Good morning and welcome to Noble Energy’s third quarter 2009 earnings conference call. As a reminder, this call is being recorded.
I would now like to turn the call over to Mr. David Larson. Please go ahead, sir.
Thanks, Ben. Good morning, everyone. Welcome to Noble Energy's third quarter 2009 earnings conference call and webcast. On the call today we have, Chuck Davidson, Chairman and CEO; and Dave Stover, President, COO.
In just a minute, I will hand the call over to Chuck who will review our financial results for the quarter, as well as Noble Energy's outlook for the future. Dave will then go over our operating results and highlights.
We'll leave time for Q&A and try to wrap up the call in less than an hour. Should you would you have any questions that we don’t get to this morning, please don't hesitate to call or contact us, and we’ll do our best to answer.
We hope everyone has seen our earnings release that we issued this morning, including the results for the quarter. Later today, if we do expect to be filing our form 10-Q the SEC and it will also be available on our website at nobleenergyinc.com.
I want to remind everyone that this 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 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 be referring to certain non-GAAP financial measures in the call today such as adjusted net income or discretionary cash flow. When we refer to these items, it is because we believe they are good metrics to use in evaluating the Company’s performance. Be sure to see the reconciliations in our earnings release tables.
With that, I’ll turn the call over to Chuck.
Thanks, David and good morning, everyone. The third quarter was very significant for Noble Energy with the strong financial, as well as operating results and also substantial progress being made on our number of our long-term growth projects.
Our adjusted net income for the quarter was $193 million or $1.10 per share diluted and that's after removing a couple of adjustment items, the largest of which was the unrealized mark-to-market hedging losses. The second time was an increase in allowance for the SemCrude receivable based on our review of the ongoing bankruptcy case, as well as consultation with Counsel.
Our results in the quarter benefited from strong volumes and price realizations, as well as lower costs, which led to outperformance versus street expectations. Adding back the adjustment items we had GAAP net income of $107 million or $0.61 per share diluted.
These financial and operational results reflect substantial improvement over the first two quarters of this year and certainly give us a lot of momentum as we approach the end of the year.
Sales volumes averaged 217,000 barrels of oil equivalent per day, now that's up from the third quarter last year and up from the first half of 2009. In the United States, Ticonderoga in the deepwater Gulf of Mexico returned to full production in the quarter. Our Wattenberg asset continues to deliver with another production record, which included record liquid volumes this quarter.
Internationally, our West Africa volumes were strong, and natural gas demand in Israel was high. Accompanying our strong volumes the third quarter also included a new pricing structure in Israel which we talked about our last quarter.
Now this new pricing structure resulted in an average realized price there of nearly $4 million per Mcf for all volumes sold. This represents a 40% increase from our average Israel realizations for the first half of the year.
With respect to costs it was an outstanding quarter where almost every cost category went our way. Lease operating expense was down over 10% on a per barrel basis from the second quarter this year, as we continue to see the efforts of our operational groups to identify cost improvement opportunities.
In addition, some planned workover slid into the fourth quarter, and certain deepwater Gulf of Mexico processing fees dropped as well. Exploration expense was favorable as a result of continued drilling success and the timing of seismic and exploratory drilling, which will pick up in the fourth quarter.
On taxes our effective rate for the quarter on an adjusted basis was 30% of which 60% was deferred.
Capital expenditures for the quarter were about $225 million with year-to-date spending now at approximately $930 million or 66% of our full-year plans. There is no change to our full-year capital spending plan of $1.4 billion with the fourth quarter expected to increase, due primarily to three deepwater drilling operations that will be starting there.
With discretionary cash flow for the quarter at approximately $500 million year-to-date discretionary cash flow now exceeds capital spending by approximately $280 million. And as hard as it is to believe it now appears that we are headed toward generating free cash flow in 2009.
Capital discipline, cost management, risk management through hedging have positioned us to generate free cash flow for the fourth year in a row, which I think is quite an achievement given the economic and commodity environments we found our self in 2009.
Total debt is down $250 million from the second quarter. It is now just under $2.2 billion. Our debt to book cap was reduced to 26%. Once you factor in the cash balance of over $920 million, on a net basis that ratio is only at 17%. We have approximately $1.6 billion available under our credit facility.
I thought, before I turn the call over to Dave, I’d take a moment and [make] over comments on how we see things for the remainder of the year. Dave will go into our fourth quarter plans and programs in greater detail as well.
Earlier in the year we forecasted that volumes for the year would be on the low end of our initial guidance of 212 to 220,000 barrels of oil equivalent per day. Driven primarily by the third-party impacts of plant delays and downtime in Israel earlier in year, and combined with some of the issues that we’ve experienced at Dumbarton and longer than expected delays to return the deepwater Gulf of Mexico production back from the hurricane that we had last year.
Looking at the fourth quarter we expect US volumes to be down versus the quarter in our deepwater Gulf of Mexico, and Dave will talk about that in a minute, as we had some maintenance work that we will be doing at Swordfish, also onshore natural gas properties, we'll see some decline in the fourth quarter.
Internationally, the last quarter of year is generally a natural gas demand in Israel, but we do anticipate increased North Sea volumes from our field development at Dumbarton, as well as the startup of the Lochranza field very late in the year. As a result, we expect our total company fourth quarter volumes to roughly approximate what we have run year-to-date so far.
On the cost side, we've performed extremely well against our initial expectations for the year. Somewhat timing issues and we do expect fourth quarter costs to be up from the third quarter, putting our total year amount at the low end of our guidance range for lease operating expense and in the lower half of the DD&A range for the year.
Exploration expense has really outperformed our earlier expectations, primarily as a result of the success of our drilling programs, offshore deepwater in West Africa and Israel. We now expect the exploration expense for the year to be at/or slightly below the bottom of our last guidance range.
We're participating in two large deepwater Gulf of Mexico tests in the fourth quarter, but we don't anticipate results until later in the first quarter of 2010, which may not be in time for our year-end 2009 recording. Deep Blue and Double Mountain are two very nice exploration projects, both subsalt lower Miocene opportunities in the deepwater Gulf.
We operate Deep Blue which we estimate to be approximately at 200 million barrel plus gross prospect where we have a 45% working interest. At Double Mountain where we estimate gross resources to be greater than 100 million barrels, we're anticipating with a 30% interest.
Our position in Deep Blue and the large amount of industry interest it had allowed us to obtain a position at Double Mountain and spread our exploration capital across two attractive prospects instead of just one. That makes a lot of sense to us when we look at the costs and risks of these significant tests.
The fourth quarter does include continued drilling in our East Texas Haynesville joint venture. There earnings release noted very positive results from our first well horizontal well there, which had a strong 30-day average initial production rate and gives another positive data point for this resource play on the Texas side.
Our second well there is currently underway, and we should have more results before the end of the year. But the same time the exploration activity continues and we’ve moved into a project execution phase at the same time that the exploration activity is continuing.
We’ve now moved into a project exaction phase focused on converting the huge inventory of resources we’ve discovered in these past few years to reserves and production.
We took a number of steps during the quarter, including the sanctioning of the large oil development project that we’re seeing Offshore Equatorial Guinea, as well as the Isabela/Santa Cruz project in the deepwater of Gulf of Mexico. We've also made important progress on the plans for our Tamar discovery in the Israel.
Our board and our executive management team are committed to ensuring product execution is of the highest importance as we move forward. In fact we’ve recently staffed a new position recently staffed a new position in our Company at the Vice President level who is charged to ensure best-in-class project implementation, as we invest multi-billion dollars for ourselves and our partners.
Significant capital investments on our lineup of major projects will start next year and are estimated to be approximately $1 billion per year in both 2010 and 2011. First production from the major projects is expected in to 2011, when Isabela/Santa Cruz comes on line.
And in 2012, Aseng and Tamar are expected to startup, and at that point we’d be begin generating a significant amount of cash flow from these initial projects enough to self-fund we believe the remaining discovered major project investments.
By 2013, we expect to be delivering 80,000 barrels a day equivalent per day of net production, over $1 billion in after-tax cash flow and approximately $700,000 million in free cash flow to Noble Energy. Again that's in 2013.
All that from perhaps 15 producing wells which really speaks to the quality of the reservoirs that we’ve discovered. We add in the Belinda cycling project and additional oil discoveries at Carmen and Diega in West Africa and then follow that by the Gunflint development in the deepwater Gulf of Mexico.
By 2015 and our net production from all of these projects is expected to exceed a 100,000 barrels a day equivalent. That doesn't include the potential impact of natural gas discovered in West Africa, which is targeted for production in the 2016 timeframe.
So the outlook for Noble Energy could not be brighter. I'm very pleased with our currently business, where we’ve created a diversified portfolio allowing us to allocate capital to optimize returns in exploration program that is just now beginning to tap the full potential of the portfolio.
A very solid balance sheet that's capable of supporting our long-term growth objectives in an organization that's committed to disciplined investment for superior reasons, and coupling that with best-in-class processes and execution. So, it's a very exciting path that we're headed down right now with much, much more to come.
With that, I'll turn the call over to Dave.
Thanks, and good morning, everyone. As Chuck mentioned, the third quarter included strong volumes in each of our major regions. Onshore in the US, the deepwater Gulf of Mexico, West Africa and Israel. If I step through each of these areas, I will mention the major operational items for the quarter, discuss our fourth quarter activity, and provide an update on our long-term growth projects.
Starting onshore in the US. During the third quarter we operated seven drilling rigs on average six of which were focused on liquid-rich properties. At Wattenberg we operated three drilling rigs setting another production record with 283 million cubic feet equivalent per day, including 22,000 barrels of liquid per day.
Earlier this month, we increased our drilling rig count to five coinciding with the completion of crop season. All five rigs will be operating fort the remainder of year setting up our program for 2010. As we continue to look for further potential on this field, we're planning to drill a couple more of horizontal amount of drier wells during the fourth quarter, targeting additional oil potential.
We have two rigs operating in our western Oklahoma Cleveland sand-play. This is another liquid-rich opportunity set, where recent well results have come online with greater than 40% liquid contribution. In fact, our latest three wells had an average gross initial production and initial potential of 2.8 million cubic feet per day of natural gas and 390 million barrels of oil per day.
With the ongoing drilling cost improvements we have seen, this continues to be an area where it makes sense for us to allocate onshore capital. Chuck mentioned earlier the results from our first horizontal East Texas Haynesville shale well, located in the Southwest part of Shelby County.
The completion on the Mary Harris Number 1 included 15 FRAC stages on a 4,500 foot lateral and produced with an initial rate of over 12.5 million cubic feet per day growth and a 30-day average of 11.7 million cubic feet per day gross.
This is just the first well but it gives us encouragement about our 15,000 gross acres in which we have a 60% working interest. We're currently drilling the second well and should have more results by the end of the year.
Overall we now have nine rigs operating on shore, and I anticipate that we will start 2010 with the same level of activity as we continue to monitor gas prices.
Moving offshore in the deepwater Gulf of Mexico, our Ticonderoga asset returned to full production in early August and it is producing around 5,000 barrels of oil equivalent per day net. At Swordfish volumes continue to be strong, despite the impact of a gas well that watered out during the quarter as we expected.
Our rig should be on-location in the next few days to sidetrack the well into an oil zone with production planned for the end of the first quarter 2010. We did had some down time at Swordfish for little over a week in early October, due to a compressor upgrade at Neptune SPAR service facility.
On the exploration front, the exciting prospect at Deep Blue and Double Mountain are set to spud by the end of the year. Deep Blue should initiate operations in November, with Double Mountain expected to start in December.
These are just two of the outstanding prospects that exist in our deepwater Gulf of Mexico portfolio, where we have put a lot of effort into building an inventory that now has some 30-plus identified prospects and total net unrisked potential of 1.6 billion barrels. As an inventory with an equal number of both large standalone prospects, as well as smaller tight back opportunities.
After operations at Deep Blue are completed, our rig will proceed to drill the first appraisal well at Gunflint, followed by two other significant exploration and/or appraisal wells to round out 2010.
The results from five meaningful deepwater Gulf of Mexico exploration and appraisal tests would generate a lot of excitement throughout next year. We recently sanctioned our Isabela and Santa Cruz project that we called the Galapagos area.
Development plans include subsea tieback of the two existing wells, along with the proposed Santiago test to BP's [Makika] facility. Our net capital investment including sump cost is estimated at $360 million targeting net resources of 28 million barrels equivalent.
Production is still expected to begin at 7 to 8,000 barrels of oil equivalent net in mid-2011. Our next rig is targeted to drill the Santiago test towards the end of the first quarter next year and then complete the wells in this development area.
Now let's turn to International. In North Sea, the Dumbarton field had a controlled shutdown at the end of August, when a problem with the turn swivel stack on the FPSO was identified. Repairs are finished and the remaining facility modifications optimized Dumbarton performance and tie in the Lochranza well will be completed over the next couple of weeks.
This has resulted in the deferral of production for essentially all of September and October with a reduced rate for most of November. However Dumbarton should be back to full production on the first Lochranza well online by late November, with the combined 2009 exit rate around 9,500 barrels of oil equivalent per day net, bringing year-end production in North Sea properties to around 13,500 barrels oil equivalent per day net.
Second well at Lochranza will be redrilled towards the end of this year with additional production estimated to come on in the first quarter of next year. As many of you know we are conducting a market test for our North Sea assets. These are mostly non-operated oil levered properties, with a number of near-term development opportunities.
North Sea doesn’t have the significant exploration upside of our operated areas, so it make sense to see if we can monetize these assets and potentially redeploy the capital and human resources to our longer term growth areas. With production increases and significant cash flow expectations in 2010, we will only sell these assets if we can't obtain full value.
Fourth quarter activity in China will include two horizontal wells from our existing platform at the CDX Field. Following this our current plan is to pre-drill four productions and two injection wells designed to be hooked up to a second platform of the field. This is part of the ongoing expansion project with plans to install the second platform and hookup the additional wells in late 2010.
Moving to West Africa, our Alba field continues its strong performance in the third quarter, despite the impact of reduced natural gas sales resulting from some downtime at the third-party L&G facility.
We have made substantial progress on the execution of the Aseng project, awarding the FPSO and subsea equipment contracts. First oil production of 16,500 barrels of oil per day net is expected at startup in 2012.
We have 2 rigs contracted to assist and fix field development, and expect drilling and completion activities to begin in the first quarter of next year. At the same time, we're continuing our geologic and reservoir feed work at Belinda, targeting liquid production from this rich gas common site field.
On the early [lec] of a development, when you code a few subsea wells tie to a production facility that would strip liquids and reinject gas, the liquids would be transported to the FPSO for storage and sales. We are targeting a sanction next year with a 2013 production timeframe.
Our Douala Basin has only had 13 wells drilled to Miocene depths. We have been extremely successful and not to mention the deep horizons which are virtually untested. We are busy maturing additional exploration prospects with the focus on oil opportunities, and I would expect us to drill at least one significant exploration well in the basin next year.
Turning to Israel. Chuck already mentioned the strong volumes and realizations that we experienced in the third quarter. Looking ahead to the fourth quarter, seasonally it is a lower demand period for natural gas, though our expectation is that volumes will be lighter than the third quarter.
We will be initiating natural gas deliveries to Israel Chemicals in the next couple of weeks, when the commissioning process is finished at a rate of up to 15 million cubic feet per day net. At Mary-B we will be mobilizing equipment later this year to drill two additional development wells in the first half of 2010.
Together with the additional compression work planned, these new wells will serve as injection wells for natural gas storage down the road and also in the near-term provide substantial additional natural gas deliverability from the Mary-B field.
Recently, we secured a rig to do the development work at Tamar discovery and to relaunch exploration activity in the region. We're continuing to feed and pre-sanction work and are working to finalize the initial landing location. One of the leading options is a site in the north which would establish our second independent point of delivery in Israel.
This option makes a lot of sense for the natural gas network as it establishes redundancy to the supply system. We are on schedule for project sanction by early 2010 with 2012 first production. Discussions with the number of potential purchasers are ongoing regarding their natural gas needs and the benefits within natural gas can provide.
Our 3D seismic work is underway in the region targeting all of the major exploration leads we currently see on 2D. As the seismic bids came in and the costs continued to decline, we increased the size of the shoot to over 1,400 square miles and should have the results early next year. Based on our drilling success to-date on what we see on 2D, we're very excited to return to exploration here in the second half of next year.
In closing, we're quickly moving towards the end of 2009 and positioning ourselves for 2010 and beyond. We are pleased with the returns of our US onshore programs, buffered by the heavy liquid influence, and initially we expect the similar sized program for 2010, with some additional emphasis on evaluating interesting new horizontal opportunities, such as, Liberia, Granite Wash and Haynesville, among others.
This year's remaining exploration calendar includes the spud of two large exploration tests in the deepwater Gulf of Mexico and our 3D shoot in the Mediterranean. 2010s exploration drilling program is planned to be our largest ever, with five high-impact deepwater Gulf of Mexico tests and a significant exploration well in both West Africa and the eastern Mediterranean, two areas with tremendous recent discoveries.
The results from seven large impact wells will keep us excited throughout the year, while continuing to develop our past success in each of these areas.
On our major projects, we have now sanctioned Galapagos in the deepwater Gulf of Mexico and Aseng in West Africa and a Tamar sanction in Israel is expected in the next few months. Our teams are focused on executing these development plans to the same standards that we have come to expect from our exploration efforts, while moving significant discovered resources to reserves in production.
At this time we'd like to go ahead Ben, and open the call to questions.
Thank you. Today's question-and-answer session will be conducted electronically. (Operator Instructions). Our first question comes from Dave Kistler with Simmons and Company.
David Kistler - Simmons and Company
Quick question kind of focused more 2010, 2011 on production. Looking at activity in the Wattenberg, Haynesville, even in the Piceance can you talk a little bit about what that can do for keeping production flat to maybe even upwards as we kind of work our way through to 2011 and '12 when Santa Cruz Isabel, Aseng, Tamar, etcetera start to come online?
I'll start out and I know Dave will want to fill in a little bit because as you’ve referenced our expectation is basically to keep our volumes flat as we then approach the period where some of these major projects start adding the incremental volumes and that of course, starts with Isabel/Santa Cruz in 2011.
In the US we would continue in the deepwater to see some declines until we do add the new deepwater project at Isabel/Santa Cruz, although as Dave pointed out, we'll have some projects along the way, such as the Swordfish project that helped to mitigate that. Our view is that the US onshore can hold its own quite well, particularly with the depth of opportunities we have in Wattenberg and some of these other place.
We will maintain some sort of program in Piceance and test some of these other areas that you mentioned. We have the potential to grow those as well as if the natural gas market continues the recovery that it's been showing here in the last month or so.
I think just the Chuck's point I think that goes to the fact that starting into the year we're assuming we're beginning hold our capital level in the onshore fairly steady to what we've done this year. And as Chuck mentioned that holds a pretty steady production program. The nice thing is we have the flexibility from the projects that if we decide to increase that based on specialty gas prices or so forth that should be able to provide a little growth if we ramped that program up. But, I think the current pace of capital spending it holds it pretty steady.
I as you step outside the United States on international we just aren't faced in the near term with any huge declining assets there. The North Sea we’re still got some investments that we're building on. Israel’s, the market continues to expand there and as Dave pointed out we're building the capacity for deliverability out of Mary-B as we bridge into the Tamar sales in 2012, and Equatorial Guinea, the Alba fields continues to perform extremely well. The international provides a nice solid base that we are not having to scramble to offset any huge declines on.
We don’t have to put a lot of capital into.
Maintaining that production and we’re going to allocate that capital to these new developments.
David Kistler - Simmons and Company
So just focusing a little bit on that allocation of capital is there gas price that you guys are targeting where you might reaccelerate the rig activity, specifically in the Piceance. Obviously we've seen the basis certainly compress here in the last couple of months?
I think, as you pointed out, the basis has really come back in, and that is helping Rockies project substantially. I mean, as we start getting into the $6 range on a Henry Hub basis or north of $6, it allows us to probably look at expanding that program. As in most of the cases, you've got core areas that do well at lower prices, and it's just a matter of how you walk and step out from those core areas that allows you to expand.
Wattenberg we're just going to keep the throttle all the way down on that. It’s really the activity there is dependent on the pace that we can get permits through the new Colorado system which is not easiest the system to get permits these days.
David Kistler - Simmons and Company
Sure, that's helpful and one last clarifying question. You mentioned the Granite Wash as an area that you might get more active in. Can you just talk a little bit about your position within the Granite Wash?
I think we mentioned it on the last call. We’ve got around 20,000 acres out there, a portion on price two thirds to three quarters of it was fairly heavy drilled on vertical wells a couple of years ago, from the prior that 2004 to 2007 timeframe. I think as we’re seeing what everybody else is doing we continue to evaluate our piece.
We’ve probably got 4 to 5,000 acres that are undeveloped that will go out and probably try a couple of tests on next year to increase our understanding, while we’re continuing to look at some of the deeper horizons and evaluate other opportunities in the area.
Our next question comes from the line of Michael Jacobs with Tudor, Pickering, Holt.
Michael Jacobs - Tudor, Pickering, Holt
Chuck, I was wondering if I can follow up on your comments on CapEx. I know there has been lot of questions in the past on how much you're going to spend in the next couple of years and you mentioned a billion per annum for the next two years in major spending kind of with the onshore program that you outlined and then your expectations for exploration. Can you kind of give us an idea of how CapEx is expected to shake out over the next two years?
I can give you a little bit of some thoughts, because this is the way we've tried to shape it is currently our base program that Dave talked about, which, of course, includes exploration and some early parts of the development projects here in 2009 is roughly 1.4 billion. What we're thinking is that when you add up 1 billion incremental from major projects, you're probably looking at something over 2.5 billion that’s a rough number and we haven’t finished all of our budget work. But that’s what you should be thinking in terms.
Then what we have the ability to do as was discussed in the prior question, is we have the ability to potentially move that program up or down a bit based on what we see in the onshore US and the gas markets. But those dollars are not huge, huge numbers in the overall scheme of things. The big thing that bumps us from where we are today, and where we’ll be in 2010 and 2011 will be that $1 billion a year of expected major project expenditures.
Michael Jacobs - Tudor, Pickering, Holt
When we think about the 2010 exploration program in the deep down and obviously it's a little way out but have you identified which prospects are under consideration?
Yeah. And Dave might just kind of go through, obviously Deep Blue and Double Mountain.
Dave [might] talk a little bit about.
We mentioned the Gunflint appraisal well I think there's the potential for one or two appraisal wells at Gunflint. We have probably another non-op significant exploration test that we expect that we’ll be budgeting for next year. And then we've got two additional operated big exploration tests, one of which we'll probably do next year that are in the queue. These things are all stacked up and in the program to factor into for the budget.
And most of them fall in the category of these middle-to-lower Miocene fairly sizable opportunities. Obviously we're seeing that already with to Double Mountain and Deep Blue. So, again you take those five in the deepwater Gulf of Mexico, you add what I think will be a very nice test that we expect in West Africa that we'll be targeting an oil prospect there, as well as returning to exploration in Israel. It’s going to be a busy year for sure.
I think the programs set up well and solid and lined out really well right now, Mike.
Our next question comes from the line of Ellen Hannan with Weeden and Company.
Ellen Hannan - Weeden and Company
Chuck I just wanted to see if you would run those numbers again that you gave for 2013. I think you said 80,000 barrels a day wells per equivalent per day net. Is this the assumption of the incremental international and the $1 billion dollars after-tax cash flow and also what were your price assumptions behind that?
Okay. Yeah, let me run through that again for you, and that was basically what I was talking about there was the incremental production from these major projects. So it's what we expect from the major projects and the numbers were by 2013. In other words, in 2013, we expect to be delivering 80,000 barrels a day equivalent net.
In addition those major projects would be delivering over $1 billion in after-tax cash flow of which about $700 million is free cash flow. The price assumptions which we used and it's again what we have been, this is consistent with what we've had in our, it shows up on our website as well, and you can refer to it in.
But we used an average price over the period from 2012 to 2015 of 67.50 for oil and these projects are primarily oil. So the gas price assumption really doesn't matter, other than for Tamar and, again, that's a contract we expect to be tied somewhere of oil pricing. So that's what we view as obviously there is upside to that kind of pricing assumption, but that's what's behind it Ellen.
Ellen Hannan - Weeden and Company
And back on the US Dave, do you have any update are you doing anything on the North Louisiana side on your Haynesville prospect?
We continue to participate with our partners. We're in a few wells up there I think they range anywhere from 10% to 30% working interest our share. And we're drilling I think, about one well a quarter. So, its one rig program up in that Caspiana field.
And our next question comes from the line of Brian Singer with Goldman Sachs.
Brian Singer - Goldman Sachs
Can you give us your latest thoughts on the development of gas in West Africa I think you talked about a startup in 2016, but how maybe L&G fits in and the contribution to long lead time spending?
Certainly, we'll get started. That's a whole different project team that we have working. We’ve actually probably now have three teams in West Africa, one that's doing Aseng, one is doing the Belinda and then we have a team that’s dedicated to gas monetization. Actually the discussions on that have moved forward nicely, and these are mainly discussions that involve the government as well as, of course, our partners. It is focused towards a second train at the existing L&G plant there on Bioko Island.
I think really at this point, the discussions are focused on, making sure everybody understands how much volume is available, what our expectations are in terms of the kind of structure. In other words how gas would be taken through the plant. What our expectation is on participation downstream of the plant. So, I would say that we’ve been encouraged, but we have allowed in our schedule, a substantial amount of time to bring these discussions to closure.
Brian Singer - Goldman Sachs
I guess when you think about capital investments, perhaps it would happen in some of the later years, but is that factored into, I think, your billion dollar number?
It would be into the very later years, and so there would not be anything in the next couple of years in terms of investment in L&G. $1 billion a year for the next couple of years really kind of covers projects through Gunflint and would not cover any investment in L&G or really the development of those fields would be in those close to that later timeframe as well. We don't know at this point if or to what extent we would invest in downstream L&G.
Brian Singer - Goldman Sachs
Also on a somewhat L&G related topic, in Israel, how are you thinking about pricing for Tamar and how does a potential regas plants and fall into that from either a competition or potentially increasing the potential for international type price realization?
I'd love to compete against imported L&G. That will be an easy pricing competition. But generally as we've talked with customers, including some of the very large customers, the discussions tend to be off prices that are indexed; and, historically we've indexed off oil, and I would guess going forward, it looks like we'll have an index that will be a factor in the formula as well.
As far as imported gas, I think, realistically, that's in my view and my understanding that's more of an emergency supply because of just when you're a country with that much gas needs out several years, there's, if for some reason our facility has some production interruption or there's an interruption from another source, they need to have a buffer, and it's also, as Dave mentioned, one of the reasons that we're looking strongly at Mary-B as a storage field, because it then provides some additional redundant capacity and supply of gas.
So, there's a lot of pieces that are being worked. Quite honestly it looks like there is a lot more value left in Mary-B as it continues beyond just a producing field to providing perhaps gas storage needs for Israel.
And our next question comes from the line of Joseph Allman with JPMorgan.
Joseph Allman - JPMorgan
Just following up on Tamar, so in terms of the timing if I hear you guys correctly, it sounds like we're going to hear something on the commercialization of Tamar early 2010. And then should we expect to hear about a few different contracts, or do you think it’s going to be one big contract that covers, 400 to 600 million a day initial production that you've previously disclosed?
And then deliverability is that 400 to 600, is that pretty much what you think that field could deliver initially? I think you said 150 million per day per well? And then L&G, what about Israel exporting L&G, is that playing a role sort of in the initial thinking about what to do with the gas resource?
We're talking to multiple customers right now, but clearly the largest producer and consumer of natural gas in the country is the Electric Utility, Israel Electric. So we would certainly think that additional sales contract to them will be significant. It all depends on where those discussions end up, and they're in discussions right now. So number one it's not appropriate for me to disclose where we are exactly on those and what terms are being covered. But there is a substantial volume there.
But there are some other customers as well that in aggregate can provide a lot of volume. The nice thing about Tamar is that, we don't have to sell 6 Tcf or 6.5 Tcf of gas to make this thing fly. We can easily do it in phases. It's a very commercial development. And so we can approach a sanction with either a one or two or three significant contracts and move on from there.
As far as deliverability, the field should have, we anticipate will to have deliverability that will be well above that 4 to 600 million a day. Probably, by the time you put in five wells or something like that at 150 million plus, and I say plus each of deliverability, you've got a lot of capacity, because the demand swings from day to night from season. So we have to accommodate that.
As far as exports of L&G, I think we're way too early. We see that the Israel market can accommodate Tamar, and we've really committed to identify customers for Tamar. And it seems like the customer list continues to grow as the understanding grows in Israel that there's an abundant supply of gas there.
With our exploration efforts that could change and we may be looking, if we have exploration success down the road that may be the point where we would consider export of gas. But it's too early to say for now.
Joseph Allman - JPMorgan
That's helpful. And then lastly, just on the exploration, I think you indicated that next year you will continue with your exploration efforts there in Israel. And then like, how far away do you expect to drill from Tamar? And how many prospects have you identified at this point in offshore Israel?
Well there is a number of prospects, but they're all based on 2D data. So what we're doing right now, as Dave pointed out is we're shooting a fairly large 3D program. And so we don't have the results of that, so we don't know which is going to fall out and, basically turn out to be the best prospect.
Keep in mind we have acreage in Cyprus as well. But it's all in that general basin area. If you really look at it's the northern part offshore Israel that goes out offshore toward Cyprus. It’s all in that basin and where we've identified and showed our acreage in the past.
And our next question comes from the line of Leo Mariani with RBC.
Leo Mariani - RBC
Just kind of heard your comments about fourth quarter production I think you guys were talking about, sort of flat with the run rate year-to-date. Just wanted to clarify if that was sort of a flat with third quarter number or just kind of flat with your average 2009 year-to-date?
No it was a flat for the average year to date. And the reason, as we pointed out as we've got seasonal decline in Israel, Dave pointed out to some downtime we had at Swordfish with some things there and then we had a little bit of downtime at Dumbarton, startup I mean to startup on that. So it’s kind of our rough guess as to where we think the fourth quarter might land.
Israel is always a wildcard, because it is so dependent on seasonal demand, as well as there is a supply of gas from Egypt and they can swing around on us a lot. So the very year-end rate with Dumbarton up and some other things up ought to be pretty nice. But that's kind of our guess for the fourth quarter, right now.
Leo Mariani - RBC
And Haynesville, obviously, your first well was pretty good there. You guys are drilling the second well. There seems to be a lot of very encouraging activity by the industry as well in the area with a number of good wells.
Do you think that area has the potential to maybe get a little bit of capital, a little more capital next year? And could you guys go to a bigger rig program over there which could potentially give you a little bit growth in US gas volumes next year?
Yeah, I think it's one of those areas that we're looking at that has the ability to adjust pretty quickly based on the result and obviously the gas market. But, yeah, we're encouraged from what we've seen both in our results and some of the other results in the industry out in that general area.
So, we're going to be taking a hard look, actually, as we get second well result here towards the end of the year. And I don't know whether it's based on two-well results or three-well results; but if things keep going as they are and we know it has the potential to bring in a second rig next year.
And Mr. Larson, at this time I show no further questions.
All right, thank you everyone. And we appreciate your interest in Noble Energy. Have a good day.
That concludes today's conference. Thank you for your participation.
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