio and drilling anywhere from 350 to 400 wells per year. Well, some of these wells are located in Foster and Christina and Narrows Lake. There is also focus on delineating our other oil sands needs as approximately half of our lands don’t even have a well per section on them.

Now talking about strat wells, we have been working on a new technology. Over the past two years we developed this new process for drilling strat wells in remote areas. You see a picture of a rig there. We commissioned this rig and which can be transported by helicopters. We’ve drilled about 16 wells in 2012. We call this the SSD rig, the SkyStrat Drilling rig, remember that name.

The benefits of this are numerous, including reducing environmental footprint, road access is not required, we don’t need to have ice bridges, things like that. At Borealis, we really couldn’t do a strat well program unless we had 40 to 50 wells, because you have to trigger camps and road access. With this rig we can drill one, two, three, fifty wells, whatever we want.

Drilling cost are expected to be approximately 25% less compared to previous strat drilling rigs. Over the last eight years our costs have gone up substantially. So this is our answer to the industry to how we can curtail, maintain our cost and actually reduce them by 25%.

Another key advantage of the SSD rig is that we can drill this all year around. This allows for the scaleable program and labor efficiencies and good safety stats, because you will be working with the same crew throughout the whole year.

In 2013 we plan to complete construction of our second SSD rig. We anticipate drilling approximately 25 wells in Steepbank in East McMurray, where we have the Borealis, here you are using our SSD rig. With two rigs we can keep our flow of helicopter busy for the whole day. We have a lot of inefficiencies with just one rig and the helicopter sets around for quite a while. So we think that will be key to getting the second rig built.

The environmental benefits of the SkyStrat drilling rig, we plan to submit this technology to COSIA, Canadian Oil Sands Industry Alliance for the benefit of industry and the stakeholders.

On the technology side, innovation is one of our areas of focus and part of our culture. Research and development is an important part of this. We have over 140 projects that are on the go right now with the objective of reducing environmental footprint, reducing SORs, lowering off cost and adding value.

A good example of this is the accelerated start-up, including dilation in the (inaudible) is one of the most recent technologies that we have applied at Christina Lake and that’s been performing very well, as you can see from the ramp ups that we’ve achieved over the last 12 months, 15 months at Christina.

I’m really excited about the new things that we are working on and look forward to sharing our progress as we implement these new technologies on our commercial facilities over the coming years.

Now I will turn it back to Brian.

Brian Ferguson

Thanks Herbir. Our track record over the last three years has shown our ability to deliver on our commitments and we are well positioned to continue delivering predictable, reliable performance in 2013.

Our 2013 budget is an integral part of our 10-year plan. In addition to further developing our oil assets, we are maintaining our financial resilience and expanding our integrated portfolio. We have predictable, reliable, oil growth, which is driven by our manufacturing model and we expect to be bringing on a new 40,000 to 50,000 barrel per day oil sand phase every year for the next five years.

We are on track to double net asset value between 2010 and the end of 2015 and remain committed to total shareholder return, which of course includes plans for growing dividend.

With that, the CVE team will be happy to respond to your questions now.

Question-and-Answer Session


(Operator Instructions). Your first question comes from the line of George Toriola with UBS. Your line is open.

George Toriola – UBS

Thanks and good morning guys. My question really revolves around the NAV estimate here. Brian in your view, what’s the most significant driver of the NAN increase you expect. Is it reserve additions, is it production growth, is it commodity prices. What is the most significant driver?

Brian Ferguson

Thanks for the question George. So we are focusing and believe that under a relatively flat price deck, that through ongoing development of an expansion of existing producing assets and importantly continuing to bring forward contingent resource on our new resource plays, that’s what’s really going to drive the lion’s share of the growth in net asset value.

One of the things that I’m really a big fan about net asset value as well is it ticks up and focuses on capital efficiencies and operating cost and that’s one of the thing that we are very much focused on, is making sure we continue to add value across the board, both in terms of increasing margins and in terms of focusing on being very capital efficient and very operating cost efficient.

So we got 157 billion barrels of oil in place on existing Cenovus lands. So continuing to move forward in a very machine like manufacturing approach to development of that resource and moving resource from continued into proven probably is our plan and that is what we are focusing on to achieve this doubling net asset value between 2010 and 2015.

George Toriola – UBS

Okay thanks. And do you have a client estimate for what your net asset value is?

Brian Ferguson

We are going to provide an updated in February once we’ve got the final reserve and resources report in from Daniels and Associates. So we will give you an updated at that time in February.

George Toriola – UBS

Okay, thanks a lot.


Your next question comes from the like of Greg Pardy with RBC Capital Markets. Your line is open.

Greg Pardy - RBC Capital Markets

Hi, good morning; just a couple of questions. The first one, just digging a little bit more into Pelican Lake, I’m curious as to wheatear just what’s the timing I guess of the 30,000 barrel a day battery coming on and is your sense right now or over the course of the year that you will build up, that you will fill a good chunk of the battery when you actually bring it into place.

I’m just trying to get a sense for what the production ramp-up looks like at Pelican and also curious as just to how well it’s responding to the polymer flood. and the second question is just a bit of a left fielder, but any aspirations in the Duvernay shale? Thanks very much.

Brian Ferguson

Thanks Greg, I’ll ask John Brannan to respond to that question.

John Brannan

Hey, thanks Greg. Well overall at Pelican Lake, we had a little bit of a slower response in 2012 than we expected as I mentioned in the call notes. But the pressures are resuming in the reservoir and we are starting to get the performance that we had expected, so we’ll continue to ramp that up.

In reference to the Bear Lake battery, we plan to start that engineering and some construction work next year. We think that would on in 2014. Generally we require that battery when we get over 30,000 barrels a day, so we would expect to be getting into those kind of numbers in 2014.

Overall, like I said the performance there has been good and we look to continue with about a four rig program and we’ll have modest ramp-up in through 2013, and currently on the Duvernay, we are really not looking at anything in that area. We have a few assets there, but not any big focus.

Greg Pardy - RBC Capital Markets

Okay, thanks very much.


Your next question comes from the line of Mike Dunn with FirstEnergy. Your line is open.

Mike Dunn – FirstEnergy

Hey, good morning everyone. Just following on Greg’s question on Pelican Lake, I wonder if you can talk to what the polymer injection profile looks like for that field as you go forward over the next two or three years. Is the absolute injection amount of polymer sort of higher now and does it pair back once you get up to sort of 55,000 barrels a day or is it reasonably consistent. I’m just trying to get an idea of how that’s going to impact unit costs as production grows and I’ve got a second question after that.

John Brennan

Mike, this is John Brennan. Again, on Pelicans we’ve moved the spacing of those programs from 200 meters down to 67 meters between our injectors and our producers and in some cases to 50 meters. The polymer injection will ramp up as we increase or the amount of polymer that we use will ramp up as we increase the number of infield producers and injectors that we have. That cost for polymer would be continuous over the growth profile and the life of that field on a say per barrel basis.

Brian Ferguson

If I could just add to that Mike, the polymer injection continuous on for a long period of time, like we’re talking like five to 10 years. But why we are looking at it to bring cost down is because we are using a lot of polymer now.

We are thinking of getting this polymer in bulk and handling it in bulk, rather than the bags that currently we get, which is a lot of headaches and we are also negotiating with the vendors to get better deals in terms of bringing our cost down and looking at additional vendors throughout the world. So we do expect to bring our cost down per barrel as the production goes up.

Mike Dunn – FirstEnergy

Great. And the second question, just a general question about planned downtime for 2013, whether it be at the refineries or Foster Creek, Christina Lake, are there any sort of major plans that you know of now?

John Brennan

Yes Mike, this is John Brennan again. At our major assets like Foster Creek and Christina Lake we do have plans to turn around. I think at Christina Lake it’s like 10 days and on an annual average maybe about 1000 barrels a day.

As to the Foster Creek, we’ve got an eight to nine to 10 day kind of turn around. We’ll be completely down from eight days. There’s a couple of days forward and back of that and we think the overall effect on the production will be about 2000 barrels a day at Foster Creek. We do have some refinery turnarounds and those type of things, but not as major as the ones that we had this year.

Mike Dunn – FirstEnergy

Okay thanks. That’s all from me folks.


Your next question comes from the line of Mark Polak with Scotiabank. Your line is open.

Mark Polak - Scotiabank

Hey guys. Just wondering on the Christina Lake solvent pilot, if you can talk about what sort of recovery rates you are seeing on the Butane and then what sort of improvement in CMO ratio you would expect to see from that at narrows and what SLOR you’re designing that project for.

Brian Ferguson

Thanks Mark. With respect to the solvent, the Butane, we are recovering approximately about 65% to 70% of what we’ve injected. We have proven that we will see responses similar to what we are designing narrows for, which is approximately like 25% to 35% improvements in oil rates and steam to oil ratios and which we think has a big kick on MPV, approximately about 45%.

So everything is the pilot. This is the third pilot we’ve done. It’s actually working really well. In addition to that we are also trying other solvents at Foster and Christina, like C4, C5, C6 type solvents and those are progressing well too. So we are all feeling very comfortable with the solvent recovery, the rate enhancement, the SOR reductions.

Narrows is being designed with SAGD at about 1.9 to 2 steam to oil ratio and we think that’s apt and we will be able to get to a steam to oil ratio by 1.6.

Mark Polak - Scotiabank

Great. Thank you very much.


Your next question comes from the line of David McColl with Morningstar. Your line is open.

David McColl - Morningstar

Yes, good morning everyone. Two questions for you, just the first one to follow-up on the solvent. Your retention and recovery, are you expecting a similar 30% to 35% solvent retention at narrows.

And then the second question just to kind of build off that and talk more about narrows is, I know you have given some cost estimates which deals with kind of a lack of infrastructure in the region. I am just wondering if you can separate the infrastructure issue out of it. Are you looking at the central plant cost to be effectively less than you have for a SAGD facility given the lower water treatment and the central steam generation requirements? Thank you.

Brian Ferguson

Yes, I’ll answer that. So the solvent retention that you talked about, basically we expect to recover anywhere from 85% to 90% of the solvent that we are putting in the ground. So what’s left in the ground, our retention is only going to be just approximately about 10% and so 90% of what we recover gets recycled and we also expect recoveries to be improved by about 10% to 15% of the solvent.

In terms of the infrastructure, this plant will be very similar in terms of the SAGD part to what we are building at Foster and Christina. It’s going to be a templating four boilers and one re-boiler and so the infrastructure costs are higher, meaning due to roads, pipelines, power lines, things like that, getting access to the area.

In terms of the cost of the solvents, I think a little bit of both. The last three to six months we told you that the costs would be about 10% to 20% higher than SAGD. Today I can’t comment on it until the first quarter, but I think we’ll be able to actually beat SAGD and the team is working on that right now. So we are working on trying to bring that incremental capital down and even improve it to compare it to SAGD.

David McColl - Morningstar

Great, thank you.


There are no further questions at this time. I would now turn the call back over to Mr. Ferguson.

Brian Ferguson

Thank you very much. That concludes our budget conference call.


Ladies and gentlemen, this concludes today’s conference call. You may now disconnect.

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