Steve Douglas - Vice President of Investor Relations Steve Williams - President and Chief Executive Officer Alister Cowan - Executive Vice President and Chief Financial Officer.

Greg Pardy - RBC Capital Markets Paul Sankey - Wolfe Research Phil Gresh - JPMorgan Guy Baber - Simmons & Company Paul Cheng - Barclays Amir Arif - Cormark Securities Mohit Bhardwaj - Citigroup Mike Dunn - FirstEnergy Capital Jason Frew - Credit Suisse.

Good morning, ladies and gentlemen and welcome to Suncor’s Fourth Quarter 2014 Financial Results Call and Webcast. I would now like to turn the call over to Mr. Steve Douglas, Vice President Investor Relations. Mr. Douglas, please go ahead..

Well, thank you, operator and good morning everyone. Welcome to the Suncor Energy Q4 shareholder call. With me here in the conference room are Steve Williams, our President and Chief Executive Officer and Alister Cowan, Executive Vice President and Chief Financial Officer.

I do need to note that today’s comments contain forward-looking information and that our actual results may differ materially from expected results, because of various risk factors and assumptions described in our Q4 earnings release, as well as our current Annual Information Form and these of course are both available on our website.

Certain financial measures that were referred are not prescribed by Canadian Generally Accepted Accounting Principles and we have a description of these measures in our Q4 release. After our formal remarks, we’ll open the call to questions, first for members of the investment community and then time permitting, members of the media.

I’ll now over to Steve Williams for his comments..

Okay, good morning and thanks for joining us. Since becoming Suncor’s CEO, I’ve been telling you about Suncor’s commitment to capital discipline and our journey to operational excellence. We’ve been working relentlessly to become the most reliable and the lowest cost operator in the sector.

We’ve been building a balance sheet that could sustain us when the inevitable downturn in crude pricing came along. The sharp drop in crude prices these past few months has underlined the importance of this approach. So far, we’ve been able to position ourselves to manage through the downturn, whilst continuing to grow the business up for the future.

Later, Alister will get into the specifics on the financial front, but first I’d like to review the operational results from the year we just completed and look at how we are set up to perform in 2015.

In the fourth quarter, our total crude production averaged almost 558,000 barrels a day, bringing our annual production well within the guidance range. In Oil Sands, the Firebag In Situ plant produced above its 180,000 barrel a day capacity throughout the quarter, while achieving continued reductions to cash costs and steam oil ratios.

At Oil Sands Base plant, maintenance activities contributed to a fall slightly short of our production guidance as we previously indicated in December. Nevertheless, our fourth quarter production contributed to annual company records for In Situ bitumen, upgraded crude, and overall Oil Sands production.

We also managed to get the costs where we were looking for, so manage them very effectively. Our fourth quarter cash costs came in at $34.45 per barrel, bringing our annual per barrel costs below $34, and that’s a reduction of almost 9% versus 2013.

For the year, we reduced our total cash operating costs by $19 million, and that was despite the production increase and much higher gas costs.

Our controllable operating expenses excluding natural gas were actually down by over $0.25 billion year-over-year, and that’s a very encouraging trend, and you can see from our 2015 guidance, it’s one that we expect to continue into the future.

In Exploration and Production, Terra Nova came back online in mid-October and produced reliably through the end of the quarter. We also saw first oil from Golden Eagle and a temporary return to production in Libya. So all added up to our strongest E&P production quarter in over a year.

Turning to the downstream, our refineries once again operated reliably in the fourth quarter. Despite plant maintenance at three of our four plants, we achieved an average utilization rate of over 95% during the quarter and 93% for the full year. Looking back on 2014 as a whole, I’m pleased with the overall operational performance.

Oil Sands production was up 8% for the year, largely driven by reliable and growing In Situ volumes, a great deal of effort as you know has been devoted to systematically improving reliability, and I remain confident that 90% upgraded utilization is achievable on a sustained basis.

The midpoint of our 2015 guidance calls for a further year-over-year increase to Oil Sands production of about 9% continuing the trend of steady growth. With no major turnaround maintenance scheduled this year, I believe we are well positioned to hit that target.

In E&P, our 2014 production exceeded the annual guidance range both in Canada and the North Sea with Golden Eagle ramping up to capacity by the middle of this year and new production from Hibernia South, we expect to overcome declines and modestly grow our E&P production this year.

We don’t include any Libyan production in our forecasts given the volatility of the situation there. Cost management was also a good story in 2014. Thanks to improved reliability and productivity.

We continue to reduce our cash costs at Oil Sands, and when combined with our relatively low cost of shore production, our blended cash operating cost for all oil production across the company averaged less than $30 a barrel. We’ve also continued to advance our large longer-term growth plan.

The Hebron project of East Coast of Canada continues to progress well. Construction activities on the top sites and facilities are continuing at the deepwater site. The project remains on budget and on schedule to produce first oil in late 2017. At Fort Hills, all critical 2014 milestones were substantially completed on schedule.

Overall, aggregate engineering and procurement progress have surpassed 60% as per plan. Site construction manpower is now over 3000, and we are beginning to see an increase in high quality labor availability as a result of the recent downturn in project spending across the industry.

Our capital and schedule outlook remains unchanged, and we continue to expect first oil late in 2017.

So, our operations came into the New Year firing on all cylinders setting us up for solid year-over-year increase in production, and our key growth projects are tracking to plan and taking advantage of the soft market conditions to maximize both quality and productivity. In short, things are moving ahead operationally according to plan.

But of course, with lower prices where they are today, there are plenty of questions about our company’s plans. With excess global oil supply and slowing demand, some analysts are suggesting that today’s price environment is the new normal. Now, I am not going to get into forecasting oil prices, but there are a few observations I’d like to make.

The first one is Suncor is a company with significant operating assets, growing production, and decades of resource in our control. We’re focused on continually improving the reliability of our operations taking capital and operating costs out of the business and profitably growing our production.

When global oil prices were consistently between $105 and $125 per barrel over the last few years, we continued to plan based on a much lower price, which we saw as more representative of the long-term.

We used the excess cash flow we generated to build a balance sheet that would see us through the downturn we knew would eventually come, and of course, we’ve returned over $5 billion to shareholders for share buybacks and steadily increased our dividend. So today’s low oil prices should not come as a surprise.

In fact, on the contrary with the stable pricing for the last few years which represented the anomaly. We planned for this crude price environment and we are prepared to manage through it. We’ve taken prudent actions to accelerate our cost reduction initiatives and defer some discretionary capital spending until a definitive price recovery is evident.

These actions have not impacted our 2015 production plan or our latest growth – our largest projects. But they will strengthen our operating model and help us maintain or improve our competitive position. So, in short, we’ve been managing the business and the balance sheet with the expectation of volatile oil prices.

We fully expect the price cycle to include highs and lows and we have a financial strategy that’s designed to work through the entire price cycle. So this is a very challenging time for the entire industry, but it’s – I hope you can see it’s a challenge we at Suncor are prepared to meet and to meet head on.

So, with that, I’ll pass along to Alister to go into the detail of our financial results..

Thanks, Steve. As we all know the final course of 2014 saw a steady drop in the global oil prices for the first time in six years and of course that had some consequences for Suncor’s results and led to a decline in our earnings and cash flows. We generated $386 million in operating earnings and $1.5 billion in cash flow from operations.

Our average sales price of the Oil Sands fell to just under $70 per barrel, a drop of almost $20 per barrel versus the third quarter. In E&P, the decline in pricing was even steeper.

East Coast and North Sea realizations fell by about $32 and $25 per barrel respectively versus the third quarter reflecting the relatively greater drop in Brent crude pricing during the quarter.

The fall in crude prices further impacted financial results on the downstream business, due to the first in first out inventory valuation that Suncor employs under Canadian GAAP. So as we all know the FIFO of Canadian methodology matches our crude costs and product sales on a lagging basis.

Generally over time, the impact on earnings and cash flow is neutral as prices even out. However, as we have seen in a sharply rising or falling market, the impact can be significant and that was the case in Q4 with the FIFO calculation resulting in a reduction to earnings and cash flow of approximately $372 million after-tax.

During the fourth quarter, we continued our focus on careful cost management taking a very disciplined approach to both capital and operating expenses. On the capital front, we invested $1.8 billion in the quarter, bringing our total CapEx for the year to just over $6.5 billion mark.

This represented a saving of about $1.3 billion versus our original budget and prudent management in the fourth quarter was within below our guidance estimate. That marks the fourth consecutive year in which we’ve delivered our capital program while spending less than our budget.

2014 was also the fourth year in a row that we have generated significant free cash flow over and above our capital spending. In 2014, our cash flow from operations exceeded our capital spending by $2.1 billion. That brought our total free cash flow for the past four years to over $10.4 billion.

And that is a quite an accomplishment, but with oil prices hitting multi-year lows, we need to exercise even greater capital discipline to ensure that we continue to live within our means. Consistent with our financial strategy, as you know [Audio Gap]. We announced stability in dollar reduction to our 2015 capital spending program.

This evolves deferring discretionary spending that will have no impact as Steve said on 2015 production and only a modest impact on future productions. We also announced the planned reduction of $600 million to $800 million of operating expenses.

The most cases represent an acceleration of cost reduction initiatives that were already under way across the company and we expect to receive sustainable reductions to our cost base which will offset growth and inflation over the next couple of years.

Moving forward, we will obviously monitor the price environment closely and make any further adjustments to our spending plans as the situation warrants. Spending within our means and preserving a strong balance sheet will continue to be top priorities for us. And speaking of the balance sheet, it remains in excellent health.

We finished the year with almost $5.5 billion in cash and a net debt to cash flow ratio of less than 0.9 times. During the fourth quarter we increased our liquidity by executing a very successful $1.6 billion debt issue and of course we continued to have access to unusualized lines of credit exceeding $4 billion.

So we have ample liquidity to execute on our strategy. Our long-term capital allocation priorities remain unchanged, fund the base business as it continues its operational excellence journey to lower costs and improved reliability, invest in our long-term profitable growth in our core business areas and return meaningful cash to the shareholders.

In the near term, we are taking the necessary steps to preserve cash and maintain our balance sheet strength. This will result on the deferral of some growth spending as we’ve already discussed. We have also suspended purchases on the share buyback program as we focus on cash preservation.

There is no change to the quarterly dividend which we have increased twice in the past year by a total of 40%. This continues to align with our commitment to a dividend that is competitive, reliable and sustainable. To sum up, our financial strategy is Steve said is designed to enable to manage through the inevitable oil price cycles.

We are making prudent, proactive moves to preserve cash and liquidity and maintain our balance sheet strength and remain resolute in the commitment to capital discipline, operational excellence and profitable growth. So with that, I’ll pass you back now to Steve Douglas..

Well, thank you Alister Just a couple of notes before we go to the questions. Some one-time impacts, obviously the LIFO, FIFO accounting adjustment was a considerable impact this quarter with crude prices falling as sharply as they did.

The after-tax impact was a negative impact to earnings and cash flow of $372 million in Q4 and for the year, it was a negative of $290 million. Stock-based compensation impact was actually a recovery after-tax of $7 million in the quarter and a cost of $251 million for the year.

And FX exchange rate was again a considerable factor with the Canadian dollar weakening. During the quarter, it had an after-tax negative impact of $302 million and for the year, a negative impact of $722 million. I should point you to our guidance. The 2015 guidance was adjusted in January. It remains as per that January adjustment.

The key changes were $1 billion reduction to our capital spending program, $1 a barrel reduction to Oil Sands cash cost and various adjustments to taxes and royalties that flow out of lower oil and gas price assumptions. Full details of course are available on our website. With that, I’d request that we keep our questions on a strategic level.

We will be available as always along with the controllers group to answer detailed modeling questions and Melanie, open the lines for Q&A..

[Operator Instructions] The first question is from Greg Pardy of RBC Capital Markets. Please go ahead..

Yes, thanks. Good morning. Steve, just want to touch on a couple things in the release.

One is, just the storage capacity you’ve now got in the Gulf Coast, just interested in what the magnitude is there and the thinking behind it? And then is there any update on the line 9 [B] reversal?.

That’s a tough first question, Greg. We’ll have to take a quick look and see what the absolute storage capacity is down on the Gulf Coast, and we’ll let you have that.

Suffice it to say, I mean, with the Keystone South leg being commissioned, we have been using that both for equity crude and trading as well, so we are making good use of the facilities down there. I’ll get you an update on the absolute inventory. On line 9, no specific update.

So, we’ve been saying for a couple of years now that our expectation was that that line would come into service the second quarter of this year. We have no reason to change that guidance at the moment.

So, it’s in process, the regulator has been reviewing it, and we have no update as to when he is going to conclude, although his latest review period is coming to an end quite quickly now. So, we are still at the moment anticipating second quarter this year..

Okay, great. Thanks for that. The second one is, just around the Oil Sands, I mean, Firebag has obviously been hitting the cover off the ball and MacKay River has been very, very strong as well.

Just with the unplanned maintenance that you’ve seen in the mining operations there, just any thoughts around that? I know that going into 2015 there is not a lot of maintenance, would you – did you see more unplanned maintenance last year than you expected?.

A little bit more than we expected, but nothing exceptional and nothing to worry. But no major events there. We have been able to – we’ve corrected those through the maintenance we did.

So the trend that you can see from guidance is, it’s about 9%, volume year-on-year underpinned by Firebag and MacKay River, but also depending on a solid mined volume as well. So, things came out of last year in great shape, and we’ve had a very, very strong start to 2015. So, it looks as though the work we did has been successful..

Okay, good stuff. Thanks all..

Thank you. The following question is from Paul Sankey of Wolfe Research. Please go ahead..

Hi, good morning everyone. Thank you. Steve, given the oil price plummet, there has been a lot of debate about the price at which Canadian Heavy Oil Sands producers would be forced to shut in production, clearly as we got cash costs exceeding the oil price. I just had a three-part question for you. You mentioned your own cash cost is below $30 a barrel.

What would be the comparable crude price – global crude price we should consider against that? The second was, where do you think the wider Canadian industry heavy Oil Sands industry sits in terms of its cash costs? And the final part was, what do you think it would take if we really get low and stay low for production actually to be forced to shut in? Thanks..

Okay, thanks. But we have a lot to that question. I’m not going to get into the game of trying to forecast prices.

What Alister and myself have tried to indicate is that we have developed a balance sheet and we’ve been driving with capital discipline and operationally excellent to position ourselves as the lowest cost and highest reliability competitor. I’m very pleased with our progress.

You’ve seen successive year-over-year reduction in cash operating cost at Oil Sands, and you can see with a high degree of confidence coming into 2015 that that trend will continue, and in fact with the current low crude prices, we’ve accelerated our cost reduction program.

So, we are confident that we are – depending on which part of the business you look at, the lowest cost operator integrated overall. I talked about a blended cash cost of less than $30 a barrel. For Oil Sands in 2014, it was just under $34 a barrel.

We believe that that is the or amongst the best in the industry, and that was a conscious challenge of ours that we set ourselves to get there and to stay there, and we believe we still have significant progress that we will continue to make this year as reliability comes up and the cost drive continues.

I think the last comment I would make is, so we are very well positioned relative to the industry. It is a significant amount of our costs are fixed or sticky, and therefore we continue to operate down to low prices, and of course we are not taking – we don’t take a – these are not planned to start up and shutdown in a day.

It has to be a long-term view of where prices are going. So, all I would say, we’ve seen nothing so far that has caused us to take capacity off, and we watch the market very closely.

We do have a proportional and progressive cost reduction program, so we’ve taken the first steps that Steve and Alister talked about, but we have more available to us if necessary. We don’t judge them to be appropriate yet, given the strength of our balance sheet and our ability to stick to our overall strategy, but we remain poised.

If we have to take action, we will face the challenge..

Great, thank you. That’s a complete answer and I understand what you are kind of prepared to comment on a knocks but comments from the way you’ve talked.

Could you just highlight, what gives you the competitive advantage that you are claiming in terms of having lower costs and I was wondering further to that if you have – if you like more or less fixed and sticky elements and, really what differentiates Suncor in terms of your ability to say you believe you lower them – as good as will lower than anyone else? And I’ll leave it there, Steve.

Thanks..

Okay, thanks, Paul. I mean, I would say, judges by our track record. So, its very easy when you come into circumstances like this to claim that you will be working hard on operational excellence and cost reduction. These are fundamental deeply engrained projects within companies and they're not things like a tap you turn on and off.

So, look at our track record. You’ve seen us come down over the last three or four years from $40 to near $30 and we’ve put that trend in our guideline. So, you should have a degree of confidence that, when we say we are going to deliver, absent something completely unforeseen, you will see us deliver on that.

The proportion of fixed cost for us is no different. I mean, if you look at the fixed cost, variable cost ratio in these businesses, a mine compared to a mine or an In Situ compared to In Situ is largely the same.

We do believe we have benefited an integrated company out there because, the ability to move plants up down on a daily basis is different between In Situ and mining and we think having a combination gives us a competitive advantage..

Thank you very much..

Thank you. The following question is from Phil Gresh of JPMorgan. Please go ahead..

Hi, good morning.

First question is just – in this environment given the strength of your balance sheet, the amount of cash you have, would you be interested in going on the offence and possibly making acquisitions and to the extent you are – you would have some interest is it in the Oil Sands or would want to diversify in other areas around the world? Just any general thoughts about the overall environment?.

Thanks, so, yes. I mean, what I would say is, I mean, we are very well positioned with our balance sheet and a degree of, what I would call cyclical base is a possibility. But we’ve always said that. So, we do look at each of the components of our business and also I’ll recap on a few comments I’ve made over the last few years.

So, each phase we look at, so, if you look at the integrated strategy, there are assets on the market in all elements of that at the moment. There are downstream assets on the market. We’ve been a very cautious purchaser with the downstream.

We like where we are in terms of downstream integration but we do keep an eye in the future to maintain at the right price to sorts of the proportion of the upstream to downstream ratio that we have. So, no particular plans, we stay prudent there.

Save money and pay, I’ve been saying for a number of years, in fact, what we’ve been doing is, selling down our E&P assets and we’ve completed most of the big pieces. So, we sold the gas business almost at the top of the market. We’ve been selling pieces, small pieces which don’t fit strategically with our view forward of E&P.

There is a great deal of assets on the market at the moment. We continue to look, we’ve got no – there is nothing significantly different today than yesterday other than there is lots of assets on the market. You will see us exercise caution and we are not in any hurry.

We’ll just take – continue to take a look and if it fits with our strategy, we’ll take a second look. And our strategy was concentrate on where we are strong, North Sea, East Coast, East Coast of Canada, not exploring the world and necessarily moving into regions we have no expertise at.

So, again, downstream and E&P, nothing particularly different today than it was yesterday. And it’s much the same in Oil Sands, I mean, we still see there are lots of assets obviously potentially becoming available.

They have to pass a very difficult hurdle in Suncor’s case because, we value the components of the company and the obvious ones are the operating assets and the resources. All resources tend to struggle to pass Suncor’s test because, we believe we have the best resource in the industry.

So any resource we buy likely wouldn’t be developed for 20 or 30 years and therefore it has very low current value so as much of asset quality of the operations. So, we continue to look, there is no special activity going on in the company at the moment and just as a general comment, we still see a gap between the expectations of buyers and sellers.

So, you’ll see us exercising an abundance of caution..

Yes, that makes a lot of sense. I appreciate all the color. It seems like you could take some time.

And just on the capital spending side of things, maybe just remind us whether, there is any additional flex in 2015 and just what kind of flex do you feel like you have in the 2016 as you think about managing the capital spending?.

This is a matter of discipline in the company. We went far beyond the $1 billion we’ve talked about. We think that proportional improvement at the moment to keep us effectively neutral at prices we are anticipating. We’ve also got the next tranche ready.

Now, it’s very – it tends to be more capital inefficient to stop projects in the current year just because the spend has started, people are mobilized there and failed, you’ve spent money on pieces of equipment and people getting them in there. But we do have – we have more that we can do in 2015.

We’ve also already taken a good look at 2016 and have considerably more scope there. And of course, it is possible to suspend the large growth projects. Our view is that that’s not appropriate at the moment and not warranted. In fact, if I give you a quick update on Fort Hills, I mean, the project is going very well. It’s 25% complete.

It will 50% complete by the end of this year. All the partners are supporting it. All of the partners of the spent up have approved the details of this year’s spend and we are seeing what we anticipated which is improved productivity and quality in the market.

So, you will see us protecting those big strategic growth projects for as long as we reasonably can and right now our judgment is that we can still go ahead with those..

If I could just ask one clarification.

Is there any deflation in your capital spending budgets? Just some other companies that started to dial-in the idea of deflation, just wondering what you are seeing in the Oil Sands specifically?.

At the micro level, the answer is yes. We are seeing it right now. We are seeing, and of course, you get it in a couple of forms. You get it in, obviously, some commodities cost – fuel is costing less. We are finding that people are much more local now. So, we are now having to flight, I mean, from such distances. Those are easy to measure on.

The other ones are, we are seeing the quality of worker improve. We are seeing the productivity of the groups improve. So, those are more difficult to reflect, but, so we haven’t put out revised numbers, but there is definitely a deflation rate pressure in the contracting unit and construction business at the moment..

Got it. Thanks a lot..

Thank you. The following question is from Guy Baber of Simmons & Company. Please go ahead..

Good morning gentlemen. Thanks for taking my question. I was hoping you could discuss your expectation for returns in this environment and what assumptions might be implicit in some of the medium-term planning? But I believe you all have the ROCE target of 15%.

So on the medium-term assumption, what combination of oil price appreciation and cost structure improvements/deflation maybe necessary for you guys to achieve your targets.

I am just trying to get a sense of how achievable those objectives are? What the confidence looks like? What we might need to see? I mean, especially, what the latest views are now that, it looks like we may not be revisiting a $100 barrel WTI environment any time soon. And then I have a follow-up..

Guy, it’s Alister. That’s a pretty detailed question. So, what I would say is, when we set out a target of 15% for our overall return on capital on our business, we are looking at that in a more normalized oil price, not in an environment we are in today clearly. I don't think there will be any expectations on this year.

So, I mean, I think, if you go back to slightly higher operators, I think we are going to see the execution on our capital being able to bring that in as we expect and the returns on the projects that we have previously discussed, whether they be in the Oil Sands or in the E&P or in the downstream business.

The combination of that with our existing business is going to get us to that 15%..

Okay, thank you. And then I had a follow-up on the prior question on capital spending guidance. But, you had some detailed slides out that showed $700 million of discretionary growth capital.

So I was just hoping to get some incremental commentary on exactly what that pertained to, I’m just considering that the strip right now is below for 2015 what your planning assumptions are.

So could you provide some commentary there? Is that – would that be spending-related to the logistics growth piece that you’ve called out or is that logistics piece such low capital intensity that you could probably achieve that and that would in a separate bucket? Just looking to get some more clarity there. Thanks..

So that discretionary capital spend really consists of a couple stuff. It’s a spend in our E&P business. We are doing some drilling this year which could of course as Steve said, it would be cut if we decided that oil prices are going to remain lower for longer. And that’s more difficult to do given some rig commitment.

And then, across the whole business, it’s projects that are nice to do and they do derive longer-term benefits, but in today’s environment, we don’t have to do in this year, we can do them next year. That’s really the kind of mix of projects in the discretionary spend which gives us some scope as Steve said to make further cuts if we need to..

So just to clarify, the incremental production if you guys think you could realize from logistics de-bottlenecking over the next couple years which is pretty significant, that looks if it should be relatively same?.

I think the – sorry, it’s Steve Douglas here, Guy. The incremental production from logistics de-bottlenecking, that’s uniquely in Oil Sands and the cuts that we’ve made to-date largely don’t impact our Oil Sands plants. We are still talking in terms of 550,000 to 600,000 barrels a day of production from Oil Sands by the end of the decade.

So, you are talking about potentially a year, one to two year push on some projects like the next phase of MacKay River for instance. But largely that growth track remains in tact..

Okay, great. Very helpful guys. Thank you..

Thank you. The following question is from Paul Cheng of Barclays. Please go ahead..

Hey guys. Maybe this is either for Steve or Alister. Before the downturn in prices, I think the company has been talking about to spend $7 billion to $8 billion a year or to grow as they call it, 5% to 8% a year in production. It looks like that cost is being somewhat reset.

So, even after the oil price recover, should we assume that, that range is now that more or like in the $6 billion to $7 billion?.

We don’t go ahead on capital for two or three or four years, but I’ll make a general comment, Paul. I mean, we’ve maintained our trajectory and we spend $6.5 billion for the last four years. So, it doesn’t mean there once the year is where it can peak in there, it doesn’t mean we haven’t got a long list of projects we can spend money on.

What we’ve always try to stick to is a capital discipline where those projects can be very effectively executed. So, one of the things we’ll be taking you through later this year is, we have now started to clarify the In Situ replication program and that’s looking really very exciting now.

It looks us though we have multi-phased program which can happen over a 5, 10 year period and we’ll start to – as we start to see oil prices recover then we’ll start to talk more of that in fact to that end. So, I think, judges by what we’ve done, you’ve seen us at that $6.5 billion level. We do have a queue of very attractive projects.

So you’ll see some pressure on that. But what I would say is if you think when you are having us to be a couple of years ago, there was a discussion of $9 billion or $10 billion, you’ve clearly seen us pull back into a more balanced range.

So, I think you are right, you are going to see and it depends, if you look at last year, we generated $9 billion, just over $9 billion, even with the price corrections at the end of the year. So, you’ve seen us spend well within the cash we’ve been generating..

Alister, that for the $600 million to $800 million of the cost savings target for the next couple of years, can you break down the nature of the cost savings.

You said, labor cost, you said, service cost or any kind of a breakdown and also that if you can roughly break it down by segments also?.

Yes, Paul. Of that, I’ll give you some high level buckets that will be easier for you. The first one is workforce which probably accounts for, maybe 30%, 40% of that number and that’s a combination of sort of contractors and some employees leaving the organization.

Then the next bucket is probably, is around that 30% too and that’s really looking at discretionary projects, expense projects much the same as the – on the capital – discretionary capital projects whereby, we’ve taken a look at them. The economics are good, but they perhaps don’t give us a benefit in terms of the next year or the year after.

So we are just going to be fair of those, they don’t need to be done in this year. And then the next sort of 20% to 30% is really looking at the men we are spending on overall contractors, consultants, professional services, stuff like that. And that’s kind of the three buckets that we are looking at taking those operating expenses.

What we want to make sure though is that, we implemented a much of those savings as sustainable as we can. So they are not just a one-time reduction that comes back. We want to make them sustainable to be built into our lower cost base going forward..

Right, and if we are looking at all over the entire organization, your supply chain, the supply costs, what – is there any move up you can give us, what is the percentage of the service cost that’s either under very short-term or no contract just based on the spot. When I say very short-term, less than two years.

I am trying to understand that, I mean, if we do see a deflation in the industry, how quickly that we could expect that could be able to pass..

Paul, I mean, I think that’s a large part of what we are trying to get after in some of the cost savings and on workforce cost savings. So, anything that is your term and even longer term contracts we are having discussions with our suppliers. We are all in this together. We will have to take it ahead here.

So that’s really – we are going to be able to get that over this year and in next year rather than wait for several years on that..

Two final questions.

Steve, let’s assume that you are going to protect the long-term major growth projects and you are going to continue to what – on the safety and not all the spending there, what is the minimum spend you need to do in 2016 and 2017? Is it a $6 billion, $5.5 billion, any number?.

Sorry, microphone on there, Paul. I think in terms of sustainable, it’s – I think we print those numbers and it’s in that sort of – depending on the year $3 billion to $4 billion and of course, 2016 is a low turnaround year – sorry 2015 is a low turnaround year. We come into a bigger turnaround in 2016. So that’s impacted.

And then there is discretion – I would go back to the same answer as before if you like that, look at what we’ve actually been doing. We’ve comfortably been doing $6.5 billion for four years now. So, you can put some factors around that.

Other than that, we’d have to take you through the specific items in the year, because there are decisions we make at the margin around turnarounds and discretion..

All right, thank you..

Thank you. The following question is from Amir Arif of Cormark Securities. Please go ahead..

Thanks, good morning guys. Just a quick question on the capital spending reductions or flexibility that you see out there. I was just trying to get a sense of how much of that is based on where you have the flexibility versus where the returns are? I appreciate the color that you gave on Fort Hills.

So, just looking at the projects that are being delayed like East Coast Canada or Fort or the MacKay River expansion.

Can you give us a sense of where the returns of those projects would be relative to Fort Hills?.

I mean, first of all, as I mentioned it’s difficult to give a simple answer on this time, because the capital discipline part of our program means that we always go to effectively the highest return projects first. Of course, there is some adjustment for the type of project.

So you know, Fort Hill, you don’t make that judgment every year on a $15 billion project. So you make some judgments, you do it on the basis of a forward projection of crude in Fort Hills case for the next 52 years. Then go back and revise that. We have a long list of projects with returns which support our objective for the 15% return on capital.

If you like the Fort Hills, the Fort Hills decision is done that – it’s difficult to see how that project will start. It will be 50% complete by the end of this year. So, that one is passed.

If you then look at the MacKay River, if you look at the replication in, In Situ, if you look at then clearly our supporting is part of the basket of projects, our objectives to make a move to 15%.

I mean, clearly the most attractive ones economically and that’s why Steve said they are also protected in here at the moment are the de-bottleneck projects.

They are higher return, lower cost, faster to execute projects and that’s why we’ve executed the first of those already and they will take a high priority, because capital discipline for us is about doing the high return ones first..

Okay, I appreciate that color.

And then just a quick question – a follow-up on the last question, the $600 million to $800 million in operating cost savings over the next two years, how much of that could show up in this year and is that factored in your current operating cost guidance?.

It’s certainly projected into our estimates for the year. Clearly, we have set a target to get those out over two years, but we are accelerating as much as we can and we are trying to receive as much as out this year as we can..

Okay, and then just a final question if I may, just, on the – I mean, as Brent spread has come in relative to WTI, just curious about the economics of the rail into Montreal and the Gulf Coast storage.

Is that, are the economics of those sensitive to the Brent? I mean, I am just curious why those fallen to the rails today?.

Yes, they certainly are sensitive to them, but it’s not as simple as taking the Brent WTI differential. You have to look at the local crude differential. So, I would say that, rail into Montreal is marginal and rail to the Gulf Coast is not economic at this point. So we are currently not railing to the Gulf Coast..

Thanks for the color..

Thank you. The following question is from Mohit Bhardwaj of Citigroup. Please go ahead..

Yes, thanks for taking my question. A lot of stuff has been hit already. Steve, I just wanted to talk a little about, some of the stuff that you mentioned before the reliability in cost management. If you look at the cost management part, after since you took over as CEO, you guys have made a lot of progress over there.

Just looking at the reliability part here in the mining operations, you’ve consistently maintained a 90% utilization on the upgrader, but we still haven’t seen even a single quarter where we have seen that kind of a utilization.

So if you could just talk about that a little bit how do we get over there?.

Yes, and remember, we did always say 90% once we’ve been through turnarounds on both of the upgraders and the one to still go is in 2016. I am confident that we are going to achieve these 90%. We are seeing steady progress where it is a question of relentlessly working on the challenges that are there. We understand a lot of them.

We are working on them. We are making the progress and if you draw a chart of upgrader reliability over the last two or three years, you’ll see consistently moving in one direction. So, I am more and more confident as the days go on.

In fact, we’ve seen a – there is always an element of seasonality just because the consequence of any challenges in terms of fixing them and winter months is that bit tougher. But we’ve seen excellent performance through this winter period. In fact, we are seeing a number of days where we are well above a 100% on those machines now.

So, getting – I am really pleased with the work that Mark Little and his team have been doing and I fully expect to see the reliability come up and the costs come down and that’s why we are reflecting in the guidance this year..

Right, thanks and just a question on Firebag. Obviously, great quarter on Firebag. Is there a scope to bring some of the de-bottlenecking projects forward to that Firebag, I guess the other produce have that 220 kind of level of evens it out to slow spending or the discretionary spending which is sort of lower in this year.

Is there a scope for moving Firebag production to a higher level and what you have currently? Is there a scope for that this year?.

There is a scope for it. The timing is important, of course, what we are doing is, if you go back two years, our objective was to ramp Firebag up quickly to its design at 180. We were able to do that more quickly.

We then said, okay, we now – now we’ve been able to get the plant up there occasionally, we want to get it up there more full-time and as we do that, that will identify or help us identify where we would spend the de-bottleneck money. Of course, we’ve been able to go much further than we expected. So we’ve got, we’ve been up as we said above 180.

We’ve actually had it up for a period above 190 and it’s looking very good. So before we design the de-bottleneck, we want to take the plant itself to where we believe we can get it. So we are very comfortable in this 180 plus range. We are working on the next de-bottleneck phase, it’s not fully designed.

It could be in that 20,000 to 40,000 barrel a day range, but we want to be able to see the plant operating at its full capacity with the existing asset.

Very encouraged, it’s gone very well, it’s proven very reliable at these sorts of levels and because of course, if you remember, I think the year ago, when we took these – there are three parts to that plant.

There is effectively the steam raising part of the pant is the reservoir and then there is the oil water separation and depending on how well you are operating, it depends where you de-bottleneck it. So early on, when the steam to oil ratios were up over three, then the place to spend the money was to raise more steam.

As we are getting into operating this at higher levels, what we are finding is, we’ve been able to bring the SORs down. So that’s not the only place you would spend money, you start to have to look at spending money in other parts of the plant.

So, it’s important that it’s a measured steady progress delighted with the reliability, a little bit more to come and the teams are working hard now on what that de-bottleneck will look like..

Thanks for taking my questions..

Thank you. The following question is from Mike Dunn of FirstEnergy. Please go ahead..

Yes, good morning all. Few questions on, I guess, asset performance, mostly offshore fields. I’ll start with Terra Nova. It looks like, November, December volumes averaged about 77,000 barrels a day gross which I believe is the highest in maybe 3.5 plus years.

Is this sort of the base from which we should assume declines? I know there were some new wells I think that a couple that came on in Q4, but, anyway, production was surprisingly strong.

Just wondering if we should be modeling declines from here or steep declines quarter-over-quarter after this?.

I mean, I’ll think I’ll take the question. First is a compliment. Yes, I think you are right. We had a very good year with E&P and it ended very strongly and that helped us within – in the fourth quarter. I think, we can give you – hey, we can give you more guidance on the actual numbers of individual assets if you need those.

But there was an element of a flushing volume in Terra Nova in particular. So, it was an excellent quarter, but the numbers were generous to us. But we are very pleased with the same reliability programs are happening in Terra Nova in Oil Sands, the same assistance through the joint ventures in the North Sea are happening with our partners there.

It’s a committed focus on reliably operating assets and we are seeing benefits right the way across the business. We are seeing it in E&P, we are seeing it in Oil Sands and clearly visible around downstream..

And Mike, we can – it will be a slightly lower base than where we finished the year that you’ll want to take your declines on Terra Nova. So we can walk you through that offline..

Sure, great. Some more questions I guess for Buzzard, gentlemen. If we go back few years ago, so what Nexen have been saying about when declines would start. They should have shown by now and then if you go back a couple years, it was supposed to be 2014, 2015 and now guidance, I guess is officially that sometime in 2015 it will begin to decline.

I am just wondering how confident are you that that’s going to happen or is there a chance that declines don’t kick in until next year?.

No, we have started to see the declines here in the fourth quarter. And so we have reflected decline in the guidance for 2015. So, you are definitely going to see….

Okay..

And it would be in the order of 15% to 20% in the first year..

Okay, thanks, Steve. The Montreal hydrocracker work, you mentioned that you are expecting a yield uplift after that.

Can you just give me a sense for order of magnitude that are we talking – a couple or a few thousand barrels a day there?.

I mean, I think it would be too early to talk about the details of the Montreal yield changes, just because, that the schedules for the later stages of the project are part of what’s under review at the moment. Most of the Montreal refinery project have refining type margins.

So we will take a moment to reflect in the new price world, what the think those returns, what the timing of the projects are and that’s probably the time to talk about the actual details of the projects..

Okay, great. And one last one from me if I may. I believe you are partnered with – I forget who, but there was plans for you to participate in an offshore well, offshore Nova Scotia this – I believe this summer.

Is that’s still going forward?.

Yes, so, just to remind you, we did deal with two – in two different joint ventures. One was with Shell and Conoco in the Shelburne basin. That’s a massive resource. The first part of that will be some exploration related to this year. That is still planned to go ahead.

The second deal was with Exxon and Conoco around the Flemish Pass, another potential reservoir with great potential, but there is no material spending on that one for the next couple of years..

Okay, thanks, Steve. That’s all for me..

Operator, we are getting pretty close to time here. I am going to ask that we take one more question and we will certainly be available offline to field further questions the rest of the day here..

Certainly. The final question is from Jason Frew of Credit Suisse. Please go ahead..

Sure, thanks for taking this.

I was wondering, Steve, if you could give a bit more life to the, what seems to be a strong operating set of results within the LIFO impact in the downstream? And then, just a quick follow-on as to how you see the downstream portfolio strategically, I think you’ve done some small optimizations in terms of the assets, but is there room for more?.

Yes, I mean, first of all, let me just talk around general operation particularly downstream. These are big operating businesses and I have to say overall, 2014 was a good year for us. I’d like to see slightly stronger operations around Oil Sands and the mine, but I am comfortable that the maintenance has been done and the plants are in place.

And so, I think you are going to see a clear year this year and you are going to see what the capability of those assets are.

There is no doubt, if you look at the downstream in particular, we are one of the – if not the number one operator on this continent, it does move around a little bit depending on what turnarounds we take, but we regularly get the best margins per barrel of capacity in the downstream.

And most of the serious players have this in their sites as a target to try and do what we are doing. That’s for a number of reasons it’s a high quality business with a high quality assets. A great team down there delivering it and this is – this has been happening over multi years.

This is not something that happened last year, it’s something that’s been happening over we started 10 years ago, continued through the merger between Suncor and PetroCanada and has continued with the new company.

We do continuously look at how much further we want to take that integration and of course the next step for us is, when line 9 gets reversed, then we will start to integrate Montreal as an inland refinery.

We then have the opportunity beyond that to look at capital expenditure there and we are looking at those projects and going through them in detail. Clearly, in a capital constrained world, those are projects that you have options on. But they are looking reasonably attractive.

So the appropriate time – we’ll take the detailed reviews and look as to whether the coking project goes in. We did make the first modifications to the Montreal refinery in anticipation of some of the change in feedstock and we’ve done that and that project was completed before Christmas and is online now.

So, there is a suite of projects around downstream integration and we’ll look at those. Beyond that, we are opportunity-driven. We look at every asset that’s bought and sold on the continent and to see further integration is planned. And we like the amount of integration we’ve got now.

We’ve got, as I say, that effectively spare Montreal refinery in terms of integration. So we’ve got some running room in front of us. In our mid and long-term plans, we look beyond that, but no plans at the moment..

Okay, thank you very much..

Okay, with that, I’d like to thank everybody for participating. We really had an unusually lengthy list of questions and I know we didn’t get to some. So, as mentioned, we are certainly available to field in the rest of the day. But I’ll thank everyone for participating and signoff..

Thank you. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation..