Murphy Oil Corporation Q2 2009 Earnings Call Transcript

Murphy Oil Corporation (NYSE:MUR) Q2 2009 Earnings Call August 6, 2009 1:00 PM ET

Executives

David M. Wood – President, Chief Executive Officer & Director

Kevin G. Fitzgerald – Chief Financial Officer & Senior Vice President

John W. Eckart – Vice President & Controller

Mindy K. West – Vice President & Treasurer

Dory Stiles – Manager of Investor Relations

Analysts

Evan Calio – Morgan Stanley

Mark Gilman – The Benchmark Company

Jean Gillespie - Gillespie Consulting Group

Michael Jacobs - Tudor, Pickering, Holt & Co.

James Mahoney - The Daily Oil Bulletin

Blake Fernandez – Howard Weil

Paul Cheng – Barclays Capital

Kate Lucas – Collins Stewart

Unidentified Analyst

Operator

Welcome to the Murphy Oil Corporation second quarter 2009 earnings conference call. During today’s presentation, all parties will be in a listen only mode. Following the presentation the conference will be open for questions. (Operator Instructions) This conference is being recorded today, Thursday, August 6, 2009. I would now like to turn the conference over to Mr. Dave Wood, President and CEO.

David M. Wood

Thanks for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer, John Eckart, Vice President and Controller, Mindy West, Vice President and Treasurer, and Dory Stiles, Manager of Investor Relations.

Dory Stiles

Today’s call will follow our usual format. Kevin will begin by providing a review of second quarter 2009 results. David will then follow with an operational update after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained.

A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy’s 2008 annual report on file with the SEC. Murphy undertakes no duty to publicly update or revise any forward-looking statement. With that being said, I will now turn the call over to Kevin for his comments.

Kevin G. Fitzgerald

Net income in the second quarter of ’09 was $168.8 million, or $0.83 per diluted share. This compares to net income in the second quarter of ’08 of $619.2 million or $3.22 per diluted share. For the six months of ’09, net income is $329.9 million or $1.72 per diluted share, compared to net income for 6 months of 2008 of $1,028.2 million or $5.36 per diluted share.

Net income in the second quarter of ’09 included a $24.7 million after-tax or $0.13 per diluted share charge associated with an anticipated reduction of our working interest in the Terra Nova field, offshore Eastern Canada. Also included are $13.4 million of after-tax gain or $0.07 per diluted share from insurance settlements related to property damage at the Meraux Louisiana refinery and a $2.1 million after-tax loss or $0.01 per share in discontinued operations for post-closing settlements related to the sale of our Ecuador properties earlier this year. Net income in the second quarter of 2008 had included a $67.9 million after tax gain or $0.35 per share on the sale of our Lloydminster heavy oil properties in Western Canada.

For the 2009 six-month period, net income included the above-mentioned Terra Nova redetermination and insurance settlements along with after-tax gains of $103.6 million or $0.54 per diluted share that is in discontinued operations from the sale of our Ecuador properties. The 2008 six-month period included after-tax gains from the sales of Canadian assets which included the just mentioned Lloydminster sale of $108.3 million or $0.57 per share.

Looking at income by segment, in the E&P segment net income from continuing operations for the second quarter of 2009 was $118.3 million, compared to net income in the second quarter of ’08 of $576.5 million. The 2009 quarter included the previously mentioned Terra Nova charge, while the 2008 quarter included the gain from the sale of Lloydminster properties. Lower E&P earnings for 2009 were primarily attributable to lower crude oil and natural gas price realizations, while production and sales volumes were higher.

Crude oil and gas liquids production for the current quarter was over 118,000 barrels per day, compared to approximately 111,500 barrels per day for the corresponding 2008 quarter. This increase was primarily attributable to production from Kikeh, offshore Malaysia, which was ramping up during 2008. This was partially offset by the sale of the Lloydminster and Ecuador properties and by lower volumes at Hibernia off the East Coast of Canada and at Syncrude which was both due to maintenance downtime.

Natural gas sales volumes were 147 million cubic feet per day in the second quarter of ’09 compared to 55 million cubic feet per day in the second quarter of last year. This increase was attributable to the December 2008 startup of production from Tupper in British Columbia and at Kikeh.

Looking at the downstream segment, R&M net income for the second quarter of 2009 was $27.8 million, compared to net income in the second quarter of ’08 of $77.3 million. This earnings decline in the 2009 quarter was primarily in the UK where refining margins were much weaker than last year. Income from operations in the US was up in the current quarter due to slightly improved refining margins, the previously mentioned insurance settlements, and improved utilization at Superior which was down for about 6 weeks for a full plant turnaround during the second quarter of ’08.

In the corporate segment, in the second quarter of ’09 we actually had a net benefit of $14.8 million, while in the second quarter of ’08, we had a net charge of $35.3 million. This improvement is attributable to a combination of favorable foreign exchange results mostly as a result of the US dollar weakening against the UK sterling and lower net interest expense due to lower interest rates on borrowed funds and higher amounts capitalized for development projects.

As of June 30, 2009, our long-term debt amounted to a little over $1.5 billion which is approximately 18.5% of total capital employed.

With that, I’ll turn it over to Dave.

David M. Wood

The most recent quarter saw crude prices regaining some ground, and as a result, our leverage to crude oil enabled us to capture the upside. On the natural gas side, bearish fundamentals continue to weigh down the market, and we’re not immune to that effect.

With a third of the year behind us the tone for the immediate term has changed little since our last call. Focus remains not so much on uncontrollable external factors but insuring we are positioned correctly to remain strategically advantaged. Overall, crude prices have improved since our last call while natural gas prices have fallen. Thunder Hawk, a deepwater project in the Gulf of Mexico, was recently brought on stream, and our Azurite project in the Republic of Congo is very near to first oil.

Our third project for natural gas in shallow water offshore Sarawak Malaysia is rapidly advancing towards start-up. I will discuss each of these individually in a moment, but want to say how proud I am of the commitment of the individuals within our organization responsible for bringing these projects on stream as efficiently as possible and with excellent safety performance.

On the exploration front, recent successes in the Gulf of Mexico, Malaysia, and the Republic of Congo will aid in backfilling our top tier production growth profile. As I’ve stated many times before, exploration remains the core of this company. We continue to look to add upside in additional undertakings such as resource plays or other value-enhancing opportunities across our business.

In downstream, US gasoline demand appears to be mildly improving off late at least at our stations. Retail started the third quarter off on the right foot before seeing margins weaken over the last week as oil prices moved up again. Refining worldwide, however, remains challenged due to excess product supply. After taking everything into account, we are favorably positioned but still looking to add more opportunities.

Now I thought I would take a few minutes and get a little more specific on our business units beginning with exploration and production. As mentioned, we achieved important exploration success on each of the four wells drilled during the second quarter. In the Gulf of Mexico, the Samurai well located in Green Canyon Block 432 where we have a third interest found oil. Appraisal options are being studied now, and we will likely develop this as a subsidiary tied back to an existing facility.

In offshore Malaysia in Sabah, oil was discovered at the Siakap North prospect located in Block K, not far from our Kikeh and Congkak fields. We have 80% in the Siakap North discovery. An additional appraisal well is currently being drilled to further assess the find as development options continue to be studied. Offshore Sarawak Malaysia, the East Patricia prospect found natural gas pay that will likely come to market utilizing existing infrastructure currently being developed. We have 60% in that prospect.

Finally, offshore Republic of Congo in the Mer Profonde Sud block, or MPS as we call it, the Turquoise Marine well where we have 50% interest found oil on a structure very analogous to our Azurite field that lies 17 miles to the south. Appraisal plans for that are being looked at now, and a development tieback to Azurite is on the table.

Currently in the Republic of Congo, we are completing abandonment operations on an unsuccessful exploration well we just drilled in the MPS block on a prospect called Diamond Marine. The well found oil pay, but in limited quantities.

While we have been quite active of late in exploration, things will naturally slow down in the second half of 2009. We plan to drill an Eastern Gulf of Mexico well later this year. We will also commence drilling this month on our Eagle Ford shale position located in south Texas where we are still actively leasing. It’s difficult to predict gas prices, but I feel confident that with cost supplies into any market situation, we will be favorably placed to grow production.

In production activity, Thunder Hawk in Mississippi Canyon 734 commenced production on July 8^th. Current production levels at this semi-submersible floating production unit are approaching 27,000 barrels a day of gross production from two wells. Offshore the Republic of Congo, the Azurite project as mentioned earlier is ready to produce anytime as we work through a mechanical problem within our first completion. In Malaysia, Kikeh’s average production for the month of July was 116,000 barrels of oil per day. Payout was achieved during the second quarter as anticipated, less than 2 years after first production, and this week marked our 100th successful lifting.

In British Columbia, Canada, at our Tupper gas field recent production volumes have been averaging in the mid 40 million cubic feet per day. We are running 3 rigs currently, 2 at Tupper Main and 1 at Tupper West. Just yesterday, our Board of Directors approved the sanctioning of the Tupper West development opening the door for added production growth. How quickly we ramp up that project will be influenced by natural gas prices which currently are weak.

During the third quarter, we will begin producing natural gas at our Sarawak project offshore Sarawak, Malaysia, in blocks 309 and 311. Production will ramp up to 250 million gross per day later this year and continue on for many years. Overall, company-wide production for the year could come in slightly lower than previously anticipated due to an array of factors including unplanned facility downtime, slower than anticipated rampups and startups, and third-party processing issues.

Depending on how the rest of the year shapes up, we anticipate that production for 2009 will average about 170,000 barrels of oil equivalent a day and a fourth quarter average of 210,000 barrels of oil equivalent a day. In our downstream business, refining segments in both the US and the UK struggled most of the quarter with negative margins. While retail margins came under pressure during the quarter, they improved toward the latter part of the quarter, as wholesale gasoline prices fell.

Today, the Meraux refinery is operating near 100,000 barrels per day while the Superior refinery is running at 36,000 barrels a day making asphalt. Milford Haven, our UK refinery, is currently running near 103,000 barrels a day. In US retail, we now have 1036 retail outlets in operation, 993 of which are Murphy USA sites, plus 43 Murphy Express sites. Volumes have improved from earlier in the year and for the month of June ran flat with previous year.

Overall, I’m pleased with the recent success in our exploration program as well as achieving first production at Thunder Hawk. Additional milestones will be reached later this quarter as we bring on Azurite and Sarawak natural gas. In downstream, retail has moved as expected, and we are well positioned for the remainder of the driving season. We are still seeing many more opportunities on the horizon, and I’m looking forward to our group of wells in our Eagle Ford share acreage.

As was announced yesterday, Harvey Doerr who many of you know was our Executive Vice President of Downstream and Planning chose to retire from the company and return back to his native Canada. Harvey has served the company exceptionally well for over 20 years in various leadership roles, and I certainly wish him and his family the very best and would like to thank him for his valuable contributions to Murphy Oil Corporation. Our downstream units will now be managed individually by three extremely capable leaders.

That ends my prepared remarks, and I’m happy to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Ryan Todd – Morgan Stanley.

Ryan Todd – Morgan Stanley

As far as I understand, your Q3 production target is around 76,000 barrels a day which is almost up to the Q1 peak despite a transition to cost recovery. Can you talk to what the drive is there? Is it outperformance at the Kikeh field, and what is the best way to look at it going forward?

David M. Wood

Let me answer the broader question, and we can kind of drill down to Kikeh I think. We’re suffering from some project delays. Azurite I was hoping would be on production by right now. It’s got a problem in one of the valves and one of the wells we want to bring on, and we kind of lost a couple of weeks here, but I’m confident we’ll get that fixed and be able to bring that up, and so that’s a little bit of delay. If I look at the whole year, we’re talking about 170,000 barrels a day average. We’re seeing some Sarawak gas delay and some Kikeh gas delay. That accounts for about 60% of the change, and the rest is delay in Thunder Hawk for about 8 days, and then one of the wells that we got on is not performing as expected. It’s doing okay, but it’s not doing as we expected. That’s about 1100 barrels a day, and then Kikeh with the issues with gas and how that field has been working is about 1500 barrels a day behind, so we add all that up, and you throw in the slight positives in Canada and the Gulf of Mexico gas, we’re down about 4900 barrels a day for the year, so that’s kind of the production guidance story there. Fourth quarter will still average 210,000 BOE a day. Specifically on Kikeh, part of it has been tied to the Kikeh gas and being able to get the gas off the facility on a consistent basis. The last few weeks, that’s been doing much better, so I think some of the relative performance is because we’ve overcome the change in entitlement with better operational performance largely tied to that. We also had a flare tip on the facility that was repaired in the first quarter and kind of knocked that down a little bit, but that was just for a few days.

Ryan Todd – Morgan Stanley

Is it still safe to say that in terms of Kikeh net production volumes going forward, we should be looking at maybe the low of 60,000 barrels a day range?

Dory Stiles

No, it should be in the low 70s. On a percentage basis of net, in the low 60 percentile range, but production barrels, you’re talking about barrels in the low 70s.

David M. Wood

That often gets confused when we talk about barrels and percentages here, and so I think it is a good question.

Ryan Todd – Morgan Stanley

You mentioned that you are still considering taking advantage of opportunities that you see in the environment out there. Can you talk to us about what type of opportunities you are seeing and maybe how you’re looking at the world and how maybe it’s changed since the last conference call a few months ago?

David M. Wood

It’s a funny world we live in, I’ll say that. Oil prices are high, and I’m not quite so sure I understand the fundamentals as to why gas prices are low. I wish they were higher. We are seeing continued opportunities for gas, particularly in North America which is why we are still leasing in Eagle Ford and why we are continuing to grow our position up in British Colombia for gas, but that’s kind of a long-term view. I think and I have talked about this before, being able to bring gas on in the $4 world and less if you can, I think is going to give you advantage long term, so that’s the type of thing we look for in North America. A lot of our exploration takes place outside of the US, and we are still trying to look for oil opportunities. I’m very pleased that some of the discoveries that we made here so far this year have been oil and have been in places that we think there is further running room. Next year, we’ll get to drill in places like Surinam which we’ve had acreage for a couple of years, just finished shooting some 3D this year. We’ve got some blocks in Indonesia and Australia, and so those types of positions will continue to grow. With respect to acquisitions, the bid-ask spread is still kind of wide, but we look at those, we look at joint ventures, and so I think we will be able to do some deals here in the next twelve months, but I am not in a big rush because now you have exploration success, we have a little bit more cushion here, but I would like to get our exploration program back up to a little higher level of activity than just 5 or 6 wells a year, so we’ll be watching ourselves pretty closely due to that.

Operator

Your next question comes from the line of Mark Gilman – The Benchmark Company.

Mark Gilman – The Benchmark Company

David, you referred to processing issues as one of the reasons for the reduction in 2009 outlook. Were you referring to issues in the Tupper area with that comment?

David M. Wood

No. In Tupper, we’re producing a little over 60 something per day, but averaging 40 million, and we’ve got some new wells to bring on there. It’s not a processing issue there. I think the most recent issue we had to deal with was pretty strong thunderstorms and typical things like that, Mark, up in that part of the world.

Mark Gilman – The Benchmark Company

So what’s the processing issue you were referring to then?

David M. Wood

Third-party processing to get the methanol plant, Mark. I’ve mentioned that before. That plant is not taking as much gas, but here recently it’s doing much better, so that the real issue I was referring to.

Mark Gilman – The Benchmark Company

David, could you talk a little bit about what kind of access options you have from a longer term perspective to the Bintulu LNG facility taking into consideration the recent East Pat discovery?

David M. Wood

East Pat is nice because it just kind of backstops stuff that we’ve already got. Don’t hold me to these numbers, but it gives you the order of magnitude of how busy we’ve been in Sarawak. I think we’ve drilled 32 exploration wells and 42 appraisal wells, and we found a number of gas fields, albeit quite small. The phase I development of Sarawak Gas is just 3 fields. In phase II, it’s two fields. So, we’ve got a number of small fields that now we’ve established the infrastructure that can be brought on tied to how much gas demand there is, and so that’s really not in our control. That’s a business that we are going to have to work out along with our partner Carigali with Petronet—how much gas do they want and when do they want it. The thing from my perspective that is important is I think we’ve discovered the reserves. Now they need some more appraisal, etc., but I’m pretty pleased with the overall position that we’ve got there. Having said that, with the level of exploration that’s been done there over the years by us, clearly a lot of wells, a lot of appraisal, that level of activity isn’t going to be kept up going forward, but I do think we have a lot of drilling activity for things that are found that need to be apprised.

Mark Gilman – The Benchmark Company

David, am I interpreting your comments correctly such that what you’re seeing is an extended plateau at this 250 or 300 a day level from Sarawak and not anything incremental there too?

David M. Wood

I can’t answer that question because I don’t know what the demand is from the company that buys the gas. It’s not a mechanical deliverability, Mark, because I think we could deliver on a rate basis substantially more, but that’s the way we’ve designed this system. It’s 250, stepping up to 350, and we can do that for a quite a long period of time. If we’re asked to produce higher than that, clearly we can accommodate that.

Mark Gilman – The Benchmark Company

I’m a little bit curious as to the reasoning behind drilling an appraisal well on Siakap North given what was indicated to be the small size of that prospect. Did the result of that first well alter you pre-drill expectations on the prospect? What’s the thinking behind an appraisal as opposed to just straight tying it back to Kikeh?

David M. Wood

Mark, that’s a very good question. The issue is that the structure is shared with another block, so we have to appraise our piece of that feature just like it’s been appraised or will be appraised on the other side, so that’s the issue there. As you remember from how we developed Kikeh, the efficient use of water injection is critical to maximize recovery in any field. If you have a field that’s shared across a lease line, you need to have a unified development so that you maximize the results of water injection and minimize the cost, and so the reason for drilling an appraisal well now is simply we need to know what’s on the side of our line. That’s all.

Operator

Your next question comes from the line of Blake Fernandez – Howard Weil.

Blake Fernandez – Howard Weil

My question is on the underlift-overlift standpoint. If I am not mistaken, we were underlifted first quarter and second quarter, and then it appears that guidance for Q3 is for another underlift. I’m just trying to get an understanding of where we are on balance from an underlift and overlift standpoint, and if Q4 could potentially see reversal?

Dory Stiles

For the six months ended at the end of June, we were in an underlift position of about 840,00 barrels. Third quarter guidance has a total underlift as you see of 7000 barrels a day, primarily the components of that would be Malaysia and the Congo.

Blake Fernandez – Howard Weil

My second question was on the R&M. It looked like performance was really strong, at least relative to what we were looking for, and obviously the refining industry has been suffering quite a bit. Is it fair to say that a lot of that performance came out of the retail division and, if so, is there a way to provide a contribution by percentage?

David M. Wood

I think it’s safe to say that everybody’s refining is getting beaten up, and we’re probably no different. I think what happens and where the discrepancy is in the UK for us we had cat problems with the Milford Haven refinery, so it should have had better results, so on a relative basis, the first quarter and the second quarter should have looked more equivalent. We had about I think 56 days of either the cat shutdown or impaired operations. So that impacted how that refinery was running in the first quarter relative to the second quarter. If it was running, we would have done much better.

Operator

Your next question comes from the line of Paul Cheng – Barclays Capital.

Paul Cheng – Barclays Capital

David, do you have a forecast for the 2010, any change? Previously I think you had been talking about $2.05 with a bit of uncertainty in the North American natural gas market. So do we assume that that’s a pretty decent one or that needs to be shaved a bit?

David M. Wood

I think that’s pretty decent, and yes, there is uncertainty in the North American Market. Paul, I’d love to have a crystal ball to be able to see where prices are going, but I don’t. In our ramp-up year, what we’re doing is kind of going to be tied to where we think price is going.

Paul Cheng – Barclays Capital

In the guidance of $2.05 for next year, what is the Malaysian gas and also the Canadian gas assumption in that, and also if you can tell us similarly for the fourth quarter when you’re talking about 210,000 barrels per day target, what is the Malaysian and Canadian gas volume?

Dory Stiles

You said the fourth quarter on the last part of your question, Paul? Is that correct?

Paul Cheng – Barclays Capital

Yes.

Dory Stiles

Fourth quarter Malaysian gas would be about 250 million a day, Canadian gas about 74 million a day, and for 2010, I may have to get that number for you Paul. Sarawak looks like in the low 30 million on a BOE basis. That’s how I’ve got it broken out on my sheet here. For Canada on a BOE basis, it’s probably about just under 12,000 a day.

Paul Cheng – Barclays Capital

So that is 72 million cubic feet per day. So you’re back to the fourth quarter level.

Dory Stiles

Then you would also have a Kikeh gas component as well in there, Paul, which is probably about 80 million a day.

Paul Cheng – Barclays Capital

So that’s 280 million cubic feet per day for the sour gas?

Dory Stiles

That’s correct.

Paul Cheng – Barclays Capital

In Congo, with that starting up, what kind of operating costs and DD&A run rate should we assume initially?

David M. Wood

This year, we’re going to have relatively small volumes, but if I look at next year, we’re looking at an operating cost of about $14.5 and DD&A in the order of $23, that kind of range.

Paul Cheng – Barclays Capital

David, as you finish the initial ramp up, those are going to go down or are they just going to say pretty flat around there?

David M. Wood

Are you talking about Azurite development, Paul?

Paul Cheng – Barclays Capital

No. Next year assuming you haven’t booked all the reserves, so maybe as a result DD&A is still going to be on a unit cost basis that is higher. Should we assume that as you move into the end of next year or early part of 2011, do you think costs as well as cash equivalent DD&A will start to go down or not really?

Dory Stiles

Paul, we haven’t booked anything at Azurite so far, so our first booking will be this year.

Operator

Your next question comes from the line of Jean Gillespie - Gillespie Consulting Group.

Jean Gillespie - Gillespie Consulting Group

I’ve got two things; one in terms, just a modeling question looking at third quarter, what would we be looking at profit versus cost recovery barrels from Kikeh to be around 50-50?

Kevin G. Fitzgerald

Jean, I’ll look into that and get back to you. I don’t have that worked out.

David M. Wood

Jean, that seems awfully low, but why don’t you let us get that question specifically answered. It seems low just at the outset.

Jean Gillespie - Gillespie Consulting Group

Which side of it sounds low?

David M. Wood

Obviously, barrel sounds low.

Jean Gillespie - Gillespie Consulting Group

The profit split?

David M. Wood

Yes, but why don’t you let us give you a number and we’ll get that.

Jean Gillespie - Gillespie Consulting Group

Can you reminded me, and I know it’s early in the year to talk about reserve replacement, but under the circumstances you’ve had four discoveries this year; you have no bookings for Azurite, you have a very minimal, I think it’s about 6 million BOEs bookings for Thunder Hawk, Sarawak Gas is starting up and you’ll have some significant production experience by the end of the year hopefully. You’ve just sanctioned less Tupper, you’ve got over 100 million barrels of unbooked Kikeh reserves; there’s a lot of BOEs there when you total it up; any comments?

David M. Wood

Yes, I like having lots of things to book; I know where they are, Jean, and we’re working hard to keep that going. For Tupper West, I think that’s going to be a great project for us. With phase I that we’ve sanctioned should get us 900 plus net BCF; we have a phase II that’s just a little less than that we’ll sanction in future years, and so projects like that do really well. Eagle Ford which will drill our first well here this month, I am hoping that will have some production tests from that well in November, and then if you get to put that online, and in the event that it does what we think it’s going to do, there will be something there as well. So, I like the momentum that we have here. For the most part, our main projects still have some sizable amounts of booking ahead. So, that’s always the best to be.

Operator

Our next question is from the line of Michael Jacobs - Tudor, Pickering, Holt & Co.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Just thinking back two years ago when you were acquiring 3D in offshore Suriname, can you talk about the geologic concept when you first entered the play?

David M. Wood

The real attraction there is the Lower Cretaceous age source rock that works very well in Venezuela and what we were looking at was difficulty in finding things that were attractive in Venezuela, not that the geology is not attractive, and so we tried to move that same geology around and see where else it could be. We looked at a number of places. We recognized a play for a turbidite fan sequence within that same source rock interval offshore Suriname, and we went to a good round and were successful in picking up the block that we picked up which we have 100%. We actually just finished shooting 3D at the end of last year and beginning of this year and we’re now getting the data in. In that same timeframe there was announced success in West Africa that if you reconstruct how the world was, put to that successful play, juxtapose to this same area. So, we think some of the things that, from a geological perspective, have worked very well in West Africa are key elements in what we’re now seeing in our data and hope to see even more as we get to work with 3D harder offshore Suriname. The encouragement directly in the country is that there is a field on-shore called Tambaredjo which is probably a billion barrels in place and it sits in sand, but sit right on basement. So, the oil has got to have been sourced from deeper in the basin, and the acreage we picked up is deeper in the basement. So, we’re looking for relatively subtle stratographic type traps that we think on the data quality that we think we’re going to get which we have got a good indication of, we should be able to sit. So, that’s the name of the game. It’s jack up water depth, it’s an oil play, it has lots of running room and an old exploration guy, and they don’t let me do any exploration anymore, I get pretty excited when I see things like that. So, I am anxious to drill it next year.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Just following up on that, the African analog, if you think about the concept where you’ve got a gassy shelf coming on and creating traps for oil accumulations, how many of those types of structures do you think you see offshore Surinam?

David M. Wood

It isn’t a question of structures because what you’re dealing with is an interval of source rock that might be in the order of 2000 to 3000 feet thick, and so what we’re looking to play is discrete sand intervals that were deposited within that section, and so the number of sand pans, if you will, could be a large number; they may not be sitting on top of each other, they may be geographically separate or we hope they sit on top of each other and they’ve been sourced by the common source, and you could have, if you will, multiple horizons all on one similar package feature. So, those are the two end members. So, it’s not so much number of structure because I don’t think we’re going to be drilling all the way that structure so much, but it’s how many of these discrete pan units do you see in this relatively thick source rock section.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Are you planning to test that any time soon?

David M. Wood

As soon as we get comfortable next year, I’d love to drill a well or more than one.

Michael Jacobs - Tudor, Pickering, Holt & Co.

If I could squeeze in one more on the Eagle Ford, you mentioned actively ongoing lease efforts; from a high level given where you’re at, I believe you’re between the Edwards and the Sligo reef; are you thinking of adding additional acreage more to the east or more to the west?

David M. Wood

Yes, the play in concept I think stretches in a pretty good length as a rhythm between the two reef trends you mentioned and we’re looking at all of that area. We’re primarily focused on the gas part here, but don’t preclude an interest in the oil part, and beyond that I really don’t want to hamper our lease guys, otherwise they’ll say it’s my fault for lease costs going up in certain areas versus others. So, I’ll bow to the pressure from them and say we’re still very actively leasing, very interested in the play, and having said that all we’ve got to go off is other people’s results because we have not drilled a well, but we’re going to fix that this month. The wells that we’re going drill, we’re going to core in and ultimately drill them horizontal and crack them. So, we’re very much climbing a learning curve ourselves, but there are a lot of other people active. We’ve been getting good experience from our British Columbia effort, in the Montney effort, we have a good idea what we need to do, and so we’re going to apply that here. Overall, I like the plan.

Operator

Our next question is from the line of James Mahoney - The Daily Oil Bulletin.

James Mahoney - The Daily Oil Bulletin

The question I had was in reference to Tupper West, and I think you mentioned, David, that you’d be bringing on production later on this year and I am wondering, is this the best time to bring on new production given that you’ve added 92 million a day in the second quarter from between Malaysia and Canada, I think it’s roughly or it’s approaching that figure, and it just strikes me that some companies might consider shutting in gas when prices were this low?

David M. Wood

Jim, let me just correct one thing. Tupper West we sanctioned here this week with our board, but first gas won’t take place until the second quarter of 2011. Tupper Main is currently on production and that’s the production that I was talking about. In 2011, in the second quarter, I am hoping gas prices are going to better than they are now, but if they’re not, I think that’s going to say a whole lot more about a whole lot of other things. I am quite happy for other people to shut their gas production and then let me produce by the way, I would say that. We do have, I think, gas up there that makes money at $4, but clearly gas prices are lower than that up there, and so we’re taking a very conservative approach to bringing new production on, and we won’t ramp up until we see things that kind of makes sense so, so I think that is along the lines that you’re saying.

James Mahoney - The Daily Oil Bulletin

And just following up on that, is there a gas price at which you would shut in production? In other words if gas falls low enough, is there a point where you’d shut in some Canadian production?

David M. Wood

I’m not looking at doing that now. I think we got to see what not the day-to-day issues are but some longer term issues. Now our operating cost for gas here is close to a dollar.

Operator

The next question is from the line of Kate Lucas with Collins Stewart.

Kate Lucas – Collins Stewart

I just had a quick question on your foreign exchange during the quarter. How much of the gain was attributable to change in the value of your Canadian government securities?

Kevin G. Fitzgerald

None because we are Canadian functional up in Canada, and they’re all Canadian securities. There is some in Malaysia; it is primarily UK.

Operator

The next question is a followup from the line of Mark Gilman with Benchmark Company.

Mark Gilman – Benchmark Company

I just had a procedural question regarding this redetermination at Terra Nova. I’m not quite sure I understand why the release suggests that the arbitration process that will go forward from here could only further reduce your working interest as opposed to potentially increasing it. Could you put some color on how this whole thing is working and why the statement regarding only further reductions?

David M. Wood

There is under the operating agreement a single set redetermination process, and that kicks in if and when all the parties cannot agree on a revised working interest going forward, and so we got to that point. We all had opinions as a group, and we all could not agree, so we are now kicking off a process where we have to select an expert. That expert has not been finalized yet, and we have not signed the contract, so I’m a little lost to start going into the who said what and who says what level everybody else should be. What will happen once that expert has been chosen is that each of the parties of which we’re one will make formal submission as to what specifically they think that the working interest for all the parties should fall down to, and then this expert will pick on of the cases, so there isn’t a negotiation sliding scale. Let’s say there are five submissions, then the expert will pick one submission, and it won’t be moved around from that, so that’s kind of the process. I’m not expecting anything until the end of 2010, and so what you got in our notification is the fact that it is likely that we are going to come down in interest, so that’s the process, that’s the timeline, and that’s what’s happening there.

Mark Gilman – Benchmark Company

Just to make sure I understand, you know what the submissions are of the remaining four, and all of them would suggest a reduction at least equal to what you’ve proposed, if not greater? Is that what you’re saying?

David M. Wood

No, what I’m saying is in the discussions that had been taking place so far wherein we have not had official submissions from anybody, there has been quite a range and that’s why we couldn’t reach agreement, that’s why we are going into the redetermination process now. We haven’t seen the official version as to this is company A’s opinion, this is company B’s opinion. We haven’t gotten there yet.

Mark Gilman – Benchmark Company

Without the laboring it, why couldn’t the reduction be less then David?

David M. Wood

It could. You’re absolutely right. It could be more I hope, but I don’t think so.

Operator

The next question is a followup from the line of Jean Gillespie - Gillespie Consulting Group.

Jean Gillespie - Gillespie Consulting Group

David, what’s next in the Congo? You didn’t provide any real followup. I know you have an issue with the rig in the short term, but what are the plans let’s say over the next couple of quarters?

David M. Wood

I was hoping somebody is going to ask the question because I could provide a little bit better color on where we’re there. As you remember when we got into the Congo, we thought it was a one in three exploration success. We made a discovery and drilled four dry holes, so it became one in five, and as Mindy reminds me all you needed was one more discovery to get back to one in three, so we drilled one more well. We made a discovery, we got back to one in three, but since then, we drilled the Diamond prospect which we just said today which actually found oil in the first sand and then had well developed sands all wet underneath it. If I look at the two prospects, Turquoise and Diamond and could choose which one was going to be successful before we drilled it, I would want Turquoise for several reasons, one of which is it’s a little bit bigger. The second thing is that there are prospects around it that have very similar attributes including CSCM anomalies which Turquoise did, and so I like the fact that we got some nearby followup from a well that has very nice oil pay in two channel sands, and one of the structures has exactly the same channels. The channels run east-west. We are on a bump. It goes down into a saddle to the west, comes back on another bump, and that same channel also has these anomalies, so I feel pretty good about followup there. The reason why we didn’t drill that is the rig that we got dried at the edge of its depth capability in terms of water, and that would be just too far, so we will have to come back with a different rig to drill that. There are other exploration prospects on the block, I think one in three is probably where we need to be, and technically we got to get ourselves comfortable, so I see other prospects to drill. What we are doing now with the rig is we’re bringing it back to Turquoise, and we’re going to drill the eastern half of the feature. As you recall in Azurite, it had multiple fault blocks, and when we drilled all the wells, all the fault blocks had oil, so we’re going to drill the eastern flank of the Turquoise feature next, so that we can then have a much better idea of how better to develop that and tie it back into Azurite, and so that’s the game plan. I’m pretty keen on coming back next year to do some more exploration in MPS, but we’ve got partners to talk to. We got our government friends to talk to, and we got a line of rig up, but current rig availability is better today than it was year and a half ago, so I feel pretty good that we will be drilling at least again next year for exploration in Congo.

Jean Gillespie - Gillespie Consulting Group

Anything happening on the North Block?

David M. Wood

The North Block has got the southern third of it. It has the same type of play, and so we’re going to put that into the mix as to where we’re going to drill. The northern part of the block has different plays which have different risk elements, and so I think we probably ought to stay with the things that we know work at least for the 1 in 3 level, so we certainly could put that into the mix for next.

Jean Gillespie - Gillespie Consulting Group

Are you still anticipating bringing a partner in at some point of time on the North Block?

David M. Wood

We traditionally don’t stay at 100%, so I think it’s possible, and we’ve talked to companies about it.

Operator

Your next question comes from the line of [unidentified analyst].

Unidentified Analyst

I got on a little bit late, but did you say anything about this Siakap North in Block K that you could be so kind as to repeat or expand for me?

David M. Wood

Siakap North is northeast of Kikeh. It’s the same type of clay and geological section. We found nice oil in several sands, and we appraised with a second well. We did that because the structure extends across into another block, another lease, and the extension of that feature is into that block, so we’re just in the appraisal phase, and once we finish that, then we’ll have to sit down and see the best way to develop it. So that’s where we’re at.

Operator

I am showing no additional questions at this time. Please continue.

David M. Wood

Thanks everyone for joining us. We appreciate you taking the time off your busy schedule, and we look forward to getting together again.