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Noble Energy (NYSE:NBL)

Q3 2012 Earnings Call

October 25, 2012 10:00 am ET

Executives

David R. Larson - Vice President of Investor Relations

Charles D. Davidson - Chairman, Chief Executive Officer and Member of Environment, Health & Safety Committee

David L. Stover - President and Chief Operating Officer

Analysts

Arun Jayaram - Crédit Suisse AG, Research Division

David W. Kistler - Simmons & Company International, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

John Malone - Global Hunter Securities, LLC, Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Operator

Good day, and welcome to Noble Energy's Third Quarter 2012 Earnings Call. I'd now like to turn the call over to David Larson, Vice President of Investor Relations.

David R. Larson

Thanks, Tim. Good morning, everyone. Welcome to Noble Energy's Third Quarter 2012 Earnings Call and Webcast. On the call today, we have Chuck Davidson, Chairman and CEO; Dave Stover, President, COO; and Ken Fisher, CFO.

Earlier this morning, we issued our earnings release for the third quarter, and hopefully you all have had a chance to review our results. A few supplemental slides were also posted on our website. You'll want to download the slides if you have not already done so, as we'll be referencing them in the call today.

Later today, we expect to be filing our 10-Q with the SEC and it will be available on our website at that time.

The agenda for today will begin with Chuck providing a quick overview of where Noble Energy stands now, then discussing the quarter and finishing up with some comments on our exploration activities. Dave will then give a more detailed overview of our operations and plans for the remainder of the year. We'll leave time for Q&A at the end and plan to wrap up the call in less than an hour. [Operator Instructions]

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 future periods to differ materially from what we talk about today. You should read our full disclosure on forward-looking statements in our latest news release and SEC filings for a discussion of the risk factors that influence our business. We'll reference certain non-GAAP financial measures, 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.

One other item before I hand the call to Chuck. Hopefully, you all are aware that we are hosting an analyst conference on December 6 in Houston. Please make sure to put that on your calendar. We'd love to -- we look forward to providing a significant update on our global asset portfolio and highlighting the significant growth that we believe sets us apart within the industry. Should you not be able to attend in person, the entire event will be webcast.

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

Charles D. Davidson

Thanks, David, and good morning, everyone. I thought I'd depart from our normal format and start out by sharing my thoughts on where I believe Noble Energy is today and where we're headed. It's so easy to get entangled in the quarterly results that sometimes we lose the bigger picture. And it's that bigger picture regarding Noble Energy that I'm so excited about and I don't want us to lose track of.

Many of you have seen our annual report. It has the word "Now" across the cover. It's a word I've been using a lot lately in talking about our company. The periods of transforming, transitioning and preparing are over. For now, we're in the midst of a multiyear period of very substantial and very transparent growth, growth that is truly adding value. This growth is being supported by major accomplishment after major accomplishment. Our organization is truly shining as it demonstrates it's ability to execute really big projects extremely well.

Some that come to mind include the Aseng field in West Africa. It continues to perform extremely well after coming onstream 7 months early and under budget. Galapagos in the Deepwater Gulf, which came on earlier this year, producing at rates well above expectations. Tamar in Israel, perhaps one of the most impactful projects ever taken on by our company, which just sailed from its U.S. construction site. Even with its scale and complexity, Tamar is right on schedule for first production in less than 6 months. Tamar is followed next year by Alen in West Africa, which will be installed by some of the same equipment as is installing Tamar. And as Dave will mention, with Tamar moving so quickly, it makes it more likely that Alen can move up a bit.

Four major complicated offshore projects with projected gross costs totaling over $7.5 billion, all being executed with precision. In my mind, Noble's ability to execute major projects has developed quickly into a competitive advantage.

Jumping to the domestic onshore, the results in the DJ Basin continue to far exceed our expectations and set record after record. Our net horizontal production there was up 29% in the past quarter and more than double from a year ago. In March, we set a year-end target for horizontal production and we blew through it in August. Drilling times continue to come down, results continue to improve and the play area continues to expand. It's hard to see where the limits are right now. Also domestically, the Marcellus is delivering strong performance, with production up 38% from last quarter alone. But I also believe that Marcellus highlights another Noble competency, which is the ability to pull together, quickly integrate and deliver superior performance from major acquisitions.

And by no means are we letting our portfolio go stale. We've successfully divested non-core assets this year and have received over $1.1 billion in proceeds. On the flip side, we've added new major positions in Sierra Leone and the Falklands, where our first well is now drilling a very significant prospect.

Financially, we remain very strong, driven by our outstanding performance and growing all production, discretionary cash flow from continuing operations was a record $714 million this quarter, up 27% from the comparable period last year. Liquidity at quarter's end was $5.6 billion with $1.6 billion in cash, coupled with an expanded and undrawn revolver.

Finally, as a result of where we find ourselves now, and with a high degree of confidence as to where we're going, our board just announced the 14% increase in our dividend, to $0.25 a share. It's all of this that really, in my mind, comprises the big -- bigger picture of Noble Energy and it's what certainly excites me so much. I've had the privilege of working in some very high performing organizations in the past, but I've never been previously involved with one that was delivering as much, with such quality, and with such future potential as Noble is today.

So let's get to the numbers. As a reminder, we reclassified our North Sea properties as discontinued operations last quarter, and our guidance ranges now are based only on our continuing operations. Previous quarters have also been reclassified to reflect the impacts of this change.

Adjusted net income from continuing operations for the third quarter was $167 million or $0.93 per share diluted. Excluded from adjusted net income were unrealized losses from commodity hedges and gains on divestitures of the non-core domestic properties.

As previously announced, we recorded $40 million pretax in exploration expense related to our exit from Senegal and approximately $20 million pretax associated with the Trema dry hole.

Revenues were $1,006,000,000 for the quarter. That's up 14% from the third quarter last year, with revenue from crude and condensate increasing 46%.

Our sales volume for the quarter were 242,000 barrels of oil equivalent per day. This number does not include the 5,000 barrels oil equivalent associated with discontinued operations. Sales of crude and condensate represent about 84,000 barrels per day or 35% of total sales. As expected, total sales were up from the second quarter due to the full quarter of production from Galapagos and the return of the Alba plant from planned maintenance, which occurred early in the second quarter.

Net gas sales in Israel averaged approximately 116 million cubic feet per day, up from the second quarter as Noa and Pinnacles contributed production to Mari-B.

But these good numbers could have been a lot better in that we experienced approximately 12,000 barrels oil equivalent of one-time impacts in the quarter, the largest being around 7,000 barrels a day of oil impact -- equivalent per day loss due to shut-ins for Hurricane Isaac. There was another 5,000 in the DJ Basin due to unusually hot weather and some third-party plant downtime. Even with these impacts, average crude oil volumes for the third quarter were 84,000 barrels per day, up 44% year-over-year.

During the quarter, we completed the first phase of our non-core divestment program by closing sales on domestic assets in the mid-continent, in the Permian and Kansas, and by closing the sale of the majority of our North Sea production. The proceeds of over $1.1 billion have contributed to our strong balance sheet, as we continued to invest in our major projects and horizontal development programs. The next phase of our non-core divestments involves smaller package -- packages, which we expect to execute through the end of the year and into 2013.

Shifting to exploration, we recently hosted a conference call, during which we provided an in-depth view of our new ventures exploration program. This is a program that's very important to us, but with all the activities we have under way in our core areas, we usually have limited time to talk about new ventures. I encourage you to listen to the call, if you've not already done so.

With regards to conventional exploration, we currently have a well being drilled in our Big Bend prospect in the Gulf of Mexico. We expect to have results there by the end of the quarter. Following that, we intend to move to our next and hopefully final appraisal well at Gunflint.

With respect to new ventures, we have 4 significant opportunities we're pursuing in our portfolio. The first of our new venture plays is offshore Falkland Islands, where we have a 35% working interest. It's an area with significant oil potential that we believe could open up a new basin play. Our 10 million gross acre position has over 30 identifiable leads on 2D seismic, with the top 10 leads alone accounting for gross unrisked potential of some 7 billion barrels of oil. An exploration well is in progress at the Scotia prospect, a cretaceous target with a P75-P25 gross unrisked resource range of 145 to 960 million barrels. We expect to have results at Scotia later this quarter.

Our second new venture is a domestic unconventional oil play in Northeast Nevada, where we have a lease position of approximately 350,000 net acres. We're presently acquiring 3D seismic, which will be used to guide a pilot test program next year in which we intend to drill a handful of wells. The play concept has a geologic chance of success of over 50% with P75-P25 gross unrisked resource range of about 200 million to 1.4 billion barrels of oil equivalent.

Our other new play frontiers include Nicaragua, where we plan to drill next year, and Sierra Leone, where we were awarded a working interest of 30% in 2 blocks with Chevron.

Finally, while not necessarily new ventures, we have our deep oil concept underneath Leviathan in the Eastern Mediterranean. And we recently announced that we've contracted a rig that's capable of drilling this prospect, which has gross unrisked resource potential of some 200 million to 1.5 billion barrels of oil equivalent. There are several deep oil prospects besides Leviathan, so we see a lot of running room there.

Before I turn this call over to Dave, let me make a few comments on our work in the Eastern Mediterranean. The countdown to Tamar is progressing rapidly and production is now 6 months away. We have plans to expand the peak capacity of Tamar. We believe there is need for onshore delivery from Leviathan, which would provide diversity of supply and possibly an onshore delivery point to the North.

And finally, we're evaluating the proposals that we've received for bringing in an additional partner at Leviathan. I know that many of you are anxious to hear the details and there's been much media speculation, but sensitive discussions are ongoing and as a result, we will not be commenting further at this time. We are encouraged and our target remains to have secured an additional partner in the project by year end.

Now I'll turn the call over to Dave who'll give you more details on our ongoing operations.

David L. Stover

Thank you, Chuck. Our growth this quarter is indicative of the culture we have been building that makes this possible and sustainable over the next decade. Let's start by discussing our activity in the DJ Basin.

Here, our team has been focused on transforming from a gas to an oil operation, leading to the significant ramp-up of our horizontal Niobrara activity and constant performance enhancements. Since we launched our horizontal program in the DJ Basin in 2010, we recognized the need to accelerate our plans to bring the resource value forward, and that is exactly what we have done. As in the development of any large field, we plan for our needs in water, services, rigs and takeaway capacity. We're in good shape in all these areas, and we continue to expand the services necessary to support our growth.

For the third quarter, we averaged production of 75,000 barrels of oil equivalent per day in the DJ Basin. Our production this quarter was impacted by some one-off issues, primarily tied to the midstream sector, that reduced our production by 5,000 barrels of oil equivalent per day. These issues have been resolved and DCP is currently setting new throughput records for gas on their system. We remain on track to meet or exceed the 5-year growth projections we announced last year. In fact, we're currently producing about 83,000 barrels of oil equivalent per day from this basin with 59% liquids, as shown on Slide 9. And that growth is dominated by our increasing crude oil production.

As we show on Slide 10, every quarter over the last 2 years, we have seen a decrease in our horizontal drilling times, and we're drilling substantially more lateral feet per rig than we would have anticipated even 3 months ago. By the end of the year, we will add 2 newbuild rigs and release 2 older rigs. We will exit the year with an 8-rig program and we will now drill over 200 horizontal wells by year end.

In the third quarter, we spud 64 horizontal wells and completed 57. The bulk of our activity has been in the core and extension areas of Wattenberg, where our liquids are approximately 60% and 75%, respectively. With our focus on the horizontal program, we have halted our legacy vertical drilling program.

In Northern Colorado, we have applied our exploration processes to an area we call East Pony. This area, shown on Slide 11, includes roughly 45,000 net acres, a good portion of which we acquired at the beginning of the year. We have 11 wells online with a 30-day production rate, averaging over 600 barrels of oil equivalent per day per well, with more than 80% oil content. Three of the wells are part of an 80-acre pilot test, and they are actually outperforming the 11-well average. As you can see, the 30-day average production for the 3 wells is over 700 barrels of oil equivalent per day. As a result of this performance, we're now close to full development, when we will transition to pad drilling to realize the efficiencies we have previously achieved in our extension area.

We're also expanding our Lilli Plant, which came as part of the Petro-Canada acquisition, to 15 million cubic feet per day by year end, and we will be installing a second plant in 2014, capable of increasing capacity in this area by an additional 30 million cubic feet per day.

Matching our overall drilling activities, we have continued to significantly increase our pace of completions. Completions in 2012 will more than double those in 2011, and we expect to complete over 70 wells in the fourth quarter. This accelerated horizontal drilling and completion activity is resulting in increased production, especially with respect to crude oil. Early this year, we set a goal for our horizontal program to exit the year at 32,000 barrels of oil equivalent per day net. We met that goal in August, and we are currently producing about 36,000 barrels of oil equivalent per day net, more than doubling our horizontal production since the beginning of the year.

We continue to focus on improving recoveries by increasing densities and testing multiple targets. Our initial 40- and 80-acre pilot project continues to perform well with all 9 wells producing above the 310,000 barrel oil equivalent-type curve after 8 months of production. On our full section 40-acre pilot, testing multiple targets and patterns, we have drilled 10 of the 15 wells, and we plan to have all online this year.

By year end, we will have drilled over 300 horizontal Niobrara and Codell wells, since we started our horizontal program in 2010. Our knowledge of the play grows every quarter, while we continue testing economic enhancements such as EcoNodes and extended reach laterals.

Slide 12 shows the performance of our 3 recent extended reach lateral wells plotted against the 750,000-barrel oil equivalent-type curve. In particular, the 2 recent wells with 90 days production history have been eye-opening. At returns over 100%, this performance is outstanding and we plan to expand this program. We are on pace to drill another half dozen or so this year, and we anticipate escalating the program in 2013 to approximately 60 extended reach lateral wells.

Slides 13 and 14 show how gas-handling capacity is expected to keep pace with our growth over the next year. DCP has announced significant infrastructure expansions to handle future production increases. They increased the capacity of their Mewbourn Plant to 160 million cubic feet per day, and they have announced 560 million cubic feet per day of new capacity, scheduled to begin coming online in the middle of 2013. In short, processing capacity in Wattenberg is growing at a pace that will support our growth projections.

In addition to pure infrastructure development, remember that our production focus has shifted from Central Wattenberg to the Northeast, where crude content is higher and where our Lilli gas plant can contribute to our gas processing needs.

On Slide 15, we show how our production in this basin will continue to shift more heavily to the extension and North Colorado portions of the play, which drives a significant increase in oil and liquids volumes relative to gas production.

Concerning both crude oil and NGLs, we are working with the purchasers and transporters in the region to ensure that capacity is available to support our expected growth profile.

Shifting over to the Marcellus. We're currently producing 115 million cubic feet equivalent per day net. We initiated production from the Majorsville wet gas region in July and now believe that this production is in a very rich area of the Marcellus. We brought 2 pads online with a total of 13 wells. The pads each experienced some production downtime from late September through early October due to a processing plant downtime. However, the plant has been returned to service and our production is ramping back up.

Our condensate yields have fluctuated between 15 and 30 barrels per million cubic feet, and NGL yields are over 50 barrels per million cubic feet. These results have exceeded our expectations, and we are pursuing options with our partner, CONSOL, to accelerate wet gas drilling in 2013. Our wet gas operation in the Marcellus is an area we can continue to apply our learnings from our DJ Basin operation to accelerate performance improvements.

Presently, we have 3 horizontal rigs running in the wet gas area, and CONSOL operates 2 dry gas horizontal rigs in Southwest Pennsylvania. They brought on 22 wells in the third quarter, adding approximately 35 million cubic feet per day net to Noble Energy.

Moving to the Deepwater Gulf of Mexico. Production is currently 27,000 barrels per day. Average production for the third quarter was impacted by Hurricane Isaac, which reduced quarterly production by close to 7,000 barrels of oil equivalent per day. At Galapagos, current production is 14,000 barrels of oil equivalent per day and still outperforming original expectations.

Our exploration well at Big Bend was spud in early October and we expect results by the end of the year. As a reminder, Big Bend is an oil prospect, with the probability of success just over 50%. If successful, it would likely be a prolific Miocene subsea tieback development like Galapagos.

Earlier in the quarter, we finished the drilling and evaluation of the Gunflint appraisal well. Gunflint was confirmed as a commercial discovery and a second appraisal well is planned to the southwest part of the field. The rig will move from Big Bend to the next Gunflint appraisal in early 2013. The information obtained from this well will determine whether development is a standalone facility or a subsea tieback.

Moving to our international programs, I'll begin in the Eastern Mediterranean. Here, our team did a fantastic job bringing Noa and Pinnacles online in record time to support Israel's power needs. This contributed to net Israel production, averaging 116 million cubic feet per day for the third quarter.

Tamar remains on schedule for sales to begin in April of 2013, less than 6 months away. As we saw at Aseng, the tremendous coordination between our folks and our contractors resulted in the Tamar jacket and deck beginning their transit to Israel for installation on schedule and within cost expectations. Slide 17 shows these massive structures as they left the shipyard.

Following the initial startup period, we expect to average approximately 700 million cubic feet per day through the remainder of 2013. The peak demand from Israel may exceed the first phase of Tamar capacity next summer, and we continue to work on solutions, such as the expansion of Tamar and the delivery of Leviathan gas onshore.

Earlier this month, we hosted an exploration conference call in which we discussed the deep oil potential of the Levant Basin. To drill the deep oil targets and to support our global drilling program, we secured a service contract for the newbuild drillship, Atwood Advantage, that is scheduled to arrive in the Eastern Mediterranean in the fourth quarter of 2013. The drillship's capabilities are sufficient to reach the deep oil targets, and the Leviathan deep oil prospect is the first exploration well expected to be spud. The dual derricks and dual BOP stacks along with the faster transit speeds of the drillship are time-saving and cost-saving features that will benefit our global drilling program.

Shifting over to our fifth [ph] quarter area in West Africa, we had another strong quarter with production from our Aseng field, averaging 64,000 barrels of oil per day gross. Sales volumes reflected 59,000 barrels of oil per day due to lifting schedules. Earlier this month, we surpassed 20 million barrels cumulative sales from Aseng.

Our Alen project construction is making excellent progress. Construction is over 85% complete at the yard in Morgan City. The vessel that will install the Alen platform is being utilized to set the Tamar jacket and platform. Once the Tamar installations are complete, this vessel will transit to West Africa. And since Tamar is making excellent progress, we could install the Alen platform earlier than previously expected. This could result in an earlier startup for Alen. The Atwood Hunter rig will be moving to our Carla oil discovery, located below the Alen field, offshore Equatorial Guinea. The rig will drill an appraisal well at Carla with results expected early next year.

Before wrapping up, I want to touch on our fourth quarter volume guidance. We estimate volumes to be 248,000 to 252,000 barrels of oil equivalent per day. On Slide 18, adjusting for the third quarter volumes associated with our onshore divestitures, the midpoint of our fourth quarter guidance range reflects a quarterly growth of 8%.

Throughout our portfolio, I am excited about the results each of our core area teams are achieving, and in particular, our consistent major project execution from Aseng, Galapagos, Tamar, Alen and carrying over to our onshore operations in the DJ Basin and the Marcellus. This attention to execution sets up our future, and will deliver the short, medium and long-term growth we expect. In addition, we now have a portfolio of frontier exploration prospects, any one of which would significantly add to our long-term growth.

With that, Tim, it's probably now time to open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Yes, Chuck or Dave, just one of the -- elaborate a little bit on the DJ Basin. Dave, you mentioned that you believe that the company could be well-positioned to meet or beat your 15% growth target that you highlighted at last year's analyst meeting. Obviously, the slide suggests that you're probably okay, but I just wanted to see if you could elaborate. Do see any pitch points in terms of growth in 2013, until the LaSalle Plant comes online later in the year?

David L. Stover

Yes, I think we're going to see pretty consistent growth here, starting in the fourth quarter and going into next year. I mean, you do have some expansion DCPs, planned expansion coming on in about midyear next year, which will help in the second half of the year some more. But again, we're focused in that high oil content area, where you're up in 70% to 80% oil. So you're actually growing oil at 4:1 to 5:1 ratio versus our gas volumes out there, especially on the areas we're concentrating on. And then we have -- the other part of it is the Lilli Plant still has additional capacity right now in Northern Colorado. So we'll be working to continue to fill that up while we're continuing to expand that area. So I think, if you look at those 2 slides we showed you on the gas comparisons, both in Wattenberg and in Northern Colorado, I think we're in good shape to stay on track and do maybe even hopefully, even a little better on our growth profile next year.

Arun Jayaram - Crédit Suisse AG, Research Division

And Dave, this is just by managing where you put the rigs, right?

David L. Stover

It is. It's also what you're seeing in performance out there on the oil content on some of this, which goes along with managing where we're keeping our activity, and a lot of it's continuing to work with the processors on plans and staying in front of this. And we've had great cooperation on that side.

Arun Jayaram - Crédit Suisse AG, Research Division

Great. Chuck, I did want to ask you a little bit about Cyprus. Now that you've gotten a favorable export ruling from Israel and you continue to move with your partners to monetize Leviathan, what is the strategic endgame for Noble regarding Cyprus? And I know [ph] you're going to appraise that discovery. But does it make sense for you guys to participate in another LNG scheme in that area? Or just thoughts around Cyprus.

Charles D. Davidson

Well, obviously the desirable outcome there would be some integrated solution that looks at how we monetize and export the gas from the basin. And so that's one of the things. As we go forward, obviously, Leviathan is the big discovery and is the one that's getting a lot of attention now, both from a domestic side because some of Leviathan will go into a domestic market, but then certainly from the export side. Still a few more pieces to work together. We're exploring a number of sites in the region. Some of those sites could accommodate gas from both Israel and Cyprus. And so that is still one of the possible solutions. But quite a bit of work needs to be done, both engineering work as well as working with our partners and the governments involved. So a lot of things, a lot of moving pieces, but nothing has fallen off the radar screen. But it just takes a lot of work. And of course, we're very focused right now, as you could expect, on getting Tamar onstream and meeting the near-term gas demand in Israel, which is really surprising us to the upside.

Operator

And we'll take our next question from Dave Kistler with Simmons Inc.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, looking at the extended laterals in the DJ, continuing to produce probably 2x the average EURs. Is that potentially location-specific, or is it just length-specific? And probably most importantly, how much of your portfolio do you think that could apply to?

David L. Stover

Yes, I think we're still working through some of that as far as -- we haven't tested it. Right now, Dave, I'd say we've been focusing in that, kind of Wells Ranch area, that extension area up there. And I would anticipate that's where still a majority of them will be next year. One of the things that area has going for it, you're dealing with large ranches, so the complexity of going to cross sections is a lot easier to deal with and you can handle that quicker up in that area. So that's been part of the reason for focusing there. Also, we're focusing in the higher oil content area with that part of the program. So the full extent of where you can go with that probably remains to be seen, but I'd say for now, we'll continue to focus up there in that extension area and then possibly even some into Northern Colorado. But we're talking about going from 10 to 12 of those this year to 60 next year.

Charles D. Davidson

And Dave, it is an area where we also have the normal length lateral wells also. So we're clearly seeing -- it's not just because of where they were drilled, this is truly -- these longer laterals are having a big impact on the recoveries and the performance. So as Dave said, it's really finding the right locations, and the ranches certainly are the place to start.

David W. Kistler - Simmons & Company International, Research Division

Okay, that's helpful, I appreciate that clarification, and then maybe one more in the DJ. When you look at your pilot test, both on the 80-acre and the 40-acre side of things, they are yielding 30-day rates that are in line or higher. And I want to focus a little bit more on the 80-acre that are showing a little bit higher. Can you talk about -- is there any interference that might be causing those rates to be higher out of the gates that could impact the ultimate recovery of those wells? Obviously, that would be a present value decision as well, but just trying to understand what that looks like at this point.

David L. Stover

Yes, David, if you're talking about the 80-acre we mentioned today, that's that portion up in East Pony. And I'd say that's kind of the natural evolution, like we did down in that Wells Ranch area, where we started with the 160s or so and moved down to 80 and are actually now starting to do 40-acre tests. So this is kind of just a the step behind that up here in the East Pony area. And this has just been our first opportunity to go down to a tighter spacing. I think what you're seeing in all of it is, with this brittle rock, or where you can find this brittle rock, and the more you can bust it open and connect it, the better off you are. So I mean, we're not seeing interference from the standpoint of affecting offset wells performance at all. In fact, you're seeing as it's showing on those 80s and what we've actually seen so far on the 40s down the Wells Ranch area, that performance actually seems to be enhanced in these wells.

David W. Kistler - Simmons & Company International, Research Division

Great, well, I appreciate the clarification and nice to know there's no interference with the wells, it probably keeps the EURs consistent, if I'm not mistaken.

David L. Stover

Right.

Charles D. Davidson

You bet.

Operator

And we'll take our next question from Leo Mariani with RBC Capital Markets.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just overall question on liquidity. Obviously, you've done a number of asset sales this year. Sounds like you've got some other minor ones planned late this year, early next year. You took -- made the decision to increase the revolver, even though it's undrawn, from $3 billion to $4 billion. It definitely sounds like you guys are kind of building a war chest of liquidity here. I mean, should we expect a potential big increase in CapEx for next year? Can you just kind of help us on sort of the thinking there?

Charles D. Davidson

No, this isn't -- we don't build war chests here. We want to make sure that we are covered for any eventual outcome, as commodities are volatile. And we have some major projects that we've made commitments to. And so we need to make sure that we can fund those through virtually any environment. And I think quite honestly, we probably originally thought that maybe we could wait until next year to expand the revolver, but the market was very, very open. We had some banks who really wanted to become part of our line. And so, Ken and the financial team decided to go ahead and do that this year and take advantage of the situation.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, thanks for clarifying that. Just kind of jumping over to Israel, you guys talked about being able to run at 700 million gross at Tamar once that comes online here. And I guess you mentioned the possibility to sort of getting it higher. Could you talk a little bit about sort of how you'd kind of go about doing that? I mean, do you see it as, if there's Israeli demand that's well above that, is that something you could get higher in the second half of '13? And also with respect to Israel, when was it that [ph] the gas price was down about 18% in the third quarter versus the prior quarter. Just any comments around the pricing dynamics and what we should expect kind of in the fourth quarter on the gas price?

David L. Stover

Well, when you look at the volume for next year, there -- it -- we have the capability to produce close to a BCF a day through the system. Now we don't expect to average that over any extended period of time because of needing to preserve some flexibility for peaking, whether it's hourly or daily peaking. But we would expect after this thing's up and running and then you get into the summer season, that we could see volumes up in that 900 or so range during some of that period of time. But I'd say a safe estimate is the average over an extended period is closer to that 700. Now we did mention, as a result of the demand, and as Chuck mentioned, the demand has been to the upside from our original expectations over there. We're looking at 2 additional projects. One is an expansion at our onshore facility, and which could add a couple hundred million a day over the next couple of years, so we're looking real hard at that. And then we're looking at this first phase of Leviathan, to have that ready to bring on to supplement supply in that kind of 2016-type time frame. So we're continuing to look to how we can continue to meet the growing demand needs in country.

Charles D. Davidson

On the gas price question that you had on that, our average gas price is a blend of contracts and terms. And so, especially as we're getting at this point, where the Mari-B volumes are coming down and we're -- we've got contributions from Noa and Pinnacles, that blend is moving around quite a bit. And so that's what we experienced as we went from the second to the third quarter. It was a mix. As you know, the contracts for Tamar are new contracts, and so that will really reset and we previously guided on what we thought the range would be on that. So starting in, hopefully, that April time frame, when Tamar starts up, then we'll have a whole new set and a whole new blend of contracts feeding the market. Just as a follow up, I just want to make sure I was clear on your question on our liquidity is, is we're not -- we're also not planning any huge changes in our capital program as we've outlined before. We see our program as very steady and very predictable as we've guided before. So I just want to make sure I was clear that we're not planning some massive capital jump or surprise from what we've been telling you before.

Operator

And we'll take our next question from Bob Brackett with Bernstein Research.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

A question on those extended laterals. You got them coming in at 8.3 million. What would be the cost of just a kind of a conventional 4,000 or 5,000 sort of lateral?

David L. Stover

Those have been running in that 4.5 to 4.7 range.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Okay. So the savings I can sort of think of is kind of an 8.3 million instead of kind of a 9.2 million?

David L. Stover

Yes, and I think, remember, this is just the first few of these extended laterals. I think our team still feels they can get those just a little under 8 at the end of the day.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Got you. And remind me, what did you guys pay for the acreage up in East Pony? And what sort of royalty do you have up there?

David L. Stover

Now we really -- we've got a blend of acreage at different prices, so we really haven't given out the acreage price. But it was a very, very reasonable price because we got in pretty early on some of this stuff. And then we added to it as we went. So it's a blend from a couple of different places.

Operator

And we'll take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Back to the DJ. Can you talk more about aerial extent and multi-event [ph] potential? On aerial extent, can you put the East Pony area into context size-wise and talk to how much additional acreage is unevaluated with some potential in Northern Colorado? And then perhaps, could you also talk to the horizontals drilled in Codell versus the Niobrara and how you're thinking about that development?

David L. Stover

Well, that's a good bit there, Brian. But let me start with Northern Colorado. In Northern Colorado, remember, we have about 220,000 acres or so that goes along with the 400,000 in Wattenberg. I'd say the East Pony area is around 44,000, 45,000 acres. We've got another of what we'd call West Pony area, of another 50,000 just west of that, where we're starting to drill some wells also. But I'd say when you think about the couple hundred thousand acres in Northern Colorado, we've probably drilled a well, at least in maybe 70% of that area. I'd say we've probably got about 6 more wells in the East Pony to complete yet this year. So out of the 30, 35 wells we've talked about drilling in Northern Colorado, it looks like about half of them will be in the East Pony area, be some more in that West Pony area and some more scattered around up there as we continue to test it. So I'd say we focused on the East Pony here originally as an area to test and move forward with a development pattern, which we've been extremely pleased with, I'd say extremely enthusiastic about what we've seen there. I mean, that looks every bit as good as anything we've seen in the Wattenberg Field. But the other areas are still in much earlier stages. So we're going to have to do some more testing in those areas yet. I'd say -- you had the question on what we're thinking on densities and recoveries and all that. And I'd say we're still -- we've been asked before what inning are we in there. Maybe we've moved from the third to the fourth inning, but we're still early in what we're doing there. As I mentioned earlier, we're down testing some 40-acre spacing in the extension area of Wattenberg. So continued encouragement from that and we'll continue to expand that program. We'll continue to expand the extended lateral program, like I mentioned. We're going to drill 5x to 6x, as many of those next year. So there's a lot of testing and a lot of things still going on. But I'll go back to one of my earlier statements, we haven't been disappointed up here, whether you look at Wattenberg or whether you look at this East Pony area. So I'd say right now, out of the 600-and-some thousand acres that we have up here, we've probably have gotten extremely good encouragement on at least 500,000 of that so far.

Brian Singer - Goldman Sachs Group Inc., Research Division

That's helpful. And then going back to that conversation on Israel and meeting demand next summer, I think you mentioned you could pick -- or you could potentially tap Leviathan, if I heard you correct in your opening comments. Can you just talk about what the level of demand your base contracts would cover? And then what are the pricing implications if you do have to or are able to run at a harder level than what those base contracts call for?

Charles D. Davidson

Well, most of these contracts have terms that allow for swing volumes. And so you can -- especially in the -- like in electricity generation there, as you get demand, it swings up. So we will see times, whether it's peak days or peak times of the day, where we will swing up under the existing contracts to the BCF a day, that is really the limit of our capacity, right as we've got it and as we're installing it now. So we'll swing up to that amount. There may be -- and there's provisions to have some additional customers that are more on what I'd call an interruptible basis, that might be able to fill in when we don't use all that capacity and that might provide some. But I think in the end, the real solution that we're seeing, because there are other customers out there that would like to buy gas, we are seeing that there's quite a bit of demand and the interest continues to grow with the savings -- the cost of savings that Israel is experiencing from natural gas. So our real focus is looking on, number one, a way that we can expand the capacity of Tamar, that will involve some installation of some additional facilities, and then also, a little longer term, looking at a development of Leviathan, that would -- probably the first phase of it, be a position to deliver to the domestic market in Israel. So those are the 2 pieces that we're really looking at to try to meet this growing demand in Israel. As I know you're well aware, when we designed Tamar, we had anticipated that the Egyptian gas would be continuing to flow into the market. And the -- and with Egyptian gas not flowing to Israel, that's left a demand gap.

Brian Singer - Goldman Sachs Group Inc., Research Division

Do you expect the incremental contracts that serve in a domestic market to be signed at more attractive pricing terms than the Tamar contract?

Charles D. Davidson

Well, each of those are negotiated on their own. So I think that -- I think there's a sense as to what the gas price market is in Israel. And we just have to take them one contract at a time.

Operator

And we'll take our next question from John Malone with Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just staying with Israel for a moment, and it looks like Noa and Pinnacles perform pretty well. But how do you see that balance of those 2 fields versus the declining Mari-B kind of playing out between now and April? And on that, you talked about a blend of contracts as one of the reasons that realizations were down. How do Noa and Pinnacles play into that? I mean, does it imply that the contracted price for Noa and Pinnacles are lower than Mari-B?

Charles D. Davidson

Well, first of all, those fields are much, much smaller than what the original Mari-B was. So the whole plan with Noa and Pinnacles was to fill a gap here, especially in 2012, as Mari-B declined. Even with Mari-B, there was a blend of different terms because as you recall, the original gas, some of it was contracted at about $2.65. And then we had some other supplemental volumes that were above that. But as Mari-B has declined, that mix has changed. And so it's a mix that has occurred at Mari-B, as well as these other fields that have come on. They've come on -- in some instances, they are also supplying that basic IEC or Israel Electric Contract. It's just, we have the right to meet that from various supplies of gas. So it's not like they were sold differently. It's the whole blend that moves around as we get down here at the real tail end on some of these contracts.

Operator

And we'll take our next question from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Going back to the DJ Basin or the Wattenberg and your extension areas there, it looks like the completed well cost has been moving up there from kind of the mid-to-low 4s earlier this year, now to $4.7 million to $5.25 million. And my question is, is that really an apples-to-apples comparison, reflecting the service costs? Or is there some scope change in there? And if you could kind of attribute the increase to those 2 things?

David L. Stover

No. Charles, I guess I'm not sure what all you're seeing, but I guess when I look at the costs this year, we're actually seeing them come down a little bit on the full drilling and completion, at least if I compare apples-to-apples type cost. For example, beginning of the year, we were seeing more of that $4.7 million in the Wattenberg area. And then as we got further north, it was closer to maybe $5 million. But you might be comparing, mixing and then matching some of those pieces. But I think now, what we're seeing is in the Wattenberg piece, you're seeing they're may be getting closer to $4.5 million to $4.7 million. So if anything, coming down a little bit. And in the Northern Colorado, they're now coming from maybe that $5 million to $5.2 million, that they were down into the high 4s. So you're actually seeing some downward movement to maybe $100,000, $200,000 per well at least on the drilling and completion, when you look from beginning of the year to what we're seeing now. And I think...

Charles D. Davidson

And also, you've got the potential in Northern Colorado to continue to bring some cost down up there because, in some instances, we've not gone to these high-density pads that we're using at Wattenberg. And that's one way that you can really get some cost savings, as well as time savings. And so as we really move forward, like in areas of East Pony, where it moves into a development phase with higher density drilling off pads, you can get some more savings as well.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. Yes, you actually didn't have the footnote, or you didn't have the slide on -- in this presentation, one of the early ones. It mentioned that may be well costs could have gotten up to $5.25 million. But it sounds like that was a mix shift and going into...

David L. Stover

That was those individual wells as we were testing new areas up in Northern Colorado. And so that wasn't representative of the development program.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Great. That answers my question. And the second thing, related to the curtailments of production in the area in 2Q and 3Q, is there any chance for makeup in Q4, coming in the form of maybe like unfractionated NGL volumes? Or is that just straight-up volume that didn't come out of the wellhead and there's going to be no makeup?

Charles D. Davidson

I think it's volume that didn't come out. I mean, in one case, there was a plant there in the field that they had some difficulties with their aiming system. They got it fixed, and -- but you really can't -- if you didn't produce it, you can't make it up. And as far as I know, we don't have any stored volumes of unfractionated NGLs. In this instance, they couldn't handle the gas at the inlet because of the aiming. So we never could get a chance to recover the NGLs.

Operator

And we'll take our next question from John Herrlin with Societe Generale Associates.

John P. Herrlin - Societe Generale Cross Asset Research

I've got 2 quick ones. With respect to the extent horizontals, given the softness on the services cost side, all things being equal, if you did more pad-type activity, could we expect the development cost to drop, say, 7% to 10% per well? I mean, have you thought about the amounts?

David L. Stover

Yes, John, it's a good question. And I think as we continue to get larger -- I mean, more wells on pad drilling, I think you have an opportunity for that 5% to 10% type range. I mean, that's kind of what the team is working towards up there, over the next year.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. My next question, on Northeast Colorado, would you consider doing greater density pilots, I mean, like, say, a 40-acre pilot rather than the 80-acre pilot with more wells in a given area?

David L. Stover

I think that's something we'll definitely be considering up there. First thing, is that they look at the performance down in the extension area of that pilot we have. Those wells, those 40-acre wells, where we have that full section, that we went the 40-acre spacing, they'll just start to come online over the next couple of months. So that will take us a few months to see how that performs. If we get the continued encouragement from those that we've seen from that first pilot, I'd say that East Pony area is a next obvious target to move up there because you've got now an 80-acre base to compare against.

Operator

And we'll take our next question from Eliot Javanmardi with Capital One Southcoast.

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

I just wanted to know if we could get any color on Big Bend and what's happening there. And also, if you could take us back on the Gunflint appraisal well that you had drilled. I know that you had seen the results initially and reported what you had saw. Is there anything, upon further evaluation, that have -- could have you repositioning the next appraisal well at Gunflint?

Charles D. Davidson

Well, on Big Bend, Big Bend is drilling and there's -- so there's really nothing to update on that. We would expect results at the end --- by the end of the quarter and we'll announce that as it comes up. We've talked a little bit about the prospect. I think our Gunflint appraisal, I mean, I think we're getting, with the appraisal, the well that we previously announced, it helps us, give us a clearer picture of the structure. And the Parkers have agreed on the next location. We know we need to go to the South and appraise that flank of the structure, which we haven't seen yet. And so that's the intent. And so we're really trying to get this nailed down so that we can position it for a sanction for a project.

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

Appreciate that color, and lastly, do you -- the JV payment to CONSOL that happens in 3Q, I believe you have one more left after this year. But in the CapEx spend that's listed for the quarter, is that payment included in that figure for this quarter?

Charles D. Davidson

Actually, that was a commitment that was accrued at the time we entered into the JV. The accounting rules would say that you have to accrue that because it's a capital commitment. So that was all booked last year. And so obviously it's cash, but in terms of capital spend, that all went into our capital spend of 2011.

Operator

And we'll take our next question from Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Yes, very quickly, I'm kind of curious about your East Pony project. And firstly, it's a very oily area, so are these wells on pump, cost-wise, a little more expensive than the wells in the extension area? And then, just a little more color on resource, have you guys come back and revised your outlook for this particular area? Then lastly, is the geology sort of continuous, or patchy, and then acres sort of look like a little rabbit ears. So I was wondering if that's the geology, or is it random?

David L. Stover

I'd say that if I can remember them in order here, Irene, on the first part, we would expect to go to pumping units on these sometime, maybe after a year or so. But right now, they're more starting out with gas lift initially and then actually holding these on some pretty tight chokes upfront, so we can continue to keep some back pressure on some of these and not open them wide open. That continues to seem to perform pretty well.

Charles D. Davidson

And on the, I think on the cost side, we were talking a little bit earlier, I think on an earlier question, about how we would expect costs to come down in this northern area as we go to more pad drilling and we can really do some concentrated wells. I was trying to get all this but before we get to the rabbit play, on the resources, we're working on that. We'll probably, in December, be able to provide an update for you on the resource potential of the entire Niobrara play. And I think that's a great -- I guess it's a rabbit or maybe it's a long-eared dog, but we got it as an East Pony and a West Pony, and I don't think there's any geologic reason that I can say there. It's just that we picked up some concentrated acreage positions and that's how it fell. And we continue to do a lot of seismic work on things, so we've got our own theories as to what's good and what's not good, but we kind of hold that tight.

Operator

And that concludes our Q&A session. I'll turn it back to our presenters for any closing remarks.

David R. Larson

I want to thank everyone again for participating in on our call today and certainly for their interest in Noble Energy. And I'd just like to hope to see all of you at our analyst conference on December 6, and have a great day.

Operator

That concludes today's conference call. We appreciate your participation.

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