Noble Energy Inc NBL
Q1 2013 Earnings Call Transcript
Transcript Call Date 04/25/2013

Operator: Good morning. Welcome to the Noble Energy's First Quarter 2013 Earnings Call.

I would now like to turn the call over to Mr. David Larson. Please go ahead.

David Larson Thanks, Camille. Good morning, everyone. Welcome to Noble Energy's first quarter 2013 earnings call and webcast. On the call today we have Chuck Davidson, Chairman and CEO; Dave Stover, President and COO; and Ken Fisher, CFO.

This morning we issued our earnings releases for the first quarter and it is available on our website. Later today we expect to be filing our 10-Q with the SEC and it will also be available on our website.

The agenda for today will begin with Chuck discussing the quarter and followed by an update of our Eastern Mediterranean business and highlights of our ongoing exploration program. Dave will then give a detailed overview of our operational programs and near term plans. We'll leave time for Q&A at the end and plan to wrap up the call in less than an hour. We would ask that participants limit themselves to one primary question and one follow-up. Should you have any questions that we don't get to today in the call, please call and we'll do our best to answer you.

I want to remind everyone that this webcast and conference call contains projections and forward-looking statements based on our current views 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 discuss here. You should read our full disclosures on forward-looking statements in our latest news releases and SEC filings for a discussion of the risk factors that influence our business.

We'll also be referencing certain non-GAAP financial measures, such as adjusted net income or discretionary cash flow on the call today. When we refer to these items, it's 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 the Chuck.

Charles D. Davidson - Chairman and CEO: Thanks, David. Good morning, everyone and thank you for joining us today. I've to say right up front that it looks like we're off to a great start for the year. As we go over our results and outlook during this call, I'm sure you'll reach the same conclusion.

My list of highlights for the quarter includes strong earnings, strong cash flow as well as solid production, all of which came in a bit higher than we expected. But certainly surpassing all of these was the surprise of experiencing the Tamar startup late in the quarter. Not only did Tamar startup a few weeks early, but then almost immediately began setting records for gas sales to Israel. A smooth and successful startup of Tamar really sets the stage for us for a great 2013. Projects of the scale and complexity of Tamar are not easy to execute, much less execute under a compressed schedule that resulted in going from discovery to production in just four years.

The project performance we've delivered at Aseng in West Africa and now Tamar in Israel are showcasing an emerging Noble competitive advantage and that is the ability to consistently deliver major projects on schedule and on budget. So, this morning, I'll highlight what I believe has been an excellent quarter. I'll review the financial results and then I'll touch upon the outlook for the upcoming quarters before turning the call over to Dave, who'll provide a more detailed operational outlook.

So, let's look at our performance for the quarter. Adjusted net income from continuing operations for the first quarter was $269 million or $1.48 per share diluted. Excluded from adjusted net income were unrealized losses from commodity hedges and gains on some non-core asset divestments in the first quarter. Revenues were $1.1 billion for the quarter, supported by another quarter of strong crude realizations. Our sales volumes for the quarter were 245,000 barrels of oil equivalent per day, of which 39% were crude and condensate volumes. Volumes for the quarter were significantly above the high end of our guidance due to stronger than expected performance in Israel, the Gulf of Mexico, and the DJ Basin.

Adjusting for divestments, our year-over-year volume growth was 9% and the growth was almost entirely due to increased crude oil volumes from the DJ Basin. Domestic sales totaled 146,000 barrels of oil equivalent per day, up 23% from the first quarter of 2012, excluding volumes from divested assets. Domestic results for the quarter exceeded our expectations as a result of the horizontal program in the DJ Basin and the faster return to production of Swordfish in the Gulf of Mexico.

Internationally, sales volumes were 99,000 barrels of oil equivalent per day, down 6% from the first quarter of 2012, but above our expectations due to stronger than expected volumes from Noa and Pinnacles in Israel, which delivered net production of 110 million cubic feet equivalent per day. As expected West Africa sales volumes were down due to scheduled underliftings.

Our discretionary cash flow from continuing operations for the quarter was $761 million up 10% from the first quarter of 2012. Our liquidity position remains extremely strong at more than $5.3 billion with $1.3 billion of cash on hand. Also in the quarter we made progress on our non-core asset divestment program. We closed two divestment packages one in the North Sea and one consisting of some Gulf Coast assets and received proceeds of approximately $90 million. We also a signed sales agreement on a package of Mid-Continent gas assets that is expected to close in the second quarter. We expect to divest of some additional non-core assets later this year as well.

As I look forward to the rest of the year I am excited about the operational successes that we are experiencing. Onshore; we are on track to drill 300 wells this year in the DJ Basin and we are testing various horizontal lateral patterns across several target zones to increase our recovery per section. We are drilling longer laterals than we have ever had done before and we are seeing some extended reach lateral well production curves that now appear to be tracking an estimated ultimate recovery curve of 1 million barrels of oil equivalent. In the Marcellus, we plan to drill 120 wells this year in cooperation with our joint venture partner CONSOL. Our emphasis remains in the wet gas area where we anticipate adding rigs this year to support the program.

In our offshore business units, our appraisal program supports scheduled sanctions for later this year. I believe that one of the reasons we've been so successful in bringing our major projects to production on schedule is that our appraisal programs have allowed us to design, properly size an effective development scenarios. In the Gulf of Mexico, we expect to complete our appraisal well at Gunflint during the second quarter. We do expect that in the coming weeks we'll be penetrating a deeper exploration target, previously untested on the Gunflint structure, which if successful provides significant upside.

Following our drilling and analysis there, we would expect to sanction a development at Gunflint later this year. Following Gunflint, we plan to spud exploration wells at Troubadour and another prospect before the end of the year. We also plan to sanction a second development in the Gulf of Mexico at our Big Bend discovery by year-end.

In West Africa, our Alen project continues to follow an accelerated plan targeting a third quarter startup and Dave will provide you an update on our progress there. We're drilling a second appraisal well at Carla and working towards the sanction of a project there later this year. Following Carla, we plan to begin an appraisal at Diega.

Looking more closely at our Eastern Mediterranean programs; I was in Israel recently and can really see the impact of our efforts there. We're supplying natural gas to Israel at a higher rate than we ever have before. In fact, we've tested the field at deliveries equivalent to over 950 million cubic feet per day. We expect the facility to deliver at full capacity during the peak summer demand period in the third quarter. Dave will fill you in on some of the details on our operations at Tamar later in the call.

Israel Electric Corporation recently exercised its option to increase the amount of natural gas it will purchase from Tamar. This further supports the need to initiate a second phase of Tamar soon. The new coalition government was recently formed in Israel and the new leaders are becoming familiar with the items on their country's energy policy agenda, which includes energy exports. Our expectation is that the export policy is one of the early issues that the new government will be addressing. Clarity on an export policy is essential as we finalize the farmout agreement with Woodside which in turn will bring us closer to sanctioning the first phase at Leviathan.

On the expiration front, we finished an appraisal well during the quarter at Leviathan which increased our gross mean resource estimate, there at the field to 18 trillion cubic feet. Coupled with the announced increase and resource estimates of commodity of these two fields gross mean resource has now totaled 28 trillion cubic feet. With necessary government support, we anticipate sanctioning Leviathan later this year.

We're currently drilling our Karish prospect, offshore Israel, which is a 3 Tcf prospect. Our analysis and modeling have verified through our earlier successes and we believe this well has a very high chance of success. Following Karish, we plan to move over to Cyprus and spud an appraisal well at our 7-Tcf Cypriot discovery. With respect to our new ventures exploration programs, we completed 3D seismic surveys in two different sections of our tight oil play in Northeast Nevada late last year. We're finishing our analysis and plan to initiate our vertical test program in the third quarter. Bear in mind, this is exploration drilling not factory drilling like we're accustomed to in the DJ Basin. This will be slower drilling, especially initially, but we expect to have some preliminary results later this year. We have a 100% working interest in our 350,000 net acre position.

We're on track to spud our first exploration well and appraisal prospect offshore Nicaragua in the third quarter. We've secured a drilling rig, and are actively evaluating bid proposals on this world-class exploration opportunity and anticipate farming down our ownership before spudding the well. We expect to farm down to include our entire acreage position which has multiple prospects identified. Paraiso alone may contain 1 billion barrels of oil equivalent. We estimate the entire acreage position has a gross unrisked resource of nearly 3 billion barrels oil equivalent. We presently hold 100% working interest and expect to farm down to a level of 40% to 50% interest.

In the Falkland Islands we have acquired almost 1.5 million acres of 3-D seismic. In Sierra Leone we are completing an initial 2-D seismic survey of our acreage, which will direct the future 3-D program. Finally our newbuild drillship should arrive on location in the Eastern Mediterranean around year end with a spud of our deep Mesozoic oil prospect below the Leviathan field.

In closing first quarter served as an excellent start to the year and we really remain well-positioned to deliver on our expectations for the year and beyond as we continue with this period of very significant growth. Earlier this week we announced that we have increased our quarterly dividend by 12% as well as announcing a two-for-one stock split. These actions reflect our confidence in our ability to execute on the plans we have previously communicated to you.

Now I will turn the call over to Dave, who will provide some more details on our ongoing operations.

David L. Stover - President and COO: Thank you, Chuck. As you mentioned we had an exciting quarter in the Eastern Mediterranean as we began production at Tamar. Late last month, we initiated flow from the Tamar field through the world's longest subsea tieback to the platform and then to the Ashdod Onshore Terminal. It took less than a week to bring on all five subsea wells in stabilized flow which was a remarkable feat by our project team. Each of the five wells has been cycled up to the design capacity of 250 million cubic feet per day.

With the startup, we shifted over 300 million barrels oil equivalent of proved undeveloped reserves to, proved developed reserves and we increased the growth mean resource estimate of Tamar by 1 trillion cubic feet to 10 trillion cubic feet total.

Looking forward, we plan to continue producing from our fields at Mari-B, Noa and Pinnacle until they are depleted. As they continue to deplete, we will ramp up Tamar volumes as necessary to support the Israel demand.

We've seen strong demand and expect it to increase as we enter the peak summer season. At times in the third quarter, it seems likely that we will deliver up to the maximum capacity of the development, which is approximately 1 billion cubic feet per day.

We're working to sanction a second phase of Tamar which will increase the system capacity to 1.5 billion cubic feet per day by 2015. The capacity increase will be through a combination of increased compression, system optimization, and the use of storage of the existing Mari-B reservoir. As Chuck commented, Israel Electric Corporation exercised its option to purchase additional natural gas beginning in 2015. The second phase will support the additional sales.

With respect to exploration, we're drilling the Karish prospect in Israel followed by our first appraisal well in Cyprus. The drillship Atwood Advantage will be mobilizing to the Eastern Mediterranean late in the year and is targeted to spud the Mesozoic oil prospect beneath Leviathan. As I've mentioned a number of times, I can't wait to test this (break our play) concept and look forward to having the capability of this new drillship.

In West Africa, Aseng production was nearly 60,000 barrels of oil equivalent per day gross, with decline expected to start this quarter. At our non-operated asset, Alba, we expect some plant maintenance downtime this quarter. Our next big operated project, Alen is progressing very well. I'm confident this will be our fourth major project in a row with outstanding execution. Platform installation was completed by the same vessel that installed the Tamar platform (indiscernible). Subsea installation and commissioning is complete. Major hookups are approximately 80% complete and facilities commissioning is approximately 40% complete. The Alen development is now scheduled for first production in the third quarter with production ramping up to 18,000 barrels oil equivalent per day net. The condensate volumes at Alen, will be transported via pipeline to the Aseng FPSO for offloading.

At Carla, we completed appraisal of a well in Block O, following a planned sidetrack, we flow tested two separate zones. The test confirmed that both zones are productive, one with oil, the other with condensate. Earlier this month, we spud another well to test similar objectives to the south in Block I. Results are expected near the end of the quarter, and we will be analyzing development options for a potential sanction later in the year. One scenario is to flow Carla to the Aseng FPSO via subsea tiebacks.

Shifting over to the deepwater Gulf of Mexico, we restored production at Swordfish following some unplanned downtime. We will be replacing an umbilical there next month, resulting in two weeks of downtime and we'll also be impacted by about a month of downtime at Galapagos, for planned maintenance at the host platform. We recently increased our working interest in Gunflint to 31%, from 26% and are currently drilling our second appraisal well. This well should complete our appraisal drilling and will help determine our development plan. There is a deep exploration zone to this well, which if successful could result in a standalone development. We expect results late second quarter, early third quarter with a possible sanction to follow later in the year.

Following the Gunflint appraisal we plan to drill the offset to our Big Bend discovery at Troubadour. If successful Troubadour would likely be another subsea tie-back similar to Big Bend. We expect to sanction Big Bend this year and if possible the Troubadour could be sanctioned at the same time and co-developed with Big Bend. Following Troubadour we plan to spud another exploration well. We have a number of potential candidates who will be maintaining a one rig program in the Gulf of Mexico through the end of the year.

Moving onshore; our domestic production continues to be led by our growing DJ Basin program as shown in Slide 5 of the packet. For the quarter sales from the DJ Basin averaged 92,000 barrels of oil equivalent per day, an increase of 7% over the fourth quarter and 25% over the first quarter of last year. This month we have been impacted by a series of spring snow storms, which has affected our ability to move volumes and bring on new production. We have taken that into account in our second quarter guidance. The horizontal program contributed 45,000 barrels of oil equivalent per day or 49% of the first quarter DJ production. This progress is amazing, when you consider, first quarter last year we averaged 18,000 barrels of oil equivalent per day from the horizontal activity.

We continue to see the impact of the increased oil production from this program as crude oil accounted for 49% of the production for the quarter. Total liquids volumes were 63% of production with natural gas accounting for the remaining 37%. We continue to expand our drilling activities as we recently added our ninth horizontal rig in March and plan to add our 10th rig later this quarter. We spud 56 horizontal wells in the first quarter, of which 10 were extended-reach laterals. Our extended-reach lateral wells continue to perform extremely well. We'll drill approximately 60 wells this year with lateral lengths generally between 6,500 and 9,500 feet.

As shown on Slide 6, we now have substantial production history on four wells that average 9,100 feet and the average production is tracking well above the 750,000 barrel oil equivalent type curve. It's interesting to point out that two of the wells are tracking at a 1 million barrel type curve. This highlights how far the transformation of this field has come, when you think that just three years ago and the average new vertical well was targeting 40,000 barrels oil equivalent per well.

Slide 7 shows production curves of five wells with an average lateral length approaching 7,000 feet. These production curves are tracking above 540,000 barrel of oil equivalent type curve. We recently finished drilling eight extended-reach lateral wells in one section, with seven of the eight laterals extending beyond 7,000 feet. The wells are currently being completed and we expect initial production from all eight, late in the second quarter. We continue to push this program and in fact we believe we have drilled the longest lateral in the State of Colorado at 9,978 feet.

With respect to our ongoing pilot programs, we're testing recoveries from multiple zones and various lateral patterns as shown on Slide 8. What we have learned up to this point is that, we need a minimum of 16 wells per section in the oil window to drain the B-Bench of the Niobrara. We've also learned that the entire 300 foot section from the Niobrara A through the Codell is productive. It is apparent that more than one well is required to vertically drain the 300 foot section.

It also appears that the B-Bench performs as expected, even with tightly spaced wells in the A-Bench, C-Bench and the Codell. We continue to focus on additional pilot testing in an effort to understand the optimum recovery plan with respect to density, lateral length, multiple zones and zone patterns. We're testing a handful of different patterns across the oil window and we've several more on the drawing board. We're doing this while growing our crude oil production significantly and continuing to accelerate the pace of our horizontal development. We see significant upside to our recoverable resource numbers, which are currently based on an average of approximately 10 wells per section.

Further north, we're actively developing our 45,000 net acre, East Pony area shown on Slide 9. We now have 27 wells on production and will be drilling between 50 and 60 wells there this year. These wells continue to generate 80% crude oil and are among the highest returning assets in our portfolio. Outside of East Pony, we're working to delineate our remaining 185,000 net acre position in northern Colorado.

With respect to crude oil infrastructure, the in-field oil gathering truck line is scheduled to begin service with an initial capacity of 50,000 barrels per day in September.

This line will help us deliver crude oil efficiently to the White Cliffs pipeline in the plains rail facility. The rail facility is scheduled to begin service in the third quarter of this year with the capacity of 68,000 barrels per day. The rail facility diversifies our sales portfolio and gives us market options to the Gulf Coast, the West Coast or the East Coast. The White Cliffs pipeline capacity will essentially be doubled when the loop of the existing line is completed in the second quarter of next year.

On the gas side, DCP is bringing on the LaSalle Plant in September of this year, which will initially add, 110 million cubic feet per day, and then we'll be expanded in the fourth quarter to 160 million cubic feet per day of total processing capacity of that facility. The 230 million cubic feet per day Lucerne 2 plant is scheduled for service in 2014, followed by another 230 million cubic feet per day plant in 2015. Also our Kyoto gas plant was scheduled for startup in the third quarter of 2014 with a processing capacity of 30 million cubic feet per day. This plant alongside the Lilli plant will support our growth in Northern Colorado.

Next to our Kyoto plant we will be building the state's first LNG facility that will be supplying our rigs and frac fleets with a clean fuel source from our owned and operated facility. These efforts give us confidence in our ability to continue to bring our production to market and we expect another year of significant growth from the DJ Basin.

Moving over to the Marcellus; we are operating three rigs in the wet gas area. Currently we have two rigs operating in Majorsville and one rig operating in the Normantown area of West Virginia. In Majorsville we have 20 wells on production from three pads. Completion operations are finishing up at our fourth pad, the 11-well WEB 4 pad, which we will bring to production in late June. Our fifth and sixth pads, the 10-well SHL 8 and the seven-well WFN 1 are finishing drilling operations soon are scheduled to begin completion operations in June.

In Normantown we are breaking out a new development area. We have taken a core and our analysis will guide our development going forward. We will be completing drilling operations on our first Normantown pad, a six-well pad around mid-May. We will begin completion operations there in late June.

We will be adding a fourth rig to our wet gas operations in the second quarter. This rig will be utilized to breakout another development area in Pennsboro, West Virginia. We also intend to add two more rigs to the wet gas area later in the year to support drilling a total of 85 to 90 wet gas wells this year. Current plans for 2013, has our partner CONSOL drilling 35 dry gas wells. In the second quarter CONSOL intends to bring two pads to production.

Let me talk about our volume guidance before we open the call for questions. Our full year volume guidance remains unchanged at 270,000 to 282,000 barrels per day and we expect second quarter volumes to be 254,000 to 260,000 barrels per day. Second quarter volumes will be up over the first quarter, primarily due to the production from Tamar. Offsetting some of the increase are about 3,000 barrels per day impact from divestments of non-core onshore assets and another 10,000 barrels per day from items I mentioned earlier, including plant downtime in Equatorial Guinea and the Gulf of Mexico, along with the early quarter weather in the DJ Basin.

The second half of the year is expected to average around 300,000 barrels per day sales, with increased demand in Israel, startup of Alen, an accelerated ramp-up in the DJ and the Marcellus wet gas programs. This mix of catalysts, will allow us to deliver on our full year volume guidance, while absorbing some ongoing non-core asset sales.

In summary, both Chuck and I have discussed the activity that underpins our confidence in delivering the exceptional growth we outlined late last year. The execution of the Tamar project and progress on Alen, continues to highlight the organization's ability to execute major projects and deliver on our promises.

Our appraisal activity this year at Leviathan, Gunflint, Carla and Cyprus, along with significant exploration wells in the Gulf of Mexico, Nicaragua, Eastern Mediterranean and Nevada provide additional catalysts. All combined with expanding and growing programs in our onshore core areas, provides an exciting year and a tremendous future.

Camille, it's now time to go ahead and open the call for questions.

Transcript Call Date 04/25/2013

Operator: Evan Calio, Morgan Stanley.

Evan Calio - Morgan Stanley: Question in the Niobrara, I know you completed 44 wells versus the 300 annual target. Should we expect completions to be backend loaded and can you help me understand the pace on the completion side? Then, I have a follow-up.

Charles D. Davidson - Chairman and CEO: Well, the completions are somewhat as expected, were a little less than average in the first quarter with some of the weather, but as we mentioned, we're bringing in – we've actually brought another rig in, in March and we've got another rig coming in this quarter. So, the activity will continue to ramp up through the year, and it won't be so much backend loaded, but it will be continual, I'd say from this point forward.

Evan Calio - Morgan Stanley: My follow-up or second question is, I know you gave us a lot of data on Slide 9, on Northern Colorado, do you have any color on the wells drilled outside of East Pony and kind of what were the number of wells drilled outside that area in the quarter?

Charles D. Davidson - Chairman and CEO: No, I'd say it's still too early for that. We're just starting on some of that delineation up there. So, that will be towards the end of the year, before we really have a lot new insight on some of these, what I'd call appraisal areas.

Operator: Doug Leggate, Bank of America Merrill Lynch.

Doug Leggate - Bank of America Merrill Lynch: Dave could I just ask you to elaborate a little bit on your plans for the phase 2 at Tamar and I guess what's behind my question is I think in Chuck's prepared remarks he talked about there was sort of a greater urgency to get that on stream quicker perhaps. Could you maybe just give us an update as to how you see the timeline there and if you could perhaps clarify some of the government noise around gas prices either released to future expansions for both (indiscernible) please? I had a quick follow-up.

Charles D. Davidson - Chairman and CEO: Sure, Doug. First on the second phase of Tamar; Tamar is – that phase is a combination of utilizing compression that we would install onshore as well as the utilization of Mari-B for storage and that's what gives us that big uplift in capacity. I think Dave noted that it would raise the capacity to about 1.5 billion. Although we again just like at Tamar right now, we wouldn't expect to be over average at that level but it raises the peak capacity. Again the key is both storage as well as compression to get there and again that project is expected to be ready to come on stream in 2015. It is actually needed to support the Israel Electric's exercise of their option to expand their gas stake, so all of that is tied together. Our contract with Israel Electric provided for that option to expand and the pricing has already been set in that. So, when it gets to pricing in Israel, really we have got multiple contracts that have already gone through the government review and approval. So, it's hard for me to really comment on any other things that are – maybe just more speculative in the media. We're very confident in terms of what our pricing is for our Tamar project.

Doug Leggate - Bank of America Merrill Lynch: My follow-up will be quite quick. Are you now back funding to carry in the Marcellus and if not, can you give us an idea when you might be starting to pay for that? I'll leave it there.

Charles D. Davidson - Chairman and CEO: Well, it's always hard to speculate on the forward curve, but again the contract provides that once Henry Hub prices average above $4 for three months, then our carry would come back on. So, if we look at the forward curve, we would expect that perhaps sometime in the third quarter, the carry would begin again. So, we're enjoying the benefits of the increased gas prices and I would just say once again as we really like that structure in the contract and it really protected us and aligned our partnership when we went through this period of very low gas prices.

Operator: Charles Meade, Johnson Rice.

Charles Meade - Johnson Rice: Two questions from me on the Wattenberg. First, I know on the graphs you guys have put out showing your well results versus type curve. I know in the past you've shown those as a rolling three day average, but I guess it struck me a little more this time that given the volatility in that line and recognizing it's a rolling three-day average that there's a lot of volatility that's hidden in there and I'm wondering, if you can kind of explain that, is that – I'm thinking, maybe one possible explanation, is that sales rather than production or…?

Charles D. Davidson - Chairman and CEO: That's exactly what it is Charles. That sale, that has – loads are being lifted from…

Charles Meade - Johnson Rice: That's a very good and easy and comforting explanation. Then the next point which follows that or the next question rather, I think it's clear to most people who are following you, are sure that you guys have a huge amount of inventory – drilling inventory here, 60 wells on a section just in the Niobrara B, but where do you think you are, I imagine, first you have to identify the resource, then you have some idea of ranking the opportunities on a present value to cap and then at some point, you're driving efficiencies to bring value forward. Where is most of your focus falling now on those kind of three areas if you agree, looking at it that way?

Charles D. Davidson - Chairman and CEO: We're approaching it on, I'd call it at least three fronts. This is outside of the other appraisal efforts going on in Northern Colorado, but if you think about it, you go back to we're looking at the areal recovery, which is number of wells per section in just the B interval alone, if you start with that, and optimizing that on different parts of the field from Northern Colorado to the Greater Wattenberg oil portion. We're testing this vertical recovery. In other words, the impact of the A, the C and the Codell relative to the Billion, and then the other piece is this long lateral. If you start and you look at it, these long laterals seem to improve efficiency, as we go, whether it's the 7,000 type or the 9,000 kind of starts with where can we fit in the long laterals and how do we do that in a way that we can improve our vertical recovery on some of this. So those are the things we're continuing to test as we develop this field out and evaluate these different patterns if you will. If you noticed on that one slide we showed some of the different pattern possibilities we are looking at. That's not all of them, but that's an example of some that we are continuing to test and will be testing this year as we move through that. To answer that specific question that you posed.

Charles Meade - Johnson Rice: Which of the – I am sorry to interrupt, but which of those three between the (10-C and the B) the vertical or vertically in the column and in the long laterals do you think is most important to you Dave?

David L. Stover - President and COO: I think the real next break through out here if you will be the improved vertical recovery. In other words how do you tie-in the A and the C in the Codell with what you know is there in the B.

Charles D. Davidson - Chairman and CEO: I think the key is that clearly some patterns are worth better than others and that is – I mean that could be the key to really unlocking the optimal development and we have to recognize there is geology at work here. So that what works in one area and we might change it in other area. So this is not just poking holes in the ground. It's a really good (prom) in the work and we are excited on it and like you say we have got a huge inventory there and we are going down a path of really trying to make it as efficient as possible while improving the recovery. But all of those pieces are important.

David L. Stover - President and COO: That's what's tying in the 3-D seismic and everything is important here too as you do optimize different patterns across the field. It won't be one size fits all as Chuck said.

Operator: Leo Mariani, RBC Capital Markets.

Leo Mariani - RBC Capital Markets: Just a quick question for any super extended laterals that you've got here in the DJ. Wanted to get a sense of where you have tested those? What sort of coverage on your acreage have you seen with the SXL test? Then additionally, just wanted to get a sense of the progression in the EURs, obviously you kind of looked like you've stepped these numbers up a little bit, with some of your recent wells. Are these wells kind of continuing to get better as you drill more and more of these and you guys are hopefully kind of optimizing or finding your techniques there?

David L. Stover - President and COO: I think we have. To your point Leo, I think we've definitely seen improvement over the last year or two in how we bring wells on, how we maintain kind of a steady production if you will as we've seen on these – especially the super long laterals, as we've seen on these. Most of these so far have been up in that Wells Ranch type area, that Greater Wattenberg oil portion up there, but it's about 50 or 60 of these to drill year. We're going to start to test some of this in some other areas. Again a lot of it gets back to the geology on this and especially tying in some of this 3-D and making sure that we stay in the zone, and not cross and fault in things and that's where that becomes real important in helping to direct and lay out your well pattern, well plan. So I'd say, we have been encouraged, especially when you look at the decline or the slow rate of decline on some of these extended laterals as you get further out in time. So, the more information we've gotten, I'd say, as we started to see that, we got beyond those 90 days and got into 180 days and beyond. That was really encouraging on these extended reads.

Leo Mariani - RBC Capital Markets: I guess, obviously you mentioned some of your best wells could be approaching upwards of 1 million Boe per well, if you guys could achieve results in that neighborhood what kind of improvement do you think you'd see in economics versus 5,000 foot laterals out here?

Charles D. Davidson - Chairman and CEO: Well, I think just given indicative numbers, we already showed that our extended reach laterals at about the 750, where 100% rates return, and even the normal lateral wells were very good rates return as well. So, looking at, 9,000 foot of maybe guessing well north of 100%, 125%, 130% rates return, that's just all numbers. I back up from this whole development and think about it a different way and that is that, this is an area where we have an opportunity in a plan to invest billions of dollars. As we announced last year, over five years perhaps $10 billion in this area, at rates of return to of07%, 80%, 90%, 100%. That is going to create huge value and growth for our company because it is rare that you can invest that amount of capital at these higher rates of return, but it's all about improving and that's really what your question was directed at, I'm sure.

Leo Mariani - RBC Capital Markets: Just one brief follow-up here, I think David mentioned impacting 2Q production by 2,000 barrels a day, as a result of the asset sale and I think you also said that some of the sales are going to close in the second quarter, so I was just trying to get a sense of what the impact could be, maybe in 3Q if you're going to lose a little bit of additional production as a result of those asset sales that you have already announced here?

Charles D. Davidson - Chairman and CEO: Yes. I think when we are looking at it on a full year basis and I said we are going to absorb some of these onshore non-core assets sales, I mean you are looking at absorbing a couple of thousand barrels for a full year type of piece.

Operator: Joe Magner, Macquarie Capital.

Joseph Magner - Macquarie Capital: Just wanted to clarify, the 10-well current spacing I guess assumptions that support your resource is there a breakdown on which zones or which types of wells are included in that 10 wells or is that assuming to be in the B-bench, I am just trying to clarify?

David L. Stover - President and COO: That goes back to what we showed in December, that presentation. So that was for that full acreage position up there and if you go back to that I think we broke it down where on average that came out to what, 67 acres per well and that included what we had looked at that time and in the Greater Wattenberg oil we were on a little bit less than 50 acre spacing assumption for probably 6,400 of the locations. So over six, almost two-thirds of our locations and about 80-acre assumption down in the gas portion and then in Northern Colorado at that time we were using the assumption of a little over 80 acre spacing up there per location. So we had broken that down in December and that's where that comes from.

Charles D. Davidson - Chairman and CEO: I think when you start looking at and trying to differentiate between the A, the B and the C in the Codell at that point we were just looking at recoveries per section and I think what Dave pointed to is now that we're really working the patterns and looking at the different pattern developments, that's what's causing us to focus in and in some areas it will probably give us an idea of how many would be in the B and how many would be in the A and how many would be in the C. I just keep focusing on as how many wells a section, because if you can – if you are looking at a minimum of 16 per section in some of these areas versus 10 to 4, that gives you an idea directionally of where this is going from a resource standpoint, from a recovery standpoint.

Joseph Magner - Macquarie Capital: So it's really the step up from – it was 10 it has gone to at least 16 and you're testing things that might – testing other ideas that might take it to 32 at sort of a progression…

David L. Stover - President and COO: When you start to roll in potential for staggered multiple laterals at different intervals through the same.

Charles D. Davidson - Chairman and CEO: But keep in mind that we've got areas in Northeastern Colorado, there's still an appraisal and those would be outside of the scope of that. This is more talking about the more concentrated developed area of Wattenberg, extended Wattenberg that we've really defined here.

Joseph Magner - Macquarie Capital: Just to clarify one thing. On this Wells Ranch pad, there were three different spacing concepts that were being targeted. The support today for the 16 per section is that based on that center pad or is the B that was being tested on 40-acre spacing or was it the results of all that work that's being done there? Just trying to…

David L. Stover - President and COO: Yeah, I mean really if you go back to what was rolled into that scenario at that point in time when we built that resource space, it was for all intents and purposes it was a B development for 16 wells per section. So, all the rest of this is testing upsides to that.

Charles D. Davidson - Chairman and CEO: I think that just is reflected also as we've looked at those closely spaced wells in the B-Bench, that's where we're really seeing the performance and that's what supports it. So, your point is correct, but then there is also other patterns that have given us encouragement and support as well.

David L. Stover - President and COO: I think the big point there, Joe, is that anything we've seen on the production from the A to C or the Codell hasn't detracted from our original expectations of the B. This is the pattern we've looked at there.

Joseph Magner - Macquarie Capital: One last question. Any progress made on determining LNG scope or development plans offshore, Israel, onshore versus flowing LNG or still more to come on the scheme there?

Charles D. Davidson - Chairman and CEO: We're working in parallel both options, both floating as well as onshore as of course, we're also looking at Cyprus as well. So, that work, from an engineering standpoint is moving forward, the key will be in Israel, hopefully obtaining a final policy decision by the government, shortly. We do believe that it is pending on the export policy and that will help us move some of those projects forward, but we're keeping every option open right. There's a lot of possibilities there.

Operator: David Kistler, Simmons & Company.

David Kistler - Simmons & Company: Real quickly, maybe tying a bunch of these Niobrara questions together, I believe, in December you talked about a net resource of about 2.1 billion barrels, obviously we didn't have a lot of the results that you've come up with subsequently. Where do we stand now in terms of thinking about net resource potential out of the Niobrara and that general area, Eastern Colorado, et cetera?

David L. Stover - President and COO: I'd say David it’s fair to say we believe it will increase. Just from all the things we have described. I'd say we are probably not ready to just focus on a particular number yet. We still got a lot of drilling, a lot of wells to complete and a lot more production history on some of these different patterns we are testing. I would imagine, we want to get that information in, get some extended production history and then revisit that number towards the end of the year.

Charles D. Davidson - Chairman and CEO: We have – believe me we ask that question all the time. But our history has been is to base our resource estimates on solid results and we don't speculate on where it's going. So this is what we are doing right now, is we are gathering all the data from these compressed patterns, increased density drilling, looking at it through the various areas and that's allowing the teams to start working on improved resource estimates. There's no doubt directionally where it's going. Because you have heard what the basis was on our prior estimates and what we are thinking now. But it's understanding how that applies in the various areas, making sure that we got a good solid estimates on recoveries, that's all part of the process. So sorry for the dodge on that, but we are still getting to answer ourselves.

David Kistler - Simmons & Company: Maybe switching over to the Marcellus just for a second. As you highlighted perhaps as early as 3Q your partner could decide to push the drill bit a little harder in the dry gas window. Just trying to think about it from a cash flow impact in terms of the potential uptick in CapEx versus rising gas prices and the potential impact in cash flow. Do you guys – should we just look at that as a wash and not be worried that any kind of upward movement in CapEx that previously was unplanned will be self-funded by the gas additional benefit of higher gas prices across your gas production in North America?

David L. Stover - President and COO: Yeah, Dave, when you look at it – as Chuck mentioned, that there's a potential if price stayed up for the next three months, let's say April, and then the next two months above that $4, then the carry would kick in what July-August type timeframe. Then the actual impact of that carry kicking in offset by the additional revenue from the gas price, above $4 versus below $4, that's pretty close to a wash, when you look at that. As far as the drilling part, additional drilling, in the discussions we've had with our partner and actually when you think about the realistic timeframe, it would to take ramp up a program again, I don't see a big increase this year in gas drilling. I think that discussion will really be as we start to look at how we lay the plans out for next year and how consistent then the outlook for gas price is.

Charles D. Davidson - Chairman and CEO: I think also, while the industry has experienced a little bit of an uptick in gas prices. We still see in our program that there's – our oil projects have much superior economics. So there's not a desire on our part to ramp up dry gas drilling. Now we'll work with our partner on the 2014 budget and we'll work through that. But this is not a time to get – in my view to get overly optimistic. It's a time to enjoy the fact that we've had a nice increase in gas prices and we need to stick with our plan and that's what we're doing this year, is staying with the plan.

Operator: Arun Jayaram, Credit Suisse.

Arun Jayaram - Credit Suisse: Dave, I was wondering if you could maybe comment a little bit more on some of the well results you saw in the A and C bench as well as the Codell and maybe, I don't know if you could walk us through how these compare, I think in the oil window you've talked about a 335 MBoe type of EUR. Are you seeing well results in any of the benches similar to what you've seen in the B?

David L. Stover - President and COO: I think we are, in cases, and that varies, and it varies with the geology up there and the different patterns. I'd say each pattern and that – I would couch this but it's still very early as Chuck mentioned, we like to get some extended production data, but from what we've seen in the first 90 days or so, each pattern looks economic and one of the things we've really kept a close eye on is just how does any one interval's performance affect the B interval and compare to the Billion. So, we've been very pleased with what we've seen there and so we're going to do a lot more of this type testing and part of the drilling program this year.

Arun Jayaram - Credit Suisse: Fair enough. That sounds like 16 wells per pad. It's kind of money in the bank with upside here. The second question Chuck is, you know, you guys have talked about a 9,500 kind of well inventory for the horizontal program, clearly upside to that number, how do you accelerate – how did this come into your plans to accelerate activity even more? I know you planned to drill 500 wells in 2016, but based on these initial positive oil results from (indiscernible) do you even go even faster than that pace Chuck?

Charles D. Davidson - Chairman and CEO: Now they don't want to answer my phone calls. So all I could say is we looked at – we have been on a pace of growing this program and we looked at our prior five-year plan versus the five year plan that you just mentioned that we put out last December that had added 1,100 wells over that five-year period. So that was a tremendous growth rate there. So it's all about making sure that we understand what the optimum development is, because you don’t want to race in, in an area and prematurely develop it in the way that's not optimum. That's what we are trying to do here, but as soon as we see where there is – we are getting – continuing to get more and more clarity on how to move forward. Yes. The ideas to grow the production, in my kind of constant speeches is that 9,000 drilling opportunities is nice but if some of them are 20 and 30 years out it doesn't add value. So we have got to move that forward but we have to do it in a very deliberate fashion. So it’s all about continuing to press forward. Making sure that we are working everything all the pieces of this, not just the fact that we have got locations but this is a huge business. This is a big manufacturing business, so we have got to work all of those supply chain logistics that go along with it. But that's what we are doing, because we know it's going to create value to accelerate it even more.

David L. Stover - President and COO: Part of the thinking there too as we are going forward is, you are involving more and more to more pad drilling and then the more wells that you can actually put on these pads as you go to a larger density of wells per section, I think optimally it will continue to evolve into an increased activity rate at some point.

Arun Jayaram - Credit Suisse: Final question, Chuck; can you just give us an update on where you stand in terms of trying to close the Woodside transaction?

Charles D. Davidson - Chairman and CEO: All the parties are committed to close it, but quite honestly with so much of that transaction focused on Leviathan and potential, an export project down the road, that we're really, at this point, waiting on the government to issue its export policy. Again, we've gotten – certainly in the recent trip that I was over there, I got a lot of comfort that, that was a high priority with the new government in Israel. So, that's a key piece. That's a key part of it. Certainly our structure that we announced as part of that is tied to an export policy. So, I think both Woodside's CEO and myself have made comments that it's important that the government make some decisions, so that we can move on, because we really can't make good decisions on how to develop Leviathan without having fully defined what the rules will be for export. I'm confident that they will issue those, but that's what's really key to getting everything close.

Operator: Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs: Back to DJ Basin, can you just talk to the cost trends that you're seeing on a per well basis and then relative to lateral lengths?

David L. Stover - President and COO: I think that costs are staying fairly constant right now, Brian, I'd say they've kind of leveled off, as we thought, they've actually come down a little bit over the last year as we've started to get more into development phase on a lot of these areas, but they've somewhat leveled off here. You're still in that range, plus or minus $4.5 million for that 4,000 foot type lateral and then you're up closer to 7.5 and 8 for the 9,000 footers, but you see increased efficiency when you look at the increased lateral lengths kind of an F&D for a well if you will, as you move from the 4,000 to the 7,000 to the 9,000. So, that's part of the economic improvement that you see as you continue to be able to step out lateral length.

Brian Singer - Goldman Sachs: Are you seeing any service cost pressure there? It just seems there's more companies talking and trend potentially accelerating activity around you based in part on your success?

Charles D. Davidson - Chairman and CEO: Haven't really seen it yet, as we get into the third quarter and get in more discussions on next year's pricing and so forth. We'll see where the industry's at and where the activity is, but I haven't picked up anything on increasing pressure on a cost side out there right now.

Brian Singer - Goldman Sachs: Then lastly for the second quarter in Israel, what should our gas price expectations or what do you expect in terms of gas price expectations for gas production applications and do you see the constraint to your production demand ahead of summer or do you see the constraints being the ramp up of capacity at Tamar?

Charles D. Davidson - Chairman and CEO: Well, I think on price, when we laid out our guidance for that, that's the best place to go on that, because it is a blend of Mari-Billion that satisfied some old contracts in the Tamar, so I wouldn't – so, it's just a little north of $5 and I wouldn't deviate from that. I think on the production side of it, I mean second quarter is a – I mean we rolled it into the guidance and it tends to be a shoulder month for Israel and we are kind of making a guess of what the demand will be.

David L. Stover - President and COO: I think when you think about it, second quarter is going to bounce between that, 600 to 700 gross type numbers, kind of what we are expecting right now. Then third quarter as we mentioned we ought to see some periods where you get up in that 900s range, but it's dependent on weather and seasonal demand.

Charles D. Davidson - Chairman and CEO: We have actually – if you go back a couple of years when Egypt was supplying gas we actually saw combined with those imports plus our own deliveries we were seeing a reduction in one third quarter of 800 million plus of total country demand and that was a couple of years ago. So we know that demand is there, guessing weather is just like guessing weather here in the U.S. So I think right now we've got the delivery capacity and we will see what the demand is.

Brian Singer - Goldman Sachs: So demand has been the constraint in the second quarter, you have fully ramped up in terms of Tamar's second quarter to meet whatever demands there maybe?

Charles D. Davidson - Chairman and CEO: Well as say we have tested the facility over 900 million so it is a just a matter of what the demand is. We are all set to deliver whatever they need right now.

David L. Stover - President and COO: We are about at the 1 hour timeframe. So let's take one more phone call and question.

Operator: Irene Haas, Wunderlich Securities.

Irene Haas - Wunderlich Securities: My question has to do with the extended lateral curve. Can you explain to me why you have a little plateau there on the 1 million barrel type curve? Are those later wells that you do something different? Are there artificial lift involved? Just kind of curious as to why it kind of normally go from hyperbolic to now you have low plateau, which is fantastic for cash flow. So a little color please.

David L. Stover - President and COO: You're talking about the initial period or the early stage period, I think yeah it kind of ramps up and then, what we saw is it actually leveled off a little bit for that 30 to 90-day or 30 almost up to 120-day period. That just seems to be the way these long laterals are performing, as you get further away from the vertical part of the well bore, you get less drawdown in these and it's almost like you've got a gravity feed into there from this long period for some period of time, but it just kind of replenishes itself. It's just what it appears to be doing on these longer laterals, until you start to get a little bit of a decline in there, but overall, that's one of the things that really caught our eye when we started to see some of the performance of these. It's how well these held up for an extended period of time, especially early here. Part of that is, just bringing these things on pretty slow. You see that initial ramp up, first zero to 30 to 45 days, we're not pulling on these very hard. We're trying to let them come on naturally and then just feed into the system.

Irene Haas - Wunderlich Securities: Should that be the kind of curve that we would expect as you get more like 300 day data on these extended laterals?

David L. Stover - President and COO: I don't know. That's what we want to see is, how this thing duplicates itself or repeats itself as we get a much wider database here to look at, but we'd like to see that, that's for sure.

Operator: That does conclude today's question-and-answer session. At this time, I will turn the conference back over to the speakers for any additional or closing remarks.

David Larson - VP, IR: Thanks again for everybody participating in the call today as well as your interest in Noble Energy. Just have a good day.

Operator: That does conclude today's presentation. Thank you for your participation.