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Noble Energy, Inc. (NYSE:NBL)

Q1 2010 Earnings Call Transcript

April 29, 2010 10:00 am ET

Executives

David Larson – VP, IR

Chuck Davidson – Chairman and CEO

Dave Stover – President and COO

Analysts

Michael Jacobs – Tudor, Pickering, Holt

Dave Kistler – Simmons & Company

Bob Morris – Citigroup

Leo Mariani – RBC Capital Markets

Irene Haas – Canaccord

Stephen Richardson – Morgan Stanley

Dan McSpirit – BMO Capital Markets

Michael Hall – Wells Fargo

David Wheeler – AllianceBernstein

Operator

Good morning and welcome to Noble Energy's first quarter 2010 earnings call. I would now like to turn the call over to David Larson. Please go ahead, sir.

David Larson

Thanks, Lisa. Good morning, everyone. Welcome to Noble Energy's first quarter 2010 earnings call and webcast. I'd like to start out with a few introductions. On the call today with me we have Chuck Davidson, Chairman, CEO, Dave Stover, President and COO and Ken Fisher, CFO. Chuck will be making some opening comments here in a few minutes and then we'll discuss the results for the quarter. Dave will then go into our global operations focusing on our first quarter highlights and the second quarter activity plans. And as usual, we'll leave time for Q&A and wrap up the call in less than an hour. Should you have any questions that we don't get to this morning, please don't hesitate to call and we'll do the best we can answer you.

We hope everyone has the earnings release in front of them that we issued this morning. It does include some new guidance updates for the second quarter. Later today, we do expect to be filing our 10-Q with the SEC and it will be available on our website.

I want to remind everyone today that the webcast and conference call contains projections and forward-looking statements based on our current views and our most reasonable expectations. We provide no assurances on these statements as a number of factors and uncertainties could cause actual results in the periods to differ materially from what we discuss here today. You should read our full disclosures on forward-looking statements in our latest news release and SEC filings for a discussion of the risk factors that influence our business. We'll reference certain non-GAAP financial measures here 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 for these items.

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

Chuck Davidson

Thanks, David, and good morning, everyone. Looking back versus the same time last year, the overall economic outlook has clearly improved and we've seen dramatic moves in the energy markets. While we'll be providing an update of our operations in today's call, we plan to go into much greater depth at our Analyst Meeting coming up on June 3rd, and I hope that you will be able to join us either in person or on the webcast at that time. I think we'll have many exciting things to share with you at that point.

Starting out on the pricing side, there continues to be a wide disparity between the market value of crude and natural gas, which on the natural gas side continues to be challenged from the vast supply that the industry has uncovered and also the forecast for production growth in 2010. Perhaps last week's break in the gas rig count is an early indicator of producer discipline setting in, but I still have a lot of concerns about North America natural gas. That's exactly why we like our diversified portfolio, which includes many oil-based projects that we can and have been redeploying capital to.

Let me reiterate our overall objectives for the year, which I plan to touch on as we go through the results for the first quarter. Number one, of course, is to maintain our strong base of production such that when our major projects come on stream, they provide incremental growth.

Second is to continue with significant investments in exploration. Continued exploration will assure the growth momentum beyond the current inventory of major projects that we're developing. Next, we want to maintain our strong financial capacity throughout the year. And finally, we're focused on progressing this lineup of major projects that will clearly deliver transformational impacts on reserves and production over the next several years. I think we made solid progress during the first quarter on these goals.

Looking at our first quarter 2010 results, GAAP net income was $237 million. That was $1.34 per share diluted on revenues of $733 million. Adjusted net income was $138 million or $0.78 per share, with the only judgment item being this quarter being the unrealized commodity derivative gain.

Sales volumes for the first quarter averaged 197,000 barrels of oil equivalent per day, which is consistent with the quarterly range we provided you during last quarter's call. Production volumes averaged 201,000 barrels of oil equivalent per day, which exceeded our sales volumes with the difference due to some specific, the timing on crude oil liftings in North Sea, as well as in Equatorial Guinea.

Our U.S. operations had a very strong quarter led by our onshore programs, which had record production for the quarter and accounted for approximately 83% of our total U.S. volumes. On shore, we remain focused on liquids opportunities, led by the Wattenberg field, which continues to deliver with record organic quarterly volumes and total volumes at about 50,000 barrels of oil equivalent per day. Another record for Wattenberg was that 50% of our volumes were liquids, either crude or natural gas liquids. Total onshore production was up nearly 6,000 barrels per day equivalent from the fourth quarter with the majority of the increase coming in crude and natural gas liquids.

Included in our first quarter's volumes is one month impact of the DJ Basin asset acquisition, which added a thousand barrels a day of liquids and 12 million cubic feet of gas per day on average for the quarter. Internationally, our first quarter volumes in Equatorial Guinea were impacted by the scheduled maintenance downtime at the Alba field and the LPG plant there. That maintenance reduced our sales volumes by 4,000 barrels a day of liquids and 49 million cubic feet of natural gas per day for the quarter. Maintenance work in Equatorial Guinea has now been completed, was carried out on schedule and on budget.

Natural gas sales in Israel were impacted during the quarter by some power plant downtime, also increased levels of competing imports, as well as warmer than usual winter weather. However, the continued strength in oil led to another pricing record for us in Israel. In the North Sea, volumes were up from Dumbarton and Lochranza; however, we were impacted by a couple of operational issues that Dave will talk about in just a few minutes.

Strong NGL pricing continues to enhance our net backed gas prices in certain U.S. locations, which overall led to U.S. gas realizations to be slightly above Henry Hub for the quarter. The increases in crude oil and natural gas liquid realizations have resulted in improved cash margins for us on a unit basis.

At this point, I want to just add a few comments on our hedging activities, as this is an important component supporting our capital programs. Recently, we've taken advantage of the oil markets to add to our hedge positions for 2011 and also began layering in oil contracts for 2012 at some very attractive price levels.

For U.S. natural gas, which only makes up about a third of our global production, we already had approximately two-thirds of our volumes hedged for 2010 and we have been increasing our hedge positions in 2011 as well, thus reducing our exposure to gas price volatility during this critical period, where we have significant capital expenditures for our major projects. Just add that all the details on our hedge positions will be found in our first quarter 10-Q, which, as David mentioned, will be filed later today.

Looking at our cost performance for the quarter, leased operating expense came in at just under $5 per barrel equivalent. That reflected lower than expected onshore U.S. repairs and workovers. DD&A was pretty consistent with our internal expectations, might have been a little bit higher than what the Street had had, with the difference being the impact of removing some of those low cost barrels in Equatorial Guinea due to the maintenance projects there, which of course then resulted in an overall higher average unit rate for the company for the quarter.

Production taxes, transportation and G&A came in on expectations and our effective tax rate and deferred portion on adjusted basis were both near the low end of our guidance ranges. On the exploration front, we participated in two of our seven significant wells for the year during the first quarter. Unfortunately, Double Mountain drilled at Green Canyon 555 in the deep water Gulf of Mexico was noncommercial, so we included $38 million of related costs before tax in the first quarter exploration expense. Our total net cost for the well was approximately $45 million. You will see the difference, which represents costs incurred in the second quarter. That will, of course, show up in the second quarter earnings.

And our other ongoing deep water Gulf of Mexico test Deep Blue, we and our partners decided to extend our planned drilling depth, which has delayed the result there a bit. We expect to have the results in the next month. Looking forward, we plan to appraise our large Gunflint discovery with one or perhaps two wells and we're preparing for additional exploration tests in both Equatorial Guinea and Israel later in the year.

Total capital expenditures for the quarter were $958 million. That was made up of $408 million for organic CapEx and then of course approximately $500 million for the DJ Basin asset acquisition.

And then in addition, there was another 40 million of non-cash accrual for the construction progress on our FPSO that's going in at Aseng. Our $2.5 billion capital budget remains unchanged for the year. And of course, this is a reminder that only represents the cash portion of our program. We should see those expenditures build throughout the year, as we develop our major projects for the deep water Gulf of Mexico, West Africa and Israel.

Discretionary cash flow for the quarter was $432 million, which exceeded our organic spending. Total debt at the end of the quarter was slightly under $2.4 billion. We maintained very strong liquidity throughout the period, ending up with $2.5 billion of liquidity between our cash and available credit facility and that's after funding the first quarter acquisition. Our debt-to-cap net of cash was 17% at the end of the period.

I'll touch briefly on the progress on our major projects before handing it over to Dave. Last year, we sanctioned both Galapagos in the deep water gulf and Aseng in Equatorial Guinea and both of these oil projects continue to move forward.

First production from Galapagos is expected next year and everything's on schedule to bring Aseng's first production in 2012. We're busy finalizing the development plans of Tamar offshore Israel and the front end engineering work at Belinda offshore Equatorial Guinea is underway, which lead to sanctions on both this year. While we have not let taken Tamar for sanction, our Board has authorized substantial pre-sanction investments. As a result, our procurement teams have been busy letting contracts for supplies and services and the project execution folks are working to assure we stay on schedule and on budget.

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

Dave Stover

Thanks, Chuck, and good morning, everyone. I plan to focus most of my comments this morning on an update of our main programs around the globe. But before we jump to the activity, I want to start with our expectations for the second quarter and the rest of the year.

Our second quarter volumes should be up significantly from the first quarter, led by our operations in Equatorial Guinea coming back online, as well as the full quarter's impact of the onshore U.S. acquisition. Current production is actually running about 212,000 barrels of oil equivalent per day, despite approximately 10,000 barrels of oil equivalent per day in the North Sea, which is shut in, waiting for facility changes at Dumbarton and Lochranza.

Total company sales for the second quarter are expected to range from 208,000 to 214,000 barrels of oil equivalent per day. This includes the impact of the Equatorial Guinea facility modifications for part of April and the assumption of two months downtime for the Dumbarton and Lochranza production. The second half of the year should be significantly higher than the first half, with full production from the North Sea, seasonal and demand increases in Israel, the full impact of the Alba production and our continued onshore U.S. growth.

Moving to our activity, let's start onshore in the United States. As Chuck mentioned, we had a stellar first quarter with record production. Currently, our onshore volumes are running a little over 100,000 barrels equivalent per day after the recent acquisition. We expect to be up another 6% to 8% by the end of the year. Activity remains focused on the liquid-rich opportunity set, which has resulted in liquids comprising 40% of our onshore volumes.

Certainly a key to this program is the core Wattenberg field. Now that the asset acquisition is closed, our total Wattenberg position is approximately 390,000 net acres, which provides us over a 10-year inventory of development projects. As we integrate the acquisition assets, we'll ramp our activity level to 8 or 9 rigs during the year. Of our six current drilling rigs in the field, with one focused on our 2010 horizontal Niobrara program, which is testing the potential for recovery in different areas of Wattenberg. This program will provide us production information and data comparisons across a large portion of the field.

Outside of Wattenberg, we'll be drilling a handful of horizontal Niobrara tests in Northern Colorado and Southern Wyoming during the year. Our overall program in the central DJ Basin area of focus now exceeds 730,000 net acres. As we look at our worldwide capital program, dry gas drilling in the U.S. represents only about 5% of our total 2010 expenditures.

In our two active onshore gas programs, the Haynesville and the Piceance, we'll reduce operated activity during the second half of the year. We plan to drop one of our two rigs in the East Texas Haynesville program by June and move our only Piceance rig to Iron Horse around August. These moves reflect our position to continue focusing on liquid-rich activities and essentially shift some gas drilling dollars into our Niobrara program evaluation.

Moving to the deep water Gulf of Mexico, we mentioned that last quarter's call that we recompleted a swordfish well into an oil zone earlier this year. As the well ramped up during the first quarter to its full rate of about 2,500 barrels of oil per day net, we encouraged facility handling problems at the third party downstream processing facility. This caused us to restrict the field from mid-March through most of April. While the repairs are being performed, we'll restrict swordfish to about 6,000 barrels of oil per day net, however, the repairs have been recently completed and swordfish is now ramping back to full rate.

At Galapagos, the INSCO 8501 rigs spud the Santiago exploration test and we expect to reach total depth by July. However, based on the proximity to the horizon rig incident, we'll continue to monitor developments that could affect our operations. Once drilling at Santiago is finished, the rig is expected to handle the completion work at Isabella, Santa Cruz, and hopefully, Santiago. This oil development represents the first of a number of major projects that will deliver substantial growth to our company over the next decade.

Our other deep water Gulf of Mexico rigs should move from Deep Blue in the next month or so to Gunflint to initiate appraisal drilling. We're certainly aware of the interest in Deep Blue, but adhering to our policy of not commenting on ongoing exploration wells do not expect any news on this well until sometime in May.

The first Gunflint appraisal location is a little over a mile north – northeast of the original discovery in block 948, where we will be testing the structure, thickness and contacts of the field. Also in the deepwater Gulf of Mexico, we were certainly thrilled to have great success at the March lease sale, where we added 16 additional blocks and a number of attractive prospects to our deep exploration inventory.

So now let's move to international. Starting with Israel, as Chuck mentioned, we achieved a record gas price for the quarter, highlighting the impact of our liquid fuel based sales agreement with the IEC and increasing sales to the Dead Sea works. As we mentioned in our last quarterly call, the Hagit power plant had down time during January and part of February. However, it is now fully operational.

Current overall Israel volume is back to our expected level. At Mari-B, we initiated the drilling of two additional development wells, which along with an offshore compression installation planned for later this year; we hope to maintain our peak field deliverability at around 600 million cubic feet per day, gross. We expect the first well to be completed in the second quarter and the second well in the third quarter. Ultimately, the new wells will also assist the field's long-term use of the storage reserve. The works that bring tomorrow is the first production in 2012 is continuing. We are reporting in place a number of long lead major service and equipment contracts consistent with our time line.

Marketing efforts continue both in securing additional supply agreements and finalizing gas sales and purchase agreements currently underpinned by the LLIs. We're continuing to work with both local and federal authorities to finalize and approve the onshore receiving terminal location, which will be an important step as we move to project sanctions.

Our processing and interpretation of the 3D seismic acquisition in the region is under way and we expect final results over the next few months. This will put us in a position to drill an exploration well when our rig arrives early in the fourth quarter.

In the North Sea, volumes in the first quarter were up from the fourth quarter 2009 and also up versus the first quarter last year, as a result of facility modifications at Dumbarton and the first Lochranza well, which came online during the first quarter 2010. We have been impacted by total field shutdowns at the third party operated Dumbarton Lochranza project since March. The field is currently shut in and is expected to be back online by the end of May. Upon restart of the field, production will ramp back up and include the impact from the second Lochranza well.

In West Africa, the scheduled downtime for equipment maintenance, upgrades and replacements at the Alba field, as well as the methanol and LPG facilities resulted in the lower first quarter volumes. In addition, the third party LNG facility had some maintenance performed at the same time. Facilities ramped back up in early April and are now back to full production. Second quarter volumes should be up significantly from the first quarter.

Our field development work at Aseng is progressing nicely. In fact, we now have all the major contracts to be awarded for the project finalized. The Pride South Pacific rig began in January and is now drilling its second development well. By early June, we expect to have a second rig on location to further assist field development. The hull being converted into the FPSO arrived in the shipyard in March. Everything looks to be progressing as expected. First production in mid 2012 isn't that far off and the anticipated oil contribution from Aseng will have a meaningful production and cash flow impact on our company.

At Belinda, our next major West Africa project, we're working with our partners to finalize the feed development work and anticipating submitting the plan of development to the government this quarter. We still expect to mix in an exploration well among our Equatorial New Guinea program later this year. In Cameroon, we recently began our 3D seismic shoot of approximately 600 square miles and we plan to process the data the second half of the year.

Before opening the call for questions, I do want to say that we are looking forward to providing further detail on our development operations, the progress of our major projects and our deep exploration portfolio at our upcoming analyst meeting June 3rd. We hope you're planning to attend.

With that, Lisa, I think we're ready for questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) Our first question comes from Michael Jacobs with Tudor Pickering Holt. Please go ahead, sir.

Michael Jacobs – Tudor, Pickering, Holt

Good morning, everyone.

Dave Stover

Good morning.

Chuck Davidson

Hi, Mike.

Michael Jacobs – Tudor, Pickering, Holt

Message received about not commenting on specific wells, but I would like to ask a couple conceptual questions, if I could, specifically, when Noble typically drills a subsalt Miocene exploration wells, do you typically target the crest of the structure given what you see on seismic?

Dave Stover

I guess what I would say is every exploration opportunity is unique, but one thing which I think you're aware of, is you just drill the crest of the structure, it – you know, you may find hydrocarbons, but it won't tell you much about the size of the opportunity. So in deep water, where the wells are costly, it's not unusual to be drilling somewhat down dip such that if you see an oil column, you're confident there's enough resource up-dip of that that you got something worth continuing to pursue.

Michael Jacobs – Tudor, Pickering, Holt

That kind of leads into my follow-up question, which – what are the possible reasons as to why a company would apply for a permit on the same block where an exploration well was already drilled, typically? And just thinking, is it side track, is it something else typically if we were to see that in a relatively short period of time?

Dave Stover

Well, I really – I mean it's – without knowing all the facts of the situation, I guess it would be hard for me to answer that.

Michael Jacobs – Tudor, Pickering, Holt

That's fair. I'm just trying to understand the concept, but I understand. Moving on, I guess my second and final question, on – when you think about the large scale development projects, what percentage of reserves do you typically book upon sanctions, thinking ahead to Tamar and Belinda, is there a company guideline upon sanction you'll book X percent of reserves?

Chuck Davidson

I don't think you can apply a percentage. I think what you have to do is look at the data that you have at the time of sanction in terms of the wells that have been drilled and use appropriate guidelines on what the, to do as proven. I think Dave can provide maybe a little bit more color, but what we talked about for instance at Aseng is because it's in a relatively new area, we have to be careful about recovery factors and until you see field performance, you would be limited to what you could say is good solid recovery factors for a field with the amount of data you got.

Tamar is a totally different picture because it's a gas reservoir and you've got a lot more things that you can look at to determine recovery. But again, it depends on at sanction, the data you have. You can't look ahead. So in the case of Aseng, that sanction is based on the wells we have in place and as we do the development program, we'll gather more data and that will likely help. And certainly at Tamar, where we have two wells, at sanction, that's the only data we'll have and we'll base our reserves on that.

Dave Stover

Yes. I think you're right, Chuck. I think beyond what you initially book, as you sanction a project, you'll have the additional development, which will give you more information to review and revisit that. Then you'll probably have another cut at it as you start to get some production the first year or two, especially on the oil projects.

Chuck Davidson

But no – we don't have a policy of booking X percent or Y percent. It's based on appropriate rules that are in place for determining proved reserves and the data that we have in hand.

Michael Jacobs – Tudor, Pickering, Holt

That makes sense. I'll hop back in the queue for other questions. Thank you.

Dave Stover

Thanks.

Operator

Our next question comes from Dave Kistler with Simmons & Company. Please go ahead.

Dave Kistler – Simmons & Company

Good morning, guys.

Chuck Davidson

Good morning, Dave.

Dave Kistler – Simmons & Company

Hey, early on, Chuck, you were talking about the premium afforded to oil and liquids and how that's changing your focus, but certainly with the rig moves, increasing your focus on the liquids portion more than it already is. Everybody, or at least seems like the majority of companies that are reporting are all trying to do this. Can you talk a little bit about what the outlook is for liquids, demand for the liquids piece of things in the United States and whether or not you think that can yield some compression actually on the premium liquids you're getting right now?

Dave Stover

Well, I think you've got two pieces. Of course, one is the crude markets, which is there, you go into a global market and you really have to look at your global assessment of the oil markets. I think our view is that still a very strong market. Now, we do have some, as we've seen in the past where Cushing gets filled up and you see some changes of WTI pricing versus as an example, Brandt. But in the overall scheme of things, I think that's relatively minor.

And the other thing which you have to be careful on, remote areas in the past we've seen challenges in moving oil out of areas where the industry has had a surge of activity. That was one of the reasons that we participated in the White Cliffs pipeline that was built out of Wattenberg. So to give us another outlet for oil there and that is certainly helpful.

On a natural gas liquids side, I mean the margins for processing have been very strong and again, that's a market that tended to be a bit of a cyclical market, but it's also being influenced by the oil markets as well.

So I think it’s – we still see that as a robust market. I think while many others are directionally moving their programs, the advantage that Noble has had all along as we've had the portfolio to be able to move capital. And as you know, we moved capital a long time ago into liquids-rich projects. So it's a matter of just continuing that emphasis.

Dave Kistler – Simmons & Company

Great. That's helpful. Maybe as a little bit of a follow-on on that, as we've watched others kind of creep into that activity, are we seeing any kind of service cost inflation, especially as we think about it with respect to Wattenberg or the Rockies on folks who are targeting the liquids-rich side of things?

Dave Stover

Yeah. Dave, I think the thing that you still see the pressure on and the thing with the rig count going up, we've seen probably a little more pressure on onshore rig costs, not a lot, but a little more. The thing up in the Rockies, doesn't take quite as big a rig as some of these other plays. We're fortunate in that even some of the vertical rigs, the rigs we would have to be drilling vertical wells, we've got two or three of those that we actually can use for horizontal drilling, at least initially, in the program if we decide to. I think the thing that still has the most pressure probably is the equipment, especially high pressure pumping equipment and then some of the frac sands and so forth. I think just availability of those things still have probably fairly significant pressure on those right now.

Dave Kistler – Simmons & Company

Okay. That's helpful. And then just jumping to the Haynesville and moving some rigs out of the Piceance as well, but specifically on the Haynesville, can you talk about any HBP requirements that you have in the Haynesville, will you guys be able to maintain that acreage? In the past, you've also commented that the pricing environment changed that, might be an area that you would actually add some acreage to. Can you just talk about what your current philosophy is right now around that play?

Dave Stover

Yeah. I mean, when we look at our current position, we're in good shape as far as being able to hold everything with one rig. In fact, I don't think we would even have to use the one rig the full year to hold acreage. We're looking at it from a level of activity there that we're comfortable with the environment. And it just doesn't make sense to keep two rigs for us running there, where we can divert some of that money into this more liquid-rich piece like additional testing up in the Rockies with some of these properties we've picked up. I think overall, as far as looking for other opportunities, I mean we'll continue to look at things. Nothing jumping out there, but I think the thing we like about our position down the Haynesville, it gives us firsthand information on some of that activity and not having to rely on third hand reports on what's actually going on down there so we can continue to monitor our results and keep this in mind as we look at other opportunities.

Chuck Davidson

And, David, actually your two questions really link together nicely and you have to think about some of the opportunities that we're seeing, whether it's in Haynesville or in other shale plays, are being driven by operators who have huge obligations to hold their lease hold. So it kind of goes counter to our philosophy where we say we don't want to accelerate investments in the dry gas drilling right now. It would run counter for us to jump into an opportunity that has a huge drilling obligation that requires you to ramp up activity over the course of the next 12 to 18 months. So that's another thing that we're very careful about as we look at the opportunities, that we don't get caught in a box where we're going to have to employ a lot of capital into a market that we're concerned may not be quite ready for.

Dave Kistler – Simmons & Company

Great. That's really helpful, guys. I'll let somebody else hop on.

Dave Stover

Thanks.

Operator

Our next question comes from Bob Morris of Citigroup. Please go ahead, sir.

Bob Morris – Citigroup

Good morning, Chuck.

Chuck Davidson

Good morning.

Bob Morris – Citigroup

You had mentioned as part of the reason Israel volumes were down were competing imports. Can you give a little bit of color on that? Are these imports competing on price, or is it just the directive of Israel, diversify their supply, or what is driving that competition that's displacing some of your volumes?

Chuck Davidson

Well, it's a couple of things. Clearly there's a bit of time to diversify supply. Our understanding is that the pricing for volumes was adjusted up and we're probably, comparable, although we do have a factor in our agreement that has allowed us to see some really some record pricing. And so we might be at maybe a slight price disadvantage on some of our volume, but I think right now there's – our customer, our primary customer is maintaining diversity of supply. They have got agreements with two suppliers and you couple that with the fact that the weather has been warm and demand's been down and it's allowed them to sort of split their supply but between the two of us.

But we clearly have the ability to swing with demands and we can swing up very quickly. Dave talked about our maintaining deliverability. So I think our view is that with increased demand through weather and just their own growing power needs, we're in a very good position. But, we really – we're just beginning to see the Egyptian imports a little over a year ago. And so that's what's affecting some of our comparisons now as they finally got their system built and got their production stabilized.

Bob Morris – Citigroup

Are the Egyptian imports, are they on a similar price formula to what your contract is? Or is that – were they such that they could provide further composition price wise in the future?

Chuck Davidson

It's a bit hard to tell. Because those agreements are typically not public documents. We think we're competitive. Once again, we believe that the general market in the Mediterranean for incremental gas is somewhere in that $4 to $5 range that we talked about in the past. And as long as you're in that range, you're competitive. Keep in mind when – if you go back 2008, that was a period when coal prices were very high and actually our gas was priced very well against the coal imports that Israel was bringing in. So we were actually able to pick up some demand there, with coal prices coming back down, they are obviously, most of the time, keeping their coal plants base loaded.

Bob Morris – Citigroup

Okay. That's helpful. Thank you.

Chuck Davidson

Thanks, Bob.

Operator

Our next question comes from Leo Mariani with RBC. Please go ahead.

Leo Mariani – RBC Capital Markets

Good morning. Hi, guys.

Chuck Davidson

Good morning.

Leo Mariani – RBC Capital Markets

Quick question on the Niobrara. You guys said you continued to test that play in the DJ. Have you been testing that in Wattenberg proper for a period of time and curious if you can kind of give us anything on sort of how long you've been out there and looking at this, just so we can get a sense of where you are in your time line wise?

Chuck Davidson

Yes. We've probably – we've got thousands of wells, vertical wells in Wattenberg, penetrated in Niobrara. We have a lot of base information that we started looking at probably two to three years ago, got some additional core data, did some PBT work and so forth. This is something we've been looking at fairly hard for a couple of years now, at least a couple of years now. We actually drilled our first horizontal well last year, but we had a chance to start to see some production from that and then compare that to three other wells now over the last year, mainly last six months or so that we've brought online over some wide areas of the field. So we're starting to get a chance to see some things over a little larger area. I think we're just bringing our fifth well on now.

So by the end of this year, we should have probably 20 to 25 wells between Wattenberg and outside of Wattenberg and the horizontal play that will give us a pretty wide spectrum of information while we continue to look at core data, understand how these things compare from the vertical well and log information and then incorporate some of the seismic that we're shooting out there. As I've mentioned before, we should have over a couple hundred square miles of 3D seismic to also tie into this information. It's not something that's going to crop up overnight. It's something we've been looking at over a few years now.

Leo Mariani – RBC Capital Markets

Okay. Sounds like you guys haven't come out and put a lot of data around this. I imagine it's still probably – from a lease perspective, there's been a couple other operators as well that have tried to pick up position in that area, I guess just trying to get a sense if you guys are still buying acreage if it's available and are you going to kind of wait before the land grab before coming out with some in here?

Chuck Davidson

Well, there's a lot of land running all over the place up there. But with the position that we have in Wattenberg, it's fairly well contained. So our hope is that come June, when we present at our Analyst Meeting, we'll be able to give you a bit more clear picture as to what we're seeing, at least in the Wattenberg field and what our views are of the potential outside. But – so just stay tuned for that.

Leo Mariani – RBC Capital Markets

Okay. Just quick question here on China. Looks like your volumes were sort of flat sequentially. I guess I thought that you guys were drilling horizontal wells there and just wanted to get a sense of how that's progressing and what we can expect China volumes to look like during the year.

Chuck Davidson

Yeah. We've been in the process of bringing on a couple wells there, but really the majority of what we talked about seeing increase would be late in the year in China. So I don't see, I don't think we'll see much change throughout the year. It will be kind of more late this year and into next year.

Leo Mariani – RBC Capital Markets

Okay. Thanks, guys.

Chuck Davidson

Thank you.

Operator

Our next question comes from Irene Haas with Canaccord. Please go ahead.

Irene Haas – Canaccord

Yeah. I would like some color on Israel and just kind of wanted to be reminded, how big is your 3D seismic and the scope of it and you have identified already and roughly how many do you think you're going to end up with that get hydrated?

And the second question really has to do with Cyprus. Have we done sort of any work in that particular area? Is there any thought in sort of starting at a new sort of exploration program there? And perhaps actually ending up with more than just one end-user market in Israel for the gas in the region?

Chuck Davidson

Well, I might let Dave talk a little bit about the scale of the seismic program that we ran in Israel and Cyprus. We expanded it a bit, of course. I think we've talked about that in the past. So we're very pleased with the quality of data we got. We brought it in now and we're going through quite a bit of processing on it. So, I would just say that there's nothing we've seen that discourages us from the program, but it's going to take a little bit further work. We're going to be sitting down with our partners to discuss programs going forward. As we said, we still have expectations that we will be drilling an expiration well there later this year.

Irene, I would say that that's another program that we'll want to talk about quite a bit with you at our June Analyst Meeting and hopefully give a good picture of what we see for a program going forward. We certainly are excited about this basin. We continue – there's nothing that's changed on Tamar and Dalit. Those are wonderful discoveries and certainly, we believe this basin has other potential.

Dave Stover

Yeah. I think to your point on the size of the seismic program, Irene, I don't have the exact numbers here, but if you think about it, it covered our block in Cypress and it covered a large portion of the acreage we showed in Israel before. So I think it was roughly 1600 square miles, but don't quote me on that. But it's – what it does, it gives us a pretty large playing field to go back and prioritize prospects and as far as whether it's Cyprus or whether it's Israel, we'll have to see how they shake out when we get the 3D in and start to prioritize some of these and set up a program here.

Irene Haas – Canaccord

And if Cyprus turned out, say 5 years forward, turned out to be another really prolific area, sort of any thoughts on building gas, transportation and processing facility and maybe use that particular land base or really lease position to provide an alternative way of distributing your large gas lines out there?

Chuck Davidson

I would say that our work right now is really almost in three key areas. One obviously is the development of the Tamar field and the marketing that's associated with that. Then of course the second is our ongoing exploration efforts, but we also have a third area where we're looking at global gas and if there's the potential for discovering additional gas resources that will not be needed in country, in Israel as an example, then we're looking at the options from markets outside that and of course for Cypress you have to look at what market is in that country and then also look at external market, should it exceed it. That work is under way and so we're pursuing all three of those in parallel.

Irene Haas – Canaccord

Thank you.

Chuck Davidson

Thanks.

Operator

Our next question comes from Stephen Richardson with Morgan Stanley. Please go ahead.

Stephen Richardson – Morgan Stanley

Good morning, guys.

Chuck Davidson

Good morning, Stephen.

Stephen Richardson – Morgan Stanley

Quick question, staying on Israel, just a quick question on the timing of the sanctioning. What really needs to happen? I appreciate that you can spend capital. That's not holding up the project right now, but in terms of sanctioning, is it the government approving the siting terminal? Are you waiting to get more end-market contracts? And is any of that impacting your partners' financing? If you can sort of address what we can see in order to – still on track for mid year?

Chuck Davidson

Well, I think the key thing with the sanction is, especially as you go to the board and you say I have truly defined this project and have engineered it to the point where you feel confident that you can move forward with massive capital commitments. We've made quite a bit so far, but they were in areas that were flexible enough such that if something changed on particular aspects that we could still maintain schedule.

The key item which you mentioned is the onshore site location. It's kind of hard to build a bridge until you know where it's going to land on the other side of the water. And where we're making great progress on narrowing that down, but until we get at least the clearance and it's narrowed down to a single site, there will still always be lots of work to be done on that site. But as it gets narrowed down, that will be the, I think in my view, one of the key factors that it will allow us to say we've got the design locked down. We're comfortable that we can bring this to our Board and say this is the project that we're going to build.

So out of everything, I think that's the most important thing that we're doing now. And again, that process is moving forward in Israel. We've seen some great progress over the last couple of months on that. We’ve got some – right now, we have some commitments from the officials that are involved in those decisions to get us an answer on a single site here very shortly. But until we get that, I think we'll be careful about making the full project commitment that comes with sanctions.

Stephen Richardson – Morgan Stanley

Thank you very much.

Chuck Davidson

Thanks.

Operator

Our next question comes from Dan McSpirit of BMO Capital Markets. Please go ahead.

Dan McSpirit – BMO Capital Markets

Gentlemen, good morning and thank you for taking my questions. If I could follow up on a question that was asked earlier in the period here, regarding the industries and the markets, the capital markets, unconditional love for all things oil or all things liquids, is there a contrarian in you that would look at gas projects today, given where gas is trading, are you being presented today, given where gas is trading, are you being presented packages for gas assets, whether conventional or unconventional? Or are you truly spooked or troubled by the fundamentals for natural gas?

Chuck Davidson

Well, I'm not spooked by the fundamentals of natural gas. I think it's going to continue to be a good market long term. I think we're in a great position for supplying natural gas to customers for decades and it's going to be a good business. But I think you have to be careful about when you spend money on it. It looks like it's fully supplied right now.

Yes, there are gas opportunities out there. This industry seems to change very quickly and all you have to do is look at the margins associated with oil projects versus gas projects right now and it has caused many producers to try to think of ways to become more orderly. I think we already had our portfolio well diversified, so we were in a very good position to allocate capital. But there's nothing wrong with being counter cyclical.

If you would have asked me a year and a half ago about making another acquisition in the Rockies, we probably would have said, no, we got too much of that. The Rockies differentials were expanding, but when that market changed and when the differential shrank and we saw the opportunity at the end of last year, we grabbed it very quickly. So it's all about value. And it's all about making sure that it's value that you can recognize based on your long-term view of the markets. So we're open to opportunities, whether gas and oil, I think that right now, as far as our internal programs, we like to invest into oil projects because of the margins, but that would not prevent us from picking up a gas opportunity. But as I noted earlier in the call, you have to be careful because many of them being presented now have huge drilling obligations that would force you to put capital into maybe a market that's a bit challenged right now.

Dan McSpirit – BMO Capital Markets

Got it. And then turning quickly to the DJ Basin, particularly the Niobrara opportunity there, what is it, recognizing that you do have lots of well control to point to, but what is it about that opportunity that you truly find attractive, whether geologically or and certainly, economically and if you can't speak to maybe the targeted economics of that play again, recognize on a horizontal basis, recognizing of course it's very, very early?

Chuck Davidson

Well, again, I think we're going to talk a bit, probably quite a bit about that at our June Analyst Meeting, so I won't upstage the folks that are working on that right now. But in general, what we're doing in the Niobrara is no different than what's being done in a number of other plays across the country. And that is by applying new drilling and completion technology where it has not been applied before, we clearly see the potential to enhance recoveries on, not only on a per well basis, but in terms of on a per unit of capital that's employed and you're looking at significantly enhanced returns as a result. Why do we like the Niobrara, why it's in Wattenberg, outside Wattenberg, within Wattenberg, because generally it's had very, very low recoveries in the field. It's been commercially developed, using vertical wells, but it has very, very low recoveries. And so the applying technology, we certainly believe there's the potential to enhance that recovery and there's a lot in place, a huge amount in place. So there's a great prize. That's why we like it.

Dan McSpirit – BMO Capital Markets

Very good. Thanks again.

Chuck Davidson

Thanks.

Operator

Our next question comes from Michael Hall of Wells Fargo. Please go ahead.

Michael Hall – Wells Fargo

Thanks. If I may just follow up on the Niobrara, understanding I may have to at least June. But continue to talk about, obviously got a very significant acreage position now at this point. Can you talk a little bit more about how you think about risking that and what's your perspective and how that risk various between the Wattenberg and between the areas outside and closer to Silo field and whatnot in the (inaudible)?

Dave Stover

Yeah. Michael, I think as mentioned earlier, it is still competitive leasing going on in the area, still a number of one and actually trying to pick up at least in this top side. I think at this point, we really don't want to get into comparing different portions of this. I think as Chuck mentioned, what we can talk about, we'll put together and have much more information in June, but one thing we don't want to do at this point while there's active leasing and so forth, is get into trying to depict a lot of difference in various areas and so forth.

Michael Hall – Wells Fargo

Okay. Fair enough. I think everything else is fairly well covered. Thank you very much.

Operator

Our next question comes from David Wheeler with AllianceBernstein. Please go ahead.

David Wheeler – AllianceBernstein

Good morning.

Chuck Davidson

Good morning.

David Wheeler – AllianceBernstein

You were talking about the onshore program and you mentioned the exit rate for this year up, I think you said 6% to 8% for the current production rate. Is that right?

Chuck Davidson

That's right, Dave.

David Wheeler – AllianceBernstein

How sustainable is the onshore growth driven by the Wattenberg, as you look forward, beyond the end of this year? Is this something you can continue to grow at that type of rate? Maybe not specifically that exact rate, but how sustainable is the growth there?

Dave Stover

You got to start with the inventory with projects and there's a huge inventory of projects. I think one of the big factors will be how successful does this horizontal play turn out to be and that will make a big difference, as we look to next year and the years beyond as to how quickly you can grow this. I think the good part is, you've got the inventory of projects and we've added that up, to that inventory of projects with this recent acquisition. That I think we can definitely make it grow. The rate of growth will get a better feel for as we get more information on how some of this horizontal program works.

Chuck Davidson

I think just to follow up on that, because Dave mentioned the acquisition, one of the things we talked about when we made that is that we expected to double that production base by 2012, I believe. So that's just one piece of it, but we see a lot of other opportunity and I think Dave has put the proper precautions on that is that we have to see some of these new plays are working, but we are getting information, we're getting results and we certainly believe that we've got a sustainable program and we know we've got an inventory of projects, because that inventory stretches probably a decade or more.

David Wheeler – AllianceBernstein

Many companies in the industry are talking about the mix of oil and gas production that they have and how that might change over time and as we've shown in today's results, you're seeing the benefits of growing on the oil side of your business. Would you care to talk a little bit about what the mix might look like this year going into next year, going into year after? Is there anything you can talk about at this point?

Chuck Davidson

Well, our portfolio is a bit unique because of the global side of it, so when you, when you look at our portfolio today, perhaps only 30% of it is U.S. gas. And as we go forward and we're growing these projects, yes, Galapagos or an Isabella, Santa Cruz coming on next year, that will be oil and that will move the oil mix. I would say from a U.S. side of things, I will expect that oil will continue to come up. And that's probably the trend that you would expect to see, especially with the way we've allocated capital.

When you look at the global portfolio and you go out to say 2012, you see perhaps a bit more of a balance because you see in Aseng, which is a rich oil coming on, but it's going to be coupled with Tamar, which is of course a gas project. But outside the U.S. and with pricing that's more tied to global liquids pricing, then certainly it's not tied to U.S. gas markets. So I think the key answer to your question is the U.S. business and clearly we see the U.S. business going more oily over the next year or two.

David Wheeler – AllianceBernstein

Okay. Great. And one last one, you mentioned deepening the Deep Blue to the EOC prospect. Was that part of the – is that incremental to the potential at that well that you've talked about in the past, the deeper target?

Chuck Davidson

We haven't given any indication of what the deepening, deeper target is. So that's something that you referenced a particular interval. We've not provided any information on that. All we're saying right now is that the partners looked at the well results and the well program and decided to deepen.

David Wheeler – AllianceBernstein

Okay. And is that an incremental target to what you guys had talked about in terms of resource potential ahead of time?

Dave Stover

That one, I won't comment on.

David Wheeler – AllianceBernstein

All right. Thanks for your help.

Dave Stover

Thanks.

Operator

And that does include the question and answer portion of today's conference. I would like to turn the call back over to Mr. Larson for any additional or closing remarks.

David Larson

Yeah. I want to thank everybody for their interest in Noble Energy. I know we're cutting the Q&A off here, but I think we committed to everyone that we would stick within the one-hour timeframe. So, again, we appreciate your interest and hope you all have a good day.

Operator

And that concludes today's teleconference. Thank you for your participation.

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Source: Noble Energy, Inc. Q1 2010 Earnings Call Transcript
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