Cenovus Energy's Management Discusses Q3 2013 Results - Earnings Call Transcript

| About: Cenovus Energy, (CVE)

Cenovus Energy Inc. (NYSE:CVE)

Q3 2013 Earnings Call

October 24, 2013 11:00 AM ET


Jim Campbell – VP, Government Affairs and Corporate Responsibility

Brian Ferguson – CEO and President

John Brannan – EVP and COO

Ivor Melvin Ruste – EVP and CFO

Harbir Chhina – EVP, Oil Sands

Don Swystun – EVP, Refining, Marketing, Transportation & Development


Greg Pardy – RBC Capital Markets

Matt Carter Tracy – Goldman Sachs

Paul Cheng – Barclays

Menno Hulshof – TD Securities Equity Research

Mike Dunn – FirstEnergy Capital Corp.

John Herrlin – Societe Generale

Chester Dawson – The Wall Street Journal


Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Third Quarter 2013 Financial and Operating Results.

As a reminder, today's call is being recorded. (Operator Instructions) Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Cenovus Energy.

I would now like to turn the conference over to Jim Campbell, Vice President, Government Affairs and Corporate Responsibility.

Please go ahead, Mr. Campbell.

Jim Campbell

Thank you, Michele, and welcome, everyone, to our third quarter 2013 results conference call. I would like to refer you to the advisory located at the end of today's news release. This advisory describes the non-GAAP measures referred to today and outlines the forward-looking information, risk factors and assumptions relevant to this discussion. Additional information is available in our Annual Information Form and third quarter report. The quarterly results have been presented in Canadian dollars and on a before-royalties basis.

Brian Ferguson, President and Chief Executive Officer, will begin with an overview of our results; John Brannan, Executive Vice President and Chief Operating Officer, will then discuss our operating performance. And Ivor Ruste, Executive Vice President and Chief Financial Officer, will discuss our financial performance. Brian will provide closing comments before we begin the question-and-answer portion of the call. Please go ahead, Brian.

Brian Ferguson

Thanks, Jim. Good morning. Thank you for joining our call today. We will share some of the highlights of our third quarter performance and our outlook for the fourth quarter.

Our strategy remains consistent and it is focused on our manufacturing approach to oil growth and total shareholder return. We achieved a major milestone in the third quarter with first oil from Christina Lake phase E expansion in July.

We have experienced a very strong ramp up in production to-date. We are seeing the lake continues to demonstrate why it is a top-tier reservoir. This is our tenth successful SAGD phase with regulatory approval for the next eight expansion phases already in hand for Foster Creek, Christina Lake and Narrows Lake.

We expect to bring on a new SAGD expansion phase every year for the next several years. We have lots of experience in SAGD. We have learned, adapted and optimized through the twelve years that we have operated SAGD facilities.

Cenovus has been pioneering SAGD technology as we develop Foster Creek. Foster Creek is a cornerstone asset and we expect the reservoir will support over 300,000 barrels per day of production capacity and achieved a cumulative steam to oil ratio of 2.1 with full field development.

However, looking back over the past three quarters, our operational performance at Foster Creek has not been at the level that we expect. You will remember that 2012 was a very good operational year for Foster Creek. In the third quarter of last year, we were producing above main place design of 126,000 barrels per day.

Based on this strong performance, we chose to defer some routine well maintenance from late 2012 into 2013. This deferral of maintenance resulted in a higher than usual inventory of well maintenance work and an unanticipated negative impact on our 2013 production volume.

This summer, we have been able to complete the majority of our backlog in well work and we plan to be back to normal levels by the end of the year. Based on the assessments we did over the summer, we had made two key observations about the way we should operate Foster Creek.

First, we require more preventative well maintenance and we have built this into our plans going forward. We are investing in improved instrumentation in our wells which will allow for increased data collection and monitoring capability. We have also improved our liner design which we expect will improve reliability.

Based on what we know now, and with the benefit of hindsight, we would have made a different decision in 2012 about deferring well maintenance. The second key observation relates to the formation of common steam chambers of Foster Creek.

This is part of the natural evolution of SAGD development and we are adapting our operating procedures accordingly. During our first twelve years of operations, we have focused on optimizing SAGD on a well pair or pad basis. We are collecting data and learning the best way now to optimize production on a full field basis.

John will talk more about this. But this is the primary reason for the slightly higher SOR and lower production that we are currently seeing. Christina Lake, Cenovus is on track for – pardon me.

Cenovus has a track record of strong execution in Oil Sands. Having more than doubled our production since the end of 2009, we are a low cost SAGD operator with a consistent strategy and a focus on innovation. The changes we are making at Foster Creek are expected to help provide decades of predictable, reliable, operating performance.

I will now turn the call over to our Chief Operating Officer, John Brannan

John Brannan

Thank you, Brian and good morning. This quarter, we benefited from better heavy oil pricing and new production at Christina Lake phase E. I am pleased with the safe and efficient startup by our Christina Lake team.

Production ramp up continues to go very well. Construction of Foster Creek phases, F, G and H remains on track and on budget. We also initiated plant construction at Narrows Lake, our next SAGD project. Steady production from our conventional oil and gas assets continues to support our Oil Sands development.

At Foster Creek, the turnaround was successfully completed in the quarter and production averaged just over 49,000 barrels per day net. Our planned major turnaround began in September, reducing our volumes by about 4400 barrels per day net for the third quarter. The fourth quarter impacted the turnaround will be at about 3000 barrels per day net.

Production has since returned to approximately 108,000 barrels per day growth or 90% utilization. Foster Creek is a top tier asset that will continue to evolve as we optimize the management of the facility and maximize the recovery of the reserve.

During the first six or seven years in a typical SAGD phase, operations are focused on optimizing each well pair and pad. As the individual steam changers developed into one common steam chamber, we focused more on field optimization.

This requires different reservoir management processes which we continue to assess. This is the main reason we are seeing increasing near-term steam to oil ratios and reduced production levels.

I’d like to talk a little more about well maintenance. In SAGD, wells need to be maintained. Electric submersible pumps or ESPs need to be changed. Liners need routine clean ups and investment in down hole instrumentation needs to be made to monitor well performance.

These events all require work over which include taking a well offline while completing the necessary maintenance. After further analysis of summer, we concluded that the deferral of well work last year negatively impacted production in 2013. As a result, we have built in more preventive well maintenance going forward.

This includes things like liner cleanups. We are investing in improved instrumentation in our wells to monitor well performance and we have also modified our slotted liner designs which we expect will improve reliability of production.

As of today, our Foster Creek team has delivered 118 days or basically four months without an unplanned well outage. This renewed operational focus has not isolated the Foster Creek. We have incorporated learning from this project across all our SAGD operations to help improve reliability and maintain operating cost discipline, a fundamental principle of our business.

We expect to operate Foster Creek phase A to E at a production level of between 100,000 to 110,000 barrels per day through the first half of 2014 at an SOR of about 2.4 to 2.5. As we continue to learn more about operating the SAGD project, with one common steam chamber, we will look to further optimize production and steam to oil ratio.

Our plan is to deliver consistent reliable performance at Foster Creek over the long-term. Based on this production outlook, combined with higher steam to oil ratio and gas cost, additional preventive well maintenance and incremental labor cost associated with the ramp up of phase F, we expect slightly higher unit operating cost at Foster Creek next year as compared to 2013.

Once we finalize our 2014 budget, we will have more details to share in December. Construction of F, G and H expansion phases at Foster Creek is on track both by cost and by schedule. Phase F is approximately 85% complete with pipe rack modules, equipment modules and major equipment all landed at site and in the process of being connected.

Initial production from Foster Creek phase F is expected in the third quarter of 2014. It is important to note that phases F, G and H are expected to ramp up similar to phases A to E at Foster Creek as they are in new development areas.

Let’s talk about the performance of Christina Lake. Phase E ramp up at Christina Lake has been proceeding very well with production recently averaging in the range of 120,000 to 125,000 of barrels per day growth. We continue to see excellent reservoir performance on phase E and we expect to reach full production capacity within six to nine months from first production or early in 2014.

The steam to oil ratio averaged 1.9 at Christina Lake during the quarter, trending lower with the ramp up of phase E. We received regulatory approval for our previously announced optimization at Christina Lake phases C, D and E. This will add about 22,000 barrels per day of gross production capacity in 2015 through the addition of two blow down boilers. We expect this to be a very efficient capital project at roughly $10,000 per flowing barrel.

Operating cost at Christina Lake averaged approximately $11.50 per barrel in the third quarter, much improved from $16.80 per barrel in the second quarter, when the plant was down for a planned turnaround. For the fourth quarter, we expect operating cost of about $11.60 per barrel.

We started the plant construction at Narrows Lake with initial piles going into the ground in August. Next year, we are set to commence module fabrication for Narrows Lake at our Nisku Module Yard.

Pelican Lake production averaged almost 25,000 barrels per day in the third quarter, up 4% from the second quarter and 5% higher than the same period last year. While slower than originally expected, we are starting to see incremental production from our infield drilling at Polymer flood program.

Operating costs were just under $20 per barrel in the quarter, slightly lower than the $22 per barrel in the second quarter. This reduction was due to increased volumes and reduced work over costs. We will continue to monitor production response for the remainder of the year but we will be taking a more measured approach to development next year. We are considering further reductions in capital in 2014 at Pelican Lake.

Our Conventional Liquids business averaged just over 50,000 barrels per day in the third quarter, down from approximately 53,000 barrels per day in the second quarter. The Shaunavon divestiture which closed in early July accounted for about 3600 barrels per day of the difference in conventional liquids production from the second quarter. This was partly offset by production additions in our fee lands.

Moving to our refining business, narrower, light heavy differentials translated into higher feedstock cost for our refineries. The shrinking of the LLS WTI spread recently to buying with lower product prices due to high inventories and refinery utilization have contributed to lower market frac spreads and lower refining operating cash flow.

This operating cash flow reduction was partially offset by strong crude throughput volumes which averaged 464,000 barrels per day or 101% of stated capacity during the quarter, of which more than half was heavy crude oil. At Wood River we processed in excess of 100,000 barrels per day of high-TAN including our Christina still be planned.

This year’s reported feedstock cost continue to be affected by RIN credits purchased to fulfill the U.S. EPA’s renewable fuel standards blending requirements. Recent announcements by the EPA have resulted in spot RIN prices retreating from a high of over $1.40 per gallon in mid-July to a level of about $0.30 per gallon so far this quarter.

We expect that changes anticipated to be made by the EPA will have a positive impact on our 2014 RIN cost. Based on a pricing assumption of $10.50 per barrel for Chicago 321 crack spreads and no major planned downtime in the fourth quarter, we expect fourth quarter refining operating cash flow of $100 million to $200 million, which will bring our full year figure in line with the lower-end of our original guidance of $1.1 billion.

This means that refining will generate about $1 billion of operating cash flow in excess of capital this year, while Midwest refining margins remain at lower levels in the past couple of years, light heavy differentials have recently expanded through the rising production and fewer production outages.

Our increased ability to source heavy crude as feedstock at our refineries allow Cenovus to take advantage of the variability in this commodity price fluctuations.

To conclude, our manufacturing approach to oil production growth remains unchanged, with our top quality reservoirs and an extensive operating experience, we are focused on the execution of our long-term plan. I will now turn the call over to Ivor.

Ivor Melvin Ruste

Thanks, John and good morning everyone. I’d like to discuss our financial performance for the quarter. With the strong commodity price environment and production growth from our Oil Sands segment, we posted our strongest upstream operating cash flow on record of more than $1 billion.

Cenovus reported total cash flow of $932 million in the quarter, or $1.23 per diluted share. Operating earnings totaled $313 million in the third quarter or $0.41 per share. John talked about the weaker refining margins we experienced in the quarter due to narrowing crack spreads and light heavy differentials and lower refined product prices.

Refining operating cash flow was $133 million in the quarter, using a LIFO inventory method as it’s done in the U.S., our operating cash flow would have been $64 million lower.

Normalizing for the divestiture of the Shaunavon assets at the beginning of the third quarter, volumes on our conventional side were steady as we saw increased production from our horizontal drilling programs. Conventional oil, natural gas in Pelican Lake represented 50% of our upstream operating cash flow for the quarter.

We continue to fund our Oil Sands growth with the free cash flow from these conventional assets and our refining operations. During the quarter, we successfully closed the U.S. $800 million public offering of senior unsecured notes at attractive long-term rates. The offering was issued in two tranches. $450 million of ten year notes at 3.8% and $350 million, 30 year notes at 5.2%. The proceeds of this were used to fund the early redemption of our $800 million, 4.5 senior unsecured notes due in 2014.

Our balance sheet metrics remain strong, exiting the quarter with a debt-to-capitalization ratio of 32% and a debt-to-adjusted EBITDA of 1.2 times both at the bottom-end of our long-term target ranges. We provided fourth quarter and updated full year guidance to reflect year-to-date actual results, scrip pricing at December 30 and our operating assumptions for the remainder of the year.

We expect fourth quarter oil production to increase 8% compared to the third quarter. And you will notice that we remain on track for total cash flow in line with our original guidance in December of 2012. Our financial strategy continues to support growth in our oil production, while also providing a dividend to our shareholders.

In 2014, we will maintain capital discipline and financial flexibility with good balance sheet capacity.

I’ll now turn the call back to Brian.

Brian Ferguson

Thanks, Ivor. We have had some significant success this year. But we have also had some key learnings about things we could have done better. We’ve made the necessary changes to our operating practices and are assessing how to best optimize production. Our oil growth strategy is unchanged and our growth plans are on track. We are currently in the middle of our budget process for 2014 and we’ll formally provide details on the December, 12.

Next year, I expect capital expenditures to be lower than they will be in 2013 and I also expect that oil production will be higher in 2014 than it is this year. We expect to generate free cash flow again in 2014. The bulk of our capital will be allocated in 2014 to our core Oil Sands growth assets and we plan to bring on another 45,000 barrel per day growth of capacity at Foster Creek.

As part of our budget process, we are performing our usual portfolio review to ensure that we maintain capital discipline. We have a strategy to continue to grow the dividend. We believe that returning cash to shareholders through our dividend remains an important part of total shareholder returns.

As always, our priority will be to have predictable and reliable performance across our operations. The Cenovus team is now ready to take your questions.

Question-and-Answer Session


(Operator Instructions) Your first caller is Greg Pardy from RBC Capital Markets. Your line is open.

Greg Pardy – RBC Capital Markets

Good morning, Brian, I wanted just, maybe to go back into what you are talking about in terms of free cash flow and so on, how should we be thinking about the – allocation of free cash flow then amongst the dividend, debt reduction, and maybe something else you guys really haven’t been active on in past, there are share buybacks, I mean, surely your share price at these levels, is it a significant discount to have, is it going to generate more free cash to get into 2014, do buybacks become more important alongside the dividends? Thanks very much.

Brian Ferguson

Thank you for the question, Greg. In terms of free cash flow generation and how we allocate that, we are generating as Ivor managed or mentioned – pardon me, free cash flow from refining in our conventional oil and natural gas business, we have to this point been first call on that has been to the development of the approved expansion phases in our Oil Sands which are going to provide significant medium and longer-term growth in earnings and cash flow.

The net call on free cash flow has been our decision in terms of increasing our dividend and we do want to send a strong signal to our equity holders in terms of a board’s belief in the sustainability of our business model and our ability to continue to essentially be self-funding as we continue to grow our Oil Sands business.

We have been giving some consideration in terms of our overall capital allocation and portfolio management as to whether or not we should be allocating some of that to share buyback. We have not yet made a decision on that and we will be talking about that further at the time of the budget release in December.

Generally, we have viewed the share buyback as a more flexible component in terms of how we return capital to shareholders. Now we manage the overall capital structure. So you should expect to hear more about that from us as part of the budget release in December.

Greg Pardy – RBC Capital Markets

Great. Thanks very much for that.


Your next question comes from Matt Carter Tracy from Goldman Sachs. Your line is open.

Matt Carter Tracy – Goldman Sachs

Great, thanks, Brian. You mentioned in your outlook that you expect significant real capacity to be added in the end of 2013 and into 2014. So, I am just curious, can you give us a little more detail on your capacity expectations are? And, kind of as follow-on, can you comment on the rail market, whether or not that’s still a bottleneck, the rail car market? Excuse me.

Brian Ferguson

Sure, let me ask Don Swystun to respond to that.

Don Swystun

Hey good morning, Matt. In terms of rail, it’s – the way we think about Q3 we were around 4000 barrels a day, we were moving. That has been reduced from previous due to couple of things; the sale of Shaunavon affected that as well as the differentials on heavy near roads such that you didn’t make a lot of money in terms of moving it on rail for Q3.

But Q4, we had widening. So we are looking at expanding our movements on rail to – in the range of back up to about 10,000 barrels a day. And we are still targeting 30,000 barrels a day, kind of with the exit of next year, obviously depending on where differential is going where prices are.

In terms of rail car backlog, it’s probably fallen off a little bit. There is still is a backlog and we have 500 cars on order that are coming next year. And they are gelding sidecars and they are – improved for safety as well as all of the protection shielding, all of the things that will make it even better. So I think that’s roughly where we stand on our rail strategy going forward.

Matt Carter Tracy – Goldman Sachs

Great, just as a quick follow-on, in terms of the industry and kind of just getting crude out of the Western Canada, do you have any expectation for the capacity additions to the rail markets in general in Western Canada rather than Cenovus specifically?

John Brannan

Couple things, yeah, I mean the rail market is becoming more and more important for us, certainly Oil Sands producers. We have tied into two terminals, one in Hardesty with gas development and one at obviously Bruderheim with Canexus and between those two we look in moving about 30,000 barrels per day.

As I mentioned that’s tied into those unit train capability. I think that’s where a lot of the producers are going, the access unit trains now in Alberta, I would expect that volumes will increase and it’s a part of your overall strategy. Of course, for us pipelines are still the most important and that will be moving in essence 90% of our volumes, but we are targeting in the range of 10% for rail.

Matt Carter Tracy – Goldman Sachs

Got it. Thank you.


Your next question comes from Paul Cheng from Barclays. Your line is open.

Paul Cheng – Barclays

Hey, good morning guys. John, just want to follow-up on the rail, have you guys pass out and ship any bitumen directly without any doing in that?

John Brannan

Not as yet, we are looking at doing that certainly – testing some volumes actually potentially in the fourth quarter but we are looking for opportunities to do that primarily next year.

Paul Cheng – Barclays

Primarily next year?

John Brannan

I think that’s the future obviously, I think that it’s certainly beneficial where you can get more competitive if you are moving more of a – in essence a dry bitumen which compare – at least competes much better with rail transport – with pipeline transportation.

Paul Cheng – Barclays

Well, Cenovus that, are we talking about early next year, mid-next year, late next year that you believe you will have the capability?

John Brannan

I think, at the earliest. We are not looking at this point at doing it to a substantial degree, I think to some – to a point we might have just after treating interim blending we may be able to get some of those levels of condensate down in our bitumen that would be the goal. So we are going to look at that, but I still don’t expect a significant amount for next year.

Paul Cheng – Barclays

Okay. Brian, two questions, one on the Foster Creek, you talk about that now you have changed the way how you look at it and that just because that now you are at about 12 year into the process. So you are looking at from a total reservoir standpoint. Can you help us understand on that elaborately bit more in terms of how that is changing the way that how you are going to operate?

Brian Ferguson

Sure, Paul. I’ll start the answer to that and ask Harbir to give some – added color to that. Basically, this is an expected at this stage in development, once there is been enough steam injected on each of the well pairs and well pads, where the – a common steam chamber develops over the full field and we are now focusing on optimizing the pressures and so on to optimize production across the whole field. This is something that we had expected that we would see this at this stage. Harbir, please expand.

Harbir Chhina

Okay, thanks, Brian. Paul, so, really when we look at SAGD, we’ll be evolving and adapting as we go long and there is three stages that normally exists in SAGD. So the first stage is, as where just operate each well pair independently, which is for the first four years.

So it doesn’t matter what’s going on the rest of the fields for the first four years and years five to seven, the wells coalesced within the same pad. So then we change our steaming strategies and optimize the pad and then what’s happened now is that because we are seven, ten years into the SAGD process, a lot of our well pads are starting to coalesce, which is exactly what we expected.

So this isn’t anything unexpected. In fact we plan the development so that the chambers would coalesce at this stage of the development and we are working on a number of things to drop our SOR given that we are at the stage of development. So some of the things that we are looking into is dropping our whole reservoir pressure. If you drop the reservoir pressure, you drop the SOR.

The other things we were looking at are blow down starting to put more pads on blow down that would add some steam to start up other well pads and that would also drop the SOR and the other thing that we are looking at is Wedge Wells can we put more Wedge Wells on earlier and – because Wedge Wells don’t require any steams.

So all of those three factors – those three things that we are looking at to optimize the whole field development should result in lowering our SOR which should increase the production to those two are related. And so this is just a normal evolution.

This does not impact F, G, H production, it doesn’t impact our capital efficiency, it doesn’t impact our total recovery factors, reserves, and it doesn’t impact any of those things.

So, our long-term view on Foster Creek has stayed unchanged. We are very impressed with how Foster Creek is performing and nothing to worry about. Our rate of return is still after tax 23% to 25% depending upon oil prices and our supply cost is still sub-40 bucks.

And so, overall things are going well. This is just a normal evolution of SAGD and we are looking there ways to bring the SOR down.

Paul Cheng – Barclays

Sure, probably, I just want to make sure, I understand, because I thought that will be the case and so I thought that in this evolution, it actually will bring down the SOR, so why next year the SOR actually will be higher than or that too at the high end if we were actually going to go with this process, should it be actually lower?

Brian Ferguson

Yes, in hindsight, when you go on blow down it should have been lower and I guess that’s the part where I say like we are adapting and learning, could we have made changes two years ago so that our SOR wouldn’t have gone down, absolutely you are right.

But we are learning as we are going through the evolution. We are leading the industry in SAGD where we are the first ones to pay out Foster Creek, we are the first ones to go through blow down and so in hindsight, we could have done some of these things that I mentioned earlier on, but we are kind of adapt and learn and we are trying to optimize the whole field now.

Paul Cheng – Barclays

Okay, very good. Brian, a last one, hedging. The company has always been a pretty active hedger, but given your integrated approach and also that as the company gets bigger at some point in the future, may not be next year. But is that at a point that you would say, hedging is we need no longer significant or necessary. Over the long haul hedging doesn’t we getting any value and get past and management time to manage.

Brian Ferguson

So, Paul, that’s really a question around risk appetite. And at this point, in Cenovus’ development where we continue to have significantly investment opportunities where we believe we’ve got really predictable, reliable investment opportunities and growth opportunities for the foreseeable future.

I think that it adds value by having certainty around a portion of our cash flow. Our objective on hedging is to have certainty around 25% to 30% of our forecast upstream cash flows and for the foreseeable future we are going to continue to have a very consistent hedging program around that.

Paul Cheng – Barclays

Thank you.


Your next question comes from Menno Hulshof from TD Securities. Your line is open.

Menno Hulshof – TD Securities Equity Research

Thanks and good morning. I’ve got a couple of questions. So just to go back to Foster Creek. It sounds like the first half of 2014 is going to be a bit light, but when do you think you can get back to 95% utilization like we saw in 2012?

And then the second question relates to sustaining capital. What is a reasonable estimate for Foster Creek and Christina Lake looking forward?

Brian Ferguson

Turn that over to Harbir.

Harbir Chhina

Yes, so Menno, like, I think, last year when we exceeded our name plate capacity it was very exceptional year. There were number of things that came together in terms of our lower SOR and having new pads and we had lower – reservoir pressure was dropping and a number of things.

I think the normal run rate for Foster is going to continue to be in that 100,000 barrels to 110,000 barrels a day until we start to put more wells on blow down and go down the path of lowering the pressure. So and this is a big shift now and it’s going to take a while, turned every time we make a move, so it’s not something we can do in a quarter or two, but can we do it over a year or two? Absolutely.

In terms of the sustaining capital, the way we look at it on a 30 year basis, our total F&D we still believe we can deliver our project at around $8 to $10 per flowing barrel and so, when you add in our capital efficiencies, currently we are at about 25,000 of flowing barrel – but the total F&D including the initial and the sustaining capital over 30 years, we do expect to run it around that $8 to $10 range.

Menno Hulshof – TD Securities Equity Research

So, nothing you’ve seen within the last year is changing your view on any of that?

Brian Ferguson

No, no. In fact, we’ve got lots of initiatives on both the operating cost and the capital cost, we are putting a lot of focus on attacking cost in different ways to cut our cost and so the SSD rig in terms of this – just an example of how we are applying new technology to bring our cost down and get the cost under our control rather than accepted an industry.

So I think we are going to continue, we were a technology company. We believe that status quos are acceptable. We are going to find and develop new technologies to help reduce our capital and interrupt cost. So, continue to expect that from us going forward.

Menno Hulshof – TD Securities Equity Research

Perfect, thanks a lot.


Your next question comes from Mike Dunn from First Energy. Your line is open.

Mike Dunn – FirstEnergy Capital Corp.

Yes, good morning everyone. Just to follow on Menno’s question, I think earlier Brian, you had noticed that by year end, Foster Creek would be back to normal, I took that to mean closer to 120,000 barrels a day and I think, Harbir just reiterated that you are going to be 100,000 to 110,000 and so more wells going blow down. So, maybe if you could just clarify to me – I guess what normal is, going forward.

Brian Ferguson

Yes, thanks for the question, Mike and if that was unclear, I do apologize for it. But my statement around normal was a normal level of well maintenance activity. So we’ve addressed the vast majority of it already here over the course of the summer and expect to be back on to normal level of well maintenance by the end of the year and that’s something where we changed our operating procedures.

We will not be choosing to defer well maintenance as we go forward. With respect to the production levels, again remember 120,000 barrels a day is the designed capacity. So that would be a very, very high level of performance. What we are targeting is to get back over time to about 95% production capacity level which again is good.

You got into consideration regular plant maintenance all sorts of things; you know there is going to be some weather issues. It gets cold in the winter, those sorts of things. So we don’t plan that we will run at designed capacity. I would observe that we are back up now after the turnaround to 108,000 barrels a day as John mentioned.

And one of the things obviously you guys should be watching and paying attention to is our production levels in November and December to make sure that we are delivering what we said, we are going to deliver. The other thing in – as we look into 2014 – don’t forget we’ll bring on another phase at F.

So you are going to see quite a significant increase over the course of the second half 2014 in terms of Foster Creek production levels and we are really continuing to focus on this reliable consistent attitude.

And as Harbir mentioned, we’ve got a big initiative here internally in terms of looking at our overall capital and operating cost across the whole corporation, not just in our Oil Sands business, but in our conventional business as well. And we are really focusing on how we can reduce our overall capital and operating cost become more efficient on a per barrel basis.

Mike Dunn – FirstEnergy Capital Corp.

Great and second question, your CapEx guidance for Foster Creek and Christina Lake this year has gone up a couple of times now. At Christina Lake is that just – would that be sort of the optimization work going maybe faster than that, faster than originally planned and that Foster Creek is mostly related to the issues you had this year or maybe is it Foster Creek had a schedule or two? Thank you.

John Brannan

Mike, this is John Brannan. In reference to Foster Creek, yes it is related to some of the additional well maintenance work that we have been doing that’s the additional capital for there. There is a bit of in-field work that we are doing inside the infrastructure and stuff like that just optimization. At Christina Lake, it is moving pads forward, so that we are going to stay ahead of our production schedule therefore the ramp ups on E and it’s actually in a little bit of capital to get that up or F development at Christina Lake. Mike

Dunn – FirstEnergy Capital Corp.

Great, that’s all for me. Thank you.


Your next question comes from John Herrlin from Societe Generale. Your line is open.

John Herrlin – Societe Generale

One more on Foster Creek. Do you think you should have done the Wedge-Wells better earlier in terms of field management and will you do so in the future or do you not think that the timing of using the matters?

Brian Ferguson

Let Harbir respond to that.

Harbir Chhina

Yes, hi, John, we are looking at all of that and we look at each one of the performance and how the Wedge-Wells are performing at Foster and Christina and so, I guess, I can’t tell you right now.

I think that’s the work that we are doing in assessing all of that. But definitely I think we got to look at are we that – could we be changing the reservoir pressure. And the blow down very much so I believe we should have done earlier, a lot of it is coming from the Alberta energy regulators.

That because nobody in the industry has gone through the blow down phase that – it’s been taking longer for us to get some of these approvals and get them on site with the blow down concept. So a lot of it is learnings, because we are the first project up. But definitely the blow down I think could have been done earlier as far as reservoir pressure and the Wedge-Wells I think we still got to study that and figure out what’s the optimum for a field at this stage of the development.

John Herrlin – Societe Generale

Okay, thanks. In term of hitting blow down what do you feel your recovery has been per well?

Harbir Chhina

Okay, normally we do, we want to start blow down when we reach about the 55% recovery factor and some of the well appears that they are currently in blow down or higher than that. So, over time, I think 55% to 65% depending upon where prices are and things like that and what’s the optimum, but that’s kind of the range and then a full-fledged recovery is expected to be 70, 70 plus type number.

John Herrlin – Societe Generale

Okay, thank you.


(Operator Instructions) Your next question comes from Chester Dawson from The Wall Street Journal. Your line is open.

Chester Dawson – The Wall Street Journal

Yes, hi, good morning. I just have a quick question in regard to the regulatory framework. That was mentioned a few moments ago, I was curious how that is working? Whether that’s an improvement over the previous regime in terms of getting permits approved, the speed and efficiency or that it’s too early see any improvements or in fact whether it’s more difficult?

Brian Ferguson

Thank you for the question. As a general statement we very much think that moving to a more coordinated single regulation, single regulator process here in Alberta is the right thing for the government to do.

That’s not yet been fully implemented, it’s anticipated to be fully implemented by the spring of 2014. So, we haven’t yet seen on the ground, a change with respect to that overall coordination, but it is definitely in the works and we are definitely very supportive of it. In the meantime, the existing regulatory system continues to work well.

And we are anticipating getting regulatory approval on our Grand Rapids project by the end of this year through the normal course and on our Telephone Lake project around midyear, next year.

Chester Dawson – The Wall Street Journal

Thank you.


Your next question comes from Jeff Lewis from The Financial Post. Your line is open.

Jeff Lewis – The Financial Post

Hello, thanks for taking my question. Can you first of all just clarify how many coiled insulated tank cars Cenovus has on order? And then secondly, there has been some talk about new rules and regulations coming to that transportation auction and I am wondering how you think that might impact your cost structure for – as well as your appetite for moving crude on rail? Thanks.

John Brannan

I’ll take the last part of the questions Brian and then I’ll turn over to Don Swystun. So, with regard, we are fully supportive of having a very vigilant regulatory system that ensures safety on how any barrel is moved, whether it’s by pipeline or by railcar.

That's very important to Cenovus. That's one of our core values in terms of safety of all our operations and all of our transport. With respect to whether that’s going to have an impact on cost or not, too early to say.

We haven’t really seen what the regulators have in mind. I would observe that as an industry, when you look at it, the rail has got a safety that is similar overall to the pipeline industry which is like 99.9% safety record. Don, with respect to the question on coiled and insulated cars?

Don Swystun

Yes, on coiled and insulated cars, we have 500 an order, right now. I was looking for other – for potentially some other opportunities that add to that but, 500 we expect to start to be delivered in about the fourth quarter of next year.

Jeff Lewis – The Financial Post


Don Swystun

Yes, 2014.

Jeff Lewis – The Financial Post

Okay, thanks.


There are no further questions in queue. Mr. Ferguson, I turn the call back over to you for closing remarks.

Brian Ferguson

Thank you for joining us today on the call. That concludes the call.


Thank you everyone. This concludes today’s conference call. You may now disconnect.

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