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Noble Energy (NYSE:NBL)

Q1 2014 Earnings Call

April 24, 2014 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, Chief Operating Officer and Director

Analysts

John T. Malone - Mizuho Securities USA Inc., Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Dan McSpirit - BMO Capital Markets U.S.

Operator

Good day, everyone, and welcome to the Noble Energy's First Quarter 2014 Earnings Conference Call. I would now like to turn the conference over to David Larson. Please go ahead, sir.

David R. Larson

Thanks, April. Good morning, everyone. Welcome to Noble Energy's first quarter 2014 earnings call and webcast.

On the call today, we have Chuck Davidson, Chairman and CEO; Dave Stover, President and COO; and Ken Fisher, CFO.

This morning, we issued our first quarter earnings release, which you hopefully have had a chance to review. A few supplemental slides for this call were posted to our website this morning as well. They will be a good reference material for the discussion today.

The agenda for today will begin with Chuck reviewing the quarter and providing an outlook for the remainder of the year. Dave will wrap up with a discussion of our 5 core operational programs. We will leave time for Q&A at the end and plan to complete the call in less than an hour. [Operator Instructions]

I want to remind everyone that this webcast and conference call contains forward-looking statements as well as references some non-GAAP financial measures. You should read our disclosures in our latest news release and SEC filings for a discussion of those.

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

Charles D. Davidson

Thanks, David. Good morning, everyone, and thank you for joining us. The opening of 2014 has gone by very quickly, and we've certainly had a good start to the year. As we look across the energy landscape, we continue to believe that Noble's strategy of having a diversified and balanced portfolio, and that's both from a commodity as well as a basin perspective, is the best strategy for sustainable multi-year success.

We also continue to believe that within specific basins, companies such as ourselves, with scale and size that have the ability to implement integrated development plans and those that are best positioned in terms of market access, will differentiate themselves over the long term. That is why I continue to be excited about the portfolio at Noble Energy, which is comprised of 5 core areas with significant and transparent growth profiles for many years into the future. This is combined with a material exploration program that is testing significant opportunities to grow further our already extensive discovered resource base.

So let me start by providing a quick review of our first quarter financial and operational results, and then I'll spend some time talking through our accomplishments to date. Sales volumes for the first quarter were 286,000 barrels of oil equivalent per day. That's a 16% increase over last year's first quarter and is up 20% after removing noncore asset divestiture impacts. Our volume growth versus last year was driven by our horizontal drilling programs in the United States, as well as from higher volumes in Israel and West Africa due to major project start-ups there at Tamar and Alen during 2013.

Highlighting our performance was the onshore, our U.S. assets, where total horizontal production in the DJ and the Marcellus averaged 100,000 barrels of oil equivalent per day, a quarterly milestone for Noble Energy. You can see on Slide 5 that these programs have delivered growth of over 70,000 barrels equivalent per day in just 2 years' time.

20% total organic company growth quarter-over-quarter is a great start and right where we need to be as we move through 2014. We expect this volume growth will continue throughout this year, and Dave will go through our second quarter guidance and expectations for the remainder of the year in just a bit.

Total revenues were up 21% to approximately $1.4 billion for the quarter, supported by strong liquids pricing, both crude and natural gas liquids, and natural gas prices as well.

On the cost side, most items were right in line with our expectations or slightly lower, primarily reflecting continued efficiency gains in the onshore programs. Adjusted earnings per diluted share was $0.82 for the first quarter.

We remain in a very strong financial position. In the first quarter, our capital expenditures of $950 million were just north of our discretionary cash flow for the period. We ended the quarter with $1.4 billion in cash, total liquidity of $4.9 billion and net debt-to-book cap ratio of 29%. We're still projecting $4.8 billion to $5 billion in total capital for the year, with a variance on that range associated with a Marcellus carry, which is now in place as Henry Hub has been above $4 since December.

Our Board of Directors recently authorized a 29% increase in our quarterly dividend, reflecting our strong performance and continued confidence in our future growth. This marks the eighth year out of the last 10 where we've increased our dividend to the shareholders.

We've continued our portfolio optimization process, which is focused on divesting the remaining noncore assets in our portfolio. During the first quarter, we closed on the sale of the Tri-State as well as East Texas, North Louisiana assets, and we executed an agreement to sell our Powder River shallow gas assets. In addition, we're finalizing an agreement to sell our assets in China and anticipate closing that transaction in the middle of the year. Combined, these properties were producing in excess of 10,000 barrels of oil equivalent per day at the beginning of the year.

As a result of these divestitures, we have adjusted our annual volume guidance, moving the midpoint of the range by 6,000 barrels equivalent per day, which is the full year effect of the divestitures. It's important to point out that the production -- projections that we have for 2015 through 2018 that we provided you last December remain unchanged as we had assumed in those projections that these noncore properties would be divested at the end of this year. This just represents an acceleration of the divestment process that was included in our long-range plan.

We've also made good progress on the next round of major projects. Here, I want to start off on the international side. On March 31, we celebrated the first anniversary of Tamar being online in Israel. In the first year of operation, Tamar produced 256 billion cubic feet of natural gas with an uptime of over 99% and 0 lost time incidents. At times, the field has produced up to the capacity rating of 1 billion cubic feet per day. It's been a tremendous first year of operation at Tamar, with outstanding performance from both the reservoir as well as the facilities. And we are taking Tamar to the next level, with increases in capacity planned for the next 2 years and the first phase of Leviathan then planned for late 2017. Dave will walk through the lineup of how we're increasing our Israel gas deliverability in each of the next 3 years, which will position us with combined capacity between Tamar and the first phase of Leviathan of approximately 3 billion cubic feet per day gross.

At Leviathan, we see nice forward movement in the last few months, following the export policy approval last year. In March, we reached a successful agreement with the Anti-trust Authority and also received a final 30-year development lease for the Leviathan field. The anti-trust agreement will now go through a public hearing period of 60 days before finalization. These are major accomplishments that will allow the development of Leviathan to move forward.

In addition, on the marketing side, we've made some great progress, with multiple regional opportunities continuing to emerge. Discussions with natural gas buyers are well underway, and I would anticipate, over the next 6 months, we will enter into a number of major long-term agreements for Leviathan gas.

Woodside negotiations continue regarding our entry into Leviathan, and we're hopeful an agreement will be reached shortly. In the meantime, we and our existing partners are moving the project forward, targeting a sanction of the first phase late this year.

We've also made great progress on our sanction projects at Big Bend and Gunflint in the Gulf of Mexico, with both on schedule for first production in 2015 and 2016, respectively. We're also preparing for project developments this year for Dantzler in the Gulf of Mexico and Diega in West Africa as well.

In the onshore U.S. programs, we're in the midst of aggressively developing our resources while, at the same time, pursuing additional upside. This is being done through active downspacing programs in both the DJ Basin and the Marcellus.

In the DJ Basin, we've highlighted in the earnings release our first wells testing beyond 16 wells per section, and the results there look very strong.

In addition, we're continuing to maximize the application of extended-reach lateral wells in both plays, which brings forward substantial value through cost efficiencies and enhanced recovery. We've shifted our drilling program in the DJ Basin to a higher percentage of extended-reach wells, based on the positive well performance we're seeing. We are now planning to drill over 90 long-lateral wells this year. That's up from our original plan of 55 wells. This is a major acceleration of value to Noble in the basin.

We've had great results in the Marcellus in the first quarter, including our first reduced stage and cluster completion, which is now on production. In addition, we are close to bringing on production in a number of new areas, and we'll be testing our first lateral downspacing to 500 feet in the near term as well. So we anticipate having a number of new items to discuss with you in the second quarter as well.

Another focus of our 2014 program is to maintain our high-impact strategic exploration program. We're currently drilling the Katmai prospect in the Deepwater Gulf of Mexico and are preparing for a very active offshore program beginning later this year and into 2015, with multiple tests planned in our existing core areas and new frontier opportunities as well.

Some of these new frontier areas have the potential to be a new core area for Noble Energy. You can see an updated exploration calendar on Slide 6, including multiple wells in the Gulf of Mexico, the Eastern Mediterranean and the Falkland Islands upcoming.

I wanted to spend a minute on the early encouragement we've had with our Wilson play in Northeast Nevada. Following the drilling of 2 wells in the center area of our acreage, we've now completed the first of those wells, which encountered a thick 700-foot primary target interval. We performed completion operations over a gross interval of about 175 feet, recovering oil of 35 degrees API flowing from each of the 3 completion stages. So we're now installing artificial lift, preparing for an extended production test of the well.

In addition, we're currently evaluating the potential for completing our second well in the play. And in the second half of the year, we'll be drilling at least 4 additional wells, 2 to the north and 2 to the south, compared with where our activity has been focused so far. This will give us additional information on the continuity of the output across our acreage. So it's still early, but certainly positive. It's a lot of activity to keep up with, but we're well on our way towards a big growth and an enhanced base of resources for development.

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

David L. Stover

Thanks, Chuck. As you mentioned, the first quarter really sets the stage for a very strong growth profile in 2014. In addition to volume growth, we continue to focus on delivering increasing returns through improved capital and operations efficiencies.

Now I'll provide highlights as I discuss each core area.

Beginning with the DJ Basin, we produced 95,000 barrels of oil equivalent per day in the first quarter, which included the impact of severe winter weather. Colder-than-normal temperatures affected our existing production, and we consumed more of our produced natural gas to keep major facilities running. In addition, the timing of bringing a number of wells online was delayed as a result of the storms and facility upgrades. All of these wells are now online and producing.

We are continuing to operate 10 drilling rigs in the DJ Basin and expect to maintain that level into the third quarter of this year. At that time, one of our DJ rigs will move over for a period to the Northeast Nevada Wilson play to perform additional drilling there. During the first quarter, we spud 67 wells in the DJ with an average lateral length of nearly 5,400 feet. 20% of these wells were extended-reach laterals.

Looking forward for the remainder of this year, our teams are extremely focused on accelerating value and pursuing the upside to our long-range plans. This includes 2 primary activities: downspacing tests, where we are developing beyond our currently assumed 16-well per section spacing plan, and continued optimization of extended-reach laterals in the basin.

With the strong and sustained results we have seen, we're highly focused on maximizing our extended-reach lateral program. You can see the change and acceleration of our long-lateral plans for 2014 on Slide 8, where we have also highlighted the potential economic benefit of these wells. Using our Wells Ranch integrated development plan as an example, long-lateral wells have seen estimated ultimate recovery 2.5x a standard-length well, with a net present value close to 3.5x a standard well.

Concentrating on continuing to improve the returns of the program provides huge value to Noble Energy. On the chart on the left, we have highlighted the shift from normal-length wells to long laterals of greater than 8,000 feet. In total, we are planning for approximately 96 medium or long laterals this year compared to our original plan of closer to 58 wells. Nearly half of these extended-reach laterals will be in Wells Ranch and East Pony, and the remainder focused in the other integrated development plans which are moving towards sanction.

Another upside area is the downspacing program, where more than 40% of our wells are targeting either 24 or 32 wells equivalent per section. The first of these tests included a couple of wells in the core IDP, as seen on Slide 9, and results look stellar. These wells were drilled in the fourth quarter last year at a spacing equivalent of 24 wells per section and have now been on production more than 100 days. They are standard-length lateral wells and are tracking at 600,000 barrel equivalent type curve, consistent with the average of all 5 wells we drilled on the Loeffler pad.

We're excited about these results and look forward to additional downspacing activity in multiple IDPs through the remainder of the year. Positive results will lead to an enhancement in recoverable resources as well as increased efficiencies as we determine the optimal development of our IDPs. Between the downspace activity and extended-reach lateral program, over 60% of our wells are focused on upside in the DJ.

I want to add a few comments on infrastructure in the basin, including both gas processing and oil export, which continue to support our long-term growth plans. The DCP O'Connor plant expansion to 160 million cubic feet per day is underway, and progress is being made on additional projects and sizable new plants that we expect will lead to over 1 billion cubic feet per day of capacity on the DCP system in 2016.

On the oil side, we continue to export over 80% of our volume out of the basin to minimize any in-basin price volatility. Additional capacity is currently under construction, including a doubling of the White Cliffs oil pipeline, which will be online by midyear. Also, the Pony Express oil pipeline is moving forward for early 2015, which will tie in our East Pony integrated development plan and provide additional market outlet for oil.

So I'm excited with where the DJ program is headed. The second half of the year should experience 15% to 20% growth over the first half as winter is behind us, fuel facilities are in place, an increasing percentage of extended-reach laterals come online and gas processing and handling capacity is expanded.

Shifting to the Marcellus. Production averaged 227 million cubic feet equivalent per day, a new quarterly record for Noble Energy. This is more than double our net production from the first quarter of last year. The joint venture is currently running 9 drilling rigs in the play, with a total of 36 wells drilled in the first quarter. Existing production from pads online in Majorsville on the wet side and Southwest Pennsylvania on the dry side continue to exhibit strong performance and relatively shallow decline.

On the wet gas side, we drilled 19 wells in the first quarter, averaging a lateral length of approximately 7,500 feet. Our team continues to drive down well cost through optimized drilling efficiencies, highlighted by the recent drilling of 2 8,000-foot lateral sections in less than 48 hours each. A year ago, these lateral portions would've taken over twice that amount of time.

In our Majorsville integrated development plan area, we anticipate over 60 new wells to commence production this year, including our first operated wells utilizing reduced stage and cluster spacing. Our initial test of this completion design was at the West Finley #3 pad, which commenced production in late March. This 4-well pad, averaging 7,500-foot laterals, came online with a rate of 35 million cubic feet equivalent per day. We utilized this new completion design on one of the wells and are seeing initial rates over 25% higher than similar wells with our standard completion design on the same pad.

In our other operated areas outside of Majorsville, I'm looking forward to our first production from the Oxford/Pennsboro/Shirley area, planned to be online in the second quarter. The activity in this area will include our first lateral downspacing test to 500 feet, and we'll continue our testing of the reduced stage and cluster spacing design as well.

We're also excited about first production from our Moundsville area, which is expected to be some of the most liquids-rich opportunities in our acreage.

We anticipate initial drilling this year in the Pittsburgh International Airport area, as well as a number of Burkett interval tests spaced throughout our acreage position. Our first Burkett well continues to be very strong, with over 9 months' production now and the well still producing about 3 million cubic feet per day, essentially flat from start-up.

As we look at the long-term expansion plans for natural gas from the Marcellus, we continue to believe being in the southwestern part of the play is advantageous for market access.

Maintaining market diversification is important. And we have highlighted on Slide 10 the multiple pipelines and pricing points we utilize in combination with our existing firm transportation position. This has helped inflate us on the differential side, and we have not seen some of the larger deducts experienced in the northeast part of the Marcellus. In addition, we have recently secured 200 million cubic feet per day of firm capacity via an open season on Columbia pipes starting in 2017, which will ultimately deliver to the Gulf Coast. And we continue to pursue additional out-of-basin projects as well.

So it's a similar message on both the DJ and Marcellus: strong growth outlook combined with cost and recovery performance focus that will develop material upside. Combined between the 2 areas, I'm expecting around 25% growth in the second half of this year compared to the first half alone. This will provide great momentum for entering 2015 and our 5-year delivery outlook. And as Chuck mentioned, our initial Nevada flow test was encouraging and provides further interest in our onshore activity.

Moving offshore to the Deepwater Gulf of Mexico, production during the quarter was 18,000 barrels of oil equivalent per day, with about 90% crude and natural gas liquids.

Our development at Big Bend in the Rio Grande area remains on schedule for first production in late 2015, and we recently completed our discovery well.

Dantzler is moving forward as well and will ultimately tie in to the Big Bend infrastructure, with first production targeted in 2016. We anticipate sanctioning Dantzler for development by midyear. We now have 2 rigs working in the Gulf, following the arrival of Atwood Advantage late in the first quarter. This rig will be focused primarily on development work at Dantzler and Gunflint. Between Big Bend, Dantzler and Gunflint, we will double our existing production in the Deepwater Gulf in the next few years.

On the exploration front, we've spud the Katmai prospect in Green Canyon. Our working interest in Katmai is now 50%, with a lower paying interest in the initial well. We should have results in the third quarter, with time to drill another Deepwater Gulf of Mexico exploration well yet this year.

We further expanded our Gulf of Mexico exploration portfolio as apparent high bidder on 12 Deepwater blocks in the March lease sale. Our share of the lease bonus is approximately $16 million, adding multiple new prospects to our already deep exploration inventory. Our Deepwater Gulf program is in great shape, with a robust growth program coming from new production in each of the next 2 years and 4 to 5 new exploration prospects through 2015.

Internationally, production in West Africa was 81,000 barrels of oil equivalent per day for the quarter and was impacted by underlifting of oil volumes at Alba. During the quarter, Aseng produced approximately 44,000 barrels of oil per day gross. In the second quarter, our sales volumes will be impacted by some maintenance at our methanol facility and Aseng, which will likely keep us in a slightly underlifted position for overall second quarter Equatorial Guinea oil volumes.

Alen continues to perform well and is expected to grow this year to a level of 30,000 to 35,000 barrels per day gross as we finish planned workover activities. Following on our successful appraisal well and flow test, appraisal well and flow test at Diega, we're targeting submitting a plan of development to the government later this year.

We'll be conducting a seismic shoot over our existing blocks, L and I, during the second half of this year to further evaluate exploration potential on -- in EG. This will also help to enhance current development and appraisal work.

In the Eastern Mediterranean, net production was nearly 220 million cubic feet equivalent per day during the first quarter. The expansion of our deliverability remains on schedule, as we're over 50% complete with the Ashdod compression project and are working towards the tie-in of the Tamar Southwest discovery as well. These projects will be the first part of a multi-year step-up in total deliverability from Israel, with the initial expansion next year, adding capacity installation at Tamar in 2016 and then the first phase of Leviathan in late 2017.

On the gas contracting side, we have recently secured 4 new contracts for Tamar, which total over $2 billion in gross sales over the life of the contracts. These include a number of new independent power plants as well as the first export agreement for Tamar to sell gas into Jordan.

I want to echo Chuck's earlier comments on the progress we have seen recently for the first phase of development at Leviathan. Our plan for Phase 1 development is a 1.6 billion cubic foot per day FPSO, which will support additional domestic gas sales in Israel and large regional contracts as well. And beyond Phase 1, we continue pre-FEED work on an FLNG project for Phase 2 of Leviathan.

On the drilling front, we anticipate bringing a rig back into the Eastern Mediterranean late this year or early next year for a multi-year program covering additional Cyprus exploration, deep Mesozoic oil exploration and development activities at Tamar and Leviathan.

On Slide 12, we've provided a walk-through of our total company volumes through the remainder of the year, including the impact of the asset sales mentioned earlier and our anticipated growth projections. As Chuck mentioned, we adjusted the midpoint of our annual volume guidance by 6,000 barrels equivalent per day for the estimated full year impact of the sale of noncore U.S. assets in China. We've also tightened the annual range a bit, leaving the bottom end of our range in place, reflecting our confidence in our delivery through the remainder of the year. Our profile through 2014 is similar to what we delivered last year.

For the second quarter, we have removed 6,000 barrels equivalent per day associated with the Tri-State, East Texas, North Louisiana and Powder River Basin asset sales. From there, we anticipate substantial growth from the DJ and Marcellus. After adjusting our noncore asset divestitures, our second quarter guidance at midpoint is up 16% from the second quarter last year.

Slide 13 will be helpful for those who are modeling our business as it lays out detailed second quarter and full year guidance.

So let me conclude by saying everything is right on track for 2014 in our longer-term plan. We're aggressively pursuing the upside in our onshore programs while adding to our major project portfolio, all with a focus on execution and performance enhancement.

So with that, April, we'd like to now open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll first hear from John Malone of Mizuho Securities.

John T. Malone - Mizuho Securities USA Inc., Research Division

Just a couple of real specific questions for me, Dave. Looking at the Loeffler pad, you talk about the 5 wells you've got there that are going over a 600 MBoe curve. What exactly are you doing at those wells? Is it downspacing and just different completion? Or what's different about those that they stand out?

David L. Stover

It's really an area where last year was probably the first of the program. We went in and started to look at something that would be equivalent to a 24-well per section test, if you will, John. So I mean, that's really what we're doing. That's down in that core area of the field. And so really, what -- we went in and drilled 5 lateral wells, all really normal lateral lengths, if I remember correctly, and they're all performing very well. The main point of that is that the 2 wells that really are testing the equivalent 24-well per section versus 16 are performing every bit as well as the other 3.

John T. Malone - Mizuho Securities USA Inc., Research Division

Right, right. Okay, that's impressive. And then just on the Marcellus as well, just talking about wells, the one which you got the 25% increase in the rate. You mentioned this before in your prepared statement, but can you elaborate on what was done differently there and how replicable it is in the rest of your acreage around Majorsville?

David L. Stover

Yes, that's where we talked about doing this reduced stage and cluster spacing completions, and we've actually -- our JV partner out there has also been doing some of that on the wet gas side, so we're trying to apply this now on -- I mean, on the dry gas side, so we're starting to apply this now on the wet gas area. So this is the first well where we did that, where you're essentially narrowing the area and impacting the area that you're affecting. If you go back to what we've normally been doing on 300-stage lengths with 60-foot cluster spacing, this has taken it down to about 150-foot stage lengths with 30-foot cluster spacing. So you're just getting a lot greater density on the completion there.

John T. Malone - Mizuho Securities USA Inc., Research Division

Okay. What does that do to the CapEx per well? I mean, your 25% increase, how much did the CapEx go up for?

David L. Stover

It's slight increase. I'd have to check on that number.

John T. Malone - Mizuho Securities USA Inc., Research Division

So not a comparable increase compared to the rates?

David L. Stover

No, no, not anywhere near that. Not anywhere near that.

John T. Malone - Mizuho Securities USA Inc., Research Division

Okay. And then just last question on that, are you changing the amount of proppant you're using? I mean, other than just -- and now you're using the total well. How does that change the proppant use?

David L. Stover

Yes, and we can get you more specifics on that, but it increases the amount of proppant, actually, because you're putting more into a smaller -- into the same area. When you look at the same effective area, you're putting more proppant into that area, and the idea is to create more connection within that same 300-foot space, if you will.

Operator

And next we'll hear from Arun Jayaram of Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Chuck, I just wanted to ask you a little bit, given some of the geopolitical tensions in Ukraine, are you having some dialogue regarding some customers regarding gas in the Mediterranean? And how do you think about Cyprus as being a strategic asset, given some of these geopolitical concerns?

Charles D. Davidson

Well, I think, certainly, with what's happened on the course of the last month or so, there's greater interest in the Mediterranean gas. And clearly, we're seeing, and we've already pointed out, that the regional market there is very strong. There's certainly a lot more work to be done in terms of possible European markets. Yes, there's interest there, but we've also got tremendous interest from our customers in the region, as we've noted, Jordan and the potential for markets in Egypt. Cyprus is -- it nicely blends into the mix, although I think our view still is that Cyprus would be based on an LNG solution. But we have to keep in mind that LNG out of this region can be taken to Europe as well. It doesn't have to be through pipelines. It could be through LNG as well, either floating or land-based. So I guess the bottom line is, yes, we get calls. Yes, we're getting a lot of interest, but right now, we see Leviathan Phase 1 being strongly supported by the regional markets that we've been developing here in the course of the last year.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And Chuck, just to follow up, can you provide us an update? I know you're relatively close to completing the Woodside deal. I know export taxes appear to be the last hurdle. Can you give us an update on what the government wants and kind of where you're at in terms of getting the export tax issue taken care of?

Charles D. Davidson

Well, there's a couple of tax questions that came up on it. And really on the export tax, the government has provided a framework, a template of what they plan to do on that. So we're actually, in terms of moving forward with Woodside and our project, we're fairly comfortable with what that framework is. They still have to put it into final legislation. But that, they actually -- the government published the, I'll call it, the framework or the template for how that would work in late March, just before we were working on some other things. There are some other tax issues that both Woodside and ourselves were working on, and they have to do with how the transaction itself is taxed, proceeds that we receive, how Woodside would be allowed to write off their investments. I think from our perspective, we're satisfied. We've got things sorted out. And I'll leave it to Woodside. I hear encouraging things, but I'll leave it to Woodside to report on where they ended up on their tax issues.

Operator

Next, we'll hear from Leo Mariani of RBC.

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

Guys, just looking at the DJ here. Clearly, it sounds like you lost some pretty significant volumes in the first quarter. Would it be possible for you guys to quantify that all and maybe give us a sense of, now that it's recovered, sort of where current DJ production is currently trending?

David L. Stover

Yes. I think when you look at the first quarter -- and we had anticipated a good bit of that when we put the guidance out, Leo, but it was probably affected, when you look at just the weather portion, 5,000 barrels a day or so. And then the other element of that was it just pushed back some timing on completions and so forth. But like I mentioned, those that had been delayed a little bit, we've now got on. So we're catching up pretty quickly here in April and moving into May. But if you look at it really and you look at first quarter and even second quarter relative to the second half of the year, it's the same type trend we're seeing this year as we saw last year. I mean, you see that seasonality impact there in the first part of the year, and we probably saw even more of it this year.

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

Okay. And I guess in terms of some of the asset sales you all talked about, I guess multiple packages in the U.S., it sounds like some of those closed. It sounds like PRB is closing maybe later this month or something. Do you guys have kind of a proceeds number to Noble for those asset sales at this point?

David L. Stover

It's roughly around $100 million or maybe a little over $100 million for the onshore U.S. portion.

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

All right. And I guess, is China still kind of in negotiations in terms of asset sale price? Just wanted to get a little bit more color in terms of where we're at on that process.

David L. Stover

Yes. We're still working through that. I mean, we're expecting -- and kind of like we laid out there, we expect to have that all completed and make good progress on that towards midyear.

Charles D. Davidson

Yes. That's probably one, until we get it all wrapped up, we wouldn't want to disclose the value on it.

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

All right. And I guess just lastly on the DJ. Any kind of comments on sort of where things are in terms of potential frac regulation that may be coming on, referendum ballots and kind of what you guys are hearing as kind of the latest and greatest out of there?

Charles D. Davidson

Well, I think, I mean, our communication efforts are fully engaged. As I think many know, we've formed with Anadarko and are getting support from other industry partners; a group, Coloradoans for Responsible Energy Development. And they're fully engaged in terms of communicating the benefits of development in Colorado and as well as a lot of our employee programs. Where we stand right now is there were a number of ballot proposals to go on the ballots that were submitted. They are just now going through the final review process. Some of them have already been pulled down, either duplicative or the sponsors felt they were not necessary. So we should have a better feel in the next few weeks as to what the emerging set will be. But then they still have to collect signatures. And so the deadline for signatures is early August. So we're really not going to know much more until then as to what may be on the ballot and what won't be on the ballot. We have through -- I would say that there have been sponsors who've submitted what I would call 4 countermeasure ballots. These are ones that are more, I think, supportive of development. And so we're going to have to see how those go and see which one of those collect the necessary signatures. But I think we're prepared for a full communication effort. It's going to be a lengthy summer, and we'll see. There's a lot of political dynamics that are happening here, and it changes daily.

Operator

And next, we'll hear from Dave Kistler of Simmons & Company.

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

Real quickly, just thinking about the DJ Basin and moving to the longer laterals there and the impressive results, can you talk a little bit about how that shift from shorter to longer impacts CapEx in that region and what that does in terms of the production profile? I would suspect longer laterals will lead to a little bit more lumpy production profile going forward.

David L. Stover

And I think you're seeing some of that, Dave, with the bigger increase in the second half of the year as you start to bring more of these longer laterals on. I think on the overall cost basis, we've adjusted the program and relooked at it in such a way that we don't see, actually, any increase to this year's capital program. We're still expecting the same overall cost. It's fewer wells now but actually the same or a little more total footage.

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

Great. I appreciate that clarification. And maybe shifting over to Nevada just for a second. You talk about having 700 feet of kind of identified play and completing about 150 feet, if I got those numbers correct. Quality of the crude, 38-degree, did it have a hot paraffin content in it? And did the quality of the crude vary at all amongst the various intervals that you completed?

David L. Stover

I think we picked 3 different intervals to test. And we tested each of those separately, at least initially, to let them flow a little bit, recover some of the fluid and see the oil content come up on each of them. All had very similar, about 35-degree, gravity. It is somewhat waxy, as we expected, so no real surprise there. And now what we're going to do now is put artificial lift on and get an extended production test.

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

Okay. And just as a standalone on verticals, and I apologize for having a follow-up, but is it commercial on a stand-alone basis just as verticals? Or is this really just way too early to tell? I'm just trying to think about how we extrapolate that in terms of what it could look like longer term.

David L. Stover

Well, and that's some of the information we really need to see from this more extended test here. That's why we're going to put it on pump, get an extended test, Dave, and continue to look at it because that's one of the unknowns yet. Is this going to be potentially a vertical program and will it stand on its own on a vertical basis? Or even as we look at it, do we see enough of a sweet spot or something that we want to target a horizontal program? Those are some of the things we don't know yet, and probably we'll need to get more answers as we see how this play develops and we drill. Probably the next couple of wells, we'll drill a couple wells to the Northeast and a couple wells to the Southwest, and we'll start to get a feel for the continuity of the formation as we move over a wider area, along with getting an extended production test. Both of those things will be really helpful in us determining what type of play we move forward with here.

Operator

Our next question comes from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

On the DJ, you talked about the increased use of longer lateral wells there. Can you talk more to both the impact on production you expect that to have and the impact on CapEx? Maybe in the context of Noble it's less material, but one would think there would be a positive impact on both.

David L. Stover

Well, I think longer term, what we're seeing is this should create more value as we go forward, the more we shift the program from normal length to longer length, as long as we can continue to duplicate the kind of results we've seen initially on some of this. But I'd say, for this year, by the way we've timed this in and laid it out, we aren't changing our expectations on volume or capital. As we continue to build the program into more longer laterals, I think it can have a positive impact on both. It definitely has a positive impact on overall, if you will, F&D per well here if you just look at those numbers that we laid out there.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then on the production trajectory you talked about in your slide, if we exclude the impact of seasonally higher Israel gas demand in the second half, can you talk to the key milestones or items on your critical path for you to get that wedge of about 30,000-plus barrels a day of growth in the second half over the second quarter?

David L. Stover

I mean, the biggest portion of that is the onshore programs. I think I mentioned in my discussion that we're expecting about 25% growth from our combined onshore programs, DJ and Marcellus, second half versus first half of the year, though it's going to be bringing on these additional pads in these new wells as we ramp up through the second half of the year here.

Brian Singer - Goldman Sachs Group Inc., Research Division

I guess, are there a specific couple of dates that we should look for specific pads that are major contributors within the onshore piece, particularly as we look at the DJ? And you had talked to a number of wells that, I think, seem to be drilled or behind pipe.

David L. Stover

No, I mean, if you go back to -- and I think we've shown it on some of our indications of some of the downspacing, that's spread out through these probably mainly the initial 5 IDP areas. I mean, that's where the majority of the drilling is. I think Wells Ranch and East Pony still have a large percentage. But you're breaking out more wells in the Mustang, the Core, the Greeley Crescent IDPs. So it's going to be across all of them.

Charles D. Davidson

Yes. So just a lot of consistent execution on this, Brian. There's no real -- not one particular pad, per se, or anything, which makes it actually good, which also gives us a lot of confidence because it's got a lot of pieces that are contributing and a lot of diversification to it. So we're not at risk by one unique project.

Operator

Our next question comes from Irene Haas of Wunderlich Securities.

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

Two questions. DJ Basin, we have a lot of great news about the Niobrara in terms of the extended lateral, downspacing and such. How should we think about Codell? Is this a sort of more porous formation? The second question has to do with Marcellus. Are you transporting your extended lateral completion techniques over to Marcellus and getting even better results?

David L. Stover

Okay. Starting with the Codell, Irene, I think we've drilled approximately 14 Codell lateral wells prior to this year. We have probably 10 planned for this year. I think when you look at it, probably 2/3 of them are in kind of a downspacing pattern test and probably another 3 to 4 are extended-reach laterals. So we'll start to get another mix of Codell like we've done Niobrara on kind of each element of this program. So more to come on that. I think when you look at the discussion on moving extended-reach laterals to the Marcellus, we're doing that. We've been doing that now for the last year. I think our average Marcellus lateral length is now up to 7,000 feet or so. And if you go back to the origin of this play, they probably started at 3,000. We've moved to 5,000. And now we're probably up over 7,000. I think we've actually drilled one pad out there that averaged around 10,000, if I remember. So yes, we're seeing great results out there, and we're moving more of the program to that extended reach. It's a little more complicated there from land issues. But that's where these contiguous acreage positions really pay off, acreage positions with scale.

Operator

Our next question comes from Charles Meade of Johnson Rice.

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

Well, I apologize if this is a little bit kind of down in the weeds on the left of the pad. But it's really a remarkable result, even compared to -- especially for standard-length laterals versus the type curves you guys put out. And I'm curious, were those all in the same bench of the Niobrara? And is it a useful distinction to make, which bench you're in, in the Niobrara?

David L. Stover

Yes. My impression -- and I'll double check it, Charles. But my impression, it is all in the same bench. And the thing that you have to remember, even in the Niobrara, and you see more consistency in the B but especially in the A and C and so forth, the thickness does change somewhat in different parts of these IDP areas. And down here in the Core, it's probably, I think, on these wells, they're probably 50% liquid content, but they're also -- what was interesting, I think there was some vertical wells around this area, too. So it's very encouraging. But again, it's still early and it's a couple of wells right now. We're anxious to get a number more of additional of these downspacing tests in place and see some results second half of the year on a number of other patterns here.

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

Got it. And then shifting over to your Eastern Med stuff, I recognize that it's difficult to speak about someone else's negotiation going on. But could you maybe offer what your characterization would be of this kind of protracted negotiation? Is this more along the lines of the final haggling at the stall in a Middle Eastern bazaar? Or is this the sort of thing that Woodside might really just might decide they don't get the tax treatment they'd like and walk?

Charles D. Davidson

I think right now, what held up our final signing late last month was primarily an unresolved tax issue that Woodside had with the state of Israel, and they've continued with those discussions. And I'm very encouraged by what I hear. But again, as I noted earlier, I'll leave that to Woodside to discuss what final treatment they are looking for there. But this is complicated. We had a number of things that we had to resolve as well in terms of how this transaction would be taxed for us, and we did get those resolved. There have also been, as I point out, a huge number of accomplishments that were achieved. The resolution of the antitrust issue, which is now out for public comment, was a big hurdle that we needed to make sure that we had taken care of that because it paves the way for us to develop Leviathan and to market Leviathan gas in Israel. We've now got a final lease. And you say, "What's important about that?" That gives us the development plan. That basically gives us the roadmap of what is going to be approved by the petroleum ministry in terms of the development of Leviathan, so it allows us to move forward on that. So there have been a number of things as well as moving forward on the marketing side. So I'm really encouraged. And as far as the transaction with Woodside, this is -- it's down to the fine details. And hopefully, again, it will get resolved. We would like to have them as a partner as a part of this project. But right now, with all of the other things that have been cleared out, we and our existing partners are moving forward, and we're starting to take steps to make sure that we can deliver this project.

Operator

Our next question comes from Gail Nicholson of KLR Group.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Just a real quick question. When we look at the downspacing tests, are any of the downspacing tests in the Niobrara utilizing extended-reach laterals? Or are they all standard lengths at this point?

David L. Stover

Yes. There are a few that are -- will use some extended-reach laterals. So you'll have a test of both concepts, I guess, if you will, on some equivalent patterns.

Operator

Doug Leggate of Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of quick ones, if I may. First of all, Dave, it's only 4 months since you did your Analyst Day, and you've already more than doubled the plan on long laterals. I'm just wondering what -- how is the thought process changing in terms of how much further and how much more running room you've got to really pick up the pace of long laterals as opposed to the standards? And I've got a follow-up, please.

David L. Stover

Yes, I mean, to that point, Doug, we actually started last year, even as we were reporting the budget, to put plans in place to look at how could we increase the number of long laterals if it made sense and we continued to see the continued performance that we've been seeing. So on that regard, as we got into the year and started to look at the year and we got into the first quarter, we started to ask the question of how could we continue to expand that, not only in Wells Ranch and East Pony but into some of these other IDP areas, and building on some of these things, like some of those good results we saw out at Mustang and so forth. So we started to push the folks a little more to see if we couldn't shift the programs some to mix in a larger number of extended-reach laterals because the opportunity and the economic value is just so great, that potential there. So we wanted to get a more extensive test around the field on some of these areas. And so the team did a great job at shifting the program and building a lot more of that into there because we kept pushing how many could we accelerate into this year.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

So we obviously -- we're all trying to figure out what the value of this asset is. And obviously, it's a huge difference between the long and the under the standard, I guess. So what I'm really trying to understand is, how should we think about how you develop the asset going forward? I mean, is this going to be -- is it kind of difficult to plan it and predict it? Or is it something that's just going to evolve, you know what I mean? Or should we think of more ratable kind of balance between activity between the 2 types of wells?

David L. Stover

Well, I think we'll start to get an even better idea as we go through this year, when you look at all the different things we're developing and testing this year. And we'll update that at the end of the year as based on the results we're seeing. But we're testing a number of different intervals. We're testing a number of different spacing. And you look at the long lateral, I think when we talked about what we sanctioned for our East Pony development, for example, we talked about the fact that we were going to continue to gravitate to more longer laterals. In fact, I think on the East Pony sanction, we discussed the fact that we could see that potentially being about 50% of those lateral wells being extended-reach laterals, whether it's at 7,000 to 9,000. So that's going to continue to evolve. I think also digging through my notes here, I'm looking at the potential. And just some of these different horizons, as we continue to focus on vertical recovery here, will be interesting to develop. For example, looking back through here, the Loeffler pad was actually the Niobrara C interval. All 5 of those wells were actually in the C. Those weren't even in the B interval. So I mean, it's just another data point. And we'll continue to get many data points through the year that will continue to build this plan.

Charles D. Davidson

Yes. Doug, I think I'd just also kind of just add one more thing. And that is, as we've kind of noted in the past, when we lay out a plan, like in last December, it's based on what we know at that time. We try to be very careful about not speculating where it might go and trying to roll some of that in. So generally, we are laying out a plan that we think is very deliverable that's got, certainly, upside to it. And these long laterals, and as you're starting to now and we're starting to see the increased density, are providing some really good hints that we need to keep pushing the program in that way. And that's going to mean that there will be an evolving growth. And as we say, this should certainly lead to some great improvement in value and, certainly, resources and opportunities going forward.

David L. Stover

But again, all of that overlaying with this thought process of treating these like major projects, laying them out in integrated development plans with large central facilities, minimizing the surface footprint and tying in the whole pipeline network to all these pads and wells. So it needs to be a well-thought-out plan, and this is all contributing to how we're going to lay it out.

Operator

And next, we'll hear from David Heikkinen of Heikkinen Energy Advisors.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Just a question. As you think about accessing the Egyptian market, both the local markets and ability to access BG's underutilized LNG export facility, do you have any thoughts or comments you can provide around that as an option for East Med gas?

Charles D. Davidson

Well, it's certainly a very real option. We're at the early stages. But clearly -- and you really highlighted what the big opportunity is, and that is the underutilized existing LNG plants that are in Egypt. And you've got 2 major opportunities there with the BG facilities as well as Unión Fenosa. And so those discussions are underway. I mean, the Tamar partners are actually pursuing one of the options and the Leviathan partners are pursuing the other. The huge value here is that these are LNG plants that need natural gas. They're built. They're operational. So really it's your critical path. In the case of Leviathan, the critical path is developing Leviathan and the connection, which would probably be a new pipeline offshore to deliver the gas over there. But you don't have to wait for a market development or you don't have to wait for an LNG plant to be built. So it's one of the things that we see as the emerging regional markets that have really created some uplift in value.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

And how -- as I think about the diversity of kind of security of pipeline, 2 offshore pipelines, 1 that goes onshore to Israel and 1 that goes to Egypt, how do you think about security for basically offtake as well and the value of that? And then how would the Israeli kind of overall market and export think about it as well?

Charles D. Davidson

Well, I think certainly, our view is that as you look at -- for instance, Egypt having offshore pipelines provides a lot of security from the standpoint of its -- we just -- for obvious reasons. Physically, you're in deepwater, and it's a better asset. I think in the case of, for instance, the Jordan market, we'll be utilizing the existing Israel pipeline infrastructure. They've got a small segment that they need to connect over to Jordan, but it's using the Israel onshore system. So I think the key in this whole market is diversification, looking at multiple outlets, looking at multiple delivery points to both the onshore Israel as well as you look at these outside regional markets as well. I think also is just going beyond Phase 1 of Leviathan, we have to keep in mind also there's an LNG phase of the project, a potentially floating LNG, which then gives you access to global markets. That's in a second phase, but it's certainly very real because we've got the resources to support all of this.

Operator

Next, we'll hear from Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

And I have just one. Turning to the Appalachian basin, you state that firm transportation is expected to increase, what is it, by 500 million a day in 2017? Can you review how much of that takes gas out of the basin, whether to the Gulf Coast or elsewhere?

David L. Stover

Yes, Dan. I think I mentioned around 200 million a day for our share that would actually move gas out of the basin, most likely to the Gulf Coast.

David R. Larson

April, this is David. We're a little past our stop deadline, so that will be the last question that we have today. So let me just say that I'd like to thank everybody for participating in the call today, and appreciate your interest in Noble Energy. Have a good day.

Operator

And that does conclude today's conference. Thank you all for your participation.

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Source: Noble Energy Management Discusses Q1 2014 Results - Earnings Call Transcript
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