Susan Grey - Director of Investor Relations Brian Charles Ferguson - Chief Executive Officer, President and Non-Independent Director Ivor Melvin Ruste - Chief Financial Officer and Executive Vice-President John K. Brannan - Chief Operating Officer and Executive Vice-President Robert William Pease - Executive Vice-President of Markets, Products & Transportation Harbir S.

Chhina - Executive Vice-President of Oil Sands

Benny Wong - Morgan Stanley, Research Division Phil M. Gresh - JP Morgan Chase & Co, Research Division Greg M.

Pardy - RBC Capital Markets, LLC, Research Division Mohit Bhardwaj - Citigroup Inc, Research Division John P. Herrlin - Societe Generale Cross Asset Research Paul Y.

Cheng - Barclays Capital, Research Division Fai Lee - Odlum Brown Limited, Research Division Michael P. Dunn - FirstEnergy Capital Corp., Research Division

Thank you, operator, and welcome, everyone, to our fourth quarter and year-end 2014 results conference call. I would like to refer you to the advisories located at the end of today's news release.

These advisories describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. Additional information will be available in our Annual Information Form.

The quarterly and annual results have been presented in the Canadian dollars and on a before-royalties basis. Brian Ferguson, President and Chief Executive Officer will begin with an overview, and then turn the call over to Ivor Ruste, Executive Vice President and Chief Financial Officer, who will discuss our financial performance and our reserves information.

Following that, John Brannan, Executive Vice President and Chief Operating Officer, will provide an overview of our operating performance. And Bob Pease, Executive Vice President, Markets Products and Transportation, will provide an update on our downstream operations and transportation plans.

Brian will then provide closing comments before we begin the Q&A portion of the call. Please go ahead, Brian.

Thanks, Susan. Good morning.

Our fundamental business performance through 2014 was strong. Our oil sands production was up 25%.

Our non-fuel operating costs at Foster Creek and Christina Lake were down 6% and 20%, respectively. And our proved bitumen reserves were up 7%.

In addition, our recycle ratio, measure of operating cash flow in excess of the costs to add reserves, was a very solid 2.8x, and our production replacement was 193%. Despite a sharp downturn in commodity prices the last 3 months of the year, Cenovus ended 2014 in a strong financial position.

Debt metrics were well within the targeted ranges for debt-to-cap and debt-to-EBITDA. In addition, if you look at our net debt metrics, which take into consideration the cash on hand we had, our net debt-to-cap was 31% and our net debt-to-EBITDA was 1.2x.

The fourth quarter was marked by a significant change to the outlook for crude oil prices in the near- to medium-term. This downturn impacted our results for the quarter and, as Ivor is going to discuss, like other companies in our industry, predicting our 2015 cash flow, given this volatility, is one of our key challenges in the short term.

I believe that we are in for a much greater volatility in oil prices for the foreseeable future and that's why you've seeing Cenovus preserve cash by moderating our growth and reducing our workforce. These actions are prudent and, we hope, protect the financial resilience of Cenovus without compromising our future.

Before I turn the call over to Ivor Ruste, our Chief Financial Officer, to provide more detail on our financial performance, I'd like to note that the board has approved a first quarter dividend of $26.62 per share, which is unchanged from the prior year. They have also approved an update to our existing dividend reinvestment plan, allowing shareholders to purchase shares via our DRIP at a discount to market prices.

This is another step that we are taking to preserve cash. We plan to issue common shares through the DRIP from treasury at a 3% discount to average market price.

I'll now turn the call over to Ivor.

Thanks, Brian, and good morning, everyone. 2014 is best described by 2 distinct periods.

The first 9 months of the year showed financial results attract [ph] better than 2013 and set us on a path to exceed our initial corporate cash flow guidance. In the last 3 months of 2014, there was a significant shift in the commodity price environment.

Crude oil prices fell between 40% and 50% from September 30 through the end of the year, making the fourth quarter financially challenging. Even in these conditions, fourth quarter upstream operating cash flow was 4% higher than 2013 due to higher hedging gains, an increase in crude oil production, and lower operating costs.

Refining operating cash flow was a negative $323 million for the quarter, primarily due to a decrease in refined product prices and lower refined product output due to a planned turnaround. In addition, the significant decline in refined product prices as the year ended resulted in inventory write-down of $110 million.

As you will recall, we report our inventory on a first in, first out basis, while most U.S. refineries use the last in, first out inventory accounting method.

If we had used this method, our operating cash flow would have been a $163 million higher for the quarter. This excludes the impact of the inventory write-down.

Each year, we evaluate our portfolio projects to ensure they are accurately represented on our balance sheet. Due to the significant decrease in forecast crude oil prices and the slowdown of the long-term development plan for Pelican Lake, we had a noncash, goodwill impairment of $497 million or, $0.66 per share.

That goodwill dates back to a business combination in our predecessor company and, as required by the accounting rules, has not been reduced in value since its creation back in 2002. We also recorded property, plant and equipment impairments of $65 million, or $0.06 per share, primarily related to equipment at Pelican Lake for which we do not believe the curing [ph] value can be recovered.

Additionally, an exploration expense of $86 million was recorded, which relates primarily to the tight oil exploration assets in Northwest Alberta that was determined to not be commercially viable. We reported our reserve bookings as at [ph] December 31, 2014, due to the development area expansion approvals at Foster Creek as well as improved performance of Christina Lake wells, our proved bitumen reserves were up 7% compared with 2013, but proved plus probable bitumen reserves were up 30%.

The associated finding and development costs, excluding changes in future development costs, were 8% lower this year due to reduced spending. When looking at FND costs for in situ oil sands developments, it's more representative to look at the 3-year average costs, given the lumpy nature of the reserve [indiscernible] [Audio Gap] [indiscernible] 3-year average is $11.77 per BOE.

Since our inception, we've been committed to maintaining a strong balance sheet and solid financial position. In this oil price environment, we are very focused on preserving the strength of our balance sheet, while not compromising our future.

We value our investment grade rating and continue to value the flexibility and access to financing this gives us in the markets. We ended the year in a strong financial position.

At the end of the fourth quarter, our debt to capitalization was 35% and our debt to adjusted EBITDA 1.4x, both within our long-term targeted ranges of 30% to 40% and 1x to 2x, respectively. And, as Brian mentioned, we had $883 million of cash on hand at year end.

I will now turn the call over to John for an update on our operational performance.

Thank you, Ivor, and good morning. Operationally, Cenovus had a strong year.

We implemented the optimization plan we outlined at the beginning of the year for Foster Creek and have delivered strong results. We have had higher facility up time at Foster Creek and Christina Lake and our asset teams have worked diligently to optimize our reservoir management activities to deliver the predictable reliable results we expect of our ourselves.

2014 was a record year for safety at Cenovus. We worked approximately 45 million man hours, the highest number of man hours worked in Cenovus's history, yet we had the lowest contractor incident rates.

Across the board, we continue to see the positive results of our increased focus on safety. Christina Lake continues to deliver strong performance.

Fourth quarter production was over 73,000 net barrels per day, which exceeded our guidance for the quarter by 6,000 net barrels per day. This was due to the improved performance of our facilities, better reservoir performance with strong base well performance and a steam-to-oil ratio of 1.7x, which was better than our expectations.

We drilled 24 wedge wells in 2014 at Christina Lake and are now producing from 22. We expect to have a total of 29 wedge wells online by the end of 2015.

We continue to work on the Christina Lake optimization project and expect incremental oil from the project near the end of 2015. Construction at Christina Lake phase H -- I'm sorry, phase F has continued as planned and is approximately 2/3 complete.

First oil is expected in the second half of 2016. In light of the recent market volatility and to preserve cash, we have suspended construction of phase G, which is less than 15% complete.

The project team has begun a safe and efficient wind down of construction activity and will focus on offloading and storing of equipment so we're ready to resume construction when market conditions improve. The previously planned first steam date of 2017 has been deferred.

Total production at Foster Creek was more than 68,000 barrels per day net in the fourth quarter, with a steam-to-oil ratio of 2.3. Phase F achieved first oil in September and has seen steady production growth, exiting the year with production of 4,000 barrels per day net.

We anticipate 18-month ramp ups at Foster Creek, from first oil to full production. Now, continuing focus on well optimization has also led to flush production in the quarter.

We anticipate some decline in these volumes, which is expected to be partially offset by the ramp up of phase F in 2015. Construction continues on phase G at Foster Creek.

This phase is approximately 2/3 complete and on track for expected first oil in the first half of 2016. Similar to phase G at Christina Lake, phase H at Foster Creek has been suspended to reduce our capital expenditures for 2015.

The project team is focused on ramping down work, preserving existing equipment and ramping up engineering to allow for a quick restart in the future. Our conventional assets performed well in 2014, with overall liquids production decreasing only slightly at 2% year-over-year.

Successful horizontal well performance in Southern Alberta and slightly higher production at Pelican Lake was offset by expected natural declines and the sale of Bakken and Wainwright assets. Our conventional assets provide us with the flexibility as development can be more easily ramped up or ramped down to match market conditions.

As such, we have significantly reduced planned spending on our conventional operations for 2015 and expect to see an associated decline in liquids production of approximately 5,000 barrels per day when compared to 2014. We plan to restart our drilling program, when prices rebound.

Strong performance in our oil sands and conventional assets continued into 2015 with production of approximately 72,000 barrels per day at Foster Creek and 77,000 barrels per day at Christina Lake and 75,000 barrels per day in conventional for the month of January. I will now hand the call over to Bob Pease to discuss our downstream results and our transportation commitments.

Thank you, John. One of the priorities I have at Cenovus is to maximize the margin that everyone of our barrels receives in the market.

And in doing so, have taken a portfolio approach to accessing tidewater and improving the price we realize for our products. In the quarter, few of our initiatives came to fruition.

The first barrels of oil were delivered via the Flanagan South pipeline. Our firm commitment of 50,000 barrels per day, ramping to 75,000 barrels per day in 2018, allows our oil to reach the Gulf Coast market and receive global pricing.

The IPL Cold Lake pipeline connecting Foster Creek, and in the future Narrows Lake, to the market hubs in Alberta was completed, and our dilbit is expected to begin shipping in the first quarter. This pipeline is essential to support the planned growth of Foster Creek and Narrows Lake.

We also began receiving our 825 coiled and insulated rail cars. These cars should enhance our rail strategy and complement our 30,000 barrels per day of rail-loading capacity.

Rail provides us with the optionality in times of pipeline constraint and gives us access to markets not connected by pipelines. With the addition of these transportational alternatives and with slower production growth in the next few years due to capital spending deferrals, our unit costs for transportation are expected to be higher in the near term.

Our expectation is that the per barrel cost at Foster Creek and Christina Lake will increase to approximately $8 per barrel and then start to decrease again as our growth phases come online. Much of this increase is expected to be offset by improvements in realized pricing from our delivered sales over the long-term and from increased options for blended crude placements.

As Ivor mentioned, the end of the year was tough on our downstream financial results despite solid operating performance during the period. Falling refined product pricing and overall lower crack spreads reduced operating cash flow.

Our realized margins were also affected by a narrow price differential, relative to WTI, for our cost-advantaged feedstock like WCS. It is important to remember that through integration, our heavy crude refining capacity provides us with the opportunity to capture value from both the WTI, WCS differential for Canadian crude, and the uplift that is derived from processing lower cost crudes into higher-valued products.

In the past 3 years, our downstream operations have contributed, on average, almost $900 million per year to our overall operating cash flow. While we believe that oil prices will improve in time, we acknowledge that they will likely remain low for the remainder of 2015.

In this environment, it becomes even more important to maximize the margin on every barrel of oil we produce. I will now pass the call back to Brian, for his closing remarks.

Thanks, Bob. My absolute top priority this year is to maintain Cenovus's financial resilience without compromising our future.

Given the expected volatility in oil prices in 2015, our financial results are unlikely to represent the strength of our operating performance. We have implemented immediate reductions to our discretionary spending, we are reducing our workforce by approximately 15% and are prepared to further moderate our capital expenditures, if necessary.

We've done a significant amount of work of evaluating the potential of our fee land properties. We are market-ready for various potential options to crystallize the value on these lands.

It is impossible to time a market, but we are ready to aggressively pursue options when the timing presents itself. With that, the Cenovus team is now ready to respond to your questions.

Correct me if I'm wrong, but when looking at the lower unit costs, it look like there is more savings than just being spread out over more barrels. Are we starting to see some of the initiatives to reduce the target of $400 million to $500 million cost show through?

I'll get John Brannan to respond to that, Benny.

Yes, thank you, Benny. Yes certainly, we have seen, besides just the increase in volumes, reductions in our operating costs.

Many things like our chemical efficiencies, our [indiscernible] oil, the fact that we are running these facilities harder and better, averaging over 95% of production capacity. In addition, in this current price environment, we are also looking to achieve additional savings from our suppliers, that we expect will be in the 5% to 10% range.

So we should have continued good performance like we've had in the fourth quarter into 2015.

Great. And just a nitty question.

In regards to your drip program, what are you guys expecting for the participation rate?

Yes, Benny, I don't think we should forecast that one. We certainly would anticipate that participation would be comparable to what other energy companies are experiencing.

Okay. And If you can provide any color on the interest that you guys received so far in the royalty assets.

And maybe, give an idea of what's preventing it from happening so far.

So I would say that we've had substantial interest from a variety of parties, and the only thing that is driving timing is our decision with regard to when the timing is right. Clearly, with the downturn in oil prices, this would not be the right time to transact.

And one of the things I don't want to be guilty of is -- I don't want to be guilty of doing the right thing at the wrong time. We do have and are ready with our data rooms, so we are ready to proceed aggressively when we think the timing is right.

And just a final question. Provide us with an update of how you guys are thinking about the dividend and the policy these days, and I'll leave it at that.

So I'd start by commenting that the Board did reaffirm our dividends at the same level as 2014. I believe the dividend is very important.

In my mind it is a commitment to our shareholders, and it is a form of capital discipline. So we are committed to the dividend, as we have indicated.

We are adding the additional measure, as we have discussed, which gives the opportunity to existing shareholders to reinvest their dividends, if they choose, at a 3% discount.

First question, this is regarding the CapEx, the comment that was made about continuing to assess the budget, moving forward it's -- I guess, I was just kind of wondering, what kind of environment would be required to further reduce CapEx, relative to where we are today?

So where we are today, we're comfortable with the guidance we've given, and there are plans at the $1.8 billion to $2 billion guidance range for this year. If we were to see substantially lower prices, we do have the flexibility, if we chose to, to reduce capital further by up to $500 million.

Okay. And I guess, how do you think about it moving forward beyond 2015, in terms of, I guess, the mandatory spend?

So you have projects that are ramping, how much flex do you have as we look to 2016?

I think, as we indicated in our December news release that our committed capital, or what we would describe as committed capital in 2016, was $1.8 billion, dropping to $1.7 billion in 2017, there is substantial flexibility in both of those numbers, should we choose, where we could choose to reduce capital further. That would -- obviously, though, have impact with regard to production volumes.

Is it the same $500 million of flexibility or so that you tabbed this year? Or just order of magnitude?

It would be larger than that.

Okay. And then, with respect to the transportation costs, I know this kind of came up last quarter.

So -- and you guys did give some more clarity there. So, certainly appreciate that.

In terms of the absolute spend that, that implies up year-over-year, I think it's, if you did take that per dollar number and turn it into dollars, so it's about $275 million year-over-year or so. So should we be thinking about this as that dollar amount basically stays constant, moving forward, and the per barrel just starts to come down when the production ramps?

Or just in general, how do you think about that?

Yes, Phil, this is Bob Pease. There's 2 components to that increasing cost.

One is the cost associated with getting the blended bitumen into the hubs. As you know with the new line that we brought -- we're bringing on this quarter, that does increase the cost while we're producing at our current level of production.

But that -- we built these lines with significant capacity to address our significant growth plans in the coming years. As our volumes begin to increase, that price on a per barrel basis actually starts to diminish, so we will see that element go down.

The rest of the increase is associated with the additional movement of product away from the Alberta hubs into the higher-priced, global-priced markets, the U.S. Gulf Coast, the West Coast.

This transportation, we have historically seen significant uplift over and above the cost of that transportation that shows up in the revenue. And we anticipate continuing to grow our sales on a delevered basis.

So it would not be surprising even to see that component of transportation to increase. But again, with an expectation of higher net revenue more than offsetting that cost of transportation.

Sure, okay. Last question, just on the one key production, the trends you've seen so far and then the flush production impact.

When would you expect that to fade? I mean, does it hold this level through the first quarter?

Or do we start to see that to fade in February, March?

Let Harbir respond to that.

Yes. So we get pretty good Q4 and Q1 looks pretty good.

And then I think the flush production starts to taper off towards the end of Q2. But by that time, we'll see Foster Creek F kicking in.

We're currently doing about 10,000, 12,000 barrels a day. And so that will continue to ramp up and make up for the decline that we'll see in the end of the second quarter.

3 questions for you then, maybe just to come back to the sale of your royalty production. Brian, would that sale impact your conventional business in any way?

Or is it really just a matter of losing the 7,600 BOE a day?

Well, the royalty land production, as you know it, is 7,600 BOE a day. And without -- I can't get into the details in terms of what we have in the data room, because it is a or will be a competitive process.

But, we will certainly be looking, as we've indicated in the news release, at all the opportunities that we have inside our existing portfolio on non-core properties to surface and crystallize added value for shareholders that would allow us to generate further near-term cash proceeds to help bolster the balance sheet.

Okay, so good -- very good answer. So in other words, I mean, if there was an opportunity -- I think what you're saying is that if there's an opportunity to monetize some of the conventional outside of this you wouldn't be averse to that if the price is right.

Correct.

Okay. The other thing is -- just in terms of thinking about tax leakage with the transaction, would your expectation be then that you'd be able to largely protect the majority of the proceeds coming out?

Or will there be -- or would there likely be some tax leakage, meaningful tax leakage?

Again, Greg, I'm not in a position at this point to get into details of what's in the data room. Obviously, that becomes part of the bid process in terms of terms and conditions and structuring and what various parties might be able to offer to distinguish their bid versus others.

Okay, okay, okay. I will stop on that line of questioning.

So just around the transportation guidance, it was -- I think that our last update on a BOE basis was 3 to 350. If we just jam in the math now with the $8 in Foster Creek, Christina Lake, we're getting $4 to $5 of BOE.

Are we in the ballpark?

Yes, so that change, again, was principally of the 2 components I mentioned before, the introduction of the [indiscernible] does increase our cost of coming to the hub. But the biggest jump from 2015 relative to 2014 is with Flanagan South, with our increased rail movements.

We are now moving a lot more volume or projecting to in 2015 relative to 2014. And that volume come -- along with that comes increased sales revenue of the sales price typically in the Gulf coast versus the sales prices typically in Alberta.

So yes, it is a significant increase, not all of it is an increase that is sustained because, again, the Polaris -- excuse me, the Cold Lake pipeline cost will diminish on a per barrel basis. But most of it is attached to revenue adding cost.

Okay, great. And then, maybe just a follow-up to that.

Is the rail ARB open rate now just given the narrowness between WCS and Mayo -- Maya?

Yes. So -- for the past year of 2014, rail was an extremely attractive option.

But we've seen a lot of our differentials swing overtime. Currently, the ARB is not open at this time if you just simply look at it on what's the going price in the Gulf versus the cost of bringing it down.

But there are additional advantages from your rail as far as being able to alleviate inventory, handle apportionment issues on other pipelines. And we do seen -- we do see this swing back and forth.

Rail also gets us to other markets and we're working to get those barrels on rail to other markets, and it allows us to move product other than just standard pipeline specification product, which we think has advantages to us. So as far as first quarter movements, we may be somewhat reduced, as a result of that.

One of the great things about rail is a component of an overall portfolio. The relationship between the fixed and variable costs, it's easier to lay off a portion of those costs than other means of transportation.

So a long answer, but in general, yes, the current ARB to the Gulf Coast is tight, but it's still an attractive overall component of our proposition.

Okay, on a year. So you're opt -- I mean, essentially you're optimizing it, I mean, you're under no obligation to be shipping crude down to the Gulf now if the dollars don't make sense, correct?

That's correct. We were trying to create as much flexibility as possible.

Okay. Then just the last one is, I mean you guys talked about your targeted debt-to-cash flow or debt-to-EBITDA ratios and so on.

Could you just touch on your liquidity and just how your covenants work?

Thanks, Greg. Ivor Ruste.

The -- I think we focused on managing to those metrics that are -- keep us in the investment grade debt credit rating territory. And we have significant liquidity and, obviously, in our undrawn credit facilities totaled $3 billion, maybe not quite that large at today's date, but that's the capacity we do have for liquidity.

The only covenant that we have is well beyond the target metric ranges that we rely on the 30% to 40% debt-to-cap, et cetera. And that actually is at 65% debt-to-cap.

So we have lots of room before we get up into that line. So we can draw on those credit facilities and fund our 2015 spending.

Greg, it's Brian. Just for clarification -- your question about transportation.

The 3 to 350 per barrel number that you had mentioned originally was across all barrels, not just the FCCL barrels and that was the discussion that we were focusing on in our news release, and that Bob was describing here was impact just on FCCL barrels, as opposed to across all barrels.

Just a follow-up on the transportation cost. I know that this question has been asked before but just to make sure -- the IPL line, is there a possibility that you guys could lease some of your capacity to somebody else and you take advantage of that in your commercial operations while the volumes ramp up?

Yes, this is Bob again. So we do look at that.

We -- not just those lines, but all of our lines. We look for what capacity we need and how best to utilize that.

So we do look for opportunities to both acquire and place surplus capacity whenever it exists.

Okay. And Bob, I think the next question is just for you as well.

If you could explain, like why a lot of the rail transportation so far out of Canada is still tied to WCS and not so much with rail bitumen when that would make a lot of more sense just trying to get to the Gulf Coast or even to the West Coast, because once Flanagan South ramps up and if Alberta Clipper goes through, a pipeline would be the most effective option.

So I think the answer to your question is that, if the question is why are we not moving more rail better drive bitumen and why not 2 other locations, one, you have to be able to remove the amount of bitumens or the amount diluents that you have in your bitumen to be able to get it to ship in that manner, and you also have to be able to establish receiving terminals that can take the product that you want to take. So all of that activity is underway.

We believe there will be value in differentiating from just the standard dilbit and what we move in rail. We are actively working those opportunities and actively working multiple destinations for the product.

Right. And one -- if I could ask Ivor.

Ivor, if you could just explain why the hedging for 2015 looks light. Is it because of the additional options for placing the product, you have more options to create value just by selling products in different markets?

Or is the opportunity to hedge more barrels, even at like $75, $80, is not there anymore?

Thank you. I think the latter part of your question is appropriate at this point in time.

We haven't been able to attach more hedges at prices beyond our budgeted prices. So our focus on using the hedging instruments is to cover as much of our next year's cash flow as we can.

And at 2015, we -- we're tracking on that objective of attaching -- covering about 30% of our cash -- next year's cash flow, until the price dropped and then -- we're double, probably double that coverage now, against the cash flow protection that we have. So our hedging strategy continues.

We're looking for those opportunities where we can lock in at reasonable prices in accordance with our budgeted prices.

Bob, a quick question. When you guys buy oil from -- for your refinery, isn't that a CMA?

I'm sorry, could you repeat the question?

When you buy oil for the refining operation, is it being purchased under some form of a CMA calendar month average? In other words, that in the contango [ph] market, is that going to benefit and reduce your purchase cost?

Yes. I -- the short answer is that our partner's the one who does the acquisition of the crudes and we do that on what is optimal for the refineries.

So they have flexibility on the means by which they acquire crudes for the refineries. I don't know whether it's tied to another benchmark or flat priced.

They have flexibility in doing that. But the basic message is the refineries are able to optimize, and we acquire on whatever is the best mechanism for those sites at the time.

And then do you have any storage facility that you have contracted out at Cushing so that you can take advantage of the current contango market?

We do have tankage at Cushing, and we are always looking at whether we have the level that we want and what the opportunities are for storing and utilizing that effectively in the market.

Right. And then, Bob, there were -- the contango market [indiscernible] you already have storage.

I presume that you will be adding a lot of inventory because, I mean, you can -- you sense already that premium they buy putting the spot in self [ph] the next month contract. Should we assume that we are going to see some financial benefit in the first quarter as a result because of that?

And can you tell us that how big is your storage facility?

Yes. Again, so we don't articulate how much and what we're doing from an inventory standpoint for competitive reasons.

What we're doing and when we're building or pulling the contango market varies in terms of the types of crude that you have and where you're going with those products. There's interesting pricing relations currently between Cushing and the Gulf Coast.

But we do -- we have a team that tracks that, monitors that and attempts to maximize the value out of that storage. And as we do so, it rolls into our results for the period in which the action takes place.

Brian, on 2 question. First, the -- when we looking at the supplier contracts for your supply chain, is there any rough estimate you can provide?

What is the percentage of your contract is the -- within or less than, say, 2 years? And how much of them is actually over 2 years?

And then a final question that on your cost reduction initiative. Can you break it down for us into major buckets, such as maybe, is the cost reduction related to the headcount or that human resources?

And how much is on the procurement or some kind of bucket that you can provide?

So I'll respond to the last question and then I'll ask John to respond your first question with regard to the length of contracts on supply chain. With regard to the cost reduction, obviously, the most impactful short-term cash preservation is to simply do what we've done, which is to reduce the capital spending.

A big part of the and the majority of the workforce reduction is and will be contractors who are directly related to the capital that we would have spent. So that is the biggest component of our near-term cash preservation is the actual reduction of the capital spend that you've seen.

We will and have been continuing to pursue other things with regard to operating costs, to G&A, to nondiscretionary spending. And I can assure you that there is no stone unturned in terms of where we are looking today to improve cost structure.

And I think importantly, I'd emphasize that we are looking for sustained cost improvement. We did talk in December about a target of $400 million to $500 million in sustained cost savings across the board, capital on operating at a more normal pricing environment.

So that's fairly material for us. Now, I'll ask John to respond to the question about the duration of the supply chain contracts.

Thank you, Brian. Currently, we have a few long-term contracts.

Those are primarily with our drilling rigs, would probably amount to less than $30 million over the period of time. I think, we've got commitments with about 4 rigs.

So we don't have any, other that, any long-term commitments.

So in other words, that, John, that as we see costs deflation in the industry coming through, we should relatively quickly [indiscernible] see it showing up in your results, say, within a matter of maybe a quarter or 2 at the worst that we should start showing through, right?

That's correct and we've got 900 suppliers that currently provide about 95% of our overall spend between OpEx and CapEx. We have contacted all of those suppliers, and we are receiving discounts that we would expect to go to the bottom line almost immediately.

And that tends to be in the range 5% to 10% or so on the overall costs.

It's Fai Lee here. Brian, I understand why you don't want to cut the dividend now.

But it seems to me whenever companies implement or change their DRIPs to preserve balance sheet flexibility, that's perhaps to say that their dividends maybe too high. How are we to respond to that?

And perhaps could you also comment on your longer-term strategy regarding the DRIP?

Thanks for the question, Fai. So the -- what we talked about in the past is that we are comfortable in terms of a normal -- more normal pricing environment, where we would be paying out on an aftertax basis, 20% to 25% of aftertax cash flow in terms of our dividends.

And we were certainly well within that, based on the actual 2014 results. Having been through a number of cycles so far in my career, and I expect I will see at least one more in my career as we go forward here.

To me, what's really important is that we're managing our corp -- our company, our balance sheets, our commitment to shareholders on a longer-term basis. And we -- I view this, as I mentioned, as an important form of capital discipline.

And I would -- before we were to reassess current dividend level, I would reduce capital further. I can't and won't speculate on what the length or duration of the current downturn is going to be.

But I can tell you that I'm committed to doing everything that I can to make sure that our dividend is sustainable. I think that by offering our existing shareholders the opportunity to reinvest their dividend, their cash dividends, at a discount, I hope is a strong signal in our belief in the sustainability of our business model and our view as to the strength of our underlying asset base, despite this short term downturn.

First question is on Pelican Lake. With -- or just reduced spending plans there for maybe the medium term.

Is the Wabasca, Palmer flood area -- is that an asset that can be separated from your Grand Rapids ID leases in terms of -- if that's maybe non-core but if that was divested, you would -- that would not impact your operations at Grand Rapids. And a couple of more questions after that.

Yes, Mike, thanks for the question. The operations at Pelican Lake we're reproducing on the Wabasca are entirely separate from our Grand Rapids operations.

There are some synergies you would expect when we're operating both areas like the roads and the infrastructure and the airport and those kinds of things, that's similar quarters. But if you needed to, you could separate it.

We don't have any plans necessarily to do that, but to answer your question that is -- they are separate facilities.

And question maybe for Bob. Presumably, you're setting some Christina Lake dilbit down to the Gulf Coast and Flanagan South now.

Just wondering, if you could comment on what you're seeing for pricing for that relative to either a WCS going down there and/or Maya at the Gulf Coast?

Yes, thanks, Mike. Yes, we are moving down on Flanagan South now.

The pricing, it fluctuates over time. But in general, we're receiving a Maya-type price, with adjustments relative to the quality.

We've seen a somewhat lower differential in the recent months between our Christina dilbit and our Cold Lake blend and the WCS benchmark and that has been narrowed, 10 discounts more narrow. But basically, the quality of crudes that we put down there is similar to Maya.

And we will receive a similar type pricing. But in any given month or quarter that can be variable depending upon when the contractual terms were put in place.

Good. And last question for me.

Just wondering if you can comment on the costs that you're seeing to defer some of these Foster Creek, Christina Lake, Narrows Lake projects. Is it -- presumably, that's going to be -- what was the magnitude?

I don't know, $50 million, $100 million to delay the timing of those -- or maybe a per year deferment cost.

I'll ask Harbir to respond to that.

Yes, Ted [ph], it really depends on what stage you slowdown the project, and if you slowdown the projects at the 30% to 40% completion stage, we do not expect a significant impact. In fact, it gives us time to look at the value engineering and to improve and get the drillings in order.

So that we can -- we're often running with the good construction work packages. But when you're at 60% to 80% completion, that will have a major impact, and that is why we are continuing to proceed with Foster Creek G and Christina Lake F, because those 2 projects are well close to within that 25% completion stage.

And that's why we're not stopping them.

Okay, Harbir. So I guess, based on that, then really no material costs being incurred I think since you've -- the one's you're slowing down are earlier in development?

No. Yes.

Yes -- there's pros and cons with that Mike. So I just gave a normal straightforward answer.

There might be some costs in some places, but we expect those to get offset with the -- with getting the drawings in place, where the deflation is occurring, all of those things. There actually might be a benefit.

But right now, I would say it's just awash [ph], and we'll see how the world turns out, and we might actually get some benefits.

Actually my question has been answered.

Would you ever consider with the R&M switching to LIFO from FIFO? It really doesn't matter, but I'm just curious.

We -- it's Ivor Ruste, we have to follow a Canadian accounting rule.

Do you have an estimate for how many contract jobs are going? And what percentage of full-time equivalent staff will be cut?

John, it's Brian. The total reduction in overall workforce is going to be approximately 800 positions, and the vast majority of those will be contract positions.

Scott just asked my question.

Thank you for joining our call today. The call is now complete.