Noble Energy's (NBL) CEO Charles Davidson on Q2 2014 Results - Earnings Call Transcript

Jul.24.14 | About: Noble Energy, (NBL)

Noble Energy, Inc. (NYSE:NBL)

Q2 2014 Earnings Conference Call

July 24, 2014 10:00 AM ET

Executives

David R. Larson – Vice President of Investor Relations

Charles D. Davidson – Chairman, Chief Executive Officer

David L. Stover – President, Chief Operating Officer and Director

Kenneth M. Fisher – Executive Vice President and Chief Financial Officer

Analysts

David M. Heikkinen – Heikkinen Energy Advisors, LLC

David W. Kistler – Simmons & Co.

Arun Jayaram - Credit Suisse Securities LLC

Leo P. Mariani – RBC Capital Markets, LLC

Irene O. Haas – Wunderlich Securities, Inc.

Charles A. Meade – Johnson Rice & Company LLC

Michael Rowe – Tudor, Pickering & Holt

David R. Tameron – Wells Fargo Securities, LLC

Brian Singer - Goldman Sachs & Co.

Gail A. Nicholson – KLR Group, LLC

Charles A. Meade – Johnson Rice & Company LLC

Rehan A. Rashid – FBR Capital Markets & Co.

Operator

Good morning and welcome to the Noble Energy's Second Quarter 2014 Earnings Call. I would now like to turn the call over to David Larson. Please go ahead, sir.

David R. Larson

Thanks, Cameron. Good morning, everyone. Welcome to Noble Energy’s second 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 quarterly earnings release, which hopefully you have had a chance to review. A few supplemental slides for this call we’re also posted to the website and they will be good reference material for the discussion today. The agenda 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 five core operational programs.

We’ll 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 to 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. Well time passes quickly another earnings call and more than halfway through the year already. In a very busy quarter for us and so we’ve got a lot to cover today. Hopefully, you’ve seen our recent highlights in the earnings release that we issued this morning. I thought I would discuss a few of these before running through the financials.

First off, our onshore programs continue to perform very well setting a new combined quarterly production record from the Marcellus and the DJ Basin in the second quarter. Total volumes were up 35% from the second quarter of last year after adjusting for the impact of the DJ Basin asset swap that was completed late in 2013.

The horizontal component of our production in these core areas was up even more dramatically 56% year-over-year. Well performance in the DJ Basin remains consistent with our type curve assumptions across the number of the integrated development plan areas including both standard length and extended reach lateral wells.

Over in the Marcellus strong legacy production combined with new well out performance in our operated areas as driving an increase in our type curves for wells with standard completion designs.

Highlighting our continued performance improvement is the West Finley 6 pad in Majorsville which began production during the second quarter results there are outstanding performing more than 50% of our type curves for the area. We’re also extremely encouraged by results from new completion designs in both core areas that look very positive for both resource and production upside.

In the DJ, we have performed plug-n-pref design in a couple of areas and have installed our second underground laboratory which includes testing of various additional completion ideas. And in the Marcellus results from 2 pads then included reduced stage and cluster spacing wells are very strong. Dave will provide more details on the vast amount of technical work going on in these onshore plays, but we are pleased with the results today and are expanding our usage of new completion techniques to the reminder of the year.

During the second quarter, we also announced plans to form an MLP for our midstream assets in the Marcellus. In this mornings release, we announced the new oil discovery in the deepwater Gulf of Mexico at Katmai prospect in Green Canyon. Drilling operation so far a resulted in over 115 feet of oil pay encountered in secondary targets that are above the primary pay zone.

Reservoir quality in these Middle Miocene sands is excellent. Although, we have further drilling and evaluation ahead of us, we’ve already got a commercial discovery in another project to work on. The question now is how ultimately – how is – the question now is of course ultimately how big will this discovery become.

After logging and running a line we anticipate reaching the primary lower Miocene target over the next few weeks, following total debt which is planned at 28,000 feet plus we'll commence an extensive logging program. So we expect to have final well results by the end of August.

Katmai represents the latest of a significant string of new field discoveries in the deepwater Gulf for Nobel Energy. It certainly appears headed to move into the development queue along with Gunflint and Big Bend and Dantzler and will further solidify our plans for a deepwater Gulf of Mexico production to more than double over the course of the next several years.

We also substantially expanded our Gulf of Mexico lease position during the second quarter, acquiring a number of new exploration opportunities on 17 Atwater Valley exploration licenses. The first of these prospects is called Bright. Bright is currently drilling targeting upper Miocene reservoirs with a large resource potential range of 90 million-barrels to 350 million-barrels equivalent. Results are expected in the third quarter.

In the Eastern Mediterranean before discussing recent performance, I just wanted to take a moment to discuss the ongoing conflict there. Clearly the humanitarian impacts of this conflict have been tragic. A number of our employees and contractors have been affected including several that have been called into service. We have experienced this before in our long tenure in the region and as in the past.

Our team has continued to perform superbly under adversity providing an uninterrupted supply of natural gas to Israel. I'm extremely proud of them and we all hope for a rapid resolution. Our facilities are well protected and they remain unaffected. However, we do feel it is appropriate to slightly reduce our estimates for near-term sales volumes there due to the situation.

Moving into the regional update last week an updated resource estimate for the Leviathan field was provided by Netherland Sewell on behalf of all partners and no surprise the resources have gone up. Leviathan is now estimated with gross mean 2C resources of 21.9 trillion cubic feet of natural gas, an increase of more than 15% from our earlier estimates. 3C resources are now estimated by Netherland Sewell to be 26.5 trillion cubic feet.

Our teams have made tremendous progress capturing the expanding regional demand for natural gas. We’ve recently executed two very substantial letters of intent to sell gas to existing LNG facilities nearby, one which supports the first phase of our Leviathan project and one which aggressively moves forward in an expansion of the Tamar project. Combined, these LOIs represent over 1 billion cubic feet of natural gas to be sold per day to regional customers. In addition, we are closing in on securing additional customers that will further support the first phase of development at Leviathan.

And In West Africa, we've had production milestones reached for both Aseng and Alen, so we have a lot of forward progress across all areas of the business during the first half of the year and I believe we're positioned very well for the remainder of the year and into 2015. Quickly second quarter financials, sales volumes were 290,000-barrels of oil equivalent per day, a 14% increase over the second quarter of last year after removing non-core asset divestitures. Our volume growth versus second quarter last year was driven by four of our five core businesses with increases in the DJ and Marcellus onshore as well as the Gulf of Mexico and West Africa offshore.

In Israel, volumes were essentially flat. As Dave will discuss, volumes would have been even better, particularly in the DJ, had we not run into midstream capacity and timing issues. As painful as it is, we decided it was prudent to provide a more conservative outlook until we are comfortable that all of this is sorted out.

Revenues for the quarter were 1.1 billion supported by strong liquids pricing both crude oil and natural gas liquids and natural gas prices as well. The majority of our cost items were relatively inline with our expectations, although our adjusted effective tax rate of 22% was a bit lighter than expectations primarily as a result of our outlook for foreign tax credit usage due to the remainder of 2014. Exploration expense was also lower than our guidance with the impact of the successful Katmai well in the deepwater Gulf.

Adjusted earnings per diluted share was $0.87 for the second quarter, after removing the impact of certain adjustment items. These items included a gain on sale, which for the second quarter was primarily China, a couple of impairments on the retirement obligation for non-producing assets and then the impact of our non-cash commodity hedges. As a reminder, regarding the China asset sale, these assets produced approximately 4000-barrels of oil per day and had total reserves of around 6 million-barrels of oil equivalent at the end of 2013. Proceeds from the sale were $186 million with final cash payment received in early July.

Capital Expenditures for the quarter were approximately $1.3 billion and discretionary cash flow for the period with nearly $900 million and we ended the second quarter with total cash of $960 million and $3.4 billion of available credit capacity. So total liquidity remains well over $4 billion.

Before handing over to Dave, I wanted to spend a couple of minutes discussing the regulatory environment for oil and gas development in Colorado, which certainly gathering a lot of attention right now. As many of you are aware certain initiatives had been proposed for inclusion on the November general election ballot, which, if adopted by voters, would become amendments to the State of Colorado constitution.

Over the past several months, we along with the number of other companies have work with the Governor's Office on a sensible legislative solution that would provide local communities a stronger regulatory voice and support responsible oil and natural gas development. Unfortunately, time for the legislative solution has passed. So while there is no still assurance on what will or will not make its way to the November ballot, we remain focused on our original plan, which we have been implementing for well over a year, this includes working with others in the industry, Coloradans for Responsible Energy Development and many non-industry stakeholders to ensure that voters understand the importance of defeating these ballot measures.

We are wholly committed to ensuring that Colorado voters are fully informed. The potential amendments include a proposal for greater local regulation and oversight of oil and gas development as well as a measure for increase setbacks. We support the input of local communities in the development of oil and gas, but that must be balanced with an overall regulatory framework that supports responsible recovery of hydrocarbons. Partnering with local communities, including surface and mineral owners, city and county authorities, and other governmental body has been and will always be critical to our success in all of our locations worldwide.

We believe the ballot measure proposing a 2000-foot set back is a step in the wrong direction for Colorado. Existing setback rules which require 500 to a 1000 foot distances from occupied strictures were just put into effect last year and they are some of the most aggressive regulations in the country. The 2000-foot setback, while a four-fold increase in direct distance is a 16-fold increase in terms of total surface area affected. This would have a significant impact on development of oil and gas in certain areas of the state, perhaps not a substantial and near term, as companies could shift their focus to areas not as affected. I know you like for us to provide a specific number of potential locations at risk; however without clarity on how the ballot measure would be implemented including the potential for obtaining wavers, quantifying the impact would be pure speculation at this point.

This type of constitutional amendment could ultimately result in a loss of many jobs throughout the state, reduce revenues to surface and mineral odors and obviously reduced tax revenue to many local and State jurisdictions as well. This ballot initiative is not just about the oil industry. As Governor Hickenlooper pointed out recently, this initiative could harm all businesses due to its broad prohibitions.

For that reason there are many other business organization that have joined us to defeat this proposal. So we will do everything we can in our power to provide the necessary information of voters, to fully assess the impacts of these ballot measures with the ultimate intention of having them defeated November and I certainly believe will be successful.

So let me ramp up with a few comments on number of exciting things for the reminder of 2014. The exploration program has a number of meaningful catalysts near term, with final results due in at Katmai and Bright, perhaps in the next month or so. In addition, we will have new drilling results in our Wilson Play in northeast Nevada later this year, along with longer term production history from our first well, which is now just coming online.

I’m also particularly excited about the 2015 exploration program that should include multiple game-changer wells, with our first operated Falklands well, the deep Mesozoic oil test in the eastern Med, and several Gulf of Mexico wells.

I'm also very excited about the Gulf of Mexico major project line up with the first of a number of fields being ready for new production next year. As well as the continued opportunities for our natural gas at are emerging in the Eastern Mediterranean.

And then of course the second half of 2014 is all about delivering growth in the upside from our onshore programs. So when you put it all together I believe we're on the cusp of delivering the next major step up for Nobel Energy. As I look at the picture as a whole we're delivering substantial long-term value for our stakeholders, including record production volumes and double-digit growth for the foreseeable future.

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

David L. Stover

Thanks, Chuck. I'll just mention I've been fighting a head cold so I'll try to speak up and make sure everybody can hear me well. We’ve a lot to cover this morning so I'll jump right into it. With our core U.S. onshore areas, total sales volumes in the second quarter were approximately 140,000 barrels of oil equivalent per day.

You can see on Slide 5, we have attached the comparison of just the horizontal volumes from the DJ Basin and Marcellus over the last couple of years and the substantial growth delivered in both core areas. Total horizontal volumes from these plays were a record 112,000 barrels of oil equivalent per day in the second quarter, up 56% and more than 200% respectively versus the same quarter in 2013 and 2012.

In the DJ Basin, we average 98,000 barrels of oil equivalent per day in the second quarter. The overall liquids component as a percent of total DJ volumes as really ramped up over the past two years, as we have concentrated our production in the more liquid rich portions of the basin. The 68% liquid contribution this quarter is a record, an increase from 62% one-year ago and 57% two-years ago.

On oil infrastructure, the doubling of the white cliffs oil pipeline 250,000 barrels per day is in the commissioning phase and should be fully operational in August. On the gas side, at times during the second quarter, we saw record throughput on the DCP System following facility expansions earlier this year. Throughput is further benefited by the start-up of additional compression this month. The addition of another field booster station in Lucerne 2 plant in the first half of next year will add an additional 270 million cubic feet per day of process and capacity to the system.

While the capacity additions have been helpful, we also experienced during the second quarter higher than expected third-party processing down time at multiple facilities, which result in reduced throughput and higher line pressures in certain areas of the basin. This impacted primarily our legacy vertical well production. We continue to be affected by third-party plant and pipeline down time with two incidents just this week impacting current volumes and as a result, our guidance for the second half of the year includes more conservative assumptions for midstream capacity.

Also during the second quarter, we delayed or shut in production from 12 pads totaling over 65 wells as we altered our Econode production facility design. This was done to allow greater capture of flash gas volumes and further reduction of error emissions in areas that are not yet tied into a central processing facility. We do not expect these design changes to have a significant impact on our cost or schedule going forward.

So while we've had temporary impacts to our second quarter volumes and ultimately our full-year contribution from the DJ Basin, well performance across our integrated development plans remains very strong. And I believe we are on an exciting path of growth through the reminder of the 2014 and beyond. I'll discuss more of the outlook in a few minutes.

We're continuing to operate 10 rigs in the DJ Basin. Late in the third quarter, one of our DJ rigs will move over to Northeast Nevada to resume our exploration drilling on the Wilson prospect. Speaking of Wilson play, our first vertical well has now been producing for about a week. While it's very early, I've been pleased with the 300 barrels of fluidity is producing per day with a roughly 45% oil cut while it's still cleaning up.

Back in the DJ Basin, our teams are working extensively on increasing the long-term value of this premier Basin. We continue to drill multiple down spacing tests, including 24 and 32 equivalent wells per section in a number of our IDP areas. The first of these tests the Loeffler pad in the core IDP continues to perform exceptionally well.

While we have drilled and completed a number of additional down space tests we don't yet have much production history so that is something to look forward to in the second half of year. In area where we do have some new results is in our ongoing completion design program where our teams are continually looking to maximize ultimate recoveries and economic return.

The most recent example is a three well pad in the core IDP where two wells utilized a plug-n-perf design in place of the traditional sliding sleeve technology. Initial results are shown on Slide 6 with production on the two plug-n-perf wells outperforming the standard design well by more than 50%. These were standard length laterals with 20 stages each and three clusters per stage. We also have initial results on a 12 well econode in Wells Ranch which is substantially outperforming our type curve for the area.

With these wells we're testing various completion ideas including different fluid and proppant designs and wells in multiple zones. In addition we have down hole fiber optic cables in a couple of the wells and are measuring recovery down to the individual stage level to evaluate the effectiveness of our completion designs. Still a lot to learn here but some strong early encouragement.

Our other core area onshore in the U.S., the Marcellus, continues to perform extremely well with production averaging nearly 250 million cubic feet per day net for the Second Quarter. This week, the joint venture production ramped in North of 700 million cubic feet equivalent per day gross which is an increase of 40% in just the last couple of months and more than 100% since this time last year. We've been able to accomplish this dramatic growth through a continued development of our assets, the application of enhanced completion designs and strong underlying well performance.

During the Second Quarter, we brought on production from WFN6 pad in Majorsville and you can see its performance Slide 8. This eight well pad averaged 6100 feet in lateral length and had an initial 30-day production average of over 65 million cubic equivalent per day, it is our strongest operated pad to-date. Included in the pad were six wells with a standard completion design and two wells testing enhanced completion techniques. One of the two enhanced completion designs utilized on this pad was our second test of the Reduced Stage and Cluster Spacing technique or RSCS as I'll refer to it.

Utilizing 150-foot stage spacing and five clusters per stage results are very strong. Not only on WFN6 but also on WFN3 where we now have more than three months of production data. Initial rates look to be 15% to 30% better for these wells utilizing RSCS, so we remain very encouraged about the application of this technique in our program going forward. We've also tested an additional completion design on WFN6 that on this initial test is performing as strongly as the RSCS technique at a lower comparative cost. While encouraged on this single well test, we want to see results in a few more tests of this completion design before talking too much about what we're doing here.

Between the RSCS and this new completion design we're now transitioning our remaining 2014 program to utilize these enhanced completion techniques on over 50% of our remaining wells. We continue to be encouraged by the production performance of our operated assets in Majorsville. This has driven an increase in our type curve for standard completion design wells in the Majorsville IDP by approximately 10%. Our standard 7,000 foot lateral length well is now estimated to recover approximately 10 billion cubic feet equivalent. You can see all of our Majorsville wells on production to-date compared to our historical and updated standard completion design type curves on Slide 9.

Our team continues to deliver improved drilling efficiency, and during the second quarter we drilled a 170-foot lateral section in just 24-hours which I believe is an industry record, not only we are continuing to achieve higher rate and ultimate recovery wells, but we are also driving down relative cost which is all moving in the right direction. In our other operated areas outside of Majorsville, we're in the early stages of bringing on production from our first pad in the Oxford, Pennsboro, Shirley area. This pad includes our first lateral of down spacing test to 550-feet as well as additional testing of enhanced completion designs.

In the dry gas area, our partner CONSOL continues to deliver a number of strong pads as well, including additional RSCS wells that are delivering a substantial production upside. We've also been encouraged by recompletion operations in the Greenhill area in Southwestern Pennsylvania. The six wells that we’re recompleted too and turned on to production with initial rates in excess of 4 million cubic feet per day each, and average 15-fold production enhancement for these wells which were originally brought online more than five years ago.

On the marketing side, we’re continuing to pursue a number of options to further diversify our markets from Marcellus gas. And we're close to adding some near and long-term firm transport that will expand both our in basin and out of basin capacity. So I couldn’t be more pleased with how the Marcellus team is delivering value. Our activity is providing dramatic growth in this area.

Moving offshore, the second quarter was very active for our deepwater Gulf of Mexico business, on both exploration as well as the development of multiple major projects. Production was 19,000 barrels of oil equivalent per day, with a majority of our volumes coming from our Galapagos, Swordfish, and Ticonderoga fields. We’re making good progress advancing our next round of major projects, where we expect to ramp up of our production to commence in just over a year from now.

The first to come online will be the Big Bend project in our Rio Grande discovery area, which remains on schedule for first production in the late 2015. You see on Slide 10, the graphic of the Rio Grande development plans, including not only Big Bend, but also our Dantzler discovery as well. The proximity of these discoveries will allow for Dantzler benefit from the production infrastructure being installed at Big Bend. We've now ordered all of the necessary long lead items for both fields and are finalizing the subsea installation contracts.

During the second quarter, we continue to progress the development of Dantzler and are now accelerating first production into the first quarter of 2016. A rig is currently on location during the extension well with the results expected in the third quarter of this year.

Following the Rio Grande development, we anticipate having our Gunflint field on production as planned in the middle part of 2016. So, the project teams are quite busy with three new fields to commence production all within a year of each other. Adding an incremental 20,000 to 25,000 barrels of oil per day to our production volumes by mid 2016. With an initial success at Katmai and the Bright well scheduled to reach total debt this quarter. Exploration program is positioning us with good opportunity for new resource discovery and continued long-term growth.

Internationally, our assets in West Africa continue to strong performance, as we sold 82,000 barrels of oil equivalent per day net in the second quarter. At our operated Aseng oil field total cumulative production is now on excess of 50 million barrels gross in start up just 2.5 years ago. We’ve highlighted on Slide 12, the fields production profile and you see our cumulative actual volumes above original expectation by more than 3 billion barrel gross through June this year.

We’ve been able to accomplish this accelerated value through active field and well management and facility uptime. I’m particularly pleased with our stable recent production, flat at slightly more than 40,000 barrels per day gross over the second quarter. We’ve recently celebrated the one-year production anniversary at Alen, where condensate production reached record highs of approximately 30,000 barrels per day gross following facility turnaround and modification procedures.

Additional work over activities at Alen are ongoing including a sidetrack of one of the production oils, which will enhance our productive capability even further by the end of the year. In the Eastern Mediterranean, production was 220 million cubic feet equivalent per day during the second quarter.

Tamar continues its strong performance with essentially no downtime during the quarter. Power generation demand for natural gas in Israel is highly depended on weather and as we move into summer period, we anticipate increased sales volumes for the third quarter. Although, we have slightly tempered our prior estimates due to the current situation in the region.

We’re in the midst of a multi-year increase in our deliver ability based on continued growth in demand in Israel and in various regional markets nearby. Our expansion plans between now and 2018 are shown on Slide 13, which highlight a more than tripling of today’s capacity.

Our initial increase comes next year with the addition of compression at the Ashdod onshore receiving terminal, which currently handles natural gas produced from Tamar. Construction remains on schedule to provide an incremental 200 million cubic feet per day of capacity by summer next year.

Additional expansion at Tamar is planned for late 2017 tied to our recent letter of intent with union Fenosa gas for gas sales to their LNG facility on Egypt. The LOI is for 440 million cubic feet per day over 15-year period and represents a significant acceleration of value for the Tamar asset. We are currently working on the gas purchase and sale agreement with the UFG targeting to finalize by the end of this year.

Also included in the chart of the expanded plans for the first phase of development at Leviathan, which is being progressed as a 1.6 billion cubic feet per day FPSO. This is up significantly versus our thoughts as of the end of last year, when we were planning on an initial project half that size. The Leviathan FPSO project is being designed with two outlets, one through Israel domestic grid providing an important second entry point for natural gas into Israel and regional markets beyond. We also anticipate direct connection of the Leviathan FPSO via subsea pipeline to the BG LNG facility in Egypt.

During the second quarter, we announced LOI with BG to provide at least 700 million cubic feet per day to their facilities for 15-years. We are also close to securing additional customers for Leviathan. From a technical perspective the Leviathan project is very well advanced including subsurface in facility design readiness. First production at Leviathan is likely at the end of 2017 or early 2018 as we balance the technical and Marketing pieces with necessary regulatory approvals.

As part of the earnings release this morning, we provided an outlook for our sales volume through the remainder of the year. Slide 14, shows the primary components to our second half growth outlook, where we estimate our core U.S. onshore plays will deliver more than 10% growth from the second quarter to the third Quarter and then again from the third quarter to the fourth quarter. You can see that we have already delivered a portion of that growth from volumes so far in July averaging over 150,000 barrels equivalent per day.

This slide also shows the transition in our timing of wells coming online impacted by facility enhancements that I mentioned earlier and the change in our programs through the course of the year to a large percentage of long laterals in both plays. A very strong fourth quarter in terms of new wells on line will ensure we deliver a larger exit rate for 2014 than we had previously planned.

Slide 15, shows the total company’s key quarterly sales component. Overall, our volumes in the second half of the year are lower than earlier expectations primarily as a result of three items impacting the DJ Basin. A more conservative assumption on third-party midstream processing and line pressures, the carryover impact from facility enhancements and the timing of wells coming online versus the second quarter or third quarter will be impacted by a significant under lifting in EG, Equatorial Guinea as well as the China asset sale, which combined account for a 12,000 barrel of oil per day difference, we've also temporarily reduced to our natural gas sales assumptions in Israel due to the current conflict there.

As mentioned earlier, the fourth quarter is still anticipate to be very strong, with the ramp in activity levels and the onshore assets delivering a higher year-end exit rate than our prior projections. Executing on this plan puts us in great shape when we think about 2015 growth.

On Slide 16, we’ve provided detail detailed third quarter and fourth quarter guidance for those that model our business. As Chuck mentioned earlier, we are excited about the future for Noble Energy. The U.S. onshore program is delivering substantial growth, while the offshore programs are aggressively advancing multiple major projects for development and at the same time, we have an impact of exploration program which is positioned to test large resource potential over the next two years.

With that Cameron, we would like to go ahead and open the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) And we will take our first question from David Heikkinen from Heikkinen Energy Advisors. Please go ahead.

David M. Heikkinen – Heikkinen Energy Advisors, LLC

Good morning, guys. Dave, I think you hit some of it on the Slide 14, but the change from the plan in December to now of just shifting so many wells towards fourth quarter. How much of that is just what percentage is extended reach laterals, and then what percentage of that is the downtime or shut-ins of as you upgrade facilities?

David L. Stover

It’s actually a combination of all of that, Dave and it's hard to put a percentage on any one piece that's all somewhat connected. You've got the movement as you referenced on more longer laterals you actually have with the down spacing more wells prepared now and so forth too so if you look at back to where we were late last year versus how we continued to adjust the program with more down space and more longer laterals, as you've got larger pads and all of that contributes to kind of the shift in when wells are coming online.

David M. Heikkinen – Heikkinen Energy Advisors, LLC

Maybe are better well results leading to out pacing some of the surface capacity and that's why you're seeing some of the problems that were expected to be really solved around third-party processing and pipeline pressures last year, is it well results that are leading to more problems or constraints?

Charles D. Davidson

I think obviously you're getting very good well results. I think the other piece there too when you look at the overall processing capacity, there may be enough processing capacity, but it may not be in the places we need it, based on the activity and how the activities ramped up in different parts of the field by all of the industry and some of that. So a lot of the effort right now is going to line looping, inner connecting and so forth and getting this gas moved and bringing high pressure areas down.

David M. Heikkinen – Heikkinen Energy Advisors, LLC

Okay. And then can you just specifically hit what do you expect to produce in third quarter in Israel what volume versus the 220 in second quarter.

Charles D. Davidson

Well I would have to look here a minute. I think, let me just look here a minute, Dave for you. I think you're probably up to probably in that 250 range or so.

David M. Heikkinen – Heikkinen Energy Advisors, LLC

Okay. Thanks.

Operator

And we’ll take our next question from Dave Kistler with Simons & Company.

David W. Kistler – Simmons & Co.

Good morning, guys.

Charles D. Davidson

Good morning.

David W. Kistler – Simmons & Co.

Real quickly with the Katmai discovery, can you talk a little about ultimate size of the prize and just what actual resource level would support your comment that as it currently stands it’s a commercial development.

David L. Stover

Well, as we identify when we first set up the Katmai prospect, there is really two prospects there and that what we're testing right now is the original four-way and then there's also another three-way that's a follow-up to that. Our comment on commercial is, our comment on commercial is the fact that we've already, it's with the infrastructure we have in the area and with the 150 net oil pay we’ve already got a commercial well. We've run through the analysis of what if we found nothing else we just carried this through, it would be fine.

So on our original, if on our original outlook for the four-way, we still got a primary target to test, so we’re, but we’re moving or making nice progress against that range of resources that we first identified. So we're going to wait until we finish the well before we put out a full resource estimate for it, but it's significant enough that we want to just highlight that we're already past the commercial threshold by a nice amount.

David W. Kistler – Simmons & Co.

Perfect, I appreciate that color and then maybe switching over to the Eastern Mediterranean. Obviously, significant progress with the LOI that you guys announced over the last bit here. Can you talk about what are the gating mechanisms between converting that from an LOI to a final purchase agreement as well as any other regulatory hurdles required to make that II transition as well.

David L. Stover

Sure, you bet. Really immediately following the execution of the LOIs our team started working together with, the potential purchasers here because it’s really its hammering out all the definitive agreements and that includes as you would expect a lot detail terms that go through, but I mean that’s just part of the process of moving to. The primary structure behind those LOI is known in terms of, how the gas would be moved, who would be paying for what components and some things like that. So in the case of for instance the BG LOI, that also allows them to start doing some detailed engineering work on their side too to really make sure they’ve got the projects scoped out.

So the process of moving from an LOI to a final sales agreement is getting all the details down, and in this case also we’re working towards agreement that will be helpful in ultimate financing of the project for ourselves and the partners, so that’s important as well. Regulatory approvals clearly fall on the category of government approvals. I mean we received the export policy from Israel, but specific exports will have to be approved and while conversations particularly by the purchasers have started on the Egyptian side, we would expect their support and approval to be required as well. So that will be all part of the process of moving these forward.

David W. Kistler – Simmons & Co.

Okay just one more clarification. So pricing as far as on a hydrocarbon basis that's already agreed to and the rest is kind of just details, obviously complicated details but details around the framework of how it’s executed?

Charles D. Davidson

The pricing and it varies by agreements as to how far that is worked through so there will certainly be further details on that because it's all part of when you may have pricing points but at the same time, our desire to participate in upside and downside because in the case the once we have talked about they are oil linked prices. So it's important that you fully define the full breadth of the curve as part of that. Now all will be worked out as well.

David W. Kistler – Simmons & Co.

Perfect, well I appreciate the clarification of guys. Thank you so much.

Charles D. Davidson

Thank you.

Operator

And we’ll take our next question from Arun Jayaram from Credit Suisse. Please go ahead.

Arun Jayaram – Credit Suisse Securities LLC

Good morning gentleman.

Charles D. Davidson

Good morning.

Arun Jayaram – Credit Suisse Securities LLC

Gentlemen, I wanted to first start off with kind of your longer-term thoughts on DJ Basin growth, at your Analyst Day you talked about kind of a 23% CAGR over the next five years including 28% in 2014. Obviously in 2014 you may not get there given the infrastructure issues that you talked about, but I wanted to see if you could maybe comment on perhaps years two and five of the program. Is there anything other than perhaps the starting lower starting part in 2014 when you think well performance or infrastructure or time to drill and complete kind of the extended reach laterals which would cause you to maybe have a different view of long growth from the basin?

David L. Stover

No, I am tell you, Arun, when I look at and I think I briefly mentioned it, I'm confident we're going to end the year even stronger than we thought right now with, some of the things were implemented and what we are doing out there and especially some of the things we're seeing on all this completion work. So when I look over the next five years I’m just as positive and optimistic in 2015 as I’m 2018 from what we have laid out before.

Like you said we've gotten half to a little slower start on some of this, but I think you'll see the pace pick up especially in the fourth quarter on this and we'll end the year in a very good spot. I guess if I look back to me on what’s changed and we are working through the infrastructure pieces we actually have a major projects team now and place to help us work that and we are truly treating this area and now the major project especially when you look at these big infrastructure facilities.

But when I look at it the biggest thing that I'm seeing here is just this potential in completions whether you look at it in the DJ Basin, or in the Marcellus to me there's probably more opportunity here. They continue to fine tune and enhance completion than I would have understood, before and I think especially when you look at it in combination with tieing into the down spacing activity and tailoring your completion specifically to some of that down spacing activity for to get here your biggest near well bore impact and adjusting some of that that's a lot of the work were going on now.

And we are putting a lot of signs into it, we talked about the about the fiber optic cables that give us realtime performance monitoring and some of the wells up and the DJs. We are learning a tremendous amount this year that I think is going to pay huge dividends for the future.

Arun Jayaram – Credit Suisse Securities LLC

Okay just a quick follow-up Dave you talked about two plug-n-perf wells obviously meaningfully out performing what you're doing on a sliding sleeve basis. Are these the first wells that you've drilled on this basis and I wonder if you could talk about how much longer does it take to drill and complete under plug-n-perf design and versus what are the efficiency losses you'll get, obviously it will take a little bit more time I wonder if you could put the 50% into context from cost and timing perspective?

David L. Stover

Yeah, I think the time piece is all on the completion on the fracking and it probably takes about 40% more time plug-n-perf than the sliding sleeve time completion but when you look at it, I think these are the first couple that we've tried up there. I think you're also seeing and hearing from some other places where they're doing some of the same things and seeing some good results in other field., but in our plan would be to do a number of more of these here in the second half of this year and get a bigger database and really start to get some extended production history on some of this. So initially bodes well, but we continuing to test some of this, but it's all part of that same thing that I mentioned before which is getting your frac to be even more effective and getting that near well bore frac treatment and that concentration around the near well bore as great as you can get it.

Charles D. Davidson

I think just to follow-up in looking at it again and just echoing Dave's comment earlier about the excitement of the plan going forward is I just see these enhanced completion techniques really supporting the upside that we’re seeing in reduced spacing because they are really allowing us to get improved results and so that's all those enhancements Dave was talking about that gave us a lot of encouragement on our forward plan that there's a lot of upside in these areas.

David L. Stover

The other thing too that's exciting when you look at it and really dig into it a little bit, we showed you the example of the Wells Ranch 21 Echonode with I think 12 wells. When you look at the mix of different completions within that you've got Codell, you've got B chalks, B Marls, Codell chalks, all of those performing – C chalks all of those performing above the type curve so far. I mean that's extremely encouraging.

Arun Jayaram – Credit Suisse Securities LLC

Thanks both of you, thanks.

Operator

We’ll take our next question from Leo Mariani from RBC Capital Markets.

Leo P. Mariani – RBC Capital Markets, LLC

Hey, guys I hope that you could give us a little bit more color around your statements regarding potential impact from the conflict in Israel. Clearly you guys are adding productive capacity next year, at Tamar, I guess mid-year and then at year-end, and do you have confidence in all that capacity can be absorbed by incremental Israeli demand over the next year or two? Maybe you can just speak to that.

David L. Stover

Yes thanks, and right now we're not really seeing impacts on sales as a result of the conflict, but we did want to be a little bit more conservative at least in the third quarter going forward, but the demand for gas in Israel is very strong, very strong. At this period of time and again as we go into the kind of the peak heating season we max out. Frequently we'll hit our maximum production rate, so there's no question about the increased demand. In fact, we’ve entered into a number of contracts with additional customers that we are not able to supply they are on basically an interruptible basis, we can't supply them today, because we don't have the gas, so we've got great support for the expansion as you point out that we're doing at Tamar and that project, adding compression at Ash Dot is moving along nicely and should start up next year. So it's a real demand and we see there is additional demand even beyond the Tamar expansion that we're doing right now and that will certainly be an element of the support for Leviathan in the future.

Leo P. Mariani – RBC Capital Markets, LLC

Okay and I guess just another unrelated question here. Can you talk a little bit about your plans for the MLP here in terms of what assets are going in there and just any expectations around sort of size of that obviously guys are a pretty big company. It wouldn't seem to be a giant MLP in the short-term, but maybe there's a larger plan to really grow this over a number of years. Could you speak to that in a little more detail?

David L. Stover

Well unfortunately we're in an S1 process that we filed confidentially so the rules pretty much limit us to just stating what we announced on the press release until that all gets worked through.

Leo P. Mariani – RBC Capital Markets, LLC

Okay, thanks guys.

David L. Stover

You bet. Thanks.

Operator

We’ll take our next question from Irene Haas with Wunderlich Securities.

Irene O. Haas – Wunderlich Securities, Inc.

Yes, hi good morning.

David L. Stover

Very good morning Irene.

Irene O. Haas – Wunderlich Securities, Inc.

Congratulations on the success in the deepwater Gulf of Mexico. My question is actually on the Marcellus, I heard you guys are doing some refrac. Is that true and if yes, sort of what are the mechanics involved, can you go in and do your RSCS configuration and then really to think a few steps further if this worked for the Marcellus, horizontal and what would be the inventory impact per refrac in terms of BCF, and then can you kind of replicate the same thing in the water burg some years down the line?

Charles D. Davidson

I mean that it’s a good question, Irene. It’s one of those things is it in another opportunity, I’ll tell you, what’s we’ve done so far, what’s been by the partnership is a few wells as I mentioned that are fairly old wells I think they are almost five year vintage, they were very short laterals, I think they were only less than 2000 foot laterals and what you saw from those, which as I mentioned is a huge increase, I think it was like a 15 fold increase from what they were producing before what they came back on after the refrac.

Now, what was interesting in a number of these wells, when you refrac them or recompleted because we added, I think there was perforations added too that was kind of the recompletion refrac if you well that actually some of these – couple of these wells came back just as strong as they started out originally or better in some of these things so, it’s something that continue to follow how much of an application can you do across the field down the road, I don’t know, I think that’s probably another phase yet to come and it’s something we’ll continue to test on basis, where it seems appropriate and we’ll continue to look at it for a possibility in the DJ down the road.

Irene O. Haas – Wunderlich Securities, Inc.

Hello, Just the configuration, do you have to go back in the borehole, the horizontal part? Do you actually use your original perf interval, or can you change that?

Charles D. Davidson

Well, I think what we did in these or what they did in these they are actually added some perforations to some of this too. So they opened it up a little bit more and then. So you have a combination of what you originally completed a long list some additional exposure here.

Irene O. Haas – Wunderlich Securities, Inc.

Gotcha, thank you.

Charles D. Davidson

Thanks.

Operator

We’ll take our next question from Joseph Allman with JP Morgan. Please go ahead.

Unidentified Analyst

Good morning, hi, this is actually [indiscernible] for Joseph Allman.

Charles D. Davidson

All right.

Unidentified Analyst

I had a brief question on the environmental issues. I know you guys can't quantify anything right now, but is there any other impacts that you guys might be seeing coming from this going forward? How will they impact the IDPs? Are there any other environmental concerns that you guys have?

Charles D. Davidson

Are you just referring to where we were capturing some additional emissions and redesigning some of our facilities.

Unidentified Analyst

Next I was referring to the Colorado ballot initiatives initially?

Charles D. Davidson

Oh, on the ballot initiatives from an environmental standpoint, I think that really the key on that is the setback initiatives and that’s just a matter of reducing the area that would be available for development around some occupied areas. And as I mentioned, we really can speculate this point, because there is a waver process involved in that, but it’s really I don’t think we view that is an environmental issue is just a – it would be a further restriction on places that you could drill.

Unidentified Analyst

Okay. And then other environmental concern? So I’ve read that Nevada is a nesting ground and I know you guys are exploring out there that going to have any impact on that?

Charles D. Davidson

I think it’s safe to say that – in all the areas we work, as part of our plans and schedules we anticipate getting the right permits and requirements. So, I think we’ve already got certainly in Colorado we have a strong regulatory environments so no, I think they are all part of our schedule and plans.

David L. Stover

And then we’re still moving ahead with our plans to drill some additional wells in Nevada later this year so that still moving forward, so no change to that plan.

Unidentified Analyst

Okay, great. And can you guys help us think through the DJ Basin Downspacing Program a little bit from this four wells per section and 32 wells per section, would that be applicable across your entire acreage and the early horizon going forward?

Charles D. Davidson

Well, as we said before we are trying it in different parts of the field and we will just need to get some more information later this year and then certainly how it expand from there.

Unidentified Analyst

Okay. All right, great, thank you.

Operator

We’ll take our next question from Charles Meade with Johnson Rice.

Charles A. Meade – Johnson Rice & Company LLC

Good morning gentlemen. First you start a quick one on Katmai, what you guys found so far, the 150 feet to pay that in the same trap as your primary objection?

Charles D. Davidson

It’s a four way closure. And so the structure is generally is there, but it wouldn’t be and I think our view is, it would be in a different pressure sale one is in I guess would be a middle Miocene and then the one that we've got to drill is in a lower Miocene. So it's all Charles it's all part of the same structure but it would be in a completely different interval.

Kenneth M. Fisher

Completely different interval

Charles A. Meade – Johnson Rice & Company LLC

Got it.

David L. Stover

Different pressures so.

Charles A. Meade – Johnson Rice & Company LLC

That makes sense with the liner that you guys still have to set there. Thanks for that and then if I could go back and try to dig in a little bit more on the pepler peaks pad. Dave I know you said in your prepared comments both of those – that all three of those peoples were 20-stages with I think you said three clusters per stage but were there any other differences that perhaps were necessitated by just the different kind of completion technique you use and I'm thinking the size of the job you pumped, whether they are all three in the same zone, that sort of thing?

David L. Stover

Yes. That I mean we’ve got – I think you've got one in the A and two in the C if I remember it correctly but as far as size of job I think they are very similar.

Charles A. Meade – Johnson Rice & Company LLC

Okay, so well that looks like a promising.

David L. Stover

Well the other difference there, Charles too and we pointed out one was a sliding sleeve and two were plug-n-perf.

Charles A. Meade – Johnson Rice & Company LLC

Right. Right.

David L. Stover

So you have a comparison in the C and a sleeve sliding sleeve so that will give us something to compare on that basis too.

Charles A. Meade – Johnson Rice & Company LLC

Within a single zone?

David L. Stover

Right.

Charles A. Meade – Johnson Rice & Company LLC

Right.

David L. Stover

Yes.

Charles A. Meade – Johnson Rice & Company LLC

That was the detail I was looking for, thank you, Dave.

David L. Stover

Okay.

Operator

We'll go next to Michael Rowe with TPH.

Michael Rowe – Tudor, Pickering & Holt

Hi good morning. I was wondering if you could just provide an update on your down spacing test in the Marcellus.

David L. Stover

No. I think what I mentioned, we just did our first well, we’re just bringing our first pad on in that 550-foot down spacing, so it will be probably next quarter or so before we really have results on that. It's just coming online.

Michael Rowe – Tudor, Pickering & Holt

Okay, great. And then just real quickly back to the DJ Basin. I know you commented about this a little bit earlier, but just maybe wanted more color on what you think – what your initial indications are on what these completion enhancements could mean for your ultimate spacing patterns in the Basin?

David L. Stover

Well I think part of what we’re doing there with the completion enhancements is as you go to some of the down spacing as you continue to test some of this down spacing, part of these completion enhancements are tailored for this increased density to plug-n-perf or some of the other things we’re trying to just get a higher concentration of propane around the well bore and get you better recovery which is even more critical on these tighter spacing wells. So, it just it's all it's all about continuing to improve our ultimate recovery up into the mid-teams from single-digits probably that we’re actually using right now.

Michael Rowe – Tudor, Pickering & Holt

Okay. Great, thank you.

Operator

And next we'll go to David Tameron with Wells Fargo. Please go ahead.

David R. Tameron – Wells Fargo Securities, LLC

Hi, good morning. Just a couple quick questions. First some of new completion techniques and the plug-n-perf and sliding can you just talk about any additional costs associated with those or I know you're in early R&D phase, but can you address that.

David L. Stover

Yes. I mean I think here, as we done the first couple years looking at 400,000 or so difference on the in the DJ on those plug-n-perf and I would expect you continue to know the gap overtime as you get more of the even and get that lined out even more, but a lot of its tide into, additional time in the down the completion side obviously. I think in the Marcellus, we're looking at an alternate design to this RSCS piece that right now at least the first one or two has been about half the cost of that so it will be interesting as we continue to compare results for this all of the design versus some of the improvement we’ve seen on the RSCS, so we'll keep a close eye on that too.

David R. Tameron – Wells Fargo Securities, LLC

Okay. And then I know we're up against 10 O’ Clock. One last quick question. The infrastructure…

David L. Stover

That was half the incremental cost, just to be clear on that.

David R. Tameron – Wells Fargo Securities, LLC

Okay. And the infrastructure issues in the DJ, it sounds like most of the facility upgrades – it sounds like most of the stuff is happening, I guess, more what you define as, or people would define as core Wattenberg rather than East Pony. Is that fair, or are you seeing infrastructure issues up in around the East Pony area, as well?

Charles D. Davidson

You're pretty accurate there because I mean when you think about it, the impact of the industry and all the activity all tie into these big central facilities is mainly down in that core Wells Ranch and the other areas down there. Up in East Pony we have a little more control of our own infrastructure up there. Yes, we have that Kiota plant that we'll be putting in later this year. So that will help us out a lot up in that part of the field too so you can’t ask to look at it in different portions here.

David Tameron - Wells Fargo Securities, LLC

Okay, all right. That's all I've got. Thanks. I appreciate it.

Charles D. Davidson

Thanks.

Operator

And we take our next question from Brian Singer at Goldman Sachs. Please go ahead.

Brian Singer – Goldman Sachs $ Co.

Thanks. I just wanted to follow up on the DJ here. At the Analyst Meeting, you highlighted the IDPs that give Noble a cost and execution advantage from a wellhead-to-processing perspective. Can you just talk more about whether you feel like there is a similar midstream advantage that can mitigate the impact expansion will have on volume growth and realizations relative to the others? Maybe Keota, which you just referenced, is that. But can you talk more about the midstream mitigation?

Charles D. Davidson

Yes, I think Brian on a midstream when we other than in the Northern area we have more control over destiny but in that – as you move into more the core regions Wells Ranch area, there we are dedicated to third-party processors so the key there is to work in coordination with the third-party to make sure that we got the timing all worked out and as Dave pointed out is making sure you got the infrastructure in the right places and you got volumes connected and moving towards there is capacity so it means there's going to be a lot of coordination work between third-party processor and our own people.

David L. Stover

The other there Brian, which was part of what we alluded to in talking and talking about the IDPs and some of the benefits what that really allows us to do is to put some real pipeline infrastructure in place like on oil hauling and water handling and so forth and really takes a lot off the road and simplifies our operations when you consolidated like that.

Brian Singer – Goldman Sachs $ Co.

As that continues to expand, is there a point six months, one year, three years down the road where you could say – here, the IDPs are in place. It's giving us this advantage, and we are now seeing much less volatility and more consistency in terms of not just getting the oil to the IDP, but getting it all the way to market relative to others?

Charles D. Davidson

Absolutely that’s where we are heading with. That's why we look at this whole thing as a major project and we have organized and staffed accordingly to handle this because there is the big price there for the future.

David L. Stover

I think also once you have that capacity there, were you really start to also see competitive advantage as you perhaps going and look at down spacing drilling, there you got the capacity you're not having to build-out new as much on the pads because you got it already in a central facility.

Charles D. Davidson

And reduce your whole cycle time over time also.

Brian Singer – Goldman Sachs $ Co.

When is that point of critical mass? Is that six months away, a year away? When did you say you would expect to reach critical mass there?

Charles D. Davidson

Well I think it depends on IDP and Wells Ranch we have got a central processing facility in place. We are expanding that so there you'll be more to that point within the next year or so here and then it says you move through these other IDPs and get their central facilities in place which is kind of probably about one a year.

Brian Singer – Goldman Sachs $ Co.

Thanks. And one last quick one in Nevada. You talked about the most recent well results. Was the liquids quality in line with expectations, or is there any change one way or the other?

Charles D. Davidson

No, no surprise there. We have actually sold some oil now.

Brian Singer – Goldman Sachs $ Co.

Great. Thank you very much.

Charles D. Davidson

Thanks Brain.

David L. Stover

Thanks Brain.

Operator

Next we have Gail Nicholson at KLR Group. Please go ahead.

Gail A. Nicholson - KLR Group, LLC

Good morning. Real quickly, when we look at the break-down that you guys give the second half of 2014 of the well count, are those evenly split on a quarterly basis between the Marcellus and Niobrara?

Charles D. Davidson

Gail, I don’t have the breakdown here with me. I would check that with Brad and David, on that.

Gail A. Nicholson - KLR Group, LLC

Okay, perfect. And then in regards to the second well at – can you talk about, by drilling that well, what any potential increase in the standpoint of production coming online? I know that Dantzler now got moved up into the first quarter of 2016, but do you think that peak rate of that field might increase to that second well?

David L. Stover

Well it's an extension well and it's testing another block. So yes it would be further upside to the field and it's one of the reasons we're moving forward with it now because it would allow us to modify our facilities as we develop the original Dantzler.

Charles D. Davidson

And the facility plan is set up such that if that's successful we'll be able to tie it in quickly so that's another big advantage for that.

Gail A. Nicholson – KLR Group, LLC

And then just one quick other question if I may. What we seen with the gas price coming off and the wide differentials we seen in Appalachia, do you guys when you look forward on your activity plans on 2015 forward does that change anything in your minds as how you'll develop the Marcellus?

Charles D. Davidson

I think as far as 2015, we’ll be sitting down with our partner, our joint venture partner and start to look at that, probably starting over the next couple months, but it's probably a little early to speculate on what we're going to do activity wise next year. Historically as the market has moved around we've made some adjustments with our partner between the distributions of wells in the wet gas area versus the dry gas area, so you can imagine that as Dave referenced as we get into the detailed discussions for 2015 that will be part of the conversation as well?

Gail A. Nicholson – KLR Group, LLC

Thank you.

Operator

And we’ll take our next question from Rehan Rashid with FBR Capital Markets & Co. Please go ahead.

Rehan A. Rashid – FBR Capital Markets & Co.

Thanks. Just two quick questions. On page 14 this is in the Niobrara fourth quarter, 172 wells. Is that good operating capacity of the platform? How should we think about it as we go into 2015? And then second, on Katmai, I'm not sure if I missed this or not, but from a development standpoint, where would it get tied in? That's it. Thanks.

David L. Stover

Okay. First of all on the 14, that's a combination of both Marcellus and the Niobrara so sorry about that but it's the sum of the two so we are just giving you an idea of the flow through that co-horizontal program and again I think we had a question early on the break out and maybe check with Brad or David they can give you some of the break out on that on the Katmai, there is a couple of existing facilities in the region that have capacity and so the plan always was that if we had success at Katmai we would engage in securing capacity so it would be – well we'll see how the primary…

Kenneth M. Fisher

Like a multiple choices.

David L. Stover

Yes. I got a lot of choices there and we'll see how it goes but certainly with what we have now that could be developed through subsea tie back.

Rehan A. Rashid – FBR Capital Markets & Co.

Got it. So cycle time should be pretty short.

David L. Stover

I would say it would be typical of what we have seen in things like Big Bend as an example. That's a good example, now we've still got a primary target to drill and the size could go up and that could alter our thinking but certainly with what we've got you would expect cycle times similar to what we've seen in other subsea tie backs.

Rehan A. Rashid – FBR Capital Markets & Co.

Got it. Last question, if I may. In the Niobrara, legislatively speaking, let's just say worst outcome, 2000 feet away. Is that on the surface limitations or subsurface?

David L. Stover

That is surface so that's where your well side is versus an occupied structure. So once you’ve got a clear location on the surface, then you can move with the horizontal development.

Rehan A. Rashid – FBR Capital Markets & Co.

So then the loss of location should – I mean you can simply extend your lateral length, right, to offset any surface loss of locations?

David L. Stover

There is lot of different things that have to be looked at as you would work just like we work it now with the existing setbacks, that's why we don’t speculate on the impact on locations, but obviously has an effect because 2000-feet is greater than 500-feet to 1000-feet so that’s we don’t believe it’s appropriate while we’re I think in greater position to help make sure that these don’t pass.

Rehan A. Rashid – FBR Capital Markets & Co.

Okay, thank you.

Kenneth M. Fisher

Thanks.

Operator

Next we have John Herrlin with Societe Generale. Please go ahead.

John P. Herrlin – Societe Generale Corporate & Investment

Yes, hi, three quick ones. With Katmai, Chuck, if you did find more is it potentially enough to justify standalone facilities that would you kind of alluding to or would it be subsea as well if you do find more?

Charles D. Davidson

Well, I think where you start thinking about standalone and when you go to the three-way. So, we’ve got to drill out the four-way closure now and I think what the range of resources we had on now. I think we would still view that as a subsea tieback, but when you start considering the three-way that’s where if you had success in that case you probably step back and rethink that and maybe start thinking standalone but that’s a waste down the road.

John P. Herrlin – Societe Generale Corporate & Investment

Right. Okay, thanks. Within the data, what was the gravity in the oil, Chuck? Or Dave?

David L. Stover

I thought it was low-to-mid 30s John, but I would have to double check that.

Charles D. Davidson

It does have a – as we said is as expected, it has a higher Parafin content.

John P. Herrlin – Societe Generale Corporate & Investment

So you would ship to Salt Lake?

David L. Stover

It would go less three of those refineries, yes.

John P. Herrlin – Societe Generale Corporate & Investment

Okay, got it. Last one for me in terms of the CapEx, could you give me a spilt of how much was unconventional and how much kind of conventional if that’s possible for the quarter?

Charles D. Davidson

69% John was the US onshore business?

John P. Herrlin – Societe Generale Corporate & Investment

Okay, thanks that’s it.

Charles D. Davidson

Thank you.

Operator

And this does conclude our question-and-answer session. I would like to turn the conference back to Mr. Larson for any closing remarks.

David R. Larson

Great, thanks again for everybody participating in the call as well as your continued interest in Nobel Energy. I hope everybody has a great day. Thanks

Operator

Ladies and gentlemen this does conclude today’s teleconference. We thank you for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!