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Executives

Jim Campbell – VP, Government Affairs and Corporate Responsibility

Brian Ferguson – President and CEO

John Brannan – EVP and COO

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

Ivor Ruste – EVP and CFO

Analysts

Arjun Murti – Goldman Sachs

Greg Pardy – RBC Capital Markets

Dave McColl – Morningstar

George Toriola – UBS

Matt Portillo – Tudor Pickering Holt

Kate Minyard – JPMorgan

Jeff Jones – Reuters

Cenovus Energy, Inc. (CVE) Q4 2012 Earnings Call February 14, 2013 11:00 AM ET

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy’s Fourth Quarter and Year-End 2012 Results Conference Call. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. (Operator Instructions) Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Cenovus Energy.

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

Jim Campbell

Thank you, operator. Good morning and welcome, everyone, to our fourth quarter and year-end 2012 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 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 and annual report. The quarterly and annual results have been presented in Canadian dollars and on a before-royalties basis.

Brian Ferguson, President and Chief Executive Officer, will begin with an overview of our results; and then turn the call over to John Brannan, Executive Vice President and Chief Operating Officer, who will provide an overview of our operating performance and our reserves and resources information. Don Swystun, Executive Vice President, Refining Marketing, Transportation and Development, will highlight results from refining. Following that, Ivor Ruste, Executive Vice President and Chief Financial Officer, will discuss our financial performance. Brian will then provide closing comments before we begin the Q&A portion of the call.

Please go ahead, Brian.

Brian Ferguson

Thanks, Jim. Good morning. Our fourth quarter concluded another strong year for Cenovus. Our integrated oil growth strategy is working well, and we continue to deliver on our overarching goal of increasing net asset value. We maintained strong operating performance throughout the year, highlighted by robust oil sands production growth at our Foster Creek and Christina Lake assets, where annual production volumes grew by 35%. We brought on our 9th phase of SAGD growth, that’s Christina Lake D, which contributed to overall oil growth of 14% in 2012.

Our upstream performance in 2012 was complimented by record operating cash flow from our refining business. However, during the fourth quarter, lower market cracks in December and a LIFO to FIFO inventory adjustment in December reduced operating cash flow by about $50 million compared to our Q4 guidance.

We had a onetime non-cash write down of goodwill related to natural gas prices, which reduced operating earnings by $0.52 per share and resulted in operating earnings falling short of consensus estimates.

We continue to make significant progress on our oil growth plans; production growth from Christina Lake continues to exceed our expectations, and in January we reached nameplate production capacity, just over six months from first production, from Phase D, another operational achievement. Foster Creek also continues to demonstrate strong performance, averaging 96% of nameplate capacity during 2012.

During the fourth quarter we also received sanctioning for Narrows Lake Phase A, our third oil sands project and first commercial use of solvent aided process, or SAP, using butane in combination with steam. We also continue to advance pilots within our emerging Grand Rapids and Telephone Lake projects.

In 2012, we booked significant increases in our reserves and resources. We achieved a 12% increase in total proved reserves and an 18% increase in proved bitumen reserves, driven primarily by sanctioning of Narrows Lake Phase A and increased recovery factors at Foster Creek and Christina Lake.

These results were achieved at a finding and development cost of $9.04 per barrel of oil equivalent. We generated a recycle ratio of 3.2 times, which demonstrates the low cost nature and overall profitability of our operations.

In addition, our independent qualified reserves evaluator has estimated the future development costs for our total proved reserves at $5.90 per BOE or $7.20 per BOE on an escalated basis. 2012 has been a year of challenging price volatility on the upstream side of the business, driven primarily by ongoing pipeline congestion.

The volatile and wide price differentials have squeezed our upstream margins, but they also continue to benefit our refining business. Our 50% ownership in two high quality Mid-Continent refineries is expected to continue to generate strong operating cash flow.

On an integrated basis our overall cash flow remains strong, and our outlook for 2013 is on track. January is off to a great start. We have concluded another year of predictable, reliable performance, and we continue to build net asset value. We are executing on the controllable aspects of our business.

Our integrated strategy has helped mitigate the pricing volatility inherent in our business, and we are well-positioned for future performance. These attributes that contributed to the Board of Directors to approve a dividend increase of 10% to $0.242 per share, starting in the first quarter of 2013. We remain dedicated to increasing total shareholder return and dividend increases are a part of that commitment.

I’ll turn the call over to John Brannan now, who’ll provide more detail on our operational performance.

John Brannan

(Audio Gap) perspective, and I would like to discuss a few of our achievements. Our performance in the fourth quarter of 2012 was highlighted by ongoing oil sands growth from Christina Lake. We continue to ramp up production from Christina Lake Phase D at an industry leading pace, reaching nameplate production capacity of 98,000 barrels per day gross a few times this past January.

Our goal is to manage steady, overall plant performance heading into our planned 10-day turnaround in the second quarter. It is important to mention that our teams achieved this production ramp up while continuing to advance the Phase E project, which is now 65% complete overall and on track for first production in the third quarter of 2013.

At Foster Creek, the fourth quarter concluded what has been another successful year. Foster Creek continues to benefit from low steam to oil ratios and contributions from our Wedge Well technology. Gross production volumes during the fourth quarter averaged just over 118,000 barrels per day at an average steam to oil ratio of 2.3.

Approximately 12% of production at Foster Creek comes from 56 wells drilled using our Wedge Well technology. In 2013, we plan to bring on another eight Wedge Wells at Foster Creek. Also at Foster Creek, we advanced construction of Phase F, a 45,000 barrel per day gross plant expansion to 67% complete, with costs and schedule tracking as planned.

When we build our SAGD phases in sets of three, such as Foster Creek F, G, and H expansion, the first phase contains a significant amount of common infrastructure to support the remaining two phases. Having Phase F on track gives us a lot of confidence that the remaining two phases will achieve project cost and timing objectives. Phases F, G, and H will add a combined 125,000 barrels per day of gross production capacity at Foster Creek.

Across operations, inflationary pressures are stable, and we are tracking within our targeted range of 3% to 5% inflation across our oil sands projects. We have experienced improved access to labor, including key trades, across all of our project areas. We remain vigilant on all operating and capital costs, and are committed to maintaining our low cost leadership in oil sands development.

This year we continue to seek out opportunities to leverage cost efficiencies across the organization. Cenovus is targeting efficiencies through lower drilling and completion cost, improved waste treatment process and fluid handling, and fewer required well workovers. We also expect to effectively use our substantial spending program to reduce supply costs.

Moving on to our conventional oil areas, including assets like Pelican Lake, we remain on track with our growth plans and have increased oil production 10% from the fourth quarter of 2011. Our multi-year growth plans at Pelican Lake involve infill drilling combined with enhanced oil recovery using a polymer flood. We exited 2012 at production rates about 15% higher than 2011 exit rates. We did experience a slower production response than we had originally planned. This was mainly due to pressure reductions required to achieve safe infill drilling program. This year, we expect to achieve further production growth from this area, but we expect this will be more weighted towards the back half of the year due to the timing of wells and the lag time of the polymer flood response.

We continue to make good progress in moving our emerging 100% Cenovus SAGD projects forward towards commercial development. We successfully started up our dewatering pilot at Telephone Lake during the fourth quarter, which is aimed at improving the commercial development plan for this reservoir. Dewatering operations have been running smoothly and early results are encouraging. At Grand Rapids, our second well pair pilot has been circulating steam, and we anticipate first production from that well later this month.

As we move forward with these plays and continue to expand our existing operation, we remain focused on cost control. Operating costs in the quarter averaged $11.26 per barrel at Foster Creek and $11.42 per barrel at Christina Lake, both in line with guidance. For 2013, we are working hard to hold our operating costs flat across all our SAGD projects. Our current full year operating cost range of $11.70 to $13 per barrel at Christina Lake reflects our planned turnaround and increased staffing and start-up costs related to bringing on Phase E. We expect operating costs will trend downward on a per barrel basis as we ramp up production from Phase E starting in the third quarter of this year.

Our natural gas business continues to generate strong free cash flow that we use to fund our oil growth plans. In 2012, we generated $462 million of operating cash flow from natural gas in excess of capital expenditures. Turning to tight oil development, we have added over 9,000 barrels per day from our tight oil plays in Alberta and Saskatchewan in 2012. We continue to see robust growth from Southern Alberta where we have shifted our focus towards oil and away from natural gas. At the lower Shaunavon and Bakken areas in Saskatchewan, we exited the year at approximately 7,000 barrels per day, about 9% higher than 2011 exit rates.

However, given the materiality of these assets relative to our overall growth portfolio, we have decided to initiate a divesture process for the lower Shaunavon and Bakken areas, excluding any royalty interest on volumes associated with fee lands. As Brian mentioned, we had another solid year of reserve bookings and resource additions. We reported bitumen proved reserves of 1.7 billion barrels, an 18% increase from year-end 2011. Reserves associated with the sanctioning of Narrow Lake, the overall improvements in recovery, led to higher reserve bookings.

Company-wide proved reserves of 2.2 billion barrels of oil equivalent represented an increase of 12% year-over-year. Another successful stratigraphic well drilling program contributed to a substantial increase of the economic bitumen best estimate contingent resources, up 17% to 9.6 billion barrels. This is a reflection of our top-tier asset base and our plans to drill between 350 and 450 strat wells every year to delineate our extensive inventories of oil sands leases.

We still have a significant portion of our oil sand leases that have yet to be drilled, and I believe there is a tremendous opportunity for us to continue to grow our reserves and contingent resources. We are proud of our achievements in 2012, and remain focused on continued improvement on our safety performance, maintaining our low-cost leadership, and efficiently executing all of our 2013 programs.

I will now pass the call on to Don Swystun to talk about refining business.

Don Swystun

Thank you, John, and good morning. 2012 marked another strong year for our refining business – in fact, as Brian mentioned, a record year.

Since completion of the core project in late 2011, Wood River has steadily increased its diet of discounted heavy crude feedstock, processing between 200,000 and 220,000 barrels per day of blended heavy oil through 2012. Wood River can access many different slates of discounted light, medium, and heavy oil from Canada and the Mid-Continent United States, due to its access to multiple crude delivery pipelines.

In 2012, production growth from the Permian Basin also resulted in price discounts per feedstock used at the Borger Refinery in Texas. Our ability to access and process discounted crudes provides a natural hedge against light/heavy differentials.

From a transportation perspective, we continue to take a portfolio approach to market access. Our ability to transport oil and make physical sales to coastal areas also provides a hedge against light/heavy differentials. We currently market over 40,000 barrels per day of oil that has tidewater access via pipeline, barge, and rail. This access has improved the opportunity to receive global pricing for our heavy oil.

In addition, we also have a multi-year supply deal with a large Mid-Continent refiner that locks in a fixed differential. Finally, an important component of our hedge program is our light/heavy differential hedges – details of which are disclosed within our financial statements.

We have 49,200 net barrels per day of light/heavy differentials locked in at West Texas Intermediate, less $20.74 per barrel, for 2013. These hedges are a key part of managing our heavy oil price exposure this year.

The combination of our top-tier refining assets, our pipeline access to coastal regions, our Mid-Continent supply arrangement, and our heavy differential hedge positions allow us to manage almost all of the price risk associated with congestion-related volatile light/heavy differentials this year. This integration gives us stability in our cash flow and added confidence to continue to execute on our oil growth strategy.

Ongoing pipeline congestion from Western Canada and industry-wide refinery downtime has led to steeper discounts for all types of crude oil, including bitumen prices. Our refining operations benefit from processing discounted heavy crude slates, but also benefit from the light oil differential between West Texas Intermediate and Brent prices.

For the first quarter of 2013, we are expecting $300 million to $400 million in operating cash flow from our refining business. This includes the impact of any maintenance activity for both Wood River and Borger.

I will now turn the call over to Ivor.

Ivor Ruste

Thanks, Don, and good morning, everyone. 2012 overall was a year of excellent financial results, which allowed us to exit the year with a solid financial position. Our balance sheet strength provides a foundation for our integrated oil growth strategy and supports our ability to increase our dividend, a key component of total shareholder return.

For the fourth quarter, Cenovus reported diluted cash flow per share of $0.92, slightly below the consensus estimate of $0.97 per share. Weaker than expected market cracks in December and our LIFO to FIFO inventory adjustment negatively impacted operating cash flow by about $50 million or $0.07 per share as compared to our fourth quarter guidance.

However, market cracks have rebounded in January and we expect that widening differentials throughout the fourth quarter of 2012 will benefit first quarter cash flows from both refineries, as crude purchased in December gets processed this year.

Our fourth quarter concluded another strong year from our refining and marketing business, which generated about $1.3 billion operating cash flow for the full year. Operating cash flow was $122 million for the quarter. Using the last in, first out accounting method employed by most U.S. refiners, Cenovus’ fourth quarter operating cash flow would have been $26 million higher or $148 million.

Now to our upstream business. Operating cash flow from Foster Creek and Christina Lake was $364 million in the fourth quarter, approximately 33% higher than the prior year. This operating cash flow increase was driven by higher production volumes from both areas, offset by realized prices that weakened 28% compared to the same period last year.

Operating cash flow from Pelican Lake and our other conventional oil assets was $338 million in the quarter, approximately 7% higher than the fourth quarter of 2011. Again, higher volumes more than offset weaker price realizations and contributed to the growth in operating cash flow.

Our natural gas business generated $134 million of operating cash flow in the fourth quarter compared with $188 million a year ago. This reflects reduced investment, natural declines, divestitures, and weaker natural gas prices.

Cenovus’ operating earnings per share during the fourth quarter of negative $0.25 per share were significantly lower than the consensus estimate of $0.40 per share, driven primarily by a one-time non-cash impairment charge of $393 million or $0.52 a share. The impairment charge related to goodwill recorded on the merger of Albert Energy Company and Canadian Energy Corporation in 2002 on our Suffield area gas assets of Southern Alberta.

The annual impairment test we conduct compares the net present value of the future cash flows using forecast prices against the carrying value of the assets. Lower forecast natural gas prices have resulted in lower future cash flow estimates for the Suffield assets, which reduced the recoverable value of the related goodwill below its carrying value. No other areas were impacted.

In addition to the goodwill impairment, which had no associated tax benefit, we incurred a one-time charge related to U.S. withholding tax of $68 million. This tax charge relates to an internal restructuring, which is designed to minimize our exposure to the higher U.S. corporate tax rates in the future. As a result of these two items, our effective tax rate for 2012 was an unusually high 44%.

General and administrative expenses for the year came in at $352 million compared with guidance of about $375 million. The main driver to lower fourth quarter G&A was the mark-to-market impact of share price changes on the long-term incentive expense.

Net earnings, which include unrealized mark-to-market and non-operating foreign exchange amounts, were negative $118 million, or a loss of $0.16 per share in the quarter. Net earnings largely reflect the non-cash adjustments that I noted earlier.

We ended 2012 with a strong balance sheet and good liquidity. Our debt to capitalization ratio of 32% and debt to adjusted EBITDA of 1.1 times remain at the low end of our targeted ranges of 30% to 40% and 1 to 2 times, respectively.

I will now turn the call back to Brian.

Brian Ferguson

Thanks, Ivor. Overall, 2012 was a very strong year from a production, reserves, cost, and financial perspective. As I look into 2013, I believe that we are off to a great start. Production volumes continue to grow, both on oil sands and conventional oil. We are on track to bring on our 10th phase of SAGD in the third quarter of this year.

Our refining business is on track for another great year. Our integrated oil growth strategy, which couples industry-leading oil sands development with top-tier Mid-Continent refineries, has translated into strong financial performance, despite challenging upstream market conditions. I believe Cenovus is well-positioned to continue to build net asset value in 2013.

Management and the Board of Directors have made a strong statement about the sustainability of our business model by approving a 10% increase in the dividend for the second year in a row.

With that, the Cenovus team is now ready to respond to your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Arjun Murti from Goldman Sachs. Your line is open.

Arjun Murti – Goldman Sachs

Thanks. Brian, you had some interesting comments in your release and you alluded to in your remarks about making sure you guys have a portfolio approach to market access. And obviously, there’s a lot of uncertainty on the timing of Keystone XL getting approved. Logic would tell you it should go forward, but obviously politics are playing a huge role here.

In the event that project continues to get delayed, can you talk in more detail about how you’re thinking about being able to access markets? You mentioned rail. It looks like a small component today. You mentioned going west. But realistically, how large could these options be to you?

And I think the real question I’m getting at is, you’ve had a very successful growth strategy, but I think there may be a growing concern that post-2015, could some of that growth strategy come under duress if Keystone XL doesn’t move forward in the absence of pursuing some of these other alternatives? Thank you.

Brian Ferguson

Thanks for the question, Arjun. I’ll start off on the answer and then turn over to Don Swystun to give a little more detail. We are in no way betting all of our eggs in one basket on Keystone XL. We do have a portfolio approach, as you mentioned, which includes rail, includes access, firm capacity on existing lines.

And our objective is that we will, over time, have a very high component in the range of 40% to 50% of our forecast production where we’ve got fixed transportation arrangements around them. And that would be through a combination of firm transportation capacity on pipelines as well as longer term arrangements on rail. So we are taking a portfolio approach. And I’ll turn over now to Don to give you a little more color on that.

Don Swystun

Hi, Arjun, as Brian highlighted, of course, that we’re moving currently – already we’re moving about 40,000, I’m just saying, of oil to tidewater and that access is via pipeline, so 11,500 on Trans Mountain, we move in the range of about 20,000 barrels a day on the Pegasus pipeline. We’re moving some volumes on barge, we’re also moving volumes on rail.

So that’s currently how we’re approaching some access to the market. Going forward with our overall strategy, though, we’re looking at obviously continuing on with the 11,500 off the west coast. And because we’ve done that, that has given us a lot of confidence in terms of developing markets there. So between both Northern Gateway and Trans Mountain, we’re looking at about 175,000 barrels a day that we’ve committed to on capacity on those lines. If we look for the Gulf Coast, we’ve had experience on Pegasus, so we’ve got a good understanding of marketing at Port Arthur.

So that we’re now looking at, in combination of dedicating volumes to Keystone XL and Enbridge Gulf Coast expansion, about 150,000 barrels a day is committed to those projects. Another project that’s coming is, of course, TCPL, an Energy East project. And we believe it is very important for the country, Canada, to move volumes to export off the east coast as well as to Quebec for refineries there.

So we will be having a significant participation when that line goes to open season also. As well, we did mention rail, and we’re working on expanding our rail options. We’re currently at about 6,000 targeting roughly in the range of 10,000. We feel that going forward we want to move some volumes, some blended bitumen volumes going forward.

So we’re looking at acquisition of, obviously, insulated coil cars, which is a strategy of many individuals. But I think that’s something we have to be looking at going forward and we’re diligently looking at all options to keep in our portfolio.

Arjun Murti – Goldman Sachs

Don, that’s a very helpful answer. Can you comment on what your actual XL exposure is in terms of those committed volumes that you gave for the other areas?

Don Swystun

I wouldn’t want to particularly comment on any one pipeline, but between the two, XL and Enbridge, it’s 150,000.

Arjun Murti – Goldman Sachs

Thank you. And on the projects to the west, is there risk that some of the expansions there also face some of the local issues of not getting approved because there are environmental concerns by some of the folks in Canada?

Don Swystun

Certainly aspects very important in terms of pipelines is safety, effective stakeholder engagement, working with both the governments and the First Nations. I mean, it’s something that we all have to do. And of course, it all relates back to our responsible development in the oil sands, particularly the environmental record that we can show that constant improvements in reducing our intensity on greenhouse gases. Those are all important in terms of promoting export capability for pipelines.

Brian Ferguson

Arjun, perhaps I can just add a closing comment here on this topic. Market access is an absolute top priority by the government here in Alberta, by the Federal Government in Ottawa, and most definitely by the oil industry here in Canada as well. There are a number of different avenues that are being pursued, both with regard to stakeholder relations, regard to government relations, and with regard to individual industry and corporate initiatives.

Right now, where we’re at as a country there is such a substantial lost opportunity here in terms of the foregone revenue that there’s a tremendous amount of economic ramp which is being left on the table and that is going to stimulate a lot of incremental projects and opportunities. I’m a big believer in the free market system. And there’s going to be a whole series of things that will occur on either existing pipe or incremental pipe expansions, rail that will address these issues.

From a Cenovus corporate perspective, I think we are in an ideal position. You mentioned the significant growth opportunity that we have. Well, that’s one of the things that gives us a high degree of confidence. We can literally see a line of sight to two decades of growth opportunities on existing assets. So that’s one of the things that gives us the confidence to make firm transportation commitments on these variety of pipelines going east, west, and south, as well as rail. And also, as Ivor mentioned, our balance sheet is in great shape, so we have the financial capacity to also be anchor shipper on many of these new projects and on existing systems.

Arjun Murti – Goldman Sachs

Brian, I appreciate that. This is just my final comment on this. I mean, I think we certainly agree with all of your long-term comments and they make quite a bit of sense. It’s just sort of that window of, I guess, Foster Creek H and J and maybe Christina Lake F, G, and H, if I have my letters correct, those kind of 2015, 2016, 2017 start ups, do we have some volatility if some of those projects just take longer to come on? But I appreciate all your comments and points and thank you so much for your answer.

Brian Ferguson

You’re welcome, Arjun, and I guess I’d be remiss if I didn’t just remind you of our integrated oil strategy, too. So that if we do see congestion in that period of time in terms of Cenovus’ overall corporate performance, we’ve got two ideally positioned refineries in the Mid-Continent region that would generate substantial cash flow to offset any economic impact on the upstream component of the business.

Arjun Murti – Goldman Sachs

That’s great. Thank you so much.

Operator

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

Greg Pardy – RBC Capital Markets

Quick ones. John, you mentioned just Pelican Lake exit rates in terms of percentage year-over-year, but I’m wondering if you could just give us the barrel per day number? And second question is just around asset sales, assuming here that formal processes are underway or they will be shortly, I’m just wondering what the timing could look like in terms of the dispositions on the Bakken and the Shaunavon? Thanks very much.

Brian Ferguson

Greg, let me – it’s Brian. Let me respond to the question with regard to the disposition process on lower Shaunavon and our operated position in the Bakken. You’re right, we expect to have a data room open very soon and it would be a process that we are targeting to complete by year end. And then over to John with regard to Pelican.

Greg Pardy – RBC Capital Markets

Okay. Thanks, Brian.

John Brannan

Thank you, Greg, for the question. Q4 2012, we exited at 23,507. Today we’re running around 24,000 barrels a day and we plan on exiting somewhere around 28,000 to 30,000 barrels a day at Pelican Lake.

Greg Pardy – RBC Capital Markets

Okay. And John, maybe just a little bit of color. I mean, we’ve already been through, I guess, some of the pressure drawdowns you were seeing with the earlier program. Do you think most of those issues are now behind you? I mean, I’ve heard other participants in that flood are actually seeing pretty good responsiveness coming. Are you seeing the same thing?

John Brannan

Yeah. So at Pelican Lake we’ve done a number of pilots to even down to 25-meter spacing between our injectors and our producers. Typically most of the patterns that we’re doing is about a 67-meter spacing and on the infill program we’ve actually had as good or as expected or a little bit better performance to our tight curves for those injector producer pairs.

And on the base, because when we were drilling that infill we dropped the pressure of the reservoir, we did see a little lesser reaction on the base, but now that some of those areas where we drilled and brought those injector producers in the infill program up to line, the infill is performing well and base has started to come back. So we’re comfortable with our numbers on the way forward.

Greg Pardy – RBC Capital Markets

Okay. Very good. Thanks very much.

Brian Ferguson

And Greg, just – we continue to forecast and expect that we will reach a total production level there of about 55,000 barrels a day at Pelican Lake.

Greg Pardy – RBC Capital Markets

Okay. And that’s by 2015, Brian?

Brian Ferguson

2016, 2017. Depends really – depends on how many rigs we choose to run. We’re in complete control of that pace so we’ll look at that from an overall corporate portfolio. But it really just depends on whether we choose to run three, four, five, six rigs.

Greg Pardy – RBC Capital Markets

Okay. Thanks again.

Operator

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

Dave McColl – Morningstar

Good morning, guys. Sorry if it’s a rough connection coming through on your end. I’m just wondering if you can provide some insight into your heavy oil hedging strategy, specifically as it relates to the downstream capacity and marking capabilities. I assume part of this ties to the agreement that you mentioned earlier with another refinery, but what I’m really trying to understand is kind of the net benefit of locking in upstream prices when you look at your integrated business model and whether this just ties back to the upstream mix relative to the downstream configuration? Thank you.

Brian Ferguson

Just as an overall comment with regard to that. Entering into a fixed differential over a fixed term with this refiner has locked in a much narrower differential on those volumes. And we haven’t given specific details on the differential or the volume and won’t because of competitive reasons, but it is a very meaningful number.

So what that does is that locks in the returns on the upstream side, which really compliments the downstream because that really is a – in essence an economic or a financial hedge that locks in that return. Our downstream is a separate profit center and it benefits from being able to purchase low cost feedstock in the market place and is really benefiting from that. So the two of them work very nicely together; they’re not in any way competing. They’re really complementary strategies.

Dave McColl – Morningstar

All right. Thank you.

Operator

(Operator Instructions) And your next question comes from the line of George Toriola from UBS. Your line is open.

George Toriola – UBS

Thanks, and good morning, guys. Just, I’ll ask the first question in a bit of a different manner here. Brian, if – at what level of, sort of, differentials as a percentage of WTI, would you slow down your investment? If you look into the future, you’re obviously getting more long bitumen. What differentials would cause you to rethink, sort of, the pace of growth that you already have or at what differentials would the projects, as you currently see them, be less economic and force a bit of a pause for you?

Brian Ferguson

Thanks for the question, George. So one of the things to remind you of with regard to Foster Creek, Christina Lake, and Narrows Lake is the supply cost that we have. So supply cost for those projects is – what we do is we define that to be the long term average WTI price. And obviously, we work through differentials and those sorts of things that would generate a minimum 9% after tax rate of return over the life of those projects.

So at Foster Creek, that’s equivalent of a $32 WTI. At Christina Lake, it’s between $40 and $45 WTI. And at Narrows Lake, that’s in the $50 to $55 WTI range. When we look at those projects, so they’ve got very, very strong economics to them.

And then I’d back up and take a look at our overall corporate capacity. So if we do see wide differentials for some period of time, we obviously benefit very substantially on the downstream side. So what we in fact would be able to do, because of the very low cost nature of those projects – and we’re running, we believe, sustainably in that $12 per barrel cash operating costs or lower – generally speaking, on those projects, that gives us the ability to actually power through some of these troughs and continue to move forward with the projects.

A great example of that, I’d go back to 2009, when we were bringing on Christina Lake C and doing that work, we were able to take significant advantage of cost savings and cost reductions. And that allowed us to bring that project in under budget.

One of the things that I hope was notable in John Brannan’s comments today is that he said, very clearly, that our capital – the expansions that are underway right now at Christina Lake to bring on E and at Foster Creek to bring on F, are in fact on schedule and on track for capital as well.

So we’ve got tremendous capital efficiencies which, I think, will really allow us to take advantage of what we’re seeing currently, both corporately because of the integration but also because of the low cost structure. So we’re not anticipating, at this point, having to make adjustments there. We do have a lot of flexibility that’s built into our overall portfolio. Our committed capital as we go forward very quickly drops down to about $1 billion a year. So we’ve got a lot of flexibility in the portfolio and choosing the timing on phases.

We could, if we wanted to choose to go another one or two quarters slower if we thought that we were in some kind of sustained period of wider differentials, but we’d have to have a look at that overall corporately and how that worked out on integrated basis, so that we looked at the integrated margins that were generated.

George Toriola – UBS

Thank you very much.

Operator

And your next question comes from the line of Matt Portillo from Tudor Pickering Holt. Your line is open.

Matt Portillo – Tudor Pickering Holt

Good morning, guys. Just a quick question from me, we’ve started to notice some trends of lighter crude products starting to trade at a discount, both in the U.S. and potentially longer term in Canada. And I was curious if you’re working internally on any projects to capture some of the additional margin via gathering on inputs like diluent and condensate?

Brian Ferguson

I’ll ask Don to respond to that question.

Don Swystun

Can you clarify your question a little more? You’re looking at particularly – are you looking in like the Chicago market in terms of the products or you’re looking in Canada more so?

Matt Portillo – Tudor Pickering Holt

Just in terms of accessing potential condensate via rail and moving it into Canada, I was curious if that’s something that’s of interest for you guys and potentially capturing some of the margin on pricing cheaper diluent access out of the U.S.?

Don Swystun

Yeah, I can go through a bit about our overall diluent strategy in terms of how we access it. I mean, currently half our diluent supply is contracted on various terms and price indices. I mean, the remaining stuff we get on spot transactions. So in the short term, we have a large component of that basically does come from domestic sources, kind of around Edmonton and it’s railed in product, typically.

With growth going forward, I guess for condensate in the industry we’re looking at, estimating up to 40% of our supply could be sourced from the U.S. Gulf Coast and from a lot of the emerging shale plays and probably railing in a lot from Chicago. Same thing as we go forward, I think as some of the shale basins expand, we expect to see more and more NGLs available and a lot of that will be railed or pipelined in on, say Southern Lights or the Cochin pipeline, as diluent supply into Canada or particularly into Edmonton. And that’s where we will be looking to optimize the purchase price of that diluent.

Matt Portillo – Tudor Pickering Holt

Great. Thank you very much.

Operator

Your next question comes from the line of Kate Minyard from JPMorgan. Your line is open.

Kate Minyard – JPMorgan

Thanks. Good morning, gentlemen. Just a quick question on the supply deal with the Mid-Continent refiner, I can appreciate that you would care not go into great detail about it, but I’m curious on a couple of points. Can you talk about whether that’s the Christina dil-bit blend or whether it’s a different heavy blend?

Brian Ferguson

Thanks for the question, Kate. Because this is quite a competitive marketplace, as you can well imagine, I think the only thing that I’ll say in addition to what we’ve already said is that it’s for a five-year term, but I would not want to get into anything more specific than that.

Kate Minyard – JPMorgan

Okay. That’s just fine. And then can I just ask whether it might be possible that we would see additional – do you have an appetite do additional such deals or is this something that we would consider more of a one-off and that your portfolio approach to market access is a little more geared around actually moving your barrels as opposed to locking in an agreement with a refiner?

Brian Ferguson

I would say that we will continue to pursue this sort of arrangement in addition to the portfolio; we consider it as one of the opportunities that we have. Having said that, given where differentials are right now, it would be very difficult to replicate that. This was an arrangement we entered into last summer when differentials were at the more typical level.

Kate Minyard – JPMorgan

Okay. All right. Thank you very much. I appreciate it.

Operator

(Operator Instructions) And your next question comes from the line of Jeff Jones from Reuters. Your line is now open.

Jeff Jones – Reuters

Thanks. I just have one point of clarification, if that’s all right. With regard to your hedge on 49,200 barrels a day, for that $20.74, I mean, is it fair to say that that is the WCS differential that you’ve locked in? Is that the proper benchmark?

Brian Ferguson

Yes, that’s correct, Jeff.

Jeff Jones – Reuters

Okay. Thank you.

Operator

And there are no further questions in queue.

Brian Ferguson

Thank you for joining us today. That concludes our year-end conference call.

Operator

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

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