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Executives

Janet Craig - Vice President of Investor Relations

Kevin J. Reinhart - Chief Executive Officer, Interim President and Director

Una M. Power - Interim Chief Financial Officer and Senior Vice President of Corporate Planning & Business Development

Analysts

George Toriola - UBS Investment Bank, Research Division

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Menno Hulshof - TD Securities Equity Research

Philip R. Skolnick - Canaccord Genuity, Research Division

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

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

Andrew Potter - CIBC World Markets Inc., Research Division

Robert Bellinski - Morningstar Inc., Research Division

Kam S. Sandhar - Peters & Co. Limited, Research Division

Mark Polak - Scotiabank Global Banking and Market, Research Division

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

Nexen (NXY) Q2 2012 Earnings Call July 19, 2012 9:00 AM ET

Operator

Good morning, ladies and gentlemen. Welcome to Nexen's Second Quarter 2012 Conference Call. I would now like to turn the meeting over to Janet Craig, Nexen's Vice President of Investor Relations. Please go ahead, Ms. Craig.

Janet Craig

Thank you, Sarah. As a reminder, some of our comments today will be forward-looking in nature. Our earnings release provides more information about these statements and our AIF describes our various risk factors. We have a few slides that supplement our disclosure again this quarter. They are available on our website. You do not require them to follow our remarks this morning.

In a moment, I'm going to turn the call over to Kevin Reinhart, Nexen's Interim President and CEO. Joining him is Una Power, our Interim CFO. Kevin will provide an update on our operation results and progress against our strategic priorities, and then Una will provide some comments on the financial results. Kevin and Una will then be available to answer questions.

I'd like to remind everyone, if you have detailed modeling questions, my IR team would be pleased to respond to those questions after the conclusion of the call. With that, I'll turn the call over to Kevin.

Kevin J. Reinhart

Thank you, Janet, and good morning, everyone. As always, we appreciate your time and interest this morning. I'm going to keep my comments quite brief as I'm assuming everyone has had a chance to read our news release.

Last quarter, I spoke about 4 topics that are very important to our business for 2012 and beyond. This quarter, let me again make a few comments on each of those 4 items.

First, we had a strong cash flow despite lower global oil prices. Cash flow was up 6% to over $700 million, primarily reflecting the inclusion of the Usan in our financial results for the first time. Netbacks at Usan are very strong. This quarter, they were almost double our corporate average net back from last year. Global oil prices were lower than the first quarter, but our waiting to Brent continues to benefit us compared to peers who have production link to either WTI or further discounted Canadian benchmark crudes.

Second, we met our production guidance again. We came at the midpoint at our guidance range which was slightly higher than what we had expected last conference call. This was due to a strong reliability run at Buzzard and good production late in the quarter from the Telford field in the UK.

We ramped up production at Usan during the quarter and we averaged about 100,000 barrels per day gross in line with our guidance. The Gulf of Mexico was at the low end of our guidance, as we previously indicated we had expected.

And lastly, we saw higher production in Canada, because of the delay in closing the shale gas joint venture. We have started the process for closing and expected to be concluded before the end of July. This will generate over $800 million of cash, including the reimbursement of capital we've incurred on our partner's behalf since the effective date of last July.

A third key business driver for us is the progress we are making towards filling the upgrader at Long Lake. As we disclosed a few weeks ago, we are ahead of schedule on pads 12 and 13, largely due to some technology advances that shorten the steam circulation phase. We are now generating record steam levels and are getting close to the capacity of the existing steam plant. As a result, since we move forward, we will direct our steam to the best available reservoir and start shutting in some of our poorest wells. This may cause a different production in the short term as the new wells ramp up, but it will pay off quickly with steam going into the better part of the reservoir.

We're also just about to start drilling on pads 14, 15 and K1A. These pads are on track to be steaming in late 2013 and into '14. This schedule should allow us to fill the upgrader by late 2015 or early part of 2016.

The final thing I'd like to emphasize is that we continue to build a solid foundation for future growth, particularly in the Norphlet play in the Gulf of Mexico. We had another success in the Appomattox area this quarter. Our appraisal of the south fault block found a very thick oil column and excellent reservoir quality, which is at the upper end of what we were expecting. We are in the process of assessing the impact on our previously reported discoveries of 150 million barrels net our interest.

The rig is getting ready to drill a sidetrack in the northwest fault block to test whether the oil stayed trapped there also. The rig will then continue to drill in the area doing a combination of appraisal and further exploration. And we have as many as 5 more wells planned over the next 12 months. We are obviously very excited with the story that is unfolding from this area in the Gulf of Mexico.

So no business is entirely free of challenges and we did have a couple this time around. Long Lake production in the second quarter was slightly lower than the first quarter, mostly because we produced only about 30,000 barrels a day in April. In that month, we had some planned maintenance and a couple of power outages that brought the plant down and disrupted production and steam generation.

In May and June, we averaged over 35,000 barrels a day, much closer to what we have expected. Usan is slightly below the midpoint of our guidance as a result of well performance and delays in the timing of new wells. We have assessed the well performance and are confident that this is a completion rather than a reservoir matter. With this knowledge, we are getting ready to start drilling additional development wells.

At this point, I'd like to turn it over to Una for some comments on the financial results.

Una M. Power

Thanks, Kevin. We were able to grow cash flow again this quarter, increasing it by 6% despite a 6% decrease in our realized prices. This primarily reflects the addition of high margin barrels from the Usan field.

Given strong production at Buzzard this quarter, you will notice the difference between production and sales in the U.K. We exceeded our production expectations and most of the excess went into inventory. We had 700,000 barrels of inventory in the U.K. at quarter end and 190,000 barrels in inventory in Nigeria. These barrels aren't in our Q2 cash flow, but they will show up in future quarters.

We continue to generate significant value from our long-term pipeline capacity to the West Coast of Canada. Year-to-date, we have generated more than $70 million of cash flow from this source. These gains are reflected in our marketing results in our financial statements.

Turning to our netbacks, they continue to be very strong at almost $45 of BOE, with the addition of Usan. Our realized price declined $6 quarter-over-quarter, but our net back dropped to only $1.

Net income also decreased from the first quarter as we booked dry hole cost related to the unsuccessful Kakuna well in the Gulf of Mexico. Looking forward, we will see a dipping cash flow in the third quarter due to schedule turnaround. Depending on how we see prices move, the fourth quarter has the potential to be quite strong on the cash flow side. With that, I'll turn it back to Kevin.

Kevin J. Reinhart

Thanks, Una. So let me close by mentioning a few of the things you should watch for during the rest of the year. We are on track to meet our production guidance for the third quarter and the full year. Just a reminder that we have some big turnarounds coming up in the third quarter. At Buzzard, we plan to start the turnaround in early September. We originally thought it would start a little bit earlier. As a result, it could affect the third quarter production a little bit less. In the fourth quarter, a little bit more than what's in our guidance.

At Long Lake, the length of the turnaround is going to be an important driver of production rates for the third quarter. We have planned for 3 weeks of SAGD downtime and about 6 weeks for the upgrader. We expect to have the SAGD production back up in early September and the upgrader just before the end of the quarter.

Now that we're halfway through the year, we're also starting to get a better idea of how the rest of the year might play out for some of our major assets. We've been well within our guidance for Usan so far this year, but a bit below the midpoint in each quarter. The current information suggests that the most likely scenario is a continuation of that trend for the third quarter and the full year.

Long Lake should be positioned for a very strong fourth quarter. We could achieve the upper half of our guidance with the current production of 35,000, 36,000 barrels a day, plus pad 11 continuing to ramp up, pads 12 and 13 ramping up for several months and some contribution from a few infill wells and redrills that we have done. Of course, Buzzard reliability is a key variable and one which we are actively managing to achieve top-tier performance.

Switching gears a little. There's a lot to watch for in the exploration front over the next 6 months as well. The North Uist well is currently drilling west of the Shetland Island in the North Sea. BP is the operator here and we have a 35% interest. The well is a big target for us, but it's still an exploration well with related risks, and we should see the results of that during the third quarter.

In Nigeria, we just started drilling the Owowo West well. This well has a high chance of success for an exploration well, given the success on the nearby Owowo South well. Results from this well will probably come sometime this fall.

We also recently drilled an appraisal well in the Buzzard Northern Terrace area. It was successful and we plan to do some more drilling to firm up our estimates of the reserve's impact.

So as you can see, there is quite a bit going on over the next few months.

Thank you for listening this morning and I'll now turn it back to Janet to get the questions started.

Janet Craig

Thank you, Kevin. And Sarah, we're now ready to poll for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of George Toriola from UBS.

George Toriola - UBS Investment Bank, Research Division

I have very three part question here. The first is around the operating efficiency at Buzzard. I guess that 88% efficiency, compared to the 85% that you were projecting, the question, what have you done different here, given that the turnaround is still ahead of you? That's the first thing. Second is, what do you believe is a sustainable level of efficiency coming out of that facility? And the third is, are there learnings from Buzzard that you can deploy at Long Lake? And at Long Lake, from here on, are the issues strictly that of visible quality and once that improves, they're going to see the volumes improve or there are still issues around surface equipment as well?

Kevin J. Reinhart

Thanks, George. With respect to the Buzzard production efficiency that we achieved. At this point in time, I think I've described in the past that we've undertaken some efforts to improve initially communications amongst the various teams that are working on, on the various aspect of the whole facility, whether it's reservoir, whether it's water injection, whether it's the equipment above ground. The efforts around communication are paying off quite significantly. Managing the facility so that we're not pushing it to its extreme all the time also helps to provide some reliability. We have several other initiatives that we're just in the early stages, like getting through the maintenance backlog, and we haven't even started to see the impact of that. We're in the preparation stage for it and we'll undertake that later this year. And so we expect to see continued improvement with respect to Buzzard efficiency. The other thing I'd caution is it's a short period of time. So over the 3-month period, we were well above the 85%. But when you're dealing with a short period of time, if we have a couple of down days, that production efficiency could go back down relatively quickly. So just be a little bit careful on a short-term trend here. We are doing everything that we possibly can in order to keep it above the 85%. But it is still somewhat volatile and we'll watch that over the next several quarters. In terms of production efficiency, our target is to get it up into the 90% range. And that would certainly make a top-tier performance if we can get it over 90%. But that is the objective that we're driving towards. And the biggest contributor there is to get through the maintenance backlog, so that we're out in front of issues happening rather than doing repair work after. In terms of your question regarding Buzzard and Long Lake, we have various initiatives, one called operation excellence programs, and we share those ideas and learnings across the various organizations as to how we manage various pieces of equipment, how we communicate between the various teams. So at this point in time, we are sharing some of the learnings. But right now, at Buzzard, the production efficiency there is really around the equipment. Whereas at Long Lake, what we need to do is focus on the reservoir and get that moving up there, and we've talked quite a bit about what we're doing on the reservoir to move forward there. So we do share these things through operational excellence programs and try to learn from each other across the entire organization.

Operator

Your next question comes from line of Katherine Minyard from JPMorgan.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Just quickly, and thinking about the Gulf of Mexico. I know that, Kevin, you mentioned that you've got about 5 wells to be drilled over the next 12 months. You've had a lot of success in that region. I can appreciate that Shell is the operator and maybe making the ultimate decisions, but to the extent that you can share, as we look for sort of signposts and what we've been looking to see as you and Shell move from drilling an appraisal to kind of formulating a development plan, what's your thought on the timeframe we'd be looking at? And what are we looking to see in terms of just some of the key milestones that will just lead us to basically arrive at that point?

Kevin J. Reinhart

Sure. There are several things to be watching for here. As we've mentioned before, we've already discovered enough resource here to be confident that this is -- this supports a standalone development. So we have concurrent activities going on really in 3 fronts. One is appraisal drilling to firm up the resource that we've already discovered so we can proceed with development planning. We have continued exploration on prospects in the area. And the third project that we have underway is to advance our development plans. And so watching for milestones in each of those areas, clearly on the development side, we're driving towards a sanctioning date sometime in 2014. So we will continue to keep the market apprised of the progress that we're making on that front. But don't expect to see anything until 2014. In terms of the appraisal and exploration drilling program, each of these wells take roughly 90 days to drill, although many of them we drill as a sidetrack out of the well bore so they could be a little shorter. So again, we will continue to let you know which wells we're drilling and what kind of results we're seeing. Initially, we'll talk about directionally what results we've seen. But each time we have new information, we put it back into our models to determine what the impact that has in our resource estimate. And that's the phase that we're at right now with respect to the appraisal well that just drilled into the south fault block, as we are assessing what the impact on reserves is. We know it's a positive impact, but we don't know the magnitude at this point in time. So I'd continue to watch for the drilling activity and whatever we can say on the development plans, we will share with the market.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay. So it just sounds like -- is it possible then that there might be multiple developments? Or would we be looking at one potentially large development that then were kind of backfilled as subsequent resources were found? Or is that yet to be determined?

Kevin J. Reinhart

Well, this -- conceptually, the intent would be to go with an optimum size of development rather than one massive development, and that's why we're able to start the development planning now, even though we haven't done all of the appraisal work and the exploration. So we believe there's a maximum size of facility that we should be building and that helps with the construction and it helps with the operation of that facility once it's up and running. We believe that we've got enough resource to already support that first one and that's why the planning is underway. If we continue to have success here as we expect, we will look at putting a second facility in place. And so I think it's more of the latter of your observation as we will continue to add facilities as the resource base justifies rather than going with one massive structure.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay, great. And then can I just ask a quick clarification on just the volumes that are going to the West Coast? What kind of quality of crude should we be thinking about you capturing the North American to global differentials on? Is that a heavy crude or is that a light crude?

Kevin J. Reinhart

We have the capacity to switch crudes along the way -- not along the way, the pipeline. But each month, we're able to select the crude quality and we tend to focus, obviously, on those that provide the greatest differential at that point in time, recognizing who the buyer might be and what slate they'd like to have. Typically though, we're moving heavier crudes to the West Coast because that's got the greatest value for a refiner to buy and get some upgrade on that differential. So we tend to be selling heavy crudes.

Operator

Your next question comes from the line of Menno Hulshof from TD Securities.

Menno Hulshof - TD Securities Equity Research

I'm going to start on a question on Usan and then I'm just going to move to the North Sea. On Usan, what can you tell us in terms of well performance to date relative to, say, capacity? I'm assuming they're still being choked back to some degree. And then what are you thinking in terms of exit rates for 2012 to the extent that you can comment on that?

Kevin J. Reinhart

In the second quarter, we averaged about 100,000 barrels a day, maybe a little bit more at times from the 7 wells. We're -- those numbers are a little bit below what we had expected. As I mentioned, we've worked through that and we're confident that this isn't a reservoir problem. It's in the completion technique. And as we go forward and drill some additional wells, we'll change the completion method. So exiting the year, we expect to have another 2 wells on stream before the end of the year. And right now, we're going through the process of reducing the gas cap pressure. And so we will see a little bit of a decline in production over the remainder of the year and then we will start the gas injections, which then regenerates some of the production going into next year. So you're going to see a little bit of volatility here as we add another 2 wells before the end of the year. Although the gas cap pressure is coming down, then gas injection should start to move that back up again as we go into '13 and we drill a few more wells in the early part of '13 to add to production. So it's a little premature for me to call where our exit rate would be, but I would say that we continue to be confident with respect to the guidance that we have given you for the fourth quarter for West Africa.

Menno Hulshof - TD Securities Equity Research

Okay. Do you think you will need -- so it sounds to me like you'll need another 2 to 3 wells to fill the FPSO?

Kevin J. Reinhart

At this point in time, I wouldn't be looking that we're going to fill the FPSO right away. We still have lots of development drilling to do in this area and we're going to prioritize the development in the area. And what we need to see is how the wells decline combined with the new wells that we're bringing on. So at this point, again, it's premature to call whether we're going to achieve full capacity here. I'd be a little more cautious on that at this point in time.

Menno Hulshof - TD Securities Equity Research

Perfect. And then moving over to the North Sea. What can you tell us about current rates at TAC? Is it in the, call it, 5,000 to 6,000 range or would it be slightly lower than that at this point in time?

Kevin J. Reinhart

Yes, the TAC well at Telford is -- that come on relatively strong at something like 10,000 barrels a day. But these are relatively small areas that they're draining. And so they come on and they go into decline pretty quickly. So today, we'd be more than 5,000 or 6,000 barrels a day, but perhaps over the rest of the year, that might be a reasonable average for the next 6 months. We have plans to drill other wells just like it. There is the D and the E wells that are in the planning phases to be drilling. So this is a lake-like field and what we're finding is little pockets of oil trapped in various places and the TAB and the TAC wells have been proven to be very prolific, but they're not long-term production-rate wells.

Menno Hulshof - TD Securities Equity Research

And then very quickly on Northern Terrace, I don't think you've released a reserve estimate for that discovery?

Kevin J. Reinhart

That's right, Menno. We have drilled the first well. We were encouraged by what we saw. We have just started to do a drill stem test on that well. And then we have a couple of appraisals to test. This is a pretty big area that's up there and we don't -- we're trying to figure out the connection with the regular Buzzard reservoir. And so we're not really sure yet how widespread the aerial extent of the oil in this reservoir. So we have a little bit of appraisal work to do here yet before we can narrow in on a resource range. But that's good news. We're pretty excited about what we see here.

Operator

Your next question comes from line of Phil Skolnick from Canaccord Genuity.

Philip R. Skolnick - Canaccord Genuity, Research Division

On Usan, has a rig returned there yet? Or if not, when do you expect it to?

Kevin J. Reinhart

So we have a rig that -- we actually had 2 rigs there. One was a service rig and we're not bringing it back. We have a second rig that is doing the drilling program and that was the plan all along. We have another rig that is drilling the Owowo West well at this point in time. So we basically have the 2 rigs going and there will be a combination of exploration and development drilling that we will do and some appraisal drilling in and around the Usan area. So those 2 rigs will be busy doing all 3 of those drilling programs.

Philip R. Skolnick - Canaccord Genuity, Research Division

So you do have. So when did that start up then to drill the remaining 2 that you're talking about?

Kevin J. Reinhart

So we're starting to drill those now and so we should be able to have those on sometime later in the third quarter.

Philip R. Skolnick - Canaccord Genuity, Research Division

Okay, great. And moving onto the impacts to JV. What caused the delay of closing that?

Kevin J. Reinhart

There was a financing condition. The buyer wanted to obtain cheaper financing, government-supported financing. This is from the government in Japan that basically subsidizes, if you will, energy imports into the country. They were waiting for that approval and that got caught up in the budgetary process. So the only way the government could approve it was part of their annual budget. That budget is working its way through the regulatory process or the parliamentary process there. And it's going relatively slowly as a result of the minority government and a lot of the fiscal challenges, Japan, like a lot of other countries are facing. Given that the time is dragging on, INPEX has indicated a willingness to proceed with closing irrespective of that approval. And that's why we have started a process for closing and we expect to have it done before the end of this month.

Philip R. Skolnick - Canaccord Genuity, Research Division

Okay. And finally, can you just outline what the technology startup changes at Long Lake that you did to help out with the ramp up at '12 and '13?

Kevin J. Reinhart

I won't get into the specific details because some of these is proprietary knowledge. But I think what's important to understand is obviously, the important thing is how quickly you get steam energy into the ground. And when we start up the circulation phase, we're using both well bores, both the steam injector and the producing well. And so the energy that we put in there initially can be inefficient just because we're using the production well bore temporarily. By changing the technology, we were able to get more intense energy into the reservoir quicker and therefore, shorten that circulation period from a typical 90 to 120 days down to 70 days. So this isn't something that has lasting benefits in terms of production rate and SORs in the future, but it certainly reduces the time that it takes to get these things on production at the front end. And moving from 90 to 70 days even is a substantial improvement, both in terms of cost and time.

Operator

Your next question comes from the line of Arjun Murti from Goldman Sachs.

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

Kevin, just a follow-up question on the Usan recompletion issue, will you be recompleting those wells and incurring any cost or you're just going to live with, I guess, maybe slightly lower production than you initially expected from those 7 wells?

Kevin J. Reinhart

That assessment is underway right now. Keep in mind that rig costs in these areas can be relatively expensive. And so we will give some consideration to whether we do asset stimulations and so forth to clean up the completions a little bit. But there is a cost involved in that and so we're going through and doing the assessment to understand whether it's economic to do that or to live with a slightly lower rate. This does not affect the recovery factors and so it doesn't impact on reserves, but it does impact a bit on the pace. And so it's really an economic decision of the incremental cost of the workover versus how fast we get that oil out.

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

If you're doing 100,000 barrels a day from 7 wells, you would have expected to have been closer to 120, 130 from those 7 wells if it had been completed as you originally thought?

Kevin J. Reinhart

Well, we were -- when you start up a new reservoir, there's a wide range of uncertainty as to what you get from those wells. So I'm not sure that our initial expectations are any better than any other estimates when we start up a new reservoir. We know these are below our expectations because of the pressure testing and so forth that we did various stages along the way. We did do production tests initially and we know that the flow rates on the initial production test than on the -- prior to the completion and post-completion, we saw a drop in production rates. And so we know that the completion had an impact on the flow rates here. So we know that the wells can do better. How much better is still a bit of

an unknown and it's a hypothetical at this point.

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

Got it. And then just one other question. You mentioned at Long Lake that you're getting close to your steam capacity, and it sounds like your plan is to shut in older wells and I guess, free up that steam, if you will. Is there any risk you were going to run out of steam capacity and has to consider investing in additional steam plants? Or do you believe by shutting in the underperforming wells, I guess you can free up enough steam for what your plans are?

Kevin J. Reinhart

If you recall, several years ago, we talked about moving our steam capacity from about a 3.3 to 3.7. That increase in steam capacity, as we described recently, is part of the K1A development. And that's in the capital estimate that we've indicated takes to get the upgrader full, includes that additional steam capacity. So we are adding that capacity right now. We're not worried about running out of steam capacity. We have a lot of wells and if you're familiar with our charts in those red categories which is the poorer reservoir, we're putting a lot of steam into that because it's excess steam at this point in time. But it's got very high SORs. These are up in the range of 8, 9 SORs. And it just doesn't make sense to use that capacity for those kind of wells rather than the really good quality reservoirs that we have available today. So we will be able to get enough steam to ramp up based on the expectations that we share with the market.

Operator

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

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

Most of my questions have been answered. But just looking at the marketing contribution in the second quarter, I know it's a pretty big number at $110 million. I'm just curious as to what the make up of that is. How much of that was coming just from crude on the pipeline in the West Coast? And secondly is from the standpoint of marketing, this was obviously a bigger business for Nexen in the past, you're not moving -- I'm just curious as to whether you're moving back into that direction or not.

Kevin J. Reinhart

It's a good question, Greg. But just to be very explicit and clear upfront is no, we're not going back into the business of a couple of years ago. That was -- that business a couple of years ago was buying and selling third-party gas. And we are not in that part of the market at this point in time. The West Coast pipeline is contributing about $40 million a quarter, give or take the differentials. But I think about $40 million in the second quarter was attributable to the TMX capacity going to the West Coast. I'd be cautioned about using -- I believe you're looking at the revenue number in marketing. That's a top line number, not a bottom line number. And so if you have more volume, you're going to have more revenue. But you also have more cost that shows up in a different category in our financial statements. So you really have to look at bottom line here rather than that top line revenue. And again, I can just assure you, this is from moving oil products primarily off the West Coast. Although we do work, some of that revenue comes from blending crudes, so buying physical products, blending them and taking advantage of price differentials. So clearly not in the business category that we were a couple of years ago.

Operator

Your next question comes from the line of Andrew Potter from CIBC.

Andrew Potter - CIBC World Markets Inc., Research Division

I know there's been a lot of questions on Usan, but I've got a few more. So just in terms of the reservoir versus vol [ph] completion issue, what is it that you've seen that gives you so much confidence that it is just the completion issue versus reservoir? And second question just related to Usan. Just seen some headlines this morning that the drafts of the petroleum industry bill is being delivered to parliament and they're, I think, saying tax- rate for 25% for deepwater and 50% for shallow water. I mean, based on what's on the table right now, what would that mean theoretically for your Usan value?

Kevin J. Reinhart

Sure. Your first question in terms of why we're confident that it's not a reserves issue. This goes back to what I mentioned earlier, with respect to the production test. We know what the flow rates on the wells were from various tests that we had beforehand. We know how the wells cleaned up, which is typical after you do a completion. It takes a little bit of time to clean up. We've seen some of that happen. But it really comes down to the flow rates, pre and post the completion activity. And when you see a real variance, you know the only variable that's changed there is the completion. So we're pretty confident that, that's the filter that's creating, holding back a little bit of the production at this point in time. And there are more than one ways to complete a well. And so as we go forward with the development program on the rest of this field, we will use a new completion technology that should make this a nonissue. In terms of your second question, the PIB is moving through the parliamentary process in Nigeria. We have no idea what the definitive plans are with respect to moving that forward. It still has a fair bit of process to go through, including the various houses and presidential support and so forth. There are a lot of rumors flying around in terms of what that bill actually will be. But Industry has not seen that bill yet. And so if there are words out, or if there are ideas out there in terms of what the tax rates are, I would just caution against believing any of that at this point in time. And I think we just wait and see where this goes. So obviously, it's pretty mature for us to comment on what impact this might have on us because we haven't seen the bill yet.

Andrew Potter - CIBC World Markets Inc., Research Division

Sure. And just to give me some context, what is the actual tax rate that's embedded in your PSCs?

Kevin J. Reinhart

Yes, we've -- each PSC is a little bit different. And as we've talked in the past, we have a 1993 contract. Generally, those contracts are available publicly. But we've not gotten into the tax rate and so forth. The important thing here is to look at the government take and whether they take in the form of production or taxes, various level of taxes. I think it all adds up and you can see the netbacks that we're generating from this area. As we go forward and see what the PIB impact has, we will work to be able to be more transparent on how that system works.

Andrew Potter - CIBC World Markets Inc., Research Division

Sure, okay. And just last question just to clarify -- on Usan, in terms of getting the peak rates, my understanding -- you're still saying that you will get to full design rates as you'd previously expected, but it's just a matter of time and more, maybe delay in more wells or am I wrong in that?

Kevin J. Reinhart

Yes, I'm not going to make that prediction at this point in time. It really comes down to the pace of drilling that we go out here in the future. And when I talk about this, I mean, just with respect to the Usan field. So these are very high flow rate wells and they come on fast and then they go into decline. They don't plateau for 5 or 7 years. And so it's a question of how fast we drill these wells and therefore, at what rate do we sustain them? We see opportunity in and around the surrounding area with some of the Usan West that we're doing appraisal drilling on. Owowo West is a potential tieback, Owowo South is a tieback to -- a potential tieback to the Usan facility. There's an exploration well in the north of Owowo. And so that's the whole program that we're putting together to figure out how best to fill up the capacity of the facility that we have there. And we have 2 rigs doing a combination of all of those activities.

Andrew Potter - CIBC World Markets Inc., Research Division

Okay. So those partly changed from the initial plan that you may need these other fields to get the facility full?

Kevin J. Reinhart

The facility was oversized, if you will, for the Usan field by itself. It had, even in the initial understanding in some of those cases, it had a very short plateau period because we saw all the potential in the area. And everybody was pretty confident there was a lot more oil to be discovered in the area and therefore, it made sense to build some excess capacity there because it was cheaper to do at the outset than to try to add it on later.

Andrew Potter - CIBC World Markets Inc., Research Division

Sure. And one last question if I can, just shifting gears a little bit. Maybe if you can just give a bit of an update on some of the global shale/tight oil exploration in India based from Poland, Colombia, Alberta Bakken, anything like that?

Kevin J. Reinhart

Yes, it's still very early stages in each of those areas. We're just into drilling, I think, our third well in Colombia, our fourth or fifth well in Poland. These are significant areas over a million acres. So 3 or 4 wells is barely scratching the surface on these. So it's premature to talk one way or the other in terms of what we're seeing here. We still have a little bit of more work to do. The good news is these wells are very inexpensive to drill. And so testing these areas, generally, you can figure out whether you want to proceed or not for, call it, $50 million for our share, which I equate to being no different than our dry hole exposure on an exploration well in other parts of the world. So while we get to drill several more wells to test the reservoir capability, we're still talking relatively small amounts of money at risk.

Operator

Your next question comes from the line of Robert Bellinski from Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

I was just wondering if you can give a mid-year update on the exploration programs in Poland and Colombia?

Kevin J. Reinhart

Sorry Robert, I think I'd just addressed that in terms of -- we've drilled a couple of wells in each of those areas at this point in time, in each of Colombia and Poland. And it's way too early at this point in time. I can tell you that we continue to drill and so we haven't made a decision to exit either of those 2 as we go forward here.

Operator

Your next question comes from the line of Kam Sandhar from Peters & Co.

Kam S. Sandhar - Peters & Co. Limited, Research Division

Kevin, a couple of questions. First of all, just on Long Lake. I'm just wondering if you could give us a bit more color around how many wells you do plan on shutting in at Long Lake and whether or not there's some sort of specific SOR cutoff or well productivity cutoff? And then the second question is just on the Liard base and obviously, your competitors talked about some of the results they've had there. I'm just wondering if you guys have any plans to drill any horizontal well there over the next year or 2?

Kevin J. Reinhart

Sure, Kam. At Long Lake, this really is about putting the steam to the best possible reservoir. So we don't really look at an SOR cutoff as being the point. We just look at what's the optimal use of whatever steam we have available. So even if it had a good SOR in the well, but we have a much better SOR opportunity, we'd still redirect the steam to that area. But given the total steam capacity that we have, we think we can fill up all the wells that we need and get the SOR down and get the upgrader full. As a rough rule of thumb, as we've described, when we bucket the reservoir into the 3 categories of good, fair and poor reservoir, there's about 29 to 30 wells in the poor-quality reservoir. So I would say those are logical candidates to redirect the steam into the better wells as we drill 14 and 15. And as we continue to steam 12 and 13, we'll make sure those wells get filled with whatever amount of steam they can take because we're quite excited by the opportunity, given the reservoir quality there. In terms of your Liard question, we were pleased with the results that we saw from one of our peers. It allowed us to reassess our view of the resource there. And I think the positive surprise that we saw was how much pressure that the high pressures of the reservoir there, and with higher pressures you can put more gas into the same area. And so our estimate of the gas content in the Liard area where we are is more optimistic now than what we had before because of that data point. We have a lease earning well, a couple of lease earning wells that we have to spend over the next couple of years. We are starting to move forward with the planning for our first well. And we haven't yet committed as to whether we're going to drill that later this year or sometime in the next year. But we are starting a planning activity for that, given that we have to drill these wells, I think, 2 wells over the next 3 years anyways. We might as well get started and see what we have there. But it looks like there's a lot of gas in that area. And when we follow the trends based on the information that we've seen, I'd say we're more confident with respect to the resource we have there now than our confidence level, say, 6 months ago.

Operator

Your next question comes from line of Mark Polak from Scotiabank.

Mark Polak - Scotiabank Global Banking and Market, Research Division

All my questions have been answered.

Operator

Your next question comes from the line of Kyle Preston from National Bank.

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

I just got 2 final questions here. First one on Long Lake. Just looking at the upgraders here, when you start to ramp up production here, in particular in the fourth quarter after turnaround. What's your comfort level there on being able to run that upgrader reliably as you ramp up production there?

Kevin J. Reinhart

Sure. The upgrader has been running at a fairly reasonable reliability here, given the rates that we're putting through there. Obviously when you come out of a turnaround, all the equipment's clean, all the equipment is ready to go and so we expect even better reliability coming out of the turnaround. But at this point in time, given the capacities we have gone through there, the upgrader has actually been pretty reliable for us.

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

Okay. And just one other question here with respect to the shale gas JV that's closing here in the next couple of weeks. Are you guys still expecting net initial proceeds of around $600 million?

Kevin J. Reinhart

The proceeds there will probably be over $800 million. There's really 3 components to the proceeds. As you recall, the deal was 50% cash, 50% carry. So the cash component was $350 million. And then the difference between $350 million and $800 million, really half of that is our partner reimbursing us for their 40% share of cost that we spent since last July when the deal was effective. So they need to reimburse us for spending money on their behalf for the last 12 months. And then the other half of that difference is them paying the carry on the 60% that we spent since then and using up some of that carry. So on closing, we expect more like $800 million with another $100 million and a little bit of carry yet to come in, in the future.

Janet Craig

Then I guess we'll turn over to Kevin for final...

Kevin J. Reinhart

Sure. Thanks, Janet. I just want to thank everybody for your participation on the call this morning. We were obviously very pleased with the results that we delivered, both financially, but also operationally. Things continue to go very well inside the company, and we're very excited about the next 6, 9, 12 months in terms of the drilling program that we have. We do have some work to do with respect to the turnarounds coming up, but we're confident we're ready for those. And coming out of the other side of those, we expect to see some very strong production numbers in the fourth quarter. So thanks, again, everybody for your time and have a great summer.

Operator

The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.

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