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Noble Energy, Inc. (NYSE:NBL)

Q2 2010 Earnings Call

July 29, 2010 10:00 am ET

Executives

David Larson - VP, IR

Chuck Davidson - Chairman and CEO

Dave Stover - President and COO

Ken Fisher - CFO

Analysts

Dave Kistler - Simmons & Company

Leo Mariani - RBC Capital

Brian Singer - Goldman Sachs

Bob Morris - Citi

Irene Haas - Canaccord

David Wheeler - Alliance

Joe Allman - JPMorgan

Dan McSpirit - BMO Capital Markets

Operator

Good morning. Welcome to the Noble Energy second quarter 2010 earnings call. It is now my pleasure to turn the conference over to David Larson. Please go ahead, sir.

David Larson

Thanks, Nicole. Good morning, everyone, welcome to Noble Energy's second quarter 2010 earnings call and webcast. On the call today, we have Chuck Davidson, Chairman and CEO; Dave Stover, President and COO; and Ken Fisher, CFO.

The plan for the call today is to have Chuck review our results for the quarter as well as discuss some updated guidance. Dave will then review our global operations focused on second quarter highlights and our ongoing activity levels. Many of you participated in our Analyst Meeting held June 3, either in person or via webcast. We won't be reviewing much of the detail in the call today so I encourage those who haven't had a chance to, to review the replay of that webcast.

Today we will leave plenty of time for Q&A at the end of our prepared remarks but we are going to try to wrap up the call in less than an hour. We know that everyone is busy with the earnings schedule. Should you have any questions that we don't get to this morning, please don't hesitate to call and we will do the best we can to answer you. We hope everyone has seen our earnings release that we issued this morning.

Later today, we expect to be filing our 10-Q with the SEC and it will also be available on our website. I want to remind everyone that this webcast and conference call contains projections and forward-looking statements based on our current view and most reasonable expectations.

We provide no assurances on these statements as a number of factors and uncertainties could cause actual results in the future periods to differ materially from what we've discussed. You should read our full disclosures on the forward-looking statements in our latest news release and SEC filings for a discussion of the risk factors that influence our business.

We will reference certain non-GAAP financial measures today, such as adjusted net income or discretionary cash flow. When we refer to these items, it is because we believe they are good metrics to use in evaluating the company's performance. Be sure to see the reconciliations in our earnings release tables.

With that, let me turn the call over to Chuck.

Chuck Davidson

Thanks, David and good morning, everyone. Today I plan to go through our quarterly results and also our updated guidance items. I'll also be discussing the deepwater Gulf of Mexico and also touch on a few of our major projects, which Dave Stover will go into greater detail on.

Our results for the quarter, for the second quarter were outstanding with GAAP net income at $204 million or $1.10 per share diluted. Adjusted net income was $198 million or $1.07 per diluted share and that's after removing the impact of the unrealized commodity derivative gain as well as a rig termination charge that I will touch on in a few minutes.

Sales volumes for the second quarter were a very robust 219,000 barrels of oil equivalent per day, outpacing production due to additional oil listings in both Equatorial Guinea and the North Sea. But even without the extra listings, our production volume was at 214,000 barrels of oil equivalent per day, which was on the high end of the quarterly guidance that we previously provided to you.

Volumes in the US were up a strong 3.5% from the first quarter. That was driven largely by our Wattenberg development program and the impact of the DJ Basin asset acquisition that closed the first of March this year. This was offset by some third-party downtime we experienced at the Swordfish and Tri-Conderoga assets in the deepwater Gulf of Mexico.

Internationally, our volumes were up a very substantial 22% over the first quarter, led by our operations in Equatorial Guinea, as well as Israel. In Equatorial Guinea, the Alba field maintenance was completed early in the second quarter and we again saw additional listings of crude there.

And in Israel, demand for our natural gas was very strong with sales up nearly 40% from the first quarter. On the pricing side of things, we continue to benefit from the strength in liquid markets, which combined with higher oil volumes contributed to a 13% increase in oil revenues over the first quarter.

Going the other direction, our natural gas revenues declined slightly, primarily a result of the softer US gas markets in the second quarter. I know I'm sounding like a broken record on this, but the US gas market is not where one should be trying to accelerate dry gas production. However, on the flip side, our natural gas realizations in Israel this quarter were actually 11% above our US gas realizations. I'm very pleased with our cost performance for the quarter. Lease operating expense stayed relatively flat from the first quarter, right at $5 per barrel oil equivalent.

Production taxes and transportation were as expected, while DD&A per unit came down significantly driven by higher low-cost volumes coming from Equatorial Guinea and Israel. G&A and taxes were in line as well. Exploration expense was lower than our original expectations which had contemplated having results by now from our deepwater drilling at the Santiago and Deep Blue wells. Drilling operations at both of these wells were suspended with the announcement of the deepwater moratorium.

After evaluating the Gulf of Mexico situation, we proceeded ahead and negotiated an agreement with Noble Corp. on the Clyde Boudreaux rig, which cancelled the terms of the original contract. We agreed to pay a $26 million fee, which we have recognized in the second quarter as a termination liability. In addition, we have established the framework for a new contract post-moratorium that will have a day rate over $200,000 per day lower than the original contract.

In this morning's release, we updated a few of our guidance items, taking into account a number of factors impacting the outlook for the year, including our performance to-date, the sale of certain non-core, onshore US assets, as well as the suspension of drilling in the deepwater Gulf. Our cash, organic capital budget is now estimated at $2.2 billion for the year. That's down from the original budget of $2.5 billion. We spent a little less than $1 billion of that to-date.

And just once again, to clarify organic CapEx excludes our acquisition capital, that would be the Petro-Canada acquisition, as well as the non-cash capital we accrue for the Aseng FPSO lease. Two-thirds of the $300 million reduction on spending is related to the deepwater Gulf of Mexico drilling suspension which of course is impacting both development and exploration operations. The remaining $100 million is related to other major projects including a combination of project cost reductions as well as some timing changes. We have adjusted our total volumes for the year to now range from 211,000 to 217,000 barrels of oil equivalent per day. We brought down the high end of our range but left the bottom end intact.

Overall the midpoint of the range is down 3,000 barrels equivalent per day with of course the primary reason being the sale of approximately 5,700 barrels of oil equivalent per day from our onshore US assets and that deal is expected to close mid-August. In addition, FPSO equipment issues that we encountered in the North Sea in a weak first quarter in Israel tightened the range some. However offsetting these variations we have seen continued strong volumes at Wattenberg which is providing us outperformance on the onshore US assets.

On the cost side we trimmed our estimate for lease operating expense primarily a result of the sale of the higher cost onshore volumes and some good performance to date. I already mentioned the expiration expense is coming down and everything else has stayed relatively in line with our prior ranges.

As a reminder, net procedures from our onshore US asset sales should be over $500 million after-tax. Combined with our lower 2010 capital spending, we will be seeing a benefit of about $800 million of additional liquidity at the end of the year versus earlier expectations further strengthening our financial position.

Switching gears here a little bit, I thought I would spend a couple of minutes on the deepwater Gulf of Mexico. Without going into a lot of detail, let me just say we have spent a vast amount of time revisiting our offshore spill plans, drilling designs, preventative measures and not just in the deepwater Gulf of Mexico but across all of our global offshore operations. We have also engaged our partners, rig and service providers and others in those discussions as well.

I would say that based on these reviews we continue to be confident that deepwater energy resources can be safely developed, however we in the broader industry are moving forward quickly with enhanced plans, enhanced procedures and equipment to better assure safe operations and incident response capabilities. The offshore environment is certainly going to be different than before the Macondo incident and there are a number of new legislative proposals out there dealing with liability, financial responsibility and new potential operating requirements.

Noble Energy has been playing a very active role in providing input to these new proposals. We've also been very involved in trade association efforts and have spent a good bit of time visiting with a variety of policy makers. Our intent is to continue to be involved and make sure that Washington understands the importance of oil and gas development in the Gulf of Mexico as well as the benefits that independents can bring to that area.

I mentioned earlier that we had terminated one of our two rig contracts from the deepwater Gulf. For our other rig, we actually received the industry's first deepwater completion permit post moratorium and that was for the Santa Cruz completion which is allowing our Galapagos project to move forward. So I just say hats off to our team and also the team over at ENSCO for working together on a number of efforts that included verification of service provider training and capability to operational compliance against federal regulations and the third-party certification of maintenance records and BOP systems. It was a substantial effort and I think all of our service providers and internal staff did a great job of providing the assurances we needed so that we could carry on with that operation.

At Tamar in offshore Israel, we're progressing a simplified development option with our partners and the appropriate agencies who will provide us a greater flexibility on that development, actually reduce the onshore impacts while maintaining our production time line. We're finishing up the final design which will take advantage of our existing infrastructure and we expect to sanction this project shortly.

Continued efforts are being made to invest in long lead materials and the lock-in installation contracts. With our focus continuing to be on delivering these important energy sources to the growing Israel markets, our goal for first production at Tamar in 2012 remains intact.

So with that, Dave, I'll turn it over to you.

Dave Stover

Thanks, Chuck. As I review our global operations, my comments will focus mainly on our core programs and I will finish with our expectations for the third quarter. Beginning in the US, it was another very strong quarter for our onshore operations, averaging over 102,000 barrels equivalent per day, a high point for Noble Energy.

Our volumes for the quarter included a full contribution from the DJ basin acquisition as well as continued growth in our Wattenberg asset, which produced nearly 53,000 barrels oil equivalent per day with 50% of the volume being liquids. In our horizontal Niobrara program, we now have two rigs drilling in the central DJ basin, both currently in the Wattenberg field.

So far we have drilled 10 horizontal Niobrara wells in Wattenberg and two in the Grover area about 20 miles northeast of Wattenberg. Eight of the Wattenberg wells are now on production with two awaiting completion operations. As we continue to step out to the north and the eastern portions of the Wattenberg field, we're encouraged by the early flow back in liquid content of our new wells. Recent initial 24 hour rates have ranged from 580 to 845 barrels of oil equivalent per day with a 70% to 90% liquid content.

Starting in September, we expect to drill a few more wells closer to the Gemini area, around the core of the field and near existing vertical producers. The Gemini well has now produced over 100,000 barrels of oil equivalent in just four months, and is currently producing about 600 barrels of oil equivalent per day.

In the Grover area, the first two horizontal wells were recently drilled and are undergoing completion operations. We will keep one of the two current horizontal rigs in Wattenberg the rest of the year and the other rig will move between Wattenberg and the Grover area.

In southern Wyoming, we are also bringing in an additional rig to drill three horizontal Niobrara wells starting in the third quarter. Overall, our horizontal Niobrara program is on target, with about 30 total wells drilled in the play by year end. Along with our ongoing 3D seismic activity, production monitoring and additional reservoir evaluation work, we should be in a good position by the end of the year to assess our expansion plans for this area. Overall, we're currently operating 13 rigs in our onshore US program. Five of those rigs are conducting horizontal operations and eight are drilling vertical wells.

Offshore in the Gulf of Mexico, we produced about 18,000 barrels of oil equivalent per day in the second quarter. On our last call, we mentioned that Swordfish was curtailed about 6,000 barrels of oil equivalent per day for most of April as some maintenance was performed at the downstream processing facilities. We are still experiencing some slight curtailment there about 1,000 barrels of oil equivalent per day waiting on final repairs in the next month or so.

After the Santa Cruz completion, we plan to move the Ensco 8501 rig to the Isabella completion using up our allocated time slot on the Ensco rig this year. This will finish the completion work for the initial two Galapagos project wells.

Moving to international, it was a very strong second quarter for our operations in Israel where we saw continued strength in the quarterly gas price. Keeping in mind that we have seasonal demand in Israel, we had the highest second quarter gas sales volume in our history.

Growth in Israel is overall, electricity demand continued shifting to natural gas and increased industrial consumption had led to higher sales. The growing demand for natural gas in Israel has strong positive implications for our Tamar development.

As we have previously noted, we believe that gas demand in Israel will grow with supply availability and that appears to be happening rapidly. Just recently, our primary gas customer, Israel Electric, announced plans that would consider converting existing coal fired power plants to natural gas.

In addition, a new power plant has been planned for some time now that originally was designed to be coal fired is now also being considered to be primarily gas fired with coal as a backup.

These market changes would provide strong upside demand for our Tamar gas. To accommodate strong near-term demand, during the second quarter we completed the first of two additional development wells at Mari-B aimed at helping to maintain peak field deliverability.

With the new well online, we were able to hit a record intra-day deliverability rate of over 550 million cubic feet per day gross in early July. The second well is drilling and remains on schedule for completion in September. And we are moving forward on our compression project with installation scheduled to begin later this year.

On the exploration front, the Sedco Express rig should spot our Leviathan prospect to offshore Israel in early October. Here the primary target is a 16 TCS gross prospect with a 50% chance of success in the same interval that we discovered at Tamar and Dalit. We operate Leviathan with 40% working interest and expect initial results by early next year.

As we evaluated our seismic and because of the extent of our development in exploration acreage, we recently signed a short-term contract with an extended option period for the Pride North America rig that will start at the beginning of next year. This will give us the ability to expand our program in this area with continued exploration success.

In addition to our upcoming drilling activity, we have recently awarded an additional 3D seismic study to commence later this year over a significant piece of our remaining acreage.

In the North Sea, we mentioned at the last call that Dumbarton and Lochranza were shut in at the end of March, due to some unexpected FPSO equipment issues. Production came back online in mid-May; however FPSO restrictions did not allow the fields to produce at a consistent volume.

We are working with the operator to identify solutions that would enable full production of between 10,000 to 15,000 barrels a day net. In West Africa, the scheduled downtime for equipment maintenance, upgrades and replacements at the Alba field as well as the methanol and LPG facilities was completed in early April and field production returned to full capacity.

In the third quarter, there are eight weeks of scheduled wireline work that will impact production by about 1,000 barrels equivalent per day net for that period. At the Aseng oil development in Equatorial Guinea, our second contracted rig the Atwood Hunter arrived in mid-June and is supplementing the ongoing field development work.

The results of this drilling program so far continue to give encouragement to additional resource potential for Aseng and between our two rigs all drilling and completion well work should be finished by the first of next year. That will put us in a great position to have this oil project online by mid 2012.

On the FPSO, hall refurbishment and module fabrication work continues on schedule and we are very pleased with the overall progress of the project and the operational readiness of our team. At Alen formerly called Belinda, we have now submitted the plan of development to the ministry and we remain on schedule to sanction this liquid project late this year.

Along with our partners we are bidding out some of the major contracts and have begun the process to commit to certain long lead items. So everything is moving forward as expected here as well. In Cameroon, we completed our 3D seismic shoot of approximately 600 square miles and we will be processing the data throughout the second half of the year, targeting the potential to drill at least one new oil prospect in 2011. We've also recently awarded a 3D seismic shoot offshore Nicaragua for later this year.

Now taking a quick look at the third quarter. Total company sales are expected to range from 212,000 to 220,000 barrels of oil equivalent per day. Our sales differ from actual production based on the timing of listings at the Alba field in Equatorial Guinea and the North Sea.

As Chuck mentioned, during the second quarter sales were greater than production but we expect sales to be less than production during the third quarter based on our current lifting schedules. It is worth mentioning that our second quarter production was 214,000 barrels equivalent per day and we expect to see continued production growth in the third quarter despite our onshore volumes impacted by the August sale of 5,700 barrels of oil equivalent per day.

The DJ basin, North Sea, Alba field and Israel will all contribute to increasing actual production in the third quarter.

So with that, Nicole, let's go ahead and open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) We will take our first question from Dave Kistler with Simmons & Company.

Dave Kistler - Simmons & Company

Stepping into Israel for just a second, can you talk a little bit about the prospective timing and the quantity of the additional plant conversions that may move from coal to gas, we may be getting ahead of ourselves just if that's an announcement but kind of curious, what that kind of impact ultimately could be?

Chuck Davidson

Well, there's really two pieces to that. One, of course, are the existing coal plants and there is actually a process that's already started for tendering gas that would be involved in supplementally either replacing the coal or supplementary firing those plants. And so, you know, I think it still depends on conversion timeframe, but that's an incremental demand that we see of somewhere around 200 million a day, and I think that the timing on that is fairly soon after we expect to start up Tamar.

That program is moving forward, and again that's being driven by availability of gas plus just the benefits from an environmental standpoint of switching from coal to gas, which is certainly being recognized in Israel. The second project is a project that's a little later, I think the timeframe they are talking about for the Ashkelon power plant is in the 2014, 2015 timeframe.

And that project again, the original plan was for two basically little over 600-megawatt plants, supercritical boilers on coal and now they have done some work and have determined that they can also fire those on natural gas with perhaps coal as backup. Israel recently announced the Infrastructure Minister announced that they were going to take that to the (inaudible), but that's still far down the road and that's some long-term demand that could be additive.

Again, our view is that the dual fueled would be seeing the impact, seeing maybe 2014, beginning 2015, depends on the conversion timing and it would probably be a couple of years later before you see the Ashkelon project. But, that's the forecast we are carrying and we are seeing there is quite an urgency underway right now to build additional power capacity in Israel. They are short so those plans could accelerate. As I mentioned, that's clearly upside to some of the earlier demand forecasts that we saw for gas.

Dave Kistler - Simmons & Company

Absolutely. Kind of staying on that theme for a bit, Tamar jumping the gun a little bit, but if Leviathan is successful, to date, you guys if I understand correctly have your contracts, somewhat tied to swing with the price of oil a little bit. If something like a Leviathan comes on, how do you guys anticipate handling any kind of discussions around whether that continued to be tied, that gas should continued to be priced or tied to crude oil versus just having an abundance of gas and having a flat contract?

Chuck Davidson

I think first of all, with the updated size estimates, resource estimates for Tamar, we continue to believe that Tamar will certainly satisfy the local market, even with some of this increased demand that we are seeing from potentially coal conversions and additional power projects. So, if Leviathan was successful and again we haven't drilled it, it's a 50% chance of success, but if it was successful and with the size that we've put it at, we certainly believe that we'd be looking at export markets for that. And so depending on what the ultimate customers would be there, would likely determine how that gas would be priced and I guess right now it would be too early to say. Some markets are tied to oil, others have some other factors that go into it, but until we are dealing with a real project there, it's a little bit too early to speculate.

Dave Kistler - Simmons & Company

Thank you for that clarification. One last question, deepwater Gulf of Mexico. Congratulations on the permit in Santa Cruz. As you think about the environment out there, were they delineating between Santa Cruz already a discovery and effectively giving you the completion permit versus the challenges you might have faced if you were looking at a straight exploration well? Any kind of color you can give us on how people are thinking about risk levels on a discovery versus exploration going forward, and obviously how that ties to the legislation coming out with liability caps on the oil spill side of things?

Chuck Davidson

The reason we were able to receive their completion permit is that they had already recognized that completions were not subject to the moratorium. Now, they were subject to significant additional stringent requirements, certifications of the rig, of compliance with rules, regulations, third-party reviews of the blowout system, so there was a lot of work. But the main driver was that they had already recognized that completions were not part of the moratorium. We just had to go through the process because we basically had to resubmit the permit application for the completion.

To date, there is no drilling being allowed for in the deepwater Gulf because of the suspension of operations. I do think that there is some appreciation that there maybe some different well categories, but right now that's not being considered. It's basically completion work. If you can qualify your operations and rigs, you can submit those permits for operations, but drilling is still suspended.

Operator

Our next question comes from Leo Mariani with RBC Capital.

Leo Mariani - RBC Capital

Quick question here on Tamar. You guys talked about trying to mute the onshore impact in Israel of facilities. I've been hearing some rumblings about trying to move. Some of your facilities offshore, which could potentially increase development cost. Just curious as to, I know you guys I think have been saying somewhere around 2.8 billion. I'm curious to see if that 2.8 billion has moved around?

Chuck Davidson

Right now we are not changing our overall cost estimate for the project. As I mentioned, we've actually looked at some additional options that would utilize our existing infrastructure and so while there may have been some earlier options that would have been a total offshore solution that might have had increased costs by utilizing some of our existing infrastructure, we can actually mitigate that. So the answer is, no. We don't expect the cost to markedly change as a result of this.

Quite honestly, we like the alternatives that we've been pursuing. We have been looking at these all along because this has been a project where we had to basically keep alive several alternatives as we went forward. And our view right now is the onshore receiving terminal is problematic, there is still a real question about its location and we have real concerns that by the time that would be approved, it would really have an impact on the project schedule.

So, while I personally believe that there will ultimately be an onshore terminal, maybe it will be tied to further exploration work that we do and additional resources that we certainly hope will be discovered in the basin. But near term, we can utilize some of our existing facilities and mitigate those onshore impacts and do it in a way that does not really markedly change the project cost.

Leo Mariani - RBC Capital

And I guess it sounds like when you talk about some of your Niobrara horizontal wells, I guess I think at your Analyst Day you reported four wells. It sounds like you had four new wells, just to clarify, I guess for the IP rates you guys gave I think were somewhere around 580 to 850. Is that just on the four new wells there in Wattenberg?

Chuck Davidson

Yes, Leo, it is, you're right, its four additional wells that we have started to see some production on now and those rates just represent the rates from those four, the four newer ones.

Leo Mariani - RBC Capital

Now that you've looked at some of the production history and some of your older horizontals, I know you guys were using sort of that 290,000 MBO EUR there on some of the old historical stuff. Have you revisited that EUR at all, is that biased, are they up or down, based on more recent production history?

Dave Stover

I think we still need to get longer term production from these newer wells before we revise anything there. I mean, we are still, you know, still comfortable with what we have and we are encouraged by what we have seen from the new rates, but we just need to get some longer-term production from these newer wells.

Leo Mariani - RBC Capital

Okay. And on those newer wells, what type of laterals are you guys drilling on those in terms of length?

Dave Stover

They are still that 4500, 4000, 4500-foot.

Leo Mariani - RBC Capital

Okay. And how many frac stages are you guys using roughly?

Dave Stover

Anywhere from 14 to 16 or so.

Leo Mariani - RBC Capital

Okay. And have you guys been picking up any more acreage out there that's respective for the Niobrara off late?

Dave Stover

We are always looking at filling in pieces but you know we are not going after large chunks of new acreage. We are just filling in spots that, you know, around some of the pieces that we have picked up here and there.

Leo Mariani - RBC Capital

Okay. I guess just jumping over to the Gulf of Mexico, do you guys have a sense of kind of where the political winds are moving in terms of the liability cap out there in terms of where you think that might go to and if it was to go to a significant number, would you guys reconsider potentially your involvement on the Gulf?

Chuck Davidson

Well, I think two things to zero in on there because there's two issues. One is a liability cap and that of course only has to do with third party economic damages. There's been no cap on spill liability, the primary driver in some of these. And then the other piece of it is what financial responsibility you demonstrate referred to as a Certificate of Financial Responsibility or COFR. I think where it is going today, the third-party liability cap has been moving up and I think most of us realize that that always was a fairly tenuous cap.

There's a lot of ways that it can be reached. So while we would like to make sure that the industry has access to other sources of funds, for instance, the oil spill liability trust fund or perhaps some other pool arrangement, when you go above whatever cap it is, I think that the area that we have been zeroed in on is the financial responsibility requirement.

And I guess I would just say that from the discussions we have had, there's a growing appreciation of raising that COFR or Certificate of Financial Responsibility to a very high number is more damaging than good. And as a result, you know, I don't know whether we will see anything in this current legislation that will move through. It may be later in the year, but certainly the trend has been as every week passes, there has been more reasonable discussion by policy makers about what's an appropriate adjustments to make in these and also more discussion about how the broader industry can have access to a pool of funds or some sort of central fund that would give them in a way a type of insurance, not true form of insurance, but a way to fund the liability of an incident should it hopefully never again occur to this magnitude, but should it occur.

Leo Mariani - RBC Capital

Okay. So it sounds like you're going to talk about move into some type of industry sort of pools of money that allow somewhat of self-insurance by the industry, if I got that right?

Ken Fisher

Yes, this is Ken Fischer. We have been working with a number of people in Washington as Chuck mentioned and trying to ensure that A, that the COFR is set at a reasonable limit that allows competitive access to the Gulf of Mexico for a range of companies including independents. And then on the liability caps, our view is that a pool or mutualization mechanism funded by the industry is probably the most practical solution to this. There's obviously strong concern in Washington about accessing taxpayer money, so that that becomes a major concern. And so some sort of industry mutual similar to what's been applied in the nuclear industry probably makes a lot of sense. There's a thing called Price Anderson that's applied in the nuclear industry and that's worked well since 1957. And so that in a sense as Chuck mentioned is a form of industry insurance that I think could be applicable here and from our discussions it's starting to gain some traction and understanding with the policy makers.

Leo Mariani - RBC Capital

Okay. Great. I guess last question referring to your production; obviously, you guys expect some increase in production sequentially into the third quarter. However, you guys did say you thought that your sales would be a bit lower than your production. Any way to sort of quantify that at all?

Chuck Davidson

I think when you're looking at production for the third quarter, you know, we were 214 in the second quarter. I think even with the impact of the sales, which is, say, roughly 3000 barrels a day for the quarter. We still should be 220 or slightly above there for production, and again, I don't want to confuse that with the sales volumes for the third quarter, which we gave the guidance, range on. So, we should be up three to 4% even with the sales impact in August. On production.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

On the Niobrara, I apologize if you mentioned this but can you talk to where well costs are trending and it may be too early, but any initial thought on the wells you have drilled so far on how the decline rates are looking?

Dave Stover

Yes, Brian, this is Dave. On well costs, you know, we haven't seen a big change on that. We've been saying drilling complete around that 3.5 million type number plus or minus depending on the well and what you're doing as far as coring activity or other things there.

What we have seen has been interesting, I think when we started the horizontal program it was taking about, you know, 18, 20 days to drill a well. I know we just did the last one in close to 13 days, so we have seen some continued operational efficiency improvement as you would expect as we continue to gain experience in the area.

I think as far as well decline, you know, we kind of showed that plot in the June analyst meeting where we had, what, 60 or 90 days type production. We will continue to update that and look at that pretty hard. But these most recent wells have only been on for a month or two. So I'll go back to my earlier comment. We just may be get more history before we are comfortable in putting out a decline on this.

Chuck Davidson

And we have been moving around in the field and as Dave noted, some of these more recent wells have much higher liquid contents than what we have seen earlier. So it's a huge area to assess and each area is probably going to have its a little bit of uniqueness to it.

Dave Stover

And to Chuck's point on some of these wells with the higher liquid content, gives you a little different producing mechanism where you don't have the gas to lift it, so we will have to go in on some of these areas and put artificial lift on some of these fields. So that will spread out some of the timing of the decline understanding.

Brian Singer - Goldman Sachs

And are you seeing with the increase in activity industry-wide, are you seeing any signs of cost pressure or availability of equipment delays and is there any carryover impact at all on your legacy Wattenberg?

Chuck Davidson

Actually, up there with the scale that we have and the long-term commitments and contracts that we've had with folks, we have been able to work through that pretty well. I think overall you continue to see some of the pressure on completion, frac sand all of that type of thing. But I'll go back to the point earlier. I think with some of the efficiencies we have continued to pick up on some of this, as we continue to go through the program. At least so far we haven't seen a big increase in cost pressure at least this year.

Brian Singer - Goldman Sachs

Great. Thanks. And lastly on Leviathan Chuck wanted to see if you just characterize any discussions you have had with the Israeli government and their openness to exporting natural gas or LNG in the event that is successful given their historic need for natural resource imports.

Chuck Davidson

I think so far the discussions have been very open to export. I mean, we made it clear early on that Tamar was in our view dedicated to the local market as Tamar size has grown, they have seen that, you know, there is a lot of gas, multi-decades of gas available from Tamar and so there has actually been a significant openness in Israel to the idea of exports and that's been talked about a lot.

Our challenge is to keep them from counting that as a done deal until we drill the exploration well. They tend to view prospects as discoveries there and so more of our effort has been on trying to make sure they understand the exploration work that we have in front of us before we can count all this as a discovery.

But certainly they have actually started to think about the economic impacts on their country of exports and what that might mean for them and some of the other implications. That will be a significant project, as I know you would appreciate of something that's 16 TCF in size if that were to happen, that is a major export project and there's a lot of work that would have to be done.

But as far as the country allowing exports, the assurance that we have gotten as long as we can demonstrate that we can adequately supply their market, that they will certainly not stand in the way of a company developing the assets and recognizing there will be economic benefits to the State of Israel as a result.

Operator

Our next question comes from Bob Morris of Citi.

Bob Morris - Citi

Just one question. On Tamar, you mentioned again this quarter that sanctioning that is dependent on securing an onshore receiving terminal which you said is problematic but you also said you still expected to come online in 2012. I would assume…

Chuck Davidson

Let me clarify that a little bit, because what has changed is that we have now moved forward one of the alternate scenarios that we have been developing that does not depend on a comma and an onshore receiving terminal and as a result of moving this alternative to the top of the priority list, that is what is allowing us to continue to be confident on our project schedule.

The onshore terminal is, as I know, is problematic in terms of timing that that would be received. There are still several alternatives that are being looked at and it appears to us as that's a decision that may have to be deferred until further exploration work so that's why we have moved to an alternate development plan that would utilize a lot of our infrastructure that we already have in the country and would get around that issue.

Bob Morris - Citi

So at what point do you have to make a decision to go one way or the other to still be able to come online in 2012? In other words, where is that break point saying okay we are not doing the onshore, we are doing the offshore, vice versa?

Chuck Davidson

Well, we have already started down that path and we are finalizing the design work, we have already started the discussions with partners and those in the country. And so we are rapidly moving to this being the solution and we just need to finish up some of the final design work and, again, because this would not require an onshore Tamar process, it would allow us to then as soon as we are comfortable with the design scope to sanction the project and move forward.

Bob Morris - Citi

So with this tract now, the startup would be end of 2012, mid 2012, sort of what is the timing then on this new track?

Chuck Davidson

We would view it as late 2012.

Bob Morris - Citi

Okay. And then you just made the comment that the onshore terminal, the difference may be that you would need additional exploration success, why is that a factor?

Chuck Davidson

Well, I think what is at issue now is that there's probably not going to be two or three onshore terminals here, but probably one. So if you are to build an onshore terminal for Tamar and then you have a discovery at Leviathan that may require a dramatically larger scope of facilities, you may have made a mistake. So I guess what the view might be is it might be better to wait until you see the exploration results and then go for an onshore terminal that really fits the full development scope rather than the initial discovery.

Bob Morris - Citi

Okay. So it's apparent that the offshore development plan is pretty well tracking on and pretty certain at this point?

Chuck Davidson

Yes. Yes, not necessarily a stand-alone but one that utilizes the infrastructure that we have down there at the Mari-B area and our existing onshore terminal at Ashdod.

Operator

Our next question comes from Irene Haas, Canaccord.

Irene Haas - Canaccord

I want to kind of just pick your frame on the Niobrara trend. Obviously you guys have done tons of work in the Wattenberg field and this chalk is sort of interesting and my question for you is from what you learned from all of the vertical wells how much can be extrapolated as you move northward, you know, north of the Wattenberg, you know, are there still quite a bit of unknowns such as which chalk bench you want to attack and which angle you want to lay your lateral, etcetera, etcetera? And then the second question really has to do with what if this trend really take off tremendously and start producing sort of 100,000 barrels a day range with the white cliff pipeline be sufficient and are there sort of any talk of expansion and how difficult would that expansion be in your view?

Chuck Davidson

Okay. Irene, let me start with the first one as far as what we are learning as we go across this trend. I would probably reference you back to one of the exhibits that Ted Brown showed in the June Analyst Meeting where it showed our plans for drilling out there and what I mentioned is I think by the end of this year we will have 15 to 20 horizontal wells in Wattenberg, we will have six or seven in this Grover area that's kind of northeast of Wattenberg and we will have three in southern Wyoming and we kind of have shown some depiction of that in Ted's presentation in June. So I think that's really what's going to give us the additional knowledge when we tie to some of the vertical comparisons. Obviously, we have a number of vertical wells in Wattenberg, and then there are some industry data outside of Wattenberg.

But when you take that range and area of extent of comparison, then by the end of year be able to tie that back to the vertical piece, that's what will give us a pretty good working knowledge then by the end of the year. And with that, we'll be able to then compare some things as to how the Niobrara changes across some of these areas, how the different zones within the Niobrara look. But we really need to get some of that work done, that horizontal work done across that wider area, especially outside of Wattenberg.

I think when you look at the pipeline piece, for example, White Cliffs, I think it can be expanded probably 20 or 30,000 barrels a day fairly easily with some compression and so forth. And I know there's a number of folks looking at that scenario what you brought up as to additional expansion out in that area and, in fact, we've got our marketing team doing a lot of work with some folks looking at what's going to be required from the whole industry scale out through that area.

So I think that's still in its early changes. We hope that is the case where production ramps up like you're talking about. But that'd be an exciting thing to watch and we're going to be staying up front on that and planning for especially the infrastructure going forward. But end of the day, I think we'll be able to move the volume out of the area.

Operator

Our next question comes from David Wheeler with Alliance.

David Wheeler - Alliance

In Israel, if there's any changes in the royalty regime, do you think Tamar would be grandfathered from that? Is that your expectation?

Dave Stover

That is certainly our expectation that Tamar would be grandfathered. It was an existing discovery and there's very strong argument to be made that it would not be part of any change in either taxes or royalty.

David Wheeler - Alliance

And when you think about gas sales, historically, Israel used to have a natural gas demand forecast, and it sounds like there is lots of places where incremental demand is showing up. What do you think the range of gas sales from Tamar might be once the field comes on-stream?

Chuck Davidson

Well, when it initially comes on-stream, we've continued to talk about numbers that are somewhere around the five plus, 500, 600 million a day. The reason that we talked about some of these additional things is that the timing of that additional demand seems to be moving up. And, of course, we always deal in average demand and there will still be seasonal demand in Israel that you will see periods of probably very high demand, peak demand. And then as you go out, one of the things that is the wildcard in all this is those numbers that I refer to assume that Egyptian supply continues to enter the system and we continue to see that Egyptian supply has its good days and it has its bad days, and it's always subject to the political issues as well. And so that's another 200 million on today's volumes that can move around. So our view is we want to be prepared to be able to handle whatever Israel needs from day one, even if that means having to deliver an additional 200 million to cover the Egypt volumes. So it's a wide range.

I wouldn't change from what we've provided in the past. I just in my own mind feel that there is upside to that because of the incremental demand needs we're seeing, this discussion of conversion of plants, the fact that electricity demand in Israel continues to grow rapidly, that industrial customers continue to appear almost daily as they see the benefits of natural gas and that the imports that they do have from Egypt continue to be volatile and that provides us incremental opportunities to deliver spot sales if those imports should fail.

David Wheeler - Alliance

Okay. Thanks for that. And in the Niobrara, Greater Niobrara area, I think you mentioned you've got a third rig that's going to start drilling in Southern Wyoming. Is that correct and what would be the timing of that?

Chuck Davidson

That's right. It should come in probably sometime in September, probably closer to late September and that will enable us to drill three wells up there before the end of the year.

David Wheeler - Alliance

So we're basically going to be able to assess across most of that northern acreage the different parcels?

Chuck Davidson

Yes. You'll have three wells up in Southern Wyoming and then you'll have six to seven outside of Wattenberg in Colorado, Northern Colorado and then you'll have that 15 to 20 overall by the end of the year in Wattenberg.

David Wheeler - Alliance

Okay, great. And you mentioned Aseng development drilling. Is that uncovering incremental resource? Could you give a little color on that? It sounded like the development drilling, I'm not sure what you were expecting to see but it sounded like you were encouraged and maybe there's some incremental resource there.

Chuck Davidson

I think as we have stepped out in some of these areas, especially as we have started to drill some of these wells that are going to be our downdip water injectors and so worth, we have actually seen in some of these areas that didn't show up very well on seismic but we found a little more pay than we expected in some of this. So it's kind of adding to our net pay count that at the end of the day is going to give us a little more resource potential here. So it's all been to the positive from this development drilling.

David Wheeler - Alliance

Okay, great. And can you provide a little color on the opportunities in Cameroon and Nicaragua? Are we looking for a giant oilfield here or medium size? What's kind of the story in those two areas?

Chuck Davidson

I think in Cameroon, we just shot the seismic so we are just starting or we will be starting to get some of that in pretty soon. But I guess our expectation is we'll prospects of variety of sizes in fact, I think I cant remember totally but I think we may have shown one and at the June Analyst Meeting that was at least in the 100 million or greater size. And Nicaragua, we'll actually start shooting our seismic later this year and there at least from the initial look and then obviously this is very high risk type prospects still at this point until we get some additional seismic shot, but those are very big prospects size. I mean, I think we've talked before in the past about billion barrel type buys of prospects down there.

Operator

Our next question comes from Joe Allman, JPMorgan.

Joe Allman - JPMorgan

On the horizontal Niobrara play, do the recent four wells look more like Gemini versus the other areas?

Dave Stover

I would say, Joe, these were actually drilled up to the north and the northeast on, way from the more gas prone part of the field. If you remember, Gemini was more towards the core of the field and had probably 60 to 70% gas content. These wells are kind of the flip of that. These are 70 to 90% oil content. Came in very nice initial rates, we just need to see some sustained production on these.

So I would say they are not really Gemini like wells. These are more on, these are early component here. Now, we are going to step back down and drill some Gemini-type wells here over the next few months, I think two or three additional wells and the difference here, the recent wells up to the north, these are kind of in new areas also. Also if you remember, the Gemini type well was down in developed part of the field.

More towards the core of the field, had a higher gas content, there was also testing the ability to drain new resources out of areas where it had fairly extensive vertical production history and that's what we are going to also test with these other couple wells that we will call more Gemini like that we are going to drill here in the next few months, so we will have both type comparisons then.

Joe Allman - JPMorgan

Okay. That's helpful. And then in terms of the first four wells, the Gemini appeared to be the most productive. I think you were estimating in the UR of 500,000 barrels equivalent. Do these four wells in terms of EURs, I know its early, first few days, do these four wells look more like that in terms of the productivity?

Dave Stover

Its still too early to call. Some of these wells have been only on a few weeks and some of them came on and then were actually going to put a rod pump on some of these too to give them a little more energy.

Chuck Davidson

We kind of measure everything off, you know, what we showed from our economic analysis, which was about 290,000 barrels and that's how we kind of measure things. Is it doing better or worse and then it seems like things are doing fairly well compared to…

Dave Stover

If you go back to that plot, we had a 60 day plot for just the average of all of those and these look very good relative to those averages.

Joe Allman - JPMorgan

Got you. And then just to clarify the 70 to 90% oil, that truly is oil, right? That's not just liquids? It's oil.

Dave Stover

Right. That's oil.

Joe Allman - JPMorgan

Okay. Got it. And then how do you phase into the horizontal play here? Assuming you continue to have success and you want to really develop it horizontally, how do you phase into the horizontal play and reduce your vertical drilling and what happens to the Codell?

Chuck Davidson

That's something that the folks are really taking a hard look at. I think you always want to have some mix of the vertical and horizontal. The vertical economics are still very good and to your point you don't want to lose the potential or the recovery of the Codell.

I would say the other thing we will continue to look at, is there an opportunity down the road to look at a different mechanism for the Codell. At some point do you want to look at Codell horizontally too? But these are all different phases of looking at this, but I would anticipate results hold up, we continue to go where we are, we will have a blend of vertical and horizontal drilling next year and one of the things we want to sort out by the end of this year is what's the right mix of those.

Joe Allman - JPMorgan

Okay. That's helpful. And then just on a different topic, on the Gulf of Mexico are you in the process of applying for permits for future drilling? Of course you can't drill new wells now, but are you actually going through the process and could you describe that process with the BOEM?

Chuck Davidson

We are not applying for future drilling permits because you don't know what the requirements are going to be for that. Our initial priority once the suspension of drilling is lifted is to resume our operations at Deep Blue and at Santiago and that will be the priority. Those are covered by existing permits. I would expect that there may be some modifications that might be expected but until we know what that is, until the government knows, it doesn't make any sense to apply for a permit.

Operator

We have time for one more question. Our final question comes from Dan McSpirit, BMO Capital Markets.

Dan McSpirit - BMO Capital Markets

Gentlemen, good morning and thank you for taking my questions and I will in fact leave it to one question here. Going back to your comments earlier at the top of the hour about the domestic gas market and sounding like a broken record, if it's not time to accelerate natural gas production given where prices are today, is it time to acquire assuming you can find a willing seller and in fact your outlook for the commodity is maybe more positive than negative?

Chuck Davidson

I think, again, we are constantly looking at opportunities. To date the seller expectations have been very high and not in synch with our outlook on the market. I would expect, as you would imply from your question, is that that will converge at some point, but it takes some weathering of this market to get to that point. But we continue to look at opportunities.

We do think there may be a point at which adding to the portfolio. We saw it with the Wattenberg opportunity and the DJ basin in Petro Canada. One of these other regions could be attractive as well as the values of the assets come in line with what I think now there's a greater consensus as to what the longer-term market is.

Dan McSpirit - BMO Capital Markets

Very good. Appreciate the comments. Thank you.

Chuck Davidson

I guess it's just patience.

Dan McSpirit - BMO Capital Markets

Right. Thank you.

Operator

And that does conclude our question-and-answer session. I will turn the call back over to our speakers for any additional or closing remarks.

Chuck Davidson

Again, I want to thank everybody for spending the time and showing their interest in Noble Energy and hope y'all have a nice day.

Operator

And with that, we will conclude today's conference. Thank you for your participation. You may now disconnect.

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Source: Noble Energy, Inc. Q2 2010 Earnings Call Transcript
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