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Cenovus Energy, Inc. (NYSE:CVE)

2013 Investor Day

June 18, 2013 11:00 am ET

Executives

Sheila M. McIntosh - Executive Vice-President of Environment & Corporate Affairs

Brian C. 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

Jim Campbell

Donald T. Swystun - Executive Vice President of Refining, Marketing, Transportation and Development

Paul Reimer

Stephen Brink

Darren Curran

Harbir S. Chhina - Executive Vice-President of Oil Sands

Al Reid

Ian Young

Dave Goldie

Analysts

Paul Y. Cheng - Barclays Capital, Research Division

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

Fai Lee - Odlum Brown Limited, Research Division

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

Peter K. Ogden - National Bank Financial, Inc., Research Division

Christopher Feltin - Macquarie Research

Kyle Preston - National Bank Financial, Inc., Research Division

Michael P. Dunn - FirstEnergy Capital Corp., Research Division

Peter K. Ogden - BofA Merrill Lynch, Research Division

Andrew Stein

Dean Highmoor

David McColl - Morningstar Inc., Research Division

Robert Bedin - ITG Investment Research ULC.

Sheila M. McIntosh

Well, good morning, everyone, and welcome to Cenovus' 2013 Investor Day. I'm Sheila McIntosh, Executive Vice President, Environment and Corporate Affairs. We are pleased that you're able to join us here today, whether in person or via the webcast. I hope that those of you that are joining us in person were able to enjoy a few of the views here from the BOE this morning, although it's a little overcast right now. But as you know, in Calgary, you can just wait a few minutes, and it will change.

All of the executive team members are with us here today, and so most of them will be speaking. But I'm going to ask them all to give you a little wave right now so that you can identify them. As well, we have a number of our VPs and Senior VPs here as well, so I'm going to ask them to give you a little wave, too. I realized that might be -- and turn around and wave, perhaps.

So as you've seen from your schedule, we have a number of Q&A sessions this morning. So I would just ask you to try to focus the questions on the Q&A's -- that's right. Focus your questions on the Q&A session that seems to be most applicable.

And now, just a couple of housekeeping items. In the unlikely event of an emergency, members of the Events team and security are on the floor and will be here to direct you to the safest evacuation point. And as those of you that have been following some of the local news, you'll see that we have the opportunity to practice that evacuation last week.

There are 4 stairwell exits on this floor, one located at each tip and 2 in the center lobby areas through the elevator area. Washrooms are located near the elevator lobby. As well, if you're able to join us for lunch, it's in the Mountain View room at the opposite tip.

Now onto some of the advisories. As we'll be talking about future projections and guidance today, please refer to this advisory on forward-looking information. The future assumptions are based on the same price deck assumptions published in our guidance document. And as some of our discussion will be around our oil and gas resource base, the Oil and Gas section of the advisory contains definitions of the terms used and references on where to find additional information. Lastly, we used some non-GAAP financial measures, and this is where you can find the definitions of those measures, as well as the abbreviations we use.

So what are you going to hear today? Lots of affirmation that we are continuing to deliver on our long-term plan, that we are well-positioned to deliver value to our shareholders and our other stakeholders. We'll be providing some updates, obviously, through the day in a number of areas, and let me just highlight a few of those for you right now.

Through execution of our plan, we expect to grow our oil production at a CAGR of 11% between 2013 and 2023. With the addition of some optimization work, we're happy to report that we expect to be able to add 22,000 barrels per day of gross capacity at Christina Lake, phases C, D and E. To support growing production, we're developing a portfolio of transportation options and are targeting to move up to 50% of our marketable production by pipeline and rail through firm commitments. And to be clear, marketable production includes blended bitumen and conventional crudes. Also, we plan to start railing bitumen, with coiled and insulated cars in 2014 and expect to exit the year with 30,000 barrels per day of rail capacity.

So we have a lots to cover during the day. And so I think we'll get started with that right now. I'm pleased to hand the podium over to Brian Ferguson, our President and CEO.

Brian C. Ferguson

Good morning, everyone. I'd like to welcome you to our new home at the BOE. I understand made in some of you may have already been here. You probably know our landlord, which is Encana. It's been about 1.5 years since our very first Investor Day, and the last one that we had was December of 2011. So we thought it was a pretty important time for us to update everyone here in terms of our plans. The key messages that we will expand on today are, that our strategy is consistent and that it continues to deliver. We continue to build on our track record as a top SAGD operator, bringing on a new phase each year, while maintaining strong production levels from our existing operations.

We are a leader in innovation through technology, and our manufacturing approach provides us with a competitive advantage. Market access is the most topical issue for industry today. Today, we will detail our pipeline and rail strategy for you through this market access and integration. We are participating in the full value chain to expand our margins.

Finally, our financial strength will support our business plan for decades to come. We remain focused on total shareholder return, and that's obviously growing net asset value and our commitment to dividend growth.

As you know, oil sands is the core of our oil growth strategy. With a growing investment opportunity set for you, investors in the energy sector, I think that it's important to remember some of the key differentiators of SAGD oil sands production.

Oil Sands has almost no exploration risk as compared to conventional oil and gas. Finding the development costs and recycle ratios in the oil sands are more competitive than most other components of the oil and gas business. We will show you today that our supply costs are very competitive on a global basis.

The scale of the oil sands is a key advantage. As illustrated here for you, we have significant opportunity to develop our extensive asset base, with lots of running room on the resource. Unlike some of the newer, lighter, tighter oil plays that face very steep initial declines, SAGD production has much lower declines, with stable production literally for decades. We've been operating in SAGD for 15 years now. We believe SAGD technology is still largely in its infancy. We believe there are significant gains that will be made through innovation in technology.

This next slide illustrates the consistency of our strategy and our operating performance. It's -- it highlights our current long-range plan compared to the one that we showed you 2 years ago. You can see it's not very different. It hasn't changed very much in terms of our growth plans. This highlights the predictable, reliable, low-risk oil growth that I believe we offer to investors. We continue to execute our plan and expect oil to grow at a compound annual rate of about 11% from now through 2023. One of the points that I really want to stress for you today is, our growth rate is an outcome. It is not a target. It's an outcome of our ability to execute. We will not target a growth rate.

Cash flow per share growth has been also the outcome of our ability to grow production over the last 3 years and it has also benefited from our integrated oil strategy. Over this time period, we estimate a 13% compound annual growth rate in cash flow per share that's based on us achieving midpoint of our 2013 guidance. Achieving the milestones that we have set out each year will help drive cash flow per share growth for our investors.

As you can see, it's been a busy year so far, with some significant plans ahead of us for the second half of the year. We remain on-track for the second-half milestones, including first production from Christina Lake phase E in the third quarter. This will be the 10th SAGD commercial phase that we will have brought on-stream. We expect similar performance at Christina Lake, E as what we have experienced and achieved on the last 2 phases at Christina Lake. The construction of Narrows Lake facility, which is our third SAGD project, will also commence in the third quarter of this year.

Dividends are an important part of total shareholder return for Cenovus. Paying a dividend requires financial health and predictable cash flow, both of which, I believe, we have demonstrate. It also requires capital discipline within the company, making sure that the capital that we are employing is allocated to high return and significant asset investment opportunities. Our production growth and cash flow stability through integration have allowed us to increase our dividend by 10% twice, first in 2012 and again this year. Based on our long-range plan, we expect to have the capacity to continue to grow that dividend into the future.

We are able to sustain and grow our dividend because we have substantial free cash flow coming from our Conventional oil business and our refining assets. We use net asset value as a diagnostic tool to make sure that we are getting the best value for our investment dollar. Investment decisions are made based on standard discounted cash flow metrics that you're all familiar with, IRR, NPV, supply costs, payback periods. There's also some really important criteria that we pay a lot of attention to, additional factors that include the materiality of what we're doing, the timeline and importantly, the risk profile.

Our announced divestiture last week of some of our conventional assets is a good example, I believe, of our capital discipline. We will take those proceeds and redeploy those proceeds back into resources that have better returns and more running room.

Our reallocation of capital from natural gas to conventional oil over the last 3 years is, I believe, another example of how we are allocating capital to focus on net asset value growth. The core of our growth is being driven by SAGD projects that have got very attractive project returns, that would be in the 20% to 25% range, and some of them, higher than that. And importantly, they have huge net present value. I believe that we remain on track for our near-term target, which we talked about in 2010, which was to double our net asset value by the end of 2015.

You will likely be familiar with an earlier version of this slide. It highlights asset quality, as defined by steam to oil ratio, or SOR. Foster Creek and Christina Lake continue to demonstrate outstanding performance with some of the lowest cumulative SORs in our industry. We have also highlighted our expected SOR for our next projects at Narrows Lake, Telephone Lake and Grand Rapids. I believe that these projects will demonstrate that they are some of the best in the industry. And we believe our competitive advantages will allow us to maintain a low-cost structure. John Brannan is going to provide a full operational overview of these projects for you and as well as our conventional oil -- our Conventional business in the refineries in just a few moments.

We have a culture of innovation at Cenovus. Harbir Chhina is going to talk about some of the new technologies and pilot programs that we are working on. Many of the technologies that we're working on are aimed at reducing steam and energy requirements, technological advances that are also going to reduce our environmental footprint.

Where we've really created a competitive advantage, I believe, is on the manufacturing side. Our phased approach to expansion, combined with in-house construction management and our own module yard have helped us achieve some of the lowest capital efficiencies in the industry. Having a deep portfolio of projects with large scale is a key to maintaining this competitive advantage for Cenovus.

Market access remains an obvious priority, and we have and are proactively looking at ways to deliver our product to market while increasing our margin.

We've made firm commitments to multiple pipeline projects so that we are not dependent on any one single project moving forward.

We are adding additional rail capacity. We believe rail will be a part of our long-term transportation strategy. We also increased our margin through our 50% ownership of 2 new refineries in the United States. This reduces the casual volatility for our cash flow stream during periods of market constraints, such as we are experiencing today. Debottlenecking opportunities may provide further integration at the Wood River refinery, although on a somewhat smaller scale.

Over the longer term, we are planning to move up to 50% of our marketable blended volumes on firm service transportation. Pipelines remain the safest and most economical mode of transportation, and we remain positive that takeaway capacity out of the Western Canadian Sedimentary Basin will improve over the coming years with the new projects. I believe that it will be important to have the optionality to move up to 10% of our production by rail. Rail provides a lot of flexibility for us. Don Swystun is going to discuss our market access and integration strategy in more detail for you.

The Chief Financial Officer, Ivor Ruste, is going to discuss our financial strategy and how it supports our business plan. Maintaining financial resilience is critical to succeeding in a volatile business climate. Our balance sheet strength is one component of our financial strategy that allows us to execute on our plan.

Having ample liquidity and flexibility are also key. Based on our forecast, we anticipate that we will be at the low end of our managed ranges on debt-to-capital and net debt-to-EBITDA, or below them for the next decade. I'd like to summarize for you why I am excited about CVE and our future.

Our strategy is sound, I believe, and continues to deliver. We continue to build on our track record as a top SAGD operator. We're bringing on our 10th phase of SAGD this year. We are a leader in innovation through technology, and our manufacturing approach provides us with a competitive advantage. We're expanding our margin through market access and integration. Our financial strength supports our business plan.

The slide that I've got up here now, I first showed you in June 2010 at our very first Investor Day. Our strategy continues to be very consistent over the last 3 years. Our value pledge remains unchanged. We look to continue to deliver on our commitments. We are on-track to grow net asset value, and I am confident that we can sustain decades of growth through our manufacturing model, where we manufacture oil growth.

Thank you, and I'm now going to ask Ivor Ruste to come up to the podium.

Ivor Melvin Ruste

Thanks, Brian, and good morning, everyone. Brian has just provided as succinct summary of our strategy, with the key message that our strategy is consistent and continues to deliver results.

Our financial plan also remains unchanged and is geared toward supporting Cenovus' business strategy. Today, I'll highlight how these 5 areas of our financial strategy support our business plan. First, the flexibility in our capital programs allows us to adapt to different economic conditions; Secondly, we have the ability to fund our oil growth through strong corporate cash flows; Next, I will illustrate how our established financial resiliency will allow us to succeed through all phases of the economic cycle; Risk management is indeed critical to our business, and we manage it through a balanced approach; Lastly, we'll talk about our dividend growth strategy and our focus on total shareholder return.

This slide is illustrative of our capital allocation priorities and highlights how a good portion of our capital spending is discretionary. This discretionary capital is where we maintain the flexibility in our program. Our first allocation in capital is towards committed capital. This includes producing projects, such as Foster Creek and Christina Lake, phases A to E. And It also includes capital related to projects that have been sanctioned and are under development, like Christina Lake phase F, Foster Creek phase F, G and H, and in Narrows Lake.

Next, we prioritize the commitment to our dividend. We'll talk more about our dividend growth strategy shortly, but we believe, as Brian mentioned, paying a dividend ensures good capital discipline across the organization.

And finally, the remaining capital available is allocated to discretionary projects. This includes emerging oil sands capital, such as Telephone Lake and Grand Rapids, but also includes a significant portion of our conventional program.

Adjusting capital on the conventional programs is much easier to do than starting and stopping on the oil sands side. As a result, this flexibility allows us to adjust our CapEx in order to keep our oil sands development on-track in almost any economic environment. The flexibility of our capital programs allows us to focus investment on the highest return and the most strategic assets to grow our net asset value and generate shareholder return.

While we're talking about capital allocation, I want to refresh your memory on how we think about project returns. This slide was in our first Investor Day package back in 2010. You've heard us talk about supply costs before, but these other metrics also determine how we allocate capital. And none of these criteria are considered in isolation.

In our case, we calculate supply costs based on the WTI prices that allows us to return our capital and generate a 9% return after tax. We target a minimum of 15% internal rate of return for all our projects. Not surprising, our industry-leading SAGD projects are among our most profitable, with IRRs well beyond 20%.

Net present value is another key indicator. It closely relates to net asset value, the most important marker for measuring value creation. We would look at that calculation with a discount factor above our weighted average cost of capital. Payback period is another factor that we consider, although obviously, it has more relevance to our Conventional business.

There is also a very important strategic element to allocating capital. Investing in projects that can materially contribute to net asset value growth is key instead of investing in isolation on the highest internal rate of return projects. Our strong corporate cash flows illustrate our ability to fund our capital program over the next few years. You can see from the last 3 years that we've demonstrated this philosophy, with cash flows in excess of our capital spending. Over the long-term, we will have significant free cash flow that we expect to redeploy into further growth opportunities at strong rates of return. This is the predictable, reliable growth that will drive increases in our oil production.

Please note that this chart excludes divestitures. We will continue to consider divestitures of certain non-core assets as part of our ongoing disciplined portfolio management program. And again, as Brian referenced, the shun of an asset sale just announced is an example of this.

Understanding the composition of our operating cash flows allows you to see how we will be able to essentially self-fund our oil-focused capital spending program. We've been talking about our increasing oil focus for the past 3 years, and this chart highlights the shift in our operating cash flow towards oil and refining over that period.

Going forward, we will continue to grow oil production by investing in high-quality oil resources and maintain operating and capital cost discipline by focusing on projects with strong returns and material net present value while continuing to manage our conventional natural gas and oil as financial assets.

It's important to remember what currently drives these strong cash flows. Over the last 2 years, with wider differentials, a significant amount of cash flow has been generated from our U.S. refining assets, and Don is going to tell you more about that soon. However, when you look at upstream operating cash flows, you'll notice a significant amount still comes from the conventional side. John will talk more about the free cash flows from our conventional program in his presentation.

As we continue to bring in a new SAGD phase every year, our cash flows become more weighted towards our Oil Sands segment, which is long life, high-margin growth. In the meantime, the Conventional business, both oil and gas, remain critical to Cenovus' strategy.

We are focused on building financial resiliency for all phases of the economic cycle, and Cenovus has a capital structure with considerable capacity and flexibility. The key element of that includes having significant liquidity, including a current cash balance of approximately $1 billion and a fully undrawn $3 billion credit -- committed credit facility with a maturity of November 2016.

In addition to this, we currently have $4.75 billion in U.S. notes with an average maturity of over 15 years, which is a -- provides a good match with our asset base life. We continue to target investment-grade credit ratings on our debt to ensure we have capacity to access incremental capital as required.

We believe our targeted debt metrics, which range from 30% to 40% debt-to-capitalization, and 1 to 2x debt-to-adjusted EBITDA, reflect prudent financial targets. These metrics help us to steward our future capital plans in order to maintain the financial strength to grow our business.

Looking forward, you can see here that we have further flexibility in our balance sheet, as our debt metrics are at or below the low end of the target ranges throughout the forecast period. This flexibility allows us the opportunity to source additional funds in periods of volatile commodity prices and execute our desired level of capital while maintaining a balance sheet strength and a strong liquidity profile.

In addition, we believe there is good capital discipline in continuously high-grading our portfolio. As such, we continue to target the monetization of some of our non-core, lower-return assets. Managing risks is a key aspect of our financial strength, and we take an active role in managing risks. Operationally, this refers to the integration with our downstream assets. The flexibility and capital plans allow us to scale programs, up or down, with performance and the overall macro environment.

Don will talk more about the portfolio of transportation solutions, but having firm service commitments on a multiple pipeline -- in multiple pipelines, pardon me, and optionality on rail reduces our exposure to any one line of transport.

Financial risk management includes our hedge program, which is focused on protecting cash flows. Our natural gas is also a financial asset that generates significant free cash flow, but will also protect us from rising energy requirements in our SAGD development and refining operations.

And environmental performance is also critical to managing the risk factors of our business. As Harbir will tell you, significant investment in technology and research is often aimed at reducing our steam to oil ratio, as well as improving our environmental track record. Together, these risk mitigation strategies help support our business plan.

Cenovus is committed to our dividend and expects to be able to grow that dividend over time. We have demonstrated what's needed to grow the dividend, including strong financial health and resiliency, a manufacturing approach to sustainable development, which results in significant annual production growth; reliable, predictable cash flow through integration; and good capital discipline.

In the first quarter of 2013 and 2012, we grew our dividend by 10% compared with the previous year, and thus, have been in-line with our overall oil production growth. We continue to feel that dividends remain a critical component of total shareholder return.

In closing, I'd like to reiterate that our financial strategy continues to support our business plan, and that plan remains consistent over the last 3 years. The discretionary capital in our budget gives us the flexibility to adjust our spending as appropriate. Strong, internally generated cash flows from oil sands, Conventional and downstream ensure our ability to fund the growth in our long-range plan.

We do not have the funding risk that some peers might have in weaker markets. We continue to maintain our financial resiliency through a strong balance sheet, with further debt capacity and at very competitive rates. Our risk management program addresses the operational, financial and environmental concerns, evident in the business we are in. And lastly, we remain committed to a dividend and expect to have the capacity to grow that dividend over time.

And with that, I'll turn it over to John Brannan, who will provide the operational review. John?

John K. Brannan

Well, thank you, Ivor, and good morning, everyone. Quarter after quarter, year after year, we have overall demonstrated our delivery -- our ability to deliver industry-leading performance. At Cenovus, we have a tremendous asset base, and I believe we have done a super job in developing that asset base over the past few years. Clearly, we've demonstrated the value of those assets and the value of our integrated oil sands growth strategy.

Assets like Foster Creek and Christina Lake are clearly benchmark assets when compared to other industry projects. We have successfully delivered 9 phases at Foster Creek and Christina Lake, on-time, on-budget, delivering the production that we said they would deliver, with industry-leading steam to oil ratios and low operating costs.

We currently have another 6 phases on-the-go at Foster Creek and Christina Lake, and they're currently under construction or certainly, have been approved, but under construction. And we are also working very hard to get regulatory projects approved -- a regulatory approval on additional emerging projects in our assets.

My talk today includes 4 key elements that in my position, in my opinion, are the critical components of Cenovus' success. The first and most important to me and to everybody in the leadership team is our overall commitment to being a safe and responsible operator. Our business is about consistency and reliability. We are delivering on our commitments to our stakeholders, and we've done that year after year. I'll have a few slides in my presentation that demonstrate that.

Third, we have an outstanding cost structure. Harbir will build on a few of my slides in his presentation, but we are striving to drive down capital and operating costs everyday. Finally, I want to reiterate how important our Conventional assets are to providing and generating free cash flow that we are then reinvesting in the development and growth of our oil sands assets. Many say we are just getting started in this business. And when you look at the long life of our assets, that's probably true. But I think we've done a great job, and we have demonstrated a super track record to this point.

So I said, first and foremost, that safety is a priority at Cenovus. And if you read the first commitment, I know it's a pretty small slide up there, but I'll read it for you. Our work is never so urgent or important that we cannot take the time to figure out a way to do it safely. This poster is well-displayed in many of our offices here in the BOE, but it's also displayed in every single field site and signed off by the executive here, but it's signed off by the leadership and the workers and the contractors at our sites. We worked very hard earlier this year in our safe start programs that re-emphasize our commitment to safety and again, get everybody, new workers especially, to sign off on those commitments.

So you can clearly see safety is a part of our culture, but we also consider ourselves a responsible operator. For Cenovus, what is good for the environment is good for our business. We're working hard everyday through technology and operations to drive down steam to oil ratios. Just driving those steam to oil ratios drives down our emission levels, our water usage, our animal habitat impact and our overall land footprint.

For those of you that have been to one of our oil sands facilities, seeing really is believing. When you look at our assets, we are entirely an in situ producer. We have no tailings bonds, no mines, no big trucks and no big megaprojects that have big cost overruns. We're proud of our track record of development of the oil sands, and we believe that communicating our story is the best way to make all Canadians proud of the way we're developing Alberta's assets. We are also named, to the Dow Jones Sustainability World Index last year, the only Canadian energy company to do so. This external recognition demonstrates that we are striking the right balance for our oil sands development.

Many of you will be familiar with our 10-year plan for oil sands development. We first rolled out this chart in 2010, and as you can see, our actual production is ahead of where we originally planned due to great reservoir performance and great execution by our teams. This development plan translates into a predictable, reliable growth profile. We're bringing on new "40,000 to 50,000 barrel a day" projects every 12 to 18 months. That's what we call, manufacturing oil.

And this chart shows that we've exceeded that commitments that we had originally made for ourselves. Since 2010, we have accelerated schedules and advanced production faster than we originally planned at both Foster Creek and Christina Lake. This speaks to the commitment and hard work of our teams, but also the value of technology to the development of our assets and the quality of our assets.

If you followed our production and project schedules, we had a chart with all the projects and those things, we had a placeholder in there, undefined future optimization at Christina Lake of about 12,000 barrels a day. Well, now we've defined it. We filed an application for 22,000 barrels a day, and we think that we could get that together and online by 2015.

In addition, this year, we're raising the bar on our own track record and performance. We've got ongoing projects today at Foster Creek and Christina Lake, and we're also kicking off a third project, so we'll have a third construction management team at Narrows Lake. We'll be running those 3 projects simultaneously.

At Christina Lake, we have delivered ramp-ups at phases C and D that have gone faster than anybody has seen in industry in the past. We've gone from first oil to full production in about 6 months. That used to take us over a year.

The quick start was a result of getting into the better parts of the reservoir, so we'll give part of the credit to the reservoir, but it's also combining new startup techniques, through our technology that we have employed, that help us accelerate that cash flow and improve that overall net present value of those assets.

We now expect to reach facility capacity for future phases at Foster Creek and Christina Lake in 6 to 9 months, well ahead of industry averages. That's just one example of the innovation that we have implied or the innovation, through technology, that we've applied to our assets. We're on-track to bring on our next phase at Christina Lake, phase E, this summer.

So most are you familiar with this slide already. We always talk about steam to oil ratio. It highlights the asset quality, generally, always shown up in steam to oil ratios. Foster Creek and Christina Lake continue to demonstrate outstanding performance with some of the lowest steam to oil ratios in SAGD business.

We have also highlighted our expected steam to oil ratio ratios for our next projects, Narrows Lake, Telephone Lake and Grand Rapids. We believe that these projects will compete as some of the best projects in the industry. I'll also talk more about supply costs later and how projects already in operation have advantage over new projects, and scale also helps for that.

So as I said, another important aspect of SAGD, the economies of scale. A large portion of fixed cost in SAGD relate to what we call indirects, their roads, camps, power lines, power assets and pipelines, among other things. All of those are required to develop a centralized SAGD asset. Having a large concentrated resource base helps create sets of scale to average the cost of that infrastructure over more barrels. A general rule of thumb is that 1 billion barrels of recoverable resource will support 100,000-barrel a day project for about 30 years. As you can see from the chart, we have some of the largest SAGD design capacities and assets in the industry. Being able to share our fixed cost across a large resource base improves overall project economics.

Having great reservoirs is the single biggest driver to top quartile performance. A good reservoir with thick continuous sands, good horizontal and vertical continuity, and a large amount of oil in place are the key drivers to low steam to oil ratios.

This geology also dictates the size of a SAGD facility required to develop those resources. What makes Cenovus unique is a combination of great reservoirs and a great execution strategy for manufacturing our oil sands development in phases. This combination has helped us deliver leading industry capital efficiencies. We continue to look at ways to further improve our performance through modularization, standardization, innovation and in-house experience.

From an operating cost perspective, Cenovus is among the top tier in the peer group. And I'd just like to caution you to compare apples-to-apples when you're comparing operating cost. Improving our cost structure includes a large emphasis on reduced chemical usage, drilling improvements and workforce planning initiatives. It also means working smarter. For example, we are analyzing the optimal frequency of when to do scheduled repairs, maintenance and workovers. We're not waiting for things to fail, we're trying to be proactive to fail -- to repair them before they do fail.

Finally, our operating cost reflect the full cost of producing a barrel of oil, not just field-based cost. It includes a corporate allocation for our shared services organization, which manages all the critical in-house services related to drilling, completions, camps, purchasing, regulatory, technical services and there are others. We believe the centralization of our shared services will help us lower both our operating costs and our capital cost.

We have shown you our low SAGD cost structure. Now I want to outline how we measure up on a global basis. Probably the biggest misconception about oil sands, in particular SAGD development, is that it's all high cost. This chart shows a breakeven WTI price for 175 global oil projects. They're offshore projects. They're onshore projects. They're mining projects as provided by Goldman Sachs. Their study uses a 10% cost of capital, which is comparable to our 9% after tax that we used to calculate our supply cost.

This global cost curve highlights all the SAGD projects currently under development. They're actually shown in green. You can see a wide range of breakeven oil prices, some under $70 WTI and some all the way up to $100 and even more, just to achieve the cost of capital returned.

Cenovus SAGD is not the marginal barrel. It is among the lowest cost globally. The next few slides will demonstrate why.

So this slide demonstrates the components used to calculate supply cost, which, as I said before, is a WTI dollar price required to achieve a 9% after-tax return. Our supply cost for emerging projects ranges from $45 to $65 per barrel. This is a full-cycle supply cost that includes all capital required to develop all the recoverable resource.

What we have proven over time, once the initial growth capital investment is complete and we move to more sustaining mode, where we are investing capital just to maintain full plant production, supply cost dramatically decrease. In fact, Foster Creek and Christina Lake have full cycle supply cost now of between $35 and $45 per barrel. Innovations like our Wedge Well technology make us more efficient along the way. Any technologies that can incrementally lower steam to oil ratios, improve cost or increase production capacity will accelerate supply cost improvements. We believe SAGD economics will get better over time.

This chart is another graphical representation of what I mean by the sustaining mode. The oil in place in these reservoirs is large enough to support 30 to 40 years of production. The largest part of our capital profile is actually sustaining capital, the capital required to maintain full plant production over the life of the project once the initial plant and facilities have been built.

We are still in the growth phase of development, and our primary focus over the past few years has been on capital efficiencies and reducing that overall growth capital. But we're also realizing how big that sustaining capital piece is, and we're working hard now with specialized teams to look at improving our efficiencies associated with that sustaining capital.

So we already have a low-cost structure, but we want to be even more efficient. Our target is full life, long-term F&Ds of $8 to $10 a barrel. This chart shows our capital cost structure. We define growth capital as all that infrastructure and initial wells to achieve full production at a project. That also includes any future debottlenecking or optimization like we're saying at Christina Lake C, D and E, where we're adding 22,000 barrels a day. That adds production capacity of that overall project. Roughly speaking, this works out to $2 to $3 per barrel.

Next is sustaining capital is defined as all wells, pads, pipelines beyond the initial capacity. This includes any and all maintenance that is not expensed, strat and seismic requirements, all the environmental and health and safety capital spending, all the wells, all the drilling, all the completions. This is a catch-up category for anything that does not add plant capacity.

Sustaining capital also includes technology spending, which we believe is a key driver into oil sands development and future reductions in supply costs. We've got a pretty good track record at this point, with innovation ideas and technology that has driven our supply cost down.

This chart shows you what goes into our operating costs. We are striving to maintain top quartile operating costs, and we have a long-term target of maintaining nonfuel operating cost at our SAGD projects under $10 a barrel. And yes, currently, we're a bit higher, but we're also staffed up to be able to do all the phase developments that we've got and getting operators ready for those quick start-ups and things that we've got along. New volumes and optimization will lower those costs and get us in that $8 to $10 a barrel range.

My final key message today relates to the importance of our conventional oil and gas portfolio. As a leader in SAGD, we are often asked about the relevance of our conventional oil and gas properties. The chart on the left sums it up fairly well. It shows a split of operating cash flow between all of our upstream assets. Conventional oil and gas provides significant cash flow to support the long-term development of our oil sands assets. If you think about the lead time required to bring on a phase of SAGD, a minimum of 2 years of regulatory work, plus 3 years of construction, and that's all 5 years if everything goes very well, that's what's required to be able to get operating cash flow from a SAGD projects.

That compares to investments in natural gas and actually, within a matter of weeks sometimes, we can get an additional production from some of our existing wells, natural gas wells. But also drilling new wells in the oil assets, the conventional oil assets we have, can take, say, 5 or 6 months, we can actually have positive cash flow from those investments.

The conventional portfolio is an underappreciated gem in our oil sands story. It allows us to self-fund our oil sands development as we grow that 11% that we've been talking about.

So this chart highlights our total conventional oil and gas portfolio in Alberta and Saskatchewan. And you might note that it's about 70% on fee lands. It also includes Pelican Lake, which has some characteristic of an oil sands asset, but is non-thermal, so we consider it conventional. This also includes our natural gas assets, which we manage as financial assets, and I'll talk a little bit more about in a moment.

Again, for your reference, we have broken about more detail from each play, and that can be found in the Supplemental section. But what I want to highlight on this slide is how much cash flow comes from these assets in total. Think of it as ATM or the cash machine for our oil sands growth programs.

The scalability of the capital gives us the flexibility to ramp up or ramp down our investment in these conventional assets as we require. Cenovus also has a core competency in enhanced oil development, water or polymer flooding, CO2 miscible floods and shallow gas developments. As Cenovus, we have reinvigorated many of these conventional oil assets when we changed our focus from natural gas to conventional oil. These assets are not in a harvest mode by any means. We still have opportunities to grow organically and where the economics compete with oil sands capital, we'll continue to allocate some resources and investments there.

The outcome of our conventional oil program is a 6% compounded annual growth rate through 2015, which is even greater when you consider a 15% to 30% natural declines on those conventional assets.

So let's talk specifically about Pelican Lake. Pelican Lake is an important heavy oil asset for Cenovus, and the 2.1 billion barrels in place represents a huge opportunity, especially when you consider we've only recovered about 7% of the oil in place to date. We have a multi-year polymer flood and infill drilling program underway here.

And while we have granted -- while we have experienced a slower-than-expected response from the low-pressure portions of the reservoir, the higher pressure pads have performed very well. Pelican Lake spending can be scaled back if we so choose, and this year, we have decided to slow down our drilling program a little bit. And we've delayed the spending on our battery there because the production's a little bit slower than we had expected.

Overall, we're currently producing about 25,000 barrels a day, and we expect to exit somewhere around 28,000 barrels a day by the end of the year. We have been through 2 years of significant capital investment, and at the rate that we're drilling wells and our production is increasing, we expect to be cash flow positive in 2014.

I also want to reiterate that we are still early in the development life of Pelican Lake, and Harbir will touch on some of the new things we're working on. We think innovation can drive down those costs, can increase the recovery factors and really start picking up some of those additional 2.1 billion barrels that we have at Pelican Lake.

My final slide on the conventional asset base relates to natural gas. It's easy to see why our natural gas assets generate so much cash flow. We are optimizing these assets with really no capital investment. In 2013, we'll only be spending about $25 million capital on the natural gas assets. They also provide -- our gas production provides a natural hedge for our overall gas consumption in our steam generators at Foster Creek and Christina Lake and also the gas that we utilize at our refineries at Wood River and Borger, Texas. We currently use about 140 million cubic feet per day net to Cenovus.

So in summary, I have outlined the 4 key points today that I believe makes Cenovus a premier oil sands operator. We are focused on being a safe and reliable operator. We want to ensure that everyone that works at Cenovus is proud of the work that they're doing and they return home in the same shape that they came to work for us after a safe day at work. Secondly, we have a track record of delivering on our commitments. Third, we have a very low cost structure that not only makes us a leader in the oil sands, but demonstrates that we can be competitive not just on basis in Alberta, but on a worldwide global basis. And finally, I am -- outlined how important our conventional assets are for supporting the oil sands development. Thank you, and I'd now like to ask Jim Campbell to come up and quarterback the Q&A sessions.

Question-and-Answer Session

Jim Campbell

Thank you, John. I'd like to ask Brian and Ivor to come up and join John on the podium, please. Good morning. As John noted, my name is Jim Campbell, and I have the privilege of leading the Investor Relations team. While we're waiting for these gentlemen to be seated, I'd like to run through the process for the question-and-answer sessions this morning. If you're here in the audience, please raise your hand and one of our staff will bring you a microphone. Please identify yourself and your company when you ask your question. For those of you participating via the webcast, there's a question tab on your screen that you can click to ask a question. One of our Cenovus staff will pose your question on your behalf. If we are not able to answer your question today, one of our Investor Relations staff will respond to you as soon as possible.

Okay, let's begin. Please raise your hand if you have a question. And while we wait for a microphone to make its way to you, perhaps I can start the ball rolling with a question for -- actually we're ready. Paul?

Paul Y. Cheng - Barclays Capital, Research Division

Paul Cheng, Barclays. Two questions. If we're looking at today your downstream and upstream exposure to WTI and heavy oil, it's essentially about the same. But as your production grow higher over the next several years, then you become net long in the upstream. So from a longer-term statistic standpoint, how important it is for you to maintain [indiscernible] integrate or that you will comfortable to allow the net production increase or that you think maybe that you were looking for some acquisition in the downstream side or joint venture to increase it? So that's the first question. Second question, from a longer term perspective, understand the conventional oil and gas, how important it is for the next several years. Is that, at some point, it will become a non-core asset or that, that would be always considered as an important piece of your portfolio?

Jim Campbell

Thanks, Paul. I think Brian will answer the first question.

Brian C. Ferguson

So with regard to the question about integration strategy and our longer term objective there, I think you first have to think about how you define integration. So is it physical integration or is it economic integration? And we think of it more along the lines of economic integration and how we can accomplish taking risk out of the differential between light and heavy crude. So yes, we are today fully physically integrated. We also have means by which we can accomplish the economic integration, you'll see a slide coming up here that Don's got, through either supply arrangements or hedging, that sort of thing where we can reduce the volatility and manage the differential. To be very honest, today, certainly wouldn't be the time you're looking at, adding more physical integration. Evaluations would be pretty steep. You also have to find refining assets in the right location with the right opportunity for investment. We do have our organic opportunity that Don's going to talk about a little bit later here to expand our heavy capacity at Wood River. So what we're going to be doing, and perhaps we can get Don to expand a little bit more on this and his team in their question period. The other question about the conventional oil business, how important that is to us as we go forward, we have -- natural gas gives us also economic integration and protection around a big component of our operating cost, our fuel gas costs for SAGD, as you saw from John's slide. So that gives us a pretty significant offset. The rule of thumb at a 2.5 steam to oil ratio, every 100,000 barrel a day of SAGD production will consume 100 million cubic feet per day of natural gas. So we will continue, as we go forward, to experience economic integration there. And as John mentioned, we continue to manage it here over the next several years as a financial asset. It does give us optionality that at some point in the future, if natural gas prices do recover, we've got opportunity there where we can reinvest and perhaps choose to offset more of the decline than what we're seeing today on natural gas.

Conventional oil, I think that one of the big strengths that it provides us, in addition to the current contribution in terms of free cash flow, but it also gives us some diversification in the nature of our revenue stream or the product that we are selling. And as long as we can continue to demonstrate that we are generating strong internal rates of return, that we've got the opportunity to add to net asset value through meaningful net present value increases, then we will continue to pursue opportunities. Right now what we're doing is we are focusing on building that -- a growth on our existing asset base, principally in Southeast Alberta.

Jim Campbell

Arj?

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

It's Arjun Murti with Goldman Sachs. You mentioned a very strong balance sheet you have, the debt ratios are towards the low end of the range. Some of your competitors have recently put up stakes for sale, perhaps less successfully. Some had backed away from these potential asset sales, perhaps due to low valuations. Obviously, we don't know what the price environment will be, what the differential environment will be. But to some degree, a strong balance sheet out there can potentially add assets. I know some of these assets aren't as strong as the ones in your portfolio, but how does oil-sands-related M&A tie into the desire to maintain a strong balance sheet? Or if you have the substantial asset base, your stocks at 30-year NAV is 40, the stock buyback become more of an avenue to use your strong balance sheet capacity?

Brian C. Ferguson

Thank you for your question. With regard to the any M&A activity, we are not considering any. We have a tremendous organic portfolio. Anything that we would consider would absolutely have to compete first and foremost with the organic opportunities that we see in front of us. And we believe we've got a great deal of knowledge in our existing organic portfolio. My view on strategy is that if you're looking at acquisitions, yes, can be opportunistic, but more importantly, are you trying to address the weakness in your portfolio? I don't see a weakness in Cenovus' portfolio. We have, over the last 3 years, on a very selective basis, done some tuck-in acquisitions where we've locked into and around existing projects to increase land positions and improve positions. We've done some swaps, all sorts of things. That's very much more what you're going to see out of Cenovus. So don't expect any significant M&A activity. The -- I'm sorry, the...

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

If you have to do M&A and you've got a very strong balance sheet and you're [indiscernible] stock buyback. I know you're committed to dividend.

Brian C. Ferguson

Yes, so with regard to stock buyback, the first way that we want to return capital to shareholders is through our dividend and continue to grow our dividend. To me, dividend is a stronger message to our shareholders about the confidence that the board and management place in the sustainability of our business model and the sustainability of our ability to grow cash flow per share. With the potential share buybacks, that is something that I think much more where it be in the situation where we had a windfall of cash, that we will then look to help manage our capital structure in that fashion. Being at the low end of our managed range right now, considering the volatility that we see in the world around us, gives us I think that staying power to be able to make sure that if we see some kind of a dislocation in commodity prices over the next couple of years to the downside that we can continue to deliver on a tremendous organic opportunities that we have right now that continue to grow that asset value.

Jim Campbell

Thank you, Arjun. There's a question in the middle at the back. And while we wait for a microphone to get there, John, maybe you could elaborate a little more on what's involved in the Christina Lake phase or CDE optimization phase that will add 22,000 barrels a day of gross capacity?

John K. Brannan

Sure, thanks, Jim. I talked in my presentation that we initially thought that we could increase capacity of C, D and E at Christina Lake by 12,000 barrels a day. We did the engineering work on it, the reservoir analysis, and thought that we can move that up to 22,000 barrels a day. We've got a project team, and they're looking at that. I think we can get it on by 2015. And what that incorporates is really some of the technology that we've implemented is this recycled boiler to reduce our overall water usage. And at C, D and E, we have 12 steam generators, 4 per phase. And we think that if we add 2 additional recycled boilers to that, we can better utilize the heat associated with that water. We can create more steam and actually get the additional 22,000 barrels out of that reservoirs. So primarily, it's adding 2 additional steam generators.

Jim Campbell

Thanks, John. Sir?

Fai Lee - Odlum Brown Limited, Research Division

Brian, it's Fai Lee from Odlum Brown. I just have a question regarding your objective of focusing on building NAV. And I was looking at the definition of how you've defined NAV, and it seems a little convoluted, and I'm just wondering how you think about that? I can see, for example, an issue like you've included your average trading price for December as part of your NAV. And, for example, if your share price drops significantly in December, does that mean you're not building NAV? It would, in my mind, but I'm just wondering how you think about that.

Brian C. Ferguson

Thank you for the question. We actually had quite a healthy debate internally about what would be the appropriate methodology around that asset value to reflect the success of our investment. And so what we decided to do was actually triangulate in on it. So one of the really important measures is one where we'd base that from the independent qualified reserve evaluators assessment of our growth in proved probable reserves and contingent resource and then use their price forecast, actually, the average of a flat price deck and an escalated price deck on that component. We also take a look at the average of the sell-side analysts. And we also, as you point out, have used what is perhaps a little bit unusual, which is the stock price. That perhaps has been the biggest variable and is perhaps the least clean component of that methodology. I know that all the sell-side analysts here have got their own view on net asset value in their own modeling. One of the things that we are also somewhat constrained by is securities requirements in terms of disclosure requirements. So that's why we thought we were better off to choose the 3 methodologies. I would observe that I agree with you. I think it was Arjun and perhaps yourself that have commented that the stock price today is trading at a discount to net asset value, and we would certainly agree with that.

Jim Campbell

I believe we have a question from the webcast. I think, Brian, again, for you. "What are your thoughts on using joint ventures to accelerate projects such as Grand Rapids, which you have 100% interest in?"

Brian C. Ferguson

That's -- that question is somewhat reminiscent of the process we undertook for Telephone Lake. Well, first and foremost, for us to consider parting with any component of what we consider to be very high-quality assets, there has to be a compelling value proposition for Cenovus shareholders. So it has to be strategic value. It isn't just about dollars. As has been observed, we've got a very strong balance sheet, we've got the capacity to do things from a financial perspective internally. The only reason that we would perhaps consider a joint venture on one of our 100% assets would be where we thought a partner brought some strategic advantage to us that would add compelling value to Cenovus' operations today. And that for example, might be around helping manage the light to heavy differential. I'd say that today, we have absolutely no plans to joint venture any assets. And from my perspective, as CEO, I think it's always going to be very important to me that we have a significant component of our asset base that is 100% Cenovus projects, so that we are in complete control of the pace of development.

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

Greg Pardy of RBC. So the question is right around earnings and earnings-based measures. So, Brian, I think you'd mentioned about a 13% CAGR, your expectation in terms of cash flow growth 2013 through 2023. Should we generally expect earnings growth to more or less mirror that? That'll be question one. Second question is you've done a lot great work in terms of supply costs and looking in individual projects. But at the end of the day, you're going to get evaluated based upon corporate returns to some extent in terms of driving your multiple. Does an earnings-based -- does a [indiscernible] target at some point move into place in terms of what you're looking for?

Brian C. Ferguson

Thanks, Greg. The reference on 13% cash flow per share growth was referencing 2010 through 2013. We didn't go beyond 2023 or up to 2023. Now I think that's a really good question. One of the things that Ivor and his team are doing is taking a look at returning capital employed methodologies and criteria and how we might see those being applicable in some of our economic criteria and the thresholds that we're looking at. We certainly appreciate that from the markets perspective that, that is one of the methodologies that allows you to compare between sectors and compare between companies in terms of the return that you're generating, taking account your capital DD&A versus earnings generation versus the capital that you've got deployed into that. So certainly, I understand that. In our case, where we have an awful lot more knowledge than you guys do, and we'll always have an awful lot more knowledge about the assets at hand and cost structures, I continue to believe that discounted cash flow analysis that takes into account a time value of money, which is one of the things that return of capital doesn't do, is a very appropriate measure for us. For Cenovus, one of the things that's really important to me is to make sure that we are continuing to invest in projects that we believe have an opportunity to move the needle in terms of increasing the underlying value underneath each and every share. And that's where net present value, that's where net asset value come in. I mentioned that's a diagnostic tool for us. So that we can -- we can all create a stream of cash flows. It's got a really high internal rate of return, and we may be able to do things in the short term that manage earnings, if you will, so that we can optimize earnings in the short run. But when you take a look at the nature of our asset base, where we've got 30-year production lives, we've got assets that are fairly capital-intensive in their early years, and then generates strong free cash flow in the mid and longer term nature, I think that one of the things that is very important to make sure that we are really stewarding assets to optimize net asset value and growing the shares is net asset value and net present value.

Jim Campbell

Peter Ogden?

Peter K. Ogden - National Bank Financial, Inc., Research Division

Peter Ogden with Bank of America Merrill Lynch. Obviously, there's a lot of competition out there for investor dollars in North America. And we've had quite the proliferation of light oil resource plays in the U.S. And you being an oil sands player, I think you correctly identified it's a 2-year regulatory cycle and a 3-year construction cycle. I'd like to just maybe hear your opinion or your perspective on how you compete for those dollars and how you compare and contrast yourself against some of those light oil players in the U.S.?

Brian C. Ferguson

It's almost a question I should perhaps ask you to answer, Peter. Sorry for that. The -- our value proposition, so I think you play to your strengths, right? And I think that we can demonstrate, and hopefully one of the messages that we conveyed here is why we like oil sands, in particular, SAGD oil sands. So we've got basically little if any exploration risk. We know we have billions of barrels of oil. The question becomes how do we efficiently manufacture that oil growth. We can take a lot of the risk out of what we're doing by being integrated, by hedging differentials, those sorts of things to manage the volatility in the cash flow stream. As John pointed out, one of the big things that I think has distinguished Cenovus to this point, and we want to continue to distinguish Cenovus, going forward, is a low capital and a low operating cost structure. It's my belief, for example, if you compare head-to-head the supply cost on Foster Creek and Christina Lake, for example, to light tight oil, you'll see that we are about half the supply cost as an example.

One of the things where SAGD and where Foster Creek, Christina Lake, in particular, really shine is in the lower price environment, the scale that we have and the scale in oil sands is one of those big advantages and being able to apply manufacturing techniques to it. We also don't face a 60% to 80% first year decline. So that's something that's fundamentally different about our business. I think from -- in terms of competing for investors' dollars, there's obviously an appropriate portfolio mix that investors are going to have as to how they view the world and whether or not they want to have a component of light tight oil that they want to have a component of oil sands in their portfolio. And certainly for Cenovus, what we intend to do is to continue to demonstrate that we can bring on projects in the oil sands at absolutely world-class cost structure, be very competitive on a global basis, and that, quite literally, we can demonstrate decades of growth opportunity ahead of us. Now the regulatory approval's one of the strategies we've employed, and I think successfully, is that we have inventoried the next 6 years' regulatory growth. So we've got regulatory approval in hand for the next -- for the growth for 2017. We've got 2 more big projects, Grand Rapids and Telephone Lake, that we expect will add another 270,000 barrels a day net to Cenovus in regulatory approvals. So very quickly, we expect we'll probably have about the next 10 years regulatory approval growth already locked in for us. So that is no longer a variable in terms of Cenovus' growth profile.

Jim Campbell

Thanks very much. We have time for one more question. Right up here.

Christopher Feltin - Macquarie Research

Chris Feltin from Macquarie. Maybe a reservoir question for John. I suspect Harbir might hit on this later, too. But just getting to the indications that you guys have up there for both Telephone Lake and Narrows, essentially hinting that Narrows is going to be one of the -- well, the lowest SOR project out there. Just wondering qualitatively, quantitatively, what you're seeing different about that reservoir? Is it purely reservoir related or are there other learnings that you're taking from Christina Lake that you're moving over to that project?

John K. Brannan

So several things to answer that. Yes, we're working hard to learn from Foster Creek and Christina Lake, particularly to incorporate that into Narrows. We're looking, particularly, at Telephone Lake at doing some additional remodularization for those assets. And the quality of the assets, Telephone Lake is by far one of the best assets. It's almost as good as Christina Lake. The challenge is at Telephone Lake is associated with the top water, and Harbir will talk more about that in his presentation. But we're just concluding a very successful top water removal process that will help drive our steam to oil ratios down at Telephone Lake. So we think that, when we get that up and running, we will have low steam to oil ratio, provided that water removal off the top of the reservoir is successful. So the reservoir quality and the thickness of Telephone Lake is very good. Narrows Lake is a bit thinner than Christina Lake but still a very, very good reservoir.

Jim Campbell

Okay. Thank you, everyone. That concludes this part of the program. We'll now break for approximately 15 minutes and ask you to please return to your seats by 10:35 a.m. The refreshment is outside the room, and staff can direct you to the facilities. And at 10:35 a.m, Don Swystun will talk about refining marketing and transportation and development.

[Break]

Donald T. Swystun

All right, good morning. Welcome back from the break, and thanks for sticking around. Hopefully, you'll enjoy the latter half of the show. My name's Don Swystun, and I'm Executive Vice President for Refining, Marketing, Transportation & Development. So my team is responsible for marketing and transportation of all of our upstream production, diluent acquisition, market fundamentals and hedging, and of course, partnership oversight of our 2 U.S. refineries.

As you can see here, Wood River, in the background with the 4-coker drum configuration. And some of you had the opportunity to visit Wood River on an analyst tour some time ago. And as you can see, in the past, the lights might have been burning kind of -- bit kind of dim a few years ago in the refining business. But certainly, as you can see today and in the last few years and certainly this year as well, it's burning bright.

So this morning, I'd like to talk to you about how our portfolio approach to market access will expand our product margins and how our integrated approach is generating significant cash flow for Cenovus.

So our goal is to increase the margin on every barrel of oil produced by Cenovus. We are creating a portfolio of opportunities, particularly related to transportation alternatives to provide us with flexibility on where we sell our products and exposure to optimal pricing structures.

We continue to pursue and execute pipeline and rail options to expand our market opportunities. By selling bitumen blend at multiple market hubs, including Alberta, the West Coast, Midwest and U.S. Gulf Coast, we can optimize realized prices. Our ownership in 2 U.S.-based refineries allows Cenovus to access the full value chain from production of oil to sale of refined products at global pricing.

So this slide depicts Cenovus' value chain for bitumen. Bitumen is produced and of course blended with diluent to facilitate transport to refinery markets. The value chain exposes us to numerous market locations, the first being local Alberta market hub, where we receive Alberta-based pricing. The second, which is down the value chain by accessing pipeline and rail capacity to get exposure to other markets with pricing tied to WTI or global pricing via tidewater, something like our firm 50.

The third part of the value chain is utilizing our refining capacity, to gain exposure to the sale of refined products with pricing typically tied to global benchmarks such as Brent or LLS. Our true goal is obviously to expand margins.

In assessing the opportunities to access markets, we need to look at the North American picture. I'm sure the graph on this slide is not likely new to anyone here, and you can see a rail at the very top, which is very important. This slideshow is the total forecast of northern tier oil supply from Western Canadian Sedimentary Basin, the Bakken and the Rockies compared to the forecasted refining consumption pipeline and rail capacity. As you can see, since mid 2012, markets and pipeline capacity had been tight and rail has helped to fill the gap. We expect that rail capacity will continue to play a growing role in transporting oil, particularly in the event that any of the planned new pipelines or pipeline expansions are delayed or canceled.

So as you've seen, Cenovus has significant plans for its oil sands growth and this predicable, reliable supply gives me comfort when I look at marketing or making our marketing commitments. As I mentioned, my team is responsible for marketing all of Cenovus' production. But what you may not know is that we're also responsible for marketing our partners' volumes from the FCCL partnership, which includes, of course, Foster Creek, Christina Lake and Narrows Lake. This reliable production provides us with security of supply to support our transportation commitments and allows us to deliver a steady consistent volume of oil to numerous refineries, including our own, for market development.

Our goal is to make specific commitments to the transportation solutions for up to 50% of this marketable production. Those transportation solutions will include both pipeline and rail commitments, with rail making up to about 10% of our marketable production.

So with our growing production, we can't reasonably expect to sell all our volumes in Alberta. We have to access new markets. This slide outlines a few of the benefits of committing to long-term transportation solutions. So in addition to ensuring that the projects become viable, we are able to create certainty of market access, define the cost of accessing the market and, in many cases, able to negotiate preferred terms and totaling arrangements.

We currently hold firm capacity of 11,500 barrels per day for the West Coast on Trans Mountain and access the Gulf Coast for about 30,000 barrels per day through a combination of the Pegasus pipeline, barge and rail, and to this point, we have not been significantly impacted by the upset with Pegasus and are selling a lot of those volumes at Patoka. We have committed volumes of 175,000 barrels per day to the West Coast on a Trans Mountain expansion and the Northern Gateway pipeline. We have also entered into a long-term deal to move an additional 150,000 barrels a day to the Gulf Coast on the Keystone XL and Enbridge's U.S. Gulf Coast access.

And also, in addition, we are also participating in TransCanada pipeline's open season to move oil to central Canada and the East Coast, as you see on the map, to St. John. Our strategy has been to participate in multiple pipeline opportunities and rail to manage the risk of some of the projects being delayed.

So we're continuing to expand our exposure to rail. We're targeting to ship up to 10% of those marketable volumes by rail. It's a great option during periods of pipeline congestion and also opens up markets not accessible to Western crudes by pipeline. As well, rail provides the flexibility to move bitumen with less diluent. And expanding our rail commitment, so far, we have least 800 rail cars, 300 general-purpose and 500 coiled and insulated cars for heavy oil that will arrive starting in late 2014. And of course, in addition to these, we contract rail cars from others. We're also looking to participate in rail terminals with the prospect of having up to 30,000 barrels per day of unit train capacity available for market hubs.

So our goal is commit to transportation solutions for up to 50% of that marketable production. So this slide gives you an idea of how our pipeline and rail commitments could ramp up over time compared to volume of marketable oil. This, of course, assumes all pipelines come on. Volume, basically, is projected. This portfolio of transportation, both pipeline and rail, will move us along the value chain, allowing us to access more markets, providing us with the opportunity to expand our margins.

Now I'd like to focus on the integrated business. Cenovus and Phillips 66 partnership, known as WRB holds a 50-50 joint interest in 2 refineries, Wood River in Roxana, Illinois next to St. Louis and Borger in Texas. These refineries are optimally located in the midcontinent region to take advantage of discounted West Texas Intermediate link crudes, including Canadian heavy oil as well. Both refineries have access to multiple sources of crude and crude qualities. The refineries are well pipeline connected and exposed to the full benefit of high crack spreads caused by inland PADD II congestion.

At this time, we are not looking at acquiring incremental refining capacity, but we continue to look at opportunities to expand heavy oil processing capacity at the existing facilities. We have identified debottlenecking opportunities at Wood River that would expand heavy oil processing by up to 10%.

Both Wood River and Borger are highly complex refineries. This means that they basically have the pots and pans and the flexibility to be able to process a wide variety of crudes and in particular, heavy crude. Wood River, in fact, has the ability to process in excess of 130,000 barrels per day of high-TAN crude like Christina Dilbit Blend or what we call CDB. By having this flexibility, the refineries are able to maximize margins based on the cost and quality of the crude input and the expected value of the refined products that a particular crude will be able to produce.

So having an ownership in refining capacity allowed Cenovus to expand the market for its heavy oil. The CORE expansion project, which came on stream in 20 -- late 2011 increased heavy oil processing capacity to about 220,000 barrels per day at Wood River. And project timing was excellent. As transportation constraints beyond the refinery provided Wood River with access to advantaged crudes and shifted the margin to inland refineries. This year, our operating cash flow guidance for refining is $1.1 billion to $1.7 billion.

Cash flow from refining has historically been countercyclical to those of the producing industry, and in combination, bring stability and reduce volatility to the cash flow for Cenovus. Also, the refinery integration provides Cenovus with exposure to global pricing through the production and sale of refined products. This table of cash flow supports the continued expansion of our SAGD projects.

So this next-to-last slide, we show how Cenovus uses a portfolio approach to manage cash flow and reduce volatility. The physical hedge provided by our heavy oil refining capacity of about 120,000 barrels per day links our oil to refined product pricing or global pricing. Additionally, our light and medium oil production is linked to global pricing through 110,000 barrels per day of light and medium oil processing at the 2 refineries.

Therefore, the refineries provide a virtual hedge to refined products and link about 230,000 barrels per day of our production to global pricing. In addition, our growing transportation portfolio of pipeline and rail provides access to a wider range of markets and pricing exposures.

And finally, our ability to use physical sales like supply deals and financial tools to hedge additional volumes further reduces exposure to market pricing.

So in conclusion, we are creating a portfolio of opportunities to provide us with the flexibility on where we sell our products and the pricing structures that we are exposed to. As I said in the beginning, our goal is to expand the margin on every barrel of oil produced by Cenovus, and I believe that the steps we're taking will do just that.

So thank you for your attention. I would like to now call upon Paul Reimer, Darren Curran, and Steve Brink to the front of the room to join me in the next question-and-answer panel.

So with me, I have Paul Reimer, Senior Vice President of Marketing, Transportation and Power; Darren Curran, Vice President of Refining; and Steve Brink, Chief of Market Fundamentals and Hedging. And with that, we're ready to take your questions.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

It's Arjun Murti with Goldman Sachs. Thanks for some of the detail on rail. Just a few questions there. I guess, why 30,000 barrels a day? Can you take it higher over time? I think you mentioned it'll come on late 2014, it's obviously mid-2013. Is that the lead time to getting the coiled railcars? And any thoughts on transportation tariffs to whatever markets via rail that you're taking the oil to?

Donald T. Swystun

Well, thanks. I'll take the easy part of that question. The cars are definitely were on order. As there has been a, as we all know, backlog in getting coiled insulated cars. So the arrival of those are slated for late 2014, and that's when the 800 -- the additional 500 should start coming. We currently have the 300 general-purpose cars, which we're using to move our light and medium crude to locations on the Gulf Coast and in the East Coast of Canada. But we will let Paul make some comments on rail.

Paul Reimer

Yes. So in part, it's the lead time on the railcars and part, it's the lead time in having unit train available on loading facilities. What we found is that the unit train is going to be far more cost effective, cost efficient for transporting our oil to the niche markets that we're in. But for right now, we actually moved a fair amount of our volumes, our conventional volumes using manifest trains, really works well. There are some logistics challenges out but we're working through all of those. But the real bang for your buck is on the unit trains, so that comes in next year. We're experiencing much the same type of cost exposure that you're reading about in the paper, probably both $15 down to the U.S. Gulf Coast is about right, and we expect that we're going to be able to do better than that once we get the unit train exposures up.

Arjun N. Murti - Goldman Sachs Group Inc., Research Division

And then just 1 follow-up to that, you alluded to 50% you'd like to have on firm transportation capacity. You have an interesting graph that shows Canadian supply versus takeaway capacity, and I think we have a similar type conclusion that the supply looks to be ahead of the local refining capacity and pipeline takeaway capacity. When we think about the issue of having a discounted price within Canada, do we think about the 50% on firm transportation that will definitively get to a market where you can get a global price but you are still exposed to the other 50%? How do we think about the source of where the differential blowout can occur? Because you have to escape Alberta, and I think then it's -- that's through the via the 50% firm commitment, but I want to make sure I understand that correctly.

Donald T. Swystun

You're -- there's 2 ways to think about that, I guess. Right now, there's a lot of capacity to be able through the Enbridge mainline, and that takes -- that's going to take a big portion and we're not -- we don't refer to the Enbridge main line as being committed volumes, and those move obviously into the United States. So when we're talking both firm transportation commitments on both pipeline and rail, those are taking us to generally tight water locations, so the West Coast of Canada, East Coast of Canada and to the Gulf Coast, and rail provides you maybe some firm transportation to specific refineries, as well as some of those tidal markets potentially as well into the Gulf Coast or even the East Coast. So when we speak to the 50%, it's strictly defining a particular market that we're trying to get to. And while we put it -- to go forward with that portfolio approach, and while we have a number of opportunities that we're pursuing, it's just the fact that we cannot or nobody can necessarily judge which pipeline will go first or if some will potentially be canceled. And at this point, we believe, honestly, Keystone XL will go ahead. That's one that we're banking on, but we hope that at least while West Coast line and certainly hopefully, and East Coast line as well. And Paul, if you had anything to add to that?

Paul Reimer

Yes, I just want to put a slightly different spin. Our portfolio approach is really driven off of the requirement that we have from market diversification. It's all about getting to the next market. So we have a primary market and we'll continue to sell into that primary market, and we've got great business partners that love our crude, and so we'll continue that. But really, as we grow this business, we have to be able to stretch out there. Portfolio doesn't mean that you're always going to the highest value market. You're not going to cherry pick but our portfolio means that we will get the best aggregate for all of our production without constraints, without having to be constrained for a marked production. So that's why we've really latched on to the portfolio approach. It really is what we can do. And I might add, and I might add that while we're talking to the refiners out there, they love the idea that we are going to be bringing 1 million barrels a day to the market that's security of supply for them. It's consistent quality. They can base load their refinery slate with our material, and I love it. Our guys love to have -- be the first phone call that the refiner gets when they're looking for barrels.

Stephen Brink

Just one other thing, over and above the 50% is our refining exposure. So that will give us global price exposure of at least 20% depending on our total volume.

Kyle Preston - National Bank Financial, Inc., Research Division

Yes, thanks. It's Kyle Preston here from National Bank. I think most of my questions were answered there. But maybe just to expand, I mean, if Keystone XL doesn't go ahead, Gateway doesn't go ahead, I mean, are you comfortable that this current rail capacity are chasing the 30,000 barrels, I think you said will be enough to sort of cover you during that period?

Donald T. Swystun

The easy answer is no to that. We -- 30,000 is just a goal in the short term. We're looking at that kind of moving towards exiting in that kind of a range. But I think that is depending on where the pipeline situation goes. I think all producers will be looking to expand opportunities on rail. It's just a natural progression, more different than what the Bakken producers had to put in place to move the considerable amount of volumes that they've had coming in the last couple of years.

Paul Reimer

And I think that's why we've chased a 10% target. We can go beyond that again. It's not just our volumes. So I think, there's a lot of refiners out there that have railcars and capability for rail movements. So we can anticipate that fluctuating based on the market dynamics and the best prices that we can get for our production.

Paul Y. Cheng - Barclays Capital, Research Division

Paul Cheng, Barclays. Don, 2 questions. First, in what [indiscernible] did the original CORE expansion or upgrade project is including a 50,000 barrels per day [indiscernible] expansion which later on has been canceled? So have you guys looked at that and whether that this will be part of when you consider the heavy oil processing increase? And that what is the capital cost and when you're going to coming up with the FID?

Donald T. Swystun

Okay. That's an obvious question for Darren, put that to you for Wood River expansion.

Darren Curran

Thanks for the question, Paul. First of all, I'll address the crude unit. There's an existing crude unit at Wood River that has been revamped. So there is no additional cost to that. We're not using that crude unit capacity today because we're limited on light ends. So CORE was premised around a largely syn-bit feedstock. What the market has provided at the greatest margin to refineries, the dilbit feedstock. So dilbit has more light ends in it. So that the project that we're talking about, this 10% expansion is really, a really attractive capital efficiency project that uses that existing equipment and just handles these light ends. So what we're talking about here is not another megaproject. And we can't really give you a capital number yet, but what I can tell you is by late this summer, we're going to be positioned to put in our permit application, and I expect that if you just stay tuned early next year, we'll be in a position to talk about capital. But we're not talking about another CORE here. This is another very manageable size project and really attractive capital efficiency, really attractive internal rate of return. And it speaks back to what Brian talked to us to start with. Our best opportunity in the refining enterprise that we have right now is really this organic growth at Wood River. So really exciting, more to come.

Paul Y. Cheng - Barclays Capital, Research Division

So yes, then I just want to make sure what is the resulting impact is that your heavy oil processing in Wood River will move from roughly 200 Mbbls/d into 220 Mbbls/d? And will your overall footprint level will move from 305 Mbbls/d into a 350 Mbbls/d? Or are you still going to maintain that 305?

Darren Curran

So right now, our heavy capacity at Wood River is in the range of 200 Mbbls/d to 220 Mbbls/d. And so with the engineering we've done so far, we believe we can get another 20% on that. So when you look at 20% on 200, another 20,000, 22,000, 25,000 barrels a day, that's a pretty significant heavy capacity when you compare it to many other refineries in the U.S. that don't even have heavy capacity of 25,000 barrels a day. So it is a pretty exciting opportunity, and yes, there will be additional total distillation capacity to it. And as always with refining, whether you use that capacity will depend on the margin on that incremental barrel.

Paul Y. Cheng - Barclays Capital, Research Division

Okay, the second question is on...

Donald T. Swystun

Currently, we have actually pushed more volume through than it -- than -- right now, we have a rated capacity at Wood River 311 Mbbls/d and we pushed through volumes in excess of 330 Mbbls/d through that refinery.

Paul Y. Cheng - Barclays Capital, Research Division

Okay, the second question is on the well operation. You mentioned that you may consider buying a well terminal. So is that the unloading terminal or that you actually may also consider the loading terminal at the destination market? And on the well cost, you're ordering, you said, a lease buyback or that is an outweigh [ph] on the railcar that you're going to be?

Donald T. Swystun

The rail terminals are for unloading. That's what we're looking at options at market hubs in Alberta. That's our preliminary goal. It's what we're looking at. Does not preclude it in the future, we could be involved at some unloading as well. But at this point, we are looking at and we talked that 30,000, it would be unloading. And maybe, Paul, do you want to take the second part?

Paul Reimer

No, I mean, that's awesome. We are looking at offload facilities at the destination location that's not in our -- that's not today, but we would probably look at that. There's some ideal spots for that and the railcars that we have on order are leased railcars.

Michael P. Dunn - FirstEnergy Capital Corp., Research Division

Mike Dunn from FirstEnergy. Just a clarification on the heated railcars, what sort of a blend ratio, if any, is it sort of a less condensate in that bitumen or any condensate at all on those railcars?

Donald T. Swystun

We've looked at a number of opportunities regarding -- I guess, in the first stage, where this would not be located because we're chasing terminals at hub locations. We would have a fully, in essence, blended bitumen, potentially in the railcar initially, but we would take -- I think our goal is to digging it down to about a 14% ratio in that kind of a case. And in the low end, you could get down to even maybe in kind of the 8% roughly for, I call it, a neat bitumen to move on railcar. I think it has to line up with a particular refinery as well. I think that's the other key and who would be able to take that particular product. So the initial driver for, obviously, rail terminals, first and foremost, is to get that additional market access. And once we have that, secondarily, you're right, limiting the amount of diluent in that rail car makes a lot of sense on a long-term basis rather than cycling it back and forth.

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

It's Greg Pardy at RBC. So Don, I'm not sure if this is a fair question for you, it's probably more a question for Brian. But just to be clear then, so if XL isn't on by end of 2015, then is the plan B essentially just to slow down, temporarily defer a couple of phases or slow down the profile? Or have you got another card up your sleeve in terms of rail becoming larger or what have you?

Donald T. Swystun

From our position, I mean I think we believe that we would continue based on our supply cost, and we feel that we could still move forward with developing the existing projects, particular possibly Christina Lake. If it came to the -- when we talk about situation of capital constraint, we could -- we do have more flexibility on the conventional oil side to maybe reduce, slow down some of that operation. That would be, maybe be the first area we would look at. But generally, at this point, we're committed to moving forward on the oil sands, and we feel that if XL doesn't go, there will be other opportunities. But I -- but as we've mentioned, I think rail is a big part of that, and you can't -- you don't have the luxury of not pursuing a rail option at this point in time. You have to be flexible in creating, giving yourself the opportunity to move volumes on rail. So the first -- we think with unit trains in Alberta, that's going to be a major step change for producers, the first one that's going to come that's going to allow us to [indiscernible] substantial belongings. But we're going to continue to expand that if some of these rail -- some of these pipeline options do not move forward.

Peter K. Ogden - BofA Merrill Lynch, Research Division

Peter Ogden with Bank of America Merrill Lynch. The high-TAN crude that comes out of Christina Lake has been the subject of a lot of discussion, the love-hate relationship the market has with the high-TAN crudes. At some point, you're going to exceed what Wood River can take in. Can you confirm that on rail, you see less of a TAN discount when you're shipping to the various locations, and whether rail is a viable, I guess, risk mitigation on the high-TAN crude going forward?

Donald T. Swystun

I think Paul [ph] can take that, maybe Darren could add to it as well in terms of handling CDB.

Unknown Executive

Yes, actually, we have done a fair amount of market development for our higher TAN crudes, our CDB. We've actually got a great number of refiners, in particular down to the U.S. Gulf Coast, that are running at -- we've got some term contracts. We've entered into substantial contracts with the refiners that want to run the CDB. There's a lot of kits out there that have already meddled up to run the material. So no, it's not just hinging on one refinery, it's not even hinging on just one region. We're finding a good home for CDB throughout North America. The real joy here is that there's a vast number of refiners internationally that would love to run that higher TAN crude as well. So again, market diversification matters. So we're finding great home for that particular product.

Andrew Stein

Andy Stein, First Manhattan. I just had one big picture question. If you look at the last year's financials, in a world of $90 WTI and $100 Brent, you're getting about 50-ish for your bitumen. So there seems to be huge differential in aggregate between the world oil prices and what you're getting for your product. And I guess it's due to various factors, I think blending, transportation, the fact that the heavy oil will typically sell at a discount to Brent, WTI. But if you look out, let's say 3 to 5 years, where do you think a normalized differential should be on the bitumen relative to prices? Or is it just too complicated to even try to forecast? And what do you think -- what are you guys going to do in order to narrow that? Because eventually, that's a key driving factor for the shareholders.

Donald T. Swystun

Well, first off, great question. And I've got an individual who spends each and every day thinking about that. And that would be Steve Rake [ph] in terms of the fundamentals guys. So I'll let him speak to the differential, our view of differentials in the future.

Unknown Executive

Yes, so I think longer term, I'd break it into 3 components. One would be kind of a global light-heavy differential, which would really be driven by the conversion capacity that's available worldwide versus heavy crude supply. And we think that's going to be plenty of that capacity around for at least the next half decade or more. So we think something in around $10 differential, $10 to $12, is probably quite sustainable. The other component is we are in land, so there is the transportation component of getting it to market depending on whatever the marginal source of transportation is, but can be upwards of another $10. And the other component is the blending of the condensate. And once again, that probably gets close to another $10 cost to bitumen.

Donald T. Swystun

I think -- but our goal is, you're right, in a long-term basis, is to get the world price -- or linked to the world price of oil, and that's where the market -- access to market is so critical in terms of our future growth markets are beyond the United States. So obviously, and then Asia is a big part of that, India is a big part of that. That's where we have to get to, and that's where, I think, the price of heavy oil will be defined in the future.

Okay. I guess thanks very much for the questions. And next on the agenda, I'd like to welcome Harbir Chhina to the stage to present our oil sands review.

Harbir S. Chhina

Thanks, Don. So I'm going to talk about innovation, technology, all the things that we're doing in our company. The first thing is really, I think when it comes to the technology development, the in situ business, I think we just got started. The phrase I normally use is, we just finished the first inning, we got 8 more innings left, so there's lots of running room. Even some of the things I'm going to talk about blow down, like that's new to the industry and we'll figure out how to improve things even further. So we've got a long ways to go. And I think innovation and technology development are going to be very important to continue to improve our economics. John showed you a supply cost of $35 to $45 with Foster and Christina. Well, they used to be higher than that. And so because of technology is why those numbers are there. So when we talk about some of our emerging plays, such as Telephone and Grand Rapids and greater Borealis area, I believe some of those plays, even though they're sitting at $55 to $65, that we will get to lower supply cost numbers for those plays. It just takes time to develop these technologies. But we've got to stay on track and continue to get after it because we've got a huge resource.

The other thing I wanted to say is we're not just talking about technology in terms of getting a new widget to get our oil out cheaper and faster. We're also doing business differently. And that comes to our execution with excellence. Brian always tells us we're going to keep running down this business as long as we can execute with excellence, and that's what we're focused on and that's why the growth rate is what it is. We believe we can grow at the rate of the charts that you've seen because we can execute with excellence. And so how we are doing our engineering module yard, construction, small contractors strategy, that's all part of our manufacturing approach, and we continue to make that even better going time.

Next. So this just shows how much we've been spending year-after-year on technology development. This is net dollars. So our key area is really to continue to drop the steam to oil ratio. To us, that's the most important metric in terms of giving us good financial metrics, this also gives us good environmental metrics. And our goal has always been to focus on that. And I think we've got to continue going down that path and to increase net asset value by applying new technologies like the SAP thing that I'll talk about later. And of course, to continue to move the reserves forward from prospective to contingent to 2P resources.

Next. So when we look at our full cycle on technology development, kind of got from an idea to a pilot stage to commercial and then we improve it. So some of this stuff takes a long time, and things like, say, example, the electric submersible pumps. We were the first company to try that back in 2001, and we still have not seen the full potential of ESPs yet. We're about to see that now that we're going into blowdown. We saw a benefit in getting higher temperatures coming into our -- in our other plants. But we're going to see even further benefits with stuff like that. One of the other things that we're doing also is about a decade ago, we used to only go to the field when we felt that there was an 80% probability of success. At the rate of which we're spending money, capital and operating, we're spending gross about $5 million a year. Now, we go to the field when there's a 30% probability of success. So we're in the mode of feeling fast, feeling cheap, or making it win and doing it faster so we can move on and commercialize it. So there's about 100, 100 to 150 things that we're currently working on, and I want to continue to grow this group and also work with industry to keep our dollars low.

The blowdown boiler's a great example of how we've been templating with full boilers all these years. But now, we're going to the fifth boiler, like John was talking about, and that's going to lead to 22,000 barrels per day at Christina Lake. So we're going to go -- and Wedge Well, of course, has been a huge success story that all of the industry is copying us on that one, and it's been a great success story.

Next. So this is kind of the goal here is to focus on the red line here. It's about adding value. But you need to have a portfolio approach when it comes to technology development. And so you got to have a bunch of projects in the hopper, the conceptual stage where you try to understand and research them and do the engineering. And then the piloting is where the value starts to get added, and you can see the list of things there that are right behind, and then commercialization is when we get full value. So we want to continue to have this portfolio approach of projects in the hopper at each phase. And so we're commercializing something every year.

Next. So this is a big price that we're going after, 137 barrels a day. And the -- converting that, when you look at our 2P, 2C resource, that's really only a small wedge of the whole thing. And I think to go after the 138 billion, as technologies that's going to continue to move it from that prospective to contingent to the 2P resource. And when you look at our 2P, 2C resource, we're only talking less than 50% of that wedges. We're really what you're seeing in a 10-year plan right now. So even with our existing 2P, 2C, we have lots of running room and good resources, and technology is going to be a big part of that.

Back in 2010, we told you that 50% of our lands didn't even have 1 well per section even with the aggressive drilling we've been doing for the last 3 years from 350 to 500 wells per year. We still, today, only have 50% of the wells, with 1 well per section or higher. So we still got half of our lands. So we have been continuing to grow our land base. We just don't talk about it a whole lot. But -- so that our pie is going to get keep getting bigger over the years to come.

Next. So this is the chart showing things that we're working on, how to increase the resource base and recovery factors. And one of the things I want to talk to you about is the thin pay well. So the IQREs, they're generally supposed to give us resource and reserves on probabilities, but that's not what they do. They actually give us contingent and probable proven reserves on pay thickness. So they go with the pay thickness of 8-, 10- and 12-meter cutoffs. We're actually doing a 10-pay pilot with 6 meters of pay to prove to them that you can make money at 6 meters of pay, and you'll still have a respectable SOR. Now, I want to develop an oilfield with 6 to 8 meters of pay. But when you got 20 to 30 meters of pay and you've got stuff that's sitting at 6, you will -- those -- that stuff is economical in my mind. But it has to be a small chunk, and that's going to have a lot of resource. So we're going to prove up that technology over the next year or 2 here. Wedge Well was a great success story in terms of increasing the recovery factor, polymer flooding at Pelican is a good example of that. And then the solvent aided process, to me, that's more of a net present value increase, increasing your NAV by 30% to 40%. It increases our recovery factor, but the big uptick is in value.

Next. So there was a question on Narrows Lake earlier on. So Narrows Lake was not as good as Christina core. Christina core is a great reservoir with 35, 40 meters of pay, good permeabilities. It's very consistent laterally and vertically narrow, it's not in the same boat. And so why did the SOR get low here? Because for the core Christina, we believe we'll get a steam to oil ratio of 1.7 on a cume basis. And with Narrows, it was actually closer to about 2.1. So that tells you that there's a difference in quality. But the way we were able to get it down to that SOR of 1.7 is because of SAP, putting in butane. And that increased our floor rates and dropped the reservoir by 30%, and that really helped and increased our rates, and so we could go to larger well spacing. The capital goes up a little bit, but sustained income's down quite a bit. Overall, good environmental footprint. And this was about butane, but really, we're looking at everything from C1 to C7, so methane, ethane, propane, butane, peptin, exy [ph], as well as CO2. And so we're going to continue to have a portfolio approach on solvents because the quantity prices, the liquids business in North America is changing. The prices have dropped. They're going to drop for different commodities at different times, and we just we want to have our -- we want test of all these technologies and have a basket, really good goal depending what our commodity prices are. That's where we're going to hit our reservoirs with, and we're going to keep applying solvents to all of our oils and operations. But -- so this Narrows Lake is just the start of what you're going to see from us.

Next. I'm really proud of this rig. We call it the SSD rig, SkyStrat drilling rig. If you look at our strat well programs over the last decade, I've seen our cost more than double on our strat well programs. And that really gets us upset when we see these costs. So this was our answer to, first of all, not letting cost escalate in the future, and secondly, they'll hopefully drop the cost by 25%. And so this has been a huge success story, things are going really well, and not only from a cost standpoint, but also, the guys are coming up with new and new innovations to make things better. For example, just found out yesterday, Alberta Environment and Resource Development were at our site and they were so impressed with it. Normally, when we drill the strat well, to abandon that site takes us 5 to 6 years, and you have to keep going back, put the top sell back on and let things grow. Well, they did basically told us this week that, "Hey, the way you guys have done it, the trees are still there. All you did was trample them and they'll come back. We'll give you a reclamation right away after you guys are done." Like that's incredible. And those are the stories we need to tell the average public on what achievements we're doing, not they do a lot for the shareholders, but we're also doing the right things to protect the environment and live up to our social responsibility. Thanks.

Okay. This is kind of a story of Pelican. So I wanted to go back to 1996. So this is the production plot. I love this property. We brought this property back in 1998. At that time, we thought this field would only recover about 6% to 7%, which is the dark blue wedge that you see there. And over time, we started waterflooding this field, so we got the production up even higher than we went to polymer flooding. And as I'm going to get into the next slide, we've got other things in the hopper to continue to increase this play. When I look at the full cycle returns on this play since 1996, we're looking at 15% to 20% after-tax IRR. And so that -- this is a great play. The SAGD projects takes us thousands of peoples to build. This is a fraction of the manpower, this is the easy stuff. And so don't get hung up on a quarter being lower or 2 quarters being low, look at the long-term picture in this play. This is a beautiful play and has got lots of potential. We've got lots of oil in place, close to 4 billion barrels, between the in-mobile and the mobile. So we've got lots of running room here, and I love this play.

Next. This chart is -- we don't start talking about stuff until we actually have results that we're very comfortable with. So even though we were encouraged with this hot waterflood that we've been doing, this is the first time we're actually showing you numbers. And you can see here, before the hot waterflood, the wells were doing about 30, 40 barrels a day. And now, they're doing some 50, 150 to 200 barrels a day. So this a huge success story. You're going to see more of this stuff coming up and our production increasing at Pelican. The other beauty of this hot waterflood is what didn't we get right with SAGD? What we didn't get right with SAGD, which everybody didn't get right, is that we don't know how to use the heat which is less than 100 degrees Celsius in our plants. That's wasted heat, and that's a lot of heat. 1/3 of the heat that we put into the reservoirs comes back as produced heat, while a lot of it that goes up in the air because we don't -- we can't transfer and make use of less than 100 degrees Celsius heat. But with this process, we could do SAGD on the Grand Rapids and we could put the hot water into the Wabasca. So there's synergies here. There's not a perfect overlap between the two, but enough that this will make it work. So that will add value both to the Wabasca and the Grand Rapids. So I'm really excited about this play working in. You're going to hear lots of things from us regarding the hot waterflood and hot SAGD, and the Wabasca plays are going to work together and add value for both of them.

This slide here is -- you've heard me before, we don't build oil plants. Oil is only a couple of vessels in our plant. So really, we build steam plants and water plants. The SOR, the reservoir dictates that. How you drill your wells, how you operate them, what technologies you apply, all that is controlling the SOR. So the oil rate is a calculated number, and you got to look at it on a project basis, not a roller pad basis. So really, and that's why we are focused on SOR because it directly relates to oil production and cash flow generating machine.

Next. Okay, I want to talk about blowdown. So we're actually one of the first projects to go through this phase. It has been done before. SAGD was augmented in the UTI facility and it was done there first. And so you see, for the first 6 to 12 months, you have this ramp-up period. Then for the next 5, 7, 8 years, you have this constant rate. Sometimes it declines with time, but more or less, steadies. And after that, we go to a ramp-down where we start injecting non-condensable gases. So we've been playing around with methane. We're also looking at CO2. We're also looking at air injection. And so those are the 3 things that we're looking at, and then we'll go to what we call full blowdown where we shut off the steam totally. Now if we didn't do this ramp down and blowdown, what you'll find is that SOR curve, it would steadily start to go up and it goes crazy after that to really high numbers. So if you want to manage the SOR, you do have to ramp this down.

The other thing you got to remember is only 30% of our rock is porous media. 70% of this stuff is stand. Sand has a very high heat capacity. So all that energy that's stored that we use to heat up that sand, you want to get that back to -- and so that heat comes back during the blowdown stages and it helps you recover this oil without any steam. So blowdown is a good thing. The question is how much of a good thing is it going to be, and how fast will this good thing come up. But it is a good thing. It is a normal thing to do, it makes a lot of sense and the whole industry is going to go through this because they have to. Otherwise, they'll start to have ridiculously high SORs.

Next. So really, what we're doing is we shut down a pad. Right now, we only have 1 pad at Foster Creek on full blowdown. We have 2 on ramp down, which is only about 7% of the production. So over time, what you're going to see is more flipping of this occurring where we're taking a pad that we're injecting steam on, go ramp down, blow down, and then we'll use that steam to start up the next pad. The goal in our business is always to run the steam plant full out. Steam in the well means oil out. That's as simple as turmoil recovery is. The max amount of steam you can generate, that's going to be the maximum cash flow you can generate, the maximum oil production. So again, blowdown is a good thing. And as the question is, that 7% of production, if we had 40% or 50% of that production on blowdown, you'd see a drop in our SOR, which means you'd see a kick in our oil production and our cash flow.

Next. I love this chart. It's a beautiful chart. It's the ramp-up is great, and really, we're putting our feet to that metal right now and growing it even faster. So this shows 2012 numbers. But really, in '13, we exceeded the high end of that scale already this year. And so we're just going to continue to grow this production. One of the key things I want to say here is we needed a lot of technical skill sets to get this production up, the manufacturing, the execution with excellence. But one of the things we're really focused on last year is, John talked about safety. It's #1 on our list. #2 is compliance on our list. #3 is adding value, but part of the adding value, we need to improve the culture. So culture, I'm telling you, today, is very important. And we're focused on having an innovative culture, and I'll get into that a little bit more. So as you are growing this business, you have to think about it differently and you have to make some tweaks. And so we're finding that 50% of our people will be here less than 3 years. You need to have culture to get them onboard really fast. Otherwise, and we're going to make mistakes. And so that's one reason we're focusing on it.

Next. So a lot of the other operators do EPCM. We don't really do that. The engineering companies do, I'd say, partly of the EP. We actually tell them what equipment to use, we tell them what the process flow diagram is. They do the detail engineering.

We like engineering companies that copy and paste well, because their templating doesn't change that often. The other thing is on the construction side. We've been doing that for over a decade now and things are going really well with the small contractor strategy. And basically, the third thing that we did was a miniscule module you heard, and we come a long ways that I can't think of any other project that has 0 rework. Christina, CDE are coming through like perfectly with little to no rework, so really proud of that.

The other thing we're really proud of is that we don't -- we're not happy with being good. The biggest hindrance to being great is being good. And so that's one of the lessons we learned in the last 12 months at Nisku. That geography was running really well, but in the last 12 months, we've cut our labor force by 20% to 25% and we've improved our productivity by 25%. So you always got to continue to challenge the status quo. And so that machine is even running better now. And I think in the future, what you'll see, as John showed you, that our sustaining capital, except as we build these projects, so we'll find a different way how to do the modules with maybe locally even. So we're going to continue to keep tweaking our manufacturing side.

Next. So these are 2 emerging plays, both in the regulatory hopper. We expect to get Grand Rapids approval by the end of this year, Telephone Lake by Q1. The beauty of the Grand Rapids is the indirects. That can eat your lunch when you're building these projects. Indirects are things like camps, roads, power lines, pipelines, things like that. So that's the beauty of the Grand Rapids. We -- our people are already there. Telephone is a huge resource, but we don't have infrastructure there. But it's a really big resource and it's got really good permeability. So once we get regulatory approval, we'll decide whether we go with one of these, both of these, what pace we go with, and so we'll give you more heads up on that towards the end of this year or the start of the quarter or the next year.

Next. So this is going to be our next biggest play to take off. I think the whole Borealis area is at least 3 Foster Creeks sitting over there. We bought this land. We weren't scared of the top water and I'll get to tell you a little bit on that one, but really, the reservoir quality here is 18 darcies. That's why we bought all this land because the permeability would drive SAGD, permeability would drive solvents and we believe that SAGD may not -- pretty sure, SAGD will not be the ultimate recovery scheme here. It's going to be combustion based and solvent based, but SAGD is a way to get the value chain kicked off and running, and that's what we're going to do here. So the 90,000 barrels a day, that's just the start. We've got lots of running room here. Like I said, at least 3 Foster Creeks sitting over there. And this is the area where we're adding the most contingent resource over the last 3 years and we're going to continue to increase that number from the 5 billion that you see here today to a higher number going forward.

Next. So let's talk about the dewatering. We started this project -- like I said, we can do SAGD without dewatering. It works just fine. We have Christina running with top gas, bottom water. We got Foster running with bottom water. So these other zones don't scare us. We've been able to manage around them pretty good. But what dewatering does is helps improve our steam to oil ratio by up to 30%. And so this was the first kind of its test in the world that I know of. We actually have a patent on it. So basically, what we're doing is producing the water, reinjecting most of it in the same zone and kind of creating a fence with disposal wells. And then all you're left with is sort of water which has a really high heat capacity or you're left with air. And so things are still going so well. We'll probably shut this thing down before the end of the year, and then we'll start it up when we get close to our first phase coming onboard if you need it.

Next. Just a quick update on the Grand Rapids. The first well didn't go too well for us. I don't really pay that much attention on the first well. But the second well so far is looking really good. We started that in February. The key thing is trying to get a 1,200-meter long well to be productive and that's not as easy at it sounds. So you need a consistent reservoir. This is under pressure. He's got top water. So I think that's a big achievement. The second well pair is going really well. Unfortunately, we have some constraints on the facility side with a high temperature coming from this project. And so we'll have that resolved here by the end of the third quarter. So I'm hoping for production to pick up on the second well. Today, we're doing about 200 to 300 barrels per day. I'm not worried about the steam to oil ratio, just want to see if we can get to the 600 barrels per day by the end of the year. That would be great news. But so far, the second well pair is looking really well. And the other thing I'll tell you guys is that these are normal things that happen when you do pilots. Like I remember the first well pair at Foster Creek, that when we're drilling the injector, it hit the producer and reacts and we cemented it in. And so stuff happens. And so you shouldn't get hung up on one well here or there. The key thing is, do we have the confidence that we can make it work? And yes, we do have the confidence we can make it work.

So it's my last slide. Really, in our business, we got to continue to drive the innovation. And as you see there, that's a picture about 3 weeks ago of -- we have -- what we call our Innovation Summit. The 1,800 people for 2 days did absolutely no work. They were at this session learning about what the rest of the company is doing, the innovation. Those posters you see there are people talking about the things that they're proud of, that they're working on. Other people get to talk to them. It's their networking. They're looking for opportunities. The guy working on gas is saying, how good do I work in the oil sands? So there's lots of technology and then we're walking the talk. We can't just say, our culture is going to be integrated. You actually got to show it, that you got to take 1,800 people and bring in motivational speakers, talk about safety and talk about innovation and how things can improve. That's what you need to do. I'm not sure if there's other companies out there doing this, but we're pretty proud of our Innovation Summit because those 50% of the people that just joined our company in the last 3 years, this is what shows them that management is not just talking, that we will listen to people, we will support them and fund them and move this technology forward. Like I said, we just finished the first inning, we've got a long ways to go. I think I'll end with that and I'm going to get some of my guys to come up and I'll introduce them. So we'll start our Q&A session now.

So the first guy to my left is Dave Moody. He's our seniors VP and he looks after Foster Creek. Next to him is Al Reid. He's our Senior VP of Christina Lake assets. Next to him is Dave Goldie. He's the VP of Pelican Lake. And then last is Ian Young, who looks after our new and emerging plays. So I'm known in our company for having a lot sayings. Well, one of them is to hire people smarter than me. So these guys are all smarter than me, so we'll open it up.

Harbir S. Chhina

Better ask some questions because I don't got any good jokes today.

Dean Highmoor

My name is Dean Highmoor from Investors Group. I just have a stupid question on geology. Where did the water come from at Telephone Lake? And is there any risk of further water inflow, let's say, just thinking about what Conoco went through at Cigar Lake, were they trying to get water out of their mine and they had a surprise inflow? Is that a risk or concern here at all?

Harbir S. Chhina

Okay. First of all, the real question should be, where did the oil come from, because the water was there right from the beginning. So this oil migrated from the foothills of the Rockies. It was conventional oil. And as it went higher and higher, the freshwater is what biodegraded this oil. And so the methane was released and you're left with all this stuff. So really the fact that the closer you get to the surface, the more the probability is you're going to have more and more water. And the depth of Telephone Lake is only about 160, 180 meters versus Foster Creek, which is at the lower end of the Athabasca deposit is more like 450 meters. So it's the shallowness of these reservoirs that's causing the water issues to be more prominent. Anybody wants to add anything?

Unknown Executive

Yes, I'd just add that at Telephone Lake, we have an extensive groundwater monitoring program. We have 45 wells, and that's in very early stage projects. So compared to Foster Creek, I think we have twice as many water monitoring wells at Telephone Lake as we do at Foster Creek, because we really need to understand and monitor that groundwater. And we do have a very thorough understanding. We've had a great working relationship with Alberta Environment and Sustainable Resource Development. They're very impressed with our understanding, the modeling we've done up there. So there should be no surprises because we have extensive 3D modeling, we have pressure monitoring, we have sampling ongoing all the time. So no worries about unpleasant surprises in the future. And I mean, what's more, the dewatering pilot is working really as expected. Usually, with a pilot is how they say it, you get some kind of unpleasant surprises, you get some things that go wrong. But the dewatering has gone exceptionally well and very much as predicted.

David McColl - Morningstar Inc., Research Division

Dave McColl with MorningStar. Just a question on the regulatory process. With the, I guess, combination now or removal of the ERCB and new Alberta regulator being formed, is there any concern that some regulatory uncertainty could be thrown into the mix for your current applications? Or is it all still kind of steady as it goes from here?

Harbir S. Chhina

Maybe, Al and Ian, the 2 of you could get that one?

Al Reid

Yes. I think we look at the formation of the AER, the Alberta Energy Regulator, as being a very good thing. It brings together agencies that had different mandates and it brings them under one umbrella. And so what we see is that rather than something sitting in one agency and getting dealt with and another issue sitting in another agency and getting dealt with, it will all be dealt within a single agency. That said, as they bring those 2 groups together, we expect there will be the normal growing pains, for lack of a better word. But we don't think that, that will, in any substantial way, affect the regulatory timelines that we think we're likely to see. And we think over time, in fact, there'd be a lot of efficiencies that we'll realize out of that process.

Ian Young

Yes, I don't have too much to add other than with the 2 major applications we've got underway right now, we do have constant interaction with the regulators to ensure that they totally understand everything we're trying to do, preempt any complicated questions. So we provide all the information and we've got that ongoing dialogue with both regulators today and moving into the one regulator. And we're very comfortable that they understand the projects well and that things are moving along as we expect at this point.

Harbir S. Chhina

Mike's got a question.

Robert Bedin - ITG Investment Research ULC.

Rob Bedin with ITG Investment Research. In regards to Telephone Lake, given the dewatering is obviously very permeable interval, shallow, low pressure, what does that imply in terms of potential deep zone for recoveries below, from the resource below?

Harbir S. Chhina

Ian, take that one.

Ian Young

Well, actually, the reservoir zone itself is highly consistent and it's all saturation, which isn't always the case. So what you're worried about within your oil zone is different, its heterogeneity with the oil saturation. But oil saturation is pretty consistently higher throughout Telephone Lake. So we're less worried about deep zones within the oil zone than we would be in other areas, in fact.

Harbir S. Chhina

The other thing I might add is Foster and Christina are running about 2,000 to 3,000 KPA. When we looked at the optimum pressure to run SAGD, we actually came up with a number about 800 to 1,000 KPA. And so Telephone Lake is sitting at 700 KPA. So it's actually closer to where you want to run SAGD, because that gives you the lowest SOR. The oil rates won't be that impressive, but overall, the economics would be better.

Robert Bedin - ITG Investment Research ULC.

Right. So the oil rates will definitely -- so that's going to impact spacing recovery factors, et cetera, as well if there's no...

Harbir S. Chhina

Yes, more impact recovery factors. But yes, the spacing and the time that the well stay will change. Mike?

Michael P. Dunn - FirstEnergy Capital Corp., Research Division

Mike Dunn with FirstEnergy. Just a brief question, on your Cenovus -- excuse me, your Christina Lake debottlenecking, I don't think you've mentioned a capital intensity number. So just thoughts on the cost around that.

Harbir S. Chhina

Yeah. Al, how low is it going to be?

Al Reid

We're looking at it right now. We think it'll be in the range of about $10,000 per flowing barrel.

Harbir S. Chhina

Is that low enough, Mike?

Peter K. Ogden - BofA Merrill Lynch, Research Division

Peter Ogden with Bank of America Merrill Lynch. At Pelican, can you explain maybe on a reservoir level what's happening, why we've seen the delays or if there are delays? And is it a waterflood? Is it -- why would you drill low pressure pads versus high pressure pads? Exactly what the mechanism is there and what you hope to improve?

Harbir S. Chhina

Yes, I'll let Dave answer that.

Dave Goldie

Mike, thanks for the question. So I think we are -- certainly, we are behind by a few months, several months in terms of the response we're expecting to get out of the reservoir. We have a total of 14 pads on now. Of those, 9 are low pressure, 5 are high pressure. So the high pressure pads, just to give you a little more background, they're pads that are previously at the wider space it had been on a waterflood or polymer flood. So what we tend to see with those is the response is very quick. When we do the infill at 50 or 67 meters, generally, we start at high rates, we start injecting polymer and they build up to their peak within 6 months, say. So of those 5 pads, 3 of them now have peaked and are on decline. The 9 low pressure pads, those are pads that were previously on primary production. So they haven't seen any water flood or polymer flood before. The issue we're seeing with those is it's taking longer for them for the pressure to build up so that we see a response from the waterflood and the polymer. So to give you an example, in many respects, Pelican Lake is more like an oil sands project in terms of its response. So on those pressure pads in particular, the lag between capital spending and when they reach their peak is up to 3 years. So we drill those pads, we put the infill wells on, the low pressure ones, they produce at low rates. And then we start injection. And it may be actually a year or more before we see any response because it takes time to build up the pressure in those pads. And it may take, as I said, up to 3 years before we get into peek. So those 9 pads that we've now put on, none of them have reached peak. In fact, over 1/2 of them haven't had any response yet. So the fact is for Pelican Lake, you have to look at it as a longer-term project. There is a significant lag between capital spending and production. So the capital we're spending today, we're not going to see the benefit from for a couple of years. So a couple...

Peter K. Ogden - National Bank Financial, Inc., Research Division

Why drill the low pressure pad versus the high pressure pads?

Dave Goldie

So a couple of reasons. Actually, the returns on the low pressure pads are better in terms of the IRR. We mentioned what our investment criteria are. The reason is that the high pressure pads, since they previously had water flood and polymer flood, they've already -- they're more mature. So while you get a high peak rate, they also decline more quickly, whereas the low pressure pads take longer to build up but they have a lower decline and last longer. So what we were trying to do, we're now into roughly 18 months. We started tying in our first pads around 18 months ago. This first phase of the program here, where we're trying to get representative pads from all parts of the field so we can step back now and watch the response and understand what's the variation between the high pressure and the low pressure, are there any differences between different parts of the field. So we want to take a representative sample. And as we wanted the response that will guide how we continue our development going forward, whether we want to do more high pressure, low pressure, in which order, that type of thing.

Harbir S. Chhina

I mean, the 2 key things that -- normally what the reservoir has pushed, we have piloted 25 meters that's going well, and the response of the existing water flooding tells me that the performance is good. So this is only a question of timing. It's not a downhole issue at all. We think we've got a solid plant. I'll take one last question.

Christopher Feltin - Macquarie Research

Chris Feltin from Macquarie. Just a question on what well is actually and I wouldn't mind your view in terms of timing and what your -- just in terms in the life cycle of a well pad, our future basis can have wedge wells right out of the gate or is this something that you're going to be looking at doing later on in the life cycle of the well pad?

Harbir S. Chhina

Dave, you haven't been talking. You take that one.

Dave Goldie

So I mean, generally, I mean wedge wells have to be put in after you get enough heat in the reservoir. So that's the bottom line is that wedge well isn't going to produce because of its position between the 2 pairs until you get enough heat in the reservoir. So you're looking to get that much heat and we've drilled some wells early to test that out and we've drilled some wells later to kind of optimize the timing. And in general, you're looking at 3 to 4 years after you start up the pair. And certainly, for our development, it is the deep hole for Foster Creek we'll be doing wedge wells in every pad.

Christopher Feltin - Macquarie Research

[Question Inaudible]

Harbir S. Chhina

The question is are there any drilling issues with the wedge wells?

Dave Goldie

Right. So I would say in general, not. We place the wedge wells kind of back of the existing pairs. So by the time we hit the zone, we've got drilling circulation and stuff to cool off the bits and stuff. So we haven't had really drilling issues with the wedge wells, no.

Harbir S. Chhina

Okay. I'm going to close it there, times up. So thanks guys for coming up. I think Brian is going to come up and have some closing remarks. Thank you.

Brian C. Ferguson

Well, thanks, everyone. We are approaching the end of the formal presentation now. I hope that we have explained to you adequately why the Cenovus executive are very confident in our future and our ability to continue to add value for shareholders. Based on the plan that we have shared today, we believe that the outcome of continued execution will be that 11% compound average growth rate in production through 2023. We also remain on track to reach our previous goal of 0.5 million barrels of oil net to Cenovus by 2021. Our Foster Creek and Christina Lake assets are exceeding expectations.

Christina Lake Phase E remains on budget and on track for first production in just a few weeks. We've defined an additional 22,000 barrel per day gross at Christina Lake, which we plan to bring on in 2015. We have highlighted further details of our marketing and our transportation strategy. We do not have all our eggs in the Keystone XL basket.

Over the long term, we are targeting to move up to 50% of our marketable production volumes by a combination of pipeline and rail firm service. We expect to begin railing bitumen next year, 2014, and exit the year with about 30,000 barrel a day of rail capacity.

Our strategy remains consistent and we continue to deliver on our commitments. John provided an update for you on our operations. While we have been successful in the first 3 years of our operations, we've got lots of work ahead of us and we want to remain focused on execution.

Ivor reviewed our emerging oil sands plays and discussed some of the new pilots and technologies that we're working on. We believe technology will continue to drive value for many years to come for Cenovus and remains an important part of our business as we move forward. Don talked about the market access and integration strategies. Having firm commitment on pipelines and capacity on rail will help improve our margin as we grow production.

We believe this portfolio approach will reduce our dependence on any one transportation solution. I re-illustrated how our financial strength and flexibility in our capital plans will provide us with the resilience to compete in all phases of the economic cycle. We remain focused on total shareholder return, growing our dividend. I had questions earlier about share buybacks, we'll think about that.

So thank you for your participation in today's investor day, and I'd be pleased to take 1 or 2 last questions before we break for lunch and you'll have an opportunity to interact with everybody there as well.

Unknown Analyst

Brian Krissdale [ph] from Kootenay Capital. A lot of the marketing slides and commentary has been on market access and just arbitraging differentials effectively to get to markets where there's incentive to do it. If you step up at a country level, a lot of the initiatives really were just still captive to the U.S. market. What do you see or how do you see it evolving? We heard about full value chain, we heard about conversion capacity in Asia setting the long-term heavy oil price. When do we truly see market diversification for your crude to Asia and other points?

Brian C. Ferguson

So the critical component there is access to tidewater. And once we can get to tidewater, then we can literally access any market in the world, but then it becomes a question of the economics, the margins. Our business is, in its essence, no other different than other business. It comes down to what your volumes are, what your margins are. So what we are focusing on, on the margin side is, obviously, driving down cost. John talked about that on the margin side also. Every dollar per barrel increase in realized price we get adds value in our margin. I won't give you a specific number, but I can tell you that we experienced a very significant uplift on every barrel that we sold at the dock in Burnaby last year because we do have firm capacity on the Trans Mountain pipeline system. We're certainly not sitting and waiting for pipeline approvals, regulatory approvals. Don talked about rail. I think that, that is something that's going to demonstrate amazing flexibility for industry and for Cenovus. What's really important to me, obviously, is we're an important part of the industry, so we want to see industry solutions. But what's even more important to me is making sure that Cenovus is at the head of the queue in any of these transportation solutions compared to our competitors here in Canada

Unknown Analyst

Brian, just another market access question. Your earnings cash flow business model has benefited greatly from your innovation with Wood River and Borger. Is there a risk as widening comes on, Flanagan South and all the U.S. options kind of ramp up, that the pricing for WCS in that greater Wood River area could be meaningfully stronger than it is in, let's just say, hardest to your Edmonton, taking away some of that integration benefit? Or does Wood River directly get its crude at Edmonton or hardest deep price adjusted for transportation, of course?

Brian C. Ferguson

So I think that is probably a question that I should either let Don or Paul Reimer respond to specifically. Paul?

Paul Reimer

What we found is that Phillips 66 who buys the crude for our Wood River and the rest of their refining universe is a really good business partner for us and can move that crude to a variety of locations. But that said, BP and the other large refiners in the area are also great business partners. We anticipate that between the 2 partnerships, ourselves and Phillips 66, that if we do the best job we do marketing our oil, we're going to get the best price we can for our production and the Phillips 66 does the best job they can do for buying crude for Wood River, they're going to get the best price. So in aggregate, we actually are 1 plus 1 is greater than 2, and that's how we've seen the partnership were in the past and we expect that will carry on in the future.

Brian C. Ferguson

Thanks, Paul. Well, thanks very much. I think what we'll do now is adjourn. The lunch is, if you follow that way around to the other tip of the building here on the West side, that's where lunch will be served and we'll be happy to -- you can interact with any of the executive team or the senior vice presidents at that point. So continue with the questions. Thank you very much. We really appreciate your continued interest in Cenovus.

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