Noble Energy (NBL) David L. Stover on Q2 2016 Results - Earnings Call Transcript

| About: Noble Energy, (NBL)

Noble Energy, Inc. (NYSE:NBL)

Q2 2016 Earnings Call

August 03, 2016 10:00 am ET

Executives

Brad Whitmarsh - Director-Investor Relations

David L. Stover - Chairman, President & Chief Executive Officer

Gary W. Willingham - Executive Vice President-Operations

Analysts

Evan Calio - Morgan Stanley & Co. LLC

Brian Singer - Goldman Sachs & Co.

Charles A. Meade - Johnson Rice & Co. LLC

Scott Hanold - RBC Capital Markets LLC

David Lorenzo Fernandez - Deutsche Bank Securities, Inc.

Arun Jayaram - JPMorgan Securities LLC

Irene Oiyin Haas - Wunderlich Securities, Inc.

Doug Leggate - Bank of America Merrill Lynch

Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

David Earl Beard - Coker & Palmer, Inc.

Gail Nicholson - KLR Group LLC

Jonathan D. Wolff - Jefferies LLC

Operator

Ladies and gentlemen, please stand by. Good morning and welcome to the Noble Energy's Second Quarter 2016 Earnings Conference Call. Following today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded.

And now I'd like to turn the conference over to Mr. Brad Whitmarsh. Please go ahead, sir.

Brad Whitmarsh - Director-Investor Relations

Thanks, Jake. Good morning, everyone, and thank you for joining us today. This morning I hope you've had a chance to review our second quarter 2016 operational and financial news release, as well as the supplemental slides for this event, which highlight a very strong quarter for Noble Energy and an enhanced outlook the remainder of the year. Both items are posted to our website. And you'll find them helpful as we talk through our prepared comments. In addition, we anticipate filing our 10-Q with the SEC later this morning.

Following prepared comments from Dave Stover, Chairman, President, and CEO, and Gary Willingham, EVP of Operations, we'll open the event for a Q&A session. In order to meet our 1-hour timeframe, we would ask that analysts limit themselves to one primary and one follow-up question. Additional management members available for Q&A are Ken Fisher, EVP and CFO; Susan Cunningham, EVP Exploration and New Ventures; and Keith Elliott, SVP of our Eastern Med Assets.

I want to remind everyone that this event may contain projections and forward-looking statements as well as certain non-GAAP financial measures. You should read our full disclosures in our latest news release and SEC filings for a discussion of those items. With that I'll turn the call to Dave.

David L. Stover - Chairman, President & Chief Executive Officer

Thanks, Brad. And good morning, everyone. Before diving into specifics on the quarter, I thought it'd be helpful to take a high level view of our performance to date in 2016.

Entering the year with an uncertain outlook on commodities, our stated focus was clear. First, operate the business within cash flows. Second, continue to improve capital efficiency to enhance returns. And third, increase our flexibility and financial strength by leveraging our portfolio. We're running well ahead of plan for the year, and meeting or exceeding all of these identified goals.

We've delivered another quarter where cash flow exceeded capital expenditures. We raised our full year 2016 volume expectation for a second time this year, providing an additional 10 million barrels of oil equivalent compared to our original expectation. And we have accomplished this with less capital than originally planned, an efficiency story that not many in our industry can match.

We've also reset our underlying cost structure and continued to strengthen our financial position through a series of portfolio optimization transactions. Each of these accomplishments has improved our long term outlook and generated significant value. In terms of what we control in our business I can easily say that we're executing as well as I've seen in my 14-year history with Noble.

Moving into the second quarter results. It was a period of operational records and milestones. To name a few, Noble reported record total company sales volumes, led by our U.S. onshore assets and Israel. Over the last year we've realized a daily volume increase of nearly 130,000 barrels of oil equivalent, while absolute lease operating expense and G&A combined were actually down period over period. As part of the volume increase, 31,000 barrels per day were oil and 32,000 barrels per day were NGLs.

Focusing onshore. In Texas we brought online our best Delaware Basin well yet, along with several great Eagle Ford wells, extending our successes in these assets since we acquired them a year ago. In the DJ Basin we enhanced our asset position through a strategic acreage exchange, adding additional depth of high quality inventory in our core Wells Ranch IDP area. And in the Marcellus, wells continue to outperform expectation, enhancing resource recovery in this leading gas position.

This operational momentum has continued offshore. Recent highlights include in the Gulf of Mexico we commenced production at Gunflint, on time and under budget. In Equatorial Guinea, the Alba compression project has also started up. And in Israel at the beginning of July we entered into an agreement for an initial 3% divestiture of our world class Tamar asset, establishing a gross valuation benchmark of $12.3 billion.

Second quarter volumes totaled 427,000 barrels of oil equivalent per day, an increase of 43% versus the second quarter of last year or 18% on a pro forma basis.

Performance for each business unit and commodity was ahead of expectations. This illustrates the benefits of our portfolio and industry leading execution, continuing to drive differential value among our peer group.

With respect to costs, results were within or below our expectation on essentially every metric. Capital was below the low end of guidance, driven by efficiency gains and the shifting of some onshore wells into the second half of the year. Unit lease operating expense stood out, down 30% from the second quarter of last year.

LOE per barrel equivalent benefited from record total production and deferred work over activity. I cannot overemphasize the strong performance of our Texas assets, where completion optimization and a busy quarter of activity drove substantial growth. Our third Noble designed Delaware Basin completion is showing robust productivity and a higher oil mix. Gary will share more on this well and our plans for the Delaware in a minute.

Everyone seems curious how we and others are thinking about capital allocation for the remainder of the year and into 2017. Our capital allocation discussion never stops. It's a continual process, focused on delivering the best value and returns.

The forward curve on oil has declined versus where it was the time of our last earnings call. And 2017 remains notably below the $50 level. The recent trend reflects resilient global supply and high inventories.

The outlook on gas appears to have improved slightly for 2017, yet it softens quickly in the following years. Significant volatility in both commodities remains. We've not yet seen market fundamentals reach a point where we would consider changing our capital plans for the year. At the same time, our execution and operating performance has increased our inventory and resource potential for when the environment is appropriate to accelerate.

While our total capital for the year remains under $1.5 billion, it has shifted slightly more toward the U.S. onshore unconventional liquid plays, where we have been able to exceed our production goals with fewer completions.

Adding to our flexibility is the expectation that we will now exit this year with about 140 operated drilled uncompleted wells. This represents a decrease of just 10% from the beginning of the year, a higher inventory than previously expected.

As we look forward, our capital will be prioritized on accelerating our Delaware Basin position, developing our DJ and Eagle Ford positions, and post-sanction, implementing our first phase of Leviathan. Our other offshore assets will provide necessary cash to support these activities. The Marcellus program will be driven by the gas price outlook.

With an improved liquidity profile following our asset sale proceeds, we're positioned to begin paying down debt by the end of the year, which will continue to lower Noble's underlying cost structure and further strengthen our balance sheet. Efficient liquidity will be maintained to allow us to increase activity when it makes sense.

We have executed as well as anyone during the volatility over the last 2 years. I am confident that our focused and disciplined strategy is the right approach in this environment. Let me now hand the call over to Gary to walk through our excellent operating performance.

Gary W. Willingham - Executive Vice President-Operations

Thanks, and good morning, everyone. As Dave mentioned, high levels of operating momentum continued in the second quarter, particularly in the U.S. onshore business. Operating and capital costs have been further reduced. And production from new wells is outperforming historical type curves in every one of our business units.

I want to start off this quarter in Texas, where improvements we've made in both areas in a relatively short period of time highlight the quality of our acreage and the value that Noble Energy can deliver.

I'll start in the Delaware with the Calamity Jane 2101H well. To say this is an exciting well is an understatement, especially when you consider it's only our third completion in the basin. You can see on Slide 5 the location of the well versus the first two Noble completions. The 2101H well is nearly 5,000 feet in lateral length and was completed with 3,000 pounds of proppant per lateral foot and slickwater fluid. In absolute terms, we have a 2,500 barrel of oil equivalent per day well with 1,450 barrels of oil, 560 barrels of natural gas liquids, and over 3 million cubic feet of gas per day.

The chart shows the production compared to our prior two wells and the type curve. The first two wells continue to widen versus the 700,000 barrel equivalent type curve. And this latest well is even better. Versus type curve, this most recent well is more than 75% higher.

From recent industry M&A activity it's clear that the value of the Delaware Basin acreage continues to increase. Two recent transactions specifically in and around our acreage reaffirm to me that we have a very enviable 45,000-acre position in the basin. Being early into the play obviously generated a tremendous amount of value.

We'll have a rig operating in the Delaware almost continuously through the remainder of the year, with several new drills and wells coming on production. Long-term development planning is under way. And our focus will be on delivering substantial well cost efficiencies by utilizing multi-well pad design and longer laterals. And we will also delineate multiple Wolfcamp zones in the Third Bone Spring across our acreage. In addition, we are working to design a centralized infrastructure, which will support our long term plans.

We also announced extremely strong results in the Eagle Ford this morning, specifically in the Gates Ranch area. Slightly more than half of the announced wells had 500-foot lateral spacing, with the remainder completed at 1,000-foot lateral spacing or more. And I want to emphasize a couple of takeaways from these results, which are shown on slide 6.

First, results continue to demonstrate the benefits of higher intensity fracs, specifically more proppant with tighter cluster and stage spacing. A great example of this is the two wells which commenced production in the north Gates Ranch area during the quarter. These wells are performing above the 3 million barrel equivalent type curves that we used for Southern Gates Ranch, or three times our prior assumption for North Gates Ranch. This follows similar significantly improved results in Briscoe Ranch, which we talked about last quarter.

Second, we are gathering additional production history on lateral spacing, which will increase our drilling inventory going forward. With the 500-foot spaced wells performing in line with the 3 million barrel equivalent type curve, we believe that South Gates Ranch area will support at least 750-foot spacing, as we move into drilling and completing the fourth row of South Gates Ranch during 2017.

In addition to our Delaware rig activity, we have a rig coming into the Eagle Ford for the remainder of the year and have ongoing completion activity as well. Our Eagle Ford volumes will be lower in the third quarter, reflecting shut in impacts for offsetting frac activity. Several new wells are expected to come online toward the end of the third quarter, giving us strong momentum exiting the year and into 2017. This will include wells in the Briscoe Ranch area, one of which will be an Upper Eagle Ford test.

Moving to the DJ Basin. The dominant theme continues to be transformative capital efficiencies from drill time reductions and cost savings, as well as performance improvements from enhanced completions. As we indicated on the first quarter call, our central processing facility underwent its first planned turnaround since starting up 3 years ago. As a result, the only wells which were brought online during the quarter were in May or June, and thus did not have a full quarter impact. The basin also experienced unplanned third-party facility downtime during the quarter.

Once again we reduced normalized extended reach lateral well costs. We are now down to $2.6 million in Wells Ranch, which represents a sequential quarterly decrease of another 4%. This includes the cost efficiencies of monobore drilling, which accounted for nearly all of our drilling activity during the second quarter, as well as the increased costs of higher sand concentrations and tighter stages.

On the completion design front the change to slickwater fluid as well as increasing proppant loading continues. And I'll turn your attention to Slide 8, which provides more detail.

Cumulative production charts on the right show the actual averages for these new completion designs with 1,000 pounds of proppant or more, compared to historical types curve. As you can see, performance in Wells Ranch is at least 15% higher than historical type curve. And East Pony has improved by more than 35%. With continued strong performance improvement, I'm excited about the potential impact of a higher percentage of these well designs coming online the remainder of the year.

The new 10-well Moser pad and the Mustang IDP includes our first seven wells testing enhanced completions outside of Wells Ranch and East Pony. These wells came online at the end of the quarter and are significantly outperforming expectations, which speaks very positively for the future potential of our Mustang IDP development.

During the quarter we continued to optimize our large DJ Basin acreage position. We completed the first closing of the previously announced sale of approximately 33,000 net acres from our Greeley Crescent area. This acreage was not in our development plans for many years. We received $486 million in proceeds, with a remaining $19 million expected around the end of the year.

In addition, we completed a strategic acreage trade with PDC Energy, which expands our Wells Ranch position by approximately 20% and provides substantial operating synergies and cost efficiencies for both companies.

Both transactions are consistent with our strategy to focus on areas with higher oil content, where we have more contiguous acreage and to drive efficiency gains through long lateral development and existing infrastructure.

As part of our focus on improving total value in the DJ Basin, we have been deferring workovers and repairs, especially for legacy vertical wells when those expenditures just don't make sense in this price environment. As a result of these economic choices, vertical production is expected to be impacted by up to 5,000 barrels equivalent per day during the second half of 2016.

Moving on to the Marcellus. Production remains above expectations, despite the limited capital spent. In addition, the JV continues to benefit from shared infrastructure to optimize recycling of produced water, significantly reducing our operating expenses.

Recent pads in both the wet and dry gas areas continue to highlight the prolific nature of our position in the play, as depicted on Slide 9. We remain aligned with our partner to operate the JV within cash flow in 2016 and will continue to be flexible with activity for the remainder of the year. At current commodity prices we expect six additional wells to be completed between now and year end. The continued outstanding performance of the Marcellus wells has driven the growth seen by CONE, the midstream gathering company partially owned by Noble.

Offshore in the Gulf of Mexico we continued to see strong production from the Big Bend and Dantzler fields during the quarter. This is despite a temporary shut-in of the Thunder Hawk facility in late June, due to issues at a downstream third-party gas processing plant.

In July we brought online our Gunflint development, on time and under budget. This is the third Middle Miocene tieback to commence production in the last 12 months, contributing to the almost doubling of our Gulf of Mexico volumes this year.

The net amount from Gunflint to Noble Energy is expected to be at least 5,000 barrels of oil equivalent per day, with potential for additional volumes, dependent upon available capacity at the third-party host facility. The two wells are currently ramping up as expected.

Sales volumes in West Africa were up from the first quarter, which had downtime from the installation of the new Alba B3 compression platform. Startup of this Marathon operated project, which will enhance full field recovery, occurred in July. While Noble's quarterly sales volumes will fluctuate a bit quarter to quarter based on the lifting schedule, we would expect total West Africa production to remain relatively level for the remainder of the year.

Our Gulf of Mexico and West Africa assets don't often get the attention from the equity markets that they deserve. The company's major project execution capabilities were highlighted again recently with the successes at Gunflint and Alba. And these capabilities continue to deliver substantial value for Noble Energy. Looking forward, near term capital needs in both are relatively low. And the assets remain significant cash flow generators.

In Israel, natural gas volumes from Tamar were up nearly 30% from the same period last year and even higher than the first quarter of this year.

The Israeli government has mandated a reduction of coal fired power generation by 15% year over year as shown on Slide 11. This reflects the government's recognition of the economic and environmental benefits of natural gas, and their confidence in the timing of the Leviathan development.

This new underlying base load demand is showing up in big numbers, particularly in the shoulder periods, when additional quantities of gas have historically been available. As a result, coal power dispatched during the second quarter was down over 20% versus the second quarter of last year.

We are now into the high demand third quarter period, when Israel will need even more gas. We've also announced plans to commence drilling another well at Tamar later this year, which will reinforce reliability and help meet peak demand going forward.

At Leviathan we are continuing to target a final investment decision around year end. We've now contracted up to 100 million cubic feet per day of natural gas to Israeli customers. And continue to advance negotiations with additional domestic and regional customers.

The regulatory progress we have seen over the last quarter is also significant, including the government's approval of the fixed platform plan of development. FEED work is under way, and early indications are that this continues to be a great opportunity to lock in very competitive costs for this long life resource project.

Over the coming months we expect to finalize remaining key milestones for sanction. This includes additional sales contracts, both in Israel and for the export market and financing plans, as well as completion of the engineering work and project cost estimates. Now I'll turn the call back over to Dave.

David L. Stover - Chairman, President & Chief Executive Officer

Thanks, Gary. We provided a full update to our 2016 guidance on Slide 14. As I mentioned earlier, we've now raised full year sales volumes to 415,000 barrels of oil equivalent per day, up more than 7% from our original guidance on a divestment adjusted basis, while reducing our original full year capital expenditure guidance.

Not many companies will grow production at that rate, while enhancing their financial position and without diluting shareholders. This is a testament to our high quality portfolio and the underlying execution in our business, delivered by our talented and dedicated workforce.

For the third quarter capital is expected to range between $400 million and $450 million, with 80% going to the U.S. onshore business. Sales volumes are anticipated to range between 405,000 and 415,000 barrels of oil equivalent per day.

The primary difference from the second quarter is our Eagle Ford volumes, due to well shut-ins for offset completions. In our other onshore areas, Marcellus will likely be up in the third quarter and DJ is expected to be down, reflecting lower vertical production as Gary mentioned. Offshore volumes should be relatively flat for the second (sic) [third] (22:07) quarter with Israel up and West Africa lower due to timing of liftings.

The third quarter outlook also includes the impact of about 2,000 barrel equivalent per day from the Badoin (22:19) sale in Montana and the initial closing of the Greeley Crescent divestiture. The production impact from asset sales grows to around 8,000 barrels of oil equivalent in the fourth quarter, with the second Greeley Crescent closing and the Tamar sell-down already announced. These asset divestitures accelerate and highlight the value in our portfolio.

There's a lot to look forward to in the second half of 2016. We have continuous operations ongoing in both the Eagle Ford and the Delaware Basins, including a doubling of new wells in the Delaware compared to the first half of the year.

We will also continue to advance the enhanced completion designs in the DJ Basin and leverage our Midstream competitive advantage. And in Israel, we expect to see higher utilization of our Tamar asset, while at the same time, progressing Leviathan toward final investment decision.

When you put it all together, this is a great company with a great future. The high quality and deep inventory of our U.S. onshore portfolio can deliver high return growth for many years. This is complemented by the visible and prolific long term growth and value potential of the Eastern Med assets. In addition, the Gulf of Mexico and West Africa assets provide meaningful and long term cash generation.

Portfolio, execution, and financial capacity, these are our competitive advantages and our strong foundation to build upon. At this time, Jake, we'll go ahead and open the call for questions.

Question-and-Answer Session

Operator

Thank you. We'll pause for just a moment to assemble the roster. And we'll now hear first from Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley & Co. LLC

Hey, good morning, guys.

David L. Stover - Chairman, President & Chief Executive Officer

Morning, Evan.

Evan Calio - Morgan Stanley & Co. LLC

Look, very strong well performance in the acquired southern Delaware acreage. Any color on the returns uplift and incremental well cost for these enhanced completions? And is that the completion design you expect to be using in the second half of 2016? And somewhat related, I know you're also drilling longer laterals in the second half, what color or – any color on the percentage of your acreage position amenable to longer laterals there?

David L. Stover - Chairman, President & Chief Executive Officer

I'll have Gary jump into more of the details. But I'll reiterate your observation first, that the performance has been outstanding, whether you're looking at the Delaware Basin or the Eagle Ford. But let me have Gary go ahead and expand on that.

Gary W. Willingham - Executive Vice President-Operations

Yeah, Evan, I mean clearly we've been very happy with the results we've seen after only the first three wells. I think for the plans of the rest of the year, lateral length may get a little bit longer for the second half of this year. And then we'll really start to see longer laterals lengths, probably beginning more in 2017.

We're continuing to test different completion designs, so we're not quite in that full development mode yet that you would expect to see and start to see significant savings on the D&C side. That'll probably come more in 2017, as we get into full development mode as well.

For the rest of this year we're going to be testing different designs though. This latest well with 3,000 pounds per foot, we'll actually go back and test some lower sand concentrations on these next couple of wells, just as we zero in on what the best value case is. I think for us, we're always trying to look at what's the most value creating completion that we can design.

It's not about IP30, although clearly we're very happy with this being our best IP30 well to date and one of the best we've seen anywhere in the basin. It's certainly not about IP24. And it's not about EUR over the long term. It's about how much value we can create.

So we'll test some smaller sand concentration designs as well, as we zero in on that best value. And we'll have another half dozen or so wells by the time we get to the end of the year to help inform what our plans are for next year.

David L. Stover - Chairman, President & Chief Executive Officer

I think, Evan, the other thing that's important to note there too, as we had set up the year, we're now moving into that part of the year where we're having them – we're setting up ourselves up for a more consistent operation in both the Delaware and the Eagle Ford. We're going to have a rig running in both areas now. I think that will help accelerate even some of this learning curve as we go forward.

Evan Calio - Morgan Stanley & Co. LLC

I mean is there – do you have a cost that you can share on the Calamity Jane? I know that the results were fantastic. I was just curious what the incremental CWCs are there? And then and just I don't know if you – it's too early, but your acreage looked very contiguous, and that's kind of why the question was, how much may be amenable to a longer lateral, when that becomes part of the development program in the future?

Gary W. Willingham - Executive Vice President-Operations

Yeah. As we move more to pad drilling you'll definitely see longer laterals, just like you've seen us do in the Wells Ranch and East Pony.

I think on the cost side, again it's only the third well. I think it's probably fair to keep using an assumption that we've rolled out in the past for these wells. And as we move into more of a development plan, we'll see potentially some cost savings from there.

Again a large part of it depends on what completion design we end up with. I mean if we end up with 3,000 pounds per foot across the board, then that's going to add several hundred thousand dollars to the completion of each well. So we'll continue to test and figure out what the most value adding completion design is, and as we move into development mode next year, we'll really start to see those cost efficiencies.

Evan Calio - Morgan Stanley & Co. LLC

Great. Good job, guys.

Operator

We'll now move to a question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs & Co.

Thank you. Good morning.

David L. Stover - Chairman, President & Chief Executive Officer

Morning, Brian.

Brian Singer - Goldman Sachs & Co.

With Leviathan potentially getting sanctioned and the interest that you described in expanding your activity in the Permian, DJ, and Eagle Ford, the potential for higher gas prices to increase interest by your Marcellus partner in increasing drilling activity, can you just talk to your interest level and extent about spending cash flow in 2017? And how you would time the level of activity based on front month and strip oil prices?

David L. Stover - Chairman, President & Chief Executive Officer

Yeah. I think as all of us are doing now, we're starting to look at our plans for 2017. And there's still probably a lot of volatility as to what kind of commodity price expectations you're looking at.

I think when you look at our capital program for 2017, obviously the capital in the Eastern Med will be driven by the timing of a Leviathan sanction. And as we've talked about, we're well set up and especially now also with some of the sell down of the Tamar interest to be able to fund that from kind of that ring fence strategy over there.

As we look at the U.S., the Eagle Ford has been great returns. The Delaware performance highlights what the returns in that area can be. And the DJ has been strong returns. So then you're looking at in the Marcellus, I think we're still in the mode of continuing to manage to cash flow and working with our partner in that element. What we've said there is as gas price continues to increase, it provides more cash to continue to be able to spend in that arena.

So I think when you put it all together, Brian, we're really going to have to continue to watch and stay flexible on how we allocate capital based on water outlook on both oil and gas commodities. The good part is we have a lot of flexibility, because we got very little what you'd call non-discretionary capital next year. I'd say it's all pretty much discretionary.

Brian Singer - Goldman Sachs & Co.

Great, thanks. And then the follow-up is on the operating costs. You've shown pretty low op costs here on the LOE side for the last few quarters. And I wondered if you can speak to, if we do go into a higher commodity environment here, the sustainability of these cost declines on the operating side? And then if you see room for any further efficiencies?

David L. Stover - Chairman, President & Chief Executive Officer

Yeah. Well I think a lot of it is sustainable. I think when you think about operating costs, a lot of it is driven by people cost and the electricity cost. So those are going to be the two moving factors on that.

I think what you're seeing as we continue to get more and more efficient, the cost will continue to be beneficial going forward. I think you're seeing that. Look at what we're doing now. We're handling about 33% more volume right now at the same LOE and G&A cost that we did prior to that. So I mean that's pretty much a testament to the ability to continue to manage that.

Brian Singer - Goldman Sachs & Co.

Great. Thank you.

Operator

And now we'll hear from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Co. LLC

Good morning, Dave, and to the rest of your team there.

David L. Stover - Chairman, President & Chief Executive Officer

Hey, Charles.

Charles A. Meade - Johnson Rice & Co. LLC

I'd like to dig a bit deeper on your U.S. oil volumes in Q2. There was a decline of about 6,000 barrels a day from 1Q. And I know you've gone into some detail on some of the things in the DJ Basin that contributed to that.

But I'm wondering if you could add any other context to what contributes to that sequential drop? And if that's the kind of thing where 2Q is what we should be thinking about as a level for the back half of the year, whether there's going to be some rebound on U.S. oil volumes, as if those issues are more transient?

David L. Stover - Chairman, President & Chief Executive Officer

Yeah. I think on oil volumes, in reality, they were right in line with what we had expected on that. We had expected and some of the DJ piece to come down a little bit from first to second quarter, just based on the activity levels, quarterly activity levels. I think in the Gulf of Mexico they were down a little bit in the second quarter also from first quarter with some of the downtime that Gary mentioned on some of the onshore facilities.

I think when you look at it going forward, it's going to move around some quarter by quarter, just from the liftings in West Africa. And as you know, Charles, we've seen that before.

But as far as the outlook on oil volumes, U.S. or total, I mean it's on track with what we've been expecting. I think when you look at the third quarter too, and a little bit in the fourth quarter, you got to not forget that we have to build in a little bit of assumption on some downtime in the Gulf of Mexico for both storms and potentially some of this onshore facility impact. So you have a little bit of that.

But you have – quarterly you have volumes moving around a good bit. For example, third quarter the West Africa volumes, oil volumes will be under lifted.

Charles A. Meade - Johnson Rice & Co. LLC

Right.

David L. Stover - Chairman, President & Chief Executive Officer

But when we look at the projection going forward, we've taken a pretty hard look even at the horizontal volumes in the DJ, for example. It's pretty consistent on oil percentage going forward. So that's why I say it's tracking pretty well with what we expected.

Charles A. Meade - Johnson Rice & Co. LLC

No, that's helpful detail, Dave. And then if I could ask a question that perhaps dovetails on those, again the really remarkably good results you had in the Delaware Basin. The thing that stands out there is the 3,000 pounds of sand a foot. And I know it's a different basin from the DJ. But it's just the contrast is there with these recent completions you have with the DJ being 1,000 pounds of sand a foot. And is there more room in the DJ to increase those sand concentrations? Or do you think you kind of zeroed in on it? And it's – and you're at the right spot that's dictated by just the reservoir conditions and the rock properties?

David L. Stover - Chairman, President & Chief Executive Officer

I think you're picking up on a good theme there, Charles. I think whichever, whether it's Eagle Ford, whether it's Delaware, or whether it's the DJ, we're seeing continued performance improvements as we continue to work on optimizing these completions.

And to my feeling, we're not at the end of that game yet. I think Gary will expand on that a little bit. We've actually seen some increased concentrations in the DJ. And he can talk a little more to how he's thinking about those from each of the different areas.

Gary W. Willingham - Executive Vice President-Operations

Yeah. Charles, I mean I think when we've talked about enhanced completions in the DJ, we've said 1,000 pounds or more. And historical designs in the DJ were in the 700- to 800-pound per foot range. So 1,000 pounds or more is 50% more to twice as much as we've historically used.

I'll tell you that we've tested some that are quite a bit more than 1,000 pounds, more in line with some of the types of designs that we've been using down in Texas. So to Dave's point it's a transition that we're making to test some higher proppant loading designs there as well. And certainly if we see a similar uplift there that we've seen in some of the areas in Texas, it could be very encouraging for those volumes going forward.

David L. Stover - Chairman, President & Chief Executive Officer

But I think part of what you're seeing too, is the ability to transfer our learnings from each area to the other. And then tailor them specific for the area. And we're seeing the big benefit of having multiple areas to continue to work on here.

Charles A. Meade - Johnson Rice & Co. LLC

It seems that way. Thanks a lot, Dave and Gary.

Gary W. Willingham - Executive Vice President-Operations

Yeah.

David L. Stover - Chairman, President & Chief Executive Officer

Thanks, Charles.

Operator

And now we'll move to a question from Scott Hanold with RBC.

Scott Hanold - RBC Capital Markets LLC

Yeah, thanks. I have a question on adding the rig in Texas. So you're going to have one in both the southern Delaware as well as the Eagle Ford. How much room have you guys found in your budget due to cost savings and efficiencies? And how much more could there be over the next say 6 months to 12 months?

David L. Stover - Chairman, President & Chief Executive Officer

Well, I think we've seen the benefit of that when you look at just what we're delivering now versus what we're spending. When we went into the year, we talked about spending $1.5 billion for – what – 390,000 barrels equivalent per day for the year. Now we're spending what looks like, if you just project out what we've laid out for guidance for third and fourth quarter, under $1.5 billion and delivering 415,000 barrels of oil equivalent per day for the year. So we're seeing that benefit.

You're seeing that's allowing us to do a little more even here in the second half of the year, which shows in some of the activity, both in some of the capital activity, what we talked about, the allocation of 80% of our capital here, this second half here going into the onshore business. Or close to that. But I don't – Gary, any other thoughts on that efficiency and how it's playing out?

Gary W. Willingham - Executive Vice President-Operations

No, I mean I think just similar to my earlier comments, it's very early days in Texas. We are picking up rigs in both places and moving into a development mode more in 2017 in the Delaware especially. So I would expect to see similar cost efficiencies and improvements in the Delaware over time, similar to what we've seen in the DJ.

And it's a bit surprising to me how we continue to still see improvements in the DJ to the magnitude we are. Another 4% just in one quarter is a pretty significant number, given how far we've already come. So I think we'll continue to see small gains in the DJ going forward. And probably some pretty significant gains in the Delaware as we move to that development mode of operating.

David L. Stover - Chairman, President & Chief Executive Officer

But those efficiency gains, they're playing out on the cost side. But we're seeing it play out, as some of the callers have referenced, just on the resource potential and the performance per well. And that's just adding inventory to us.

Scott Hanold - RBC Capital Markets LLC

And you all have highlighted development in the southern Delaware in 2017. What do you envision that looks like? Is it pad drilling? How many wells do you set up on a pad? What zones do you figure you're going to target in? Would that be more than one rig? Would that say be maybe two or possibly three rigs?

Gary W. Willingham - Executive Vice President-Operations

Yeah. I mean it could definitely be more than one rig. We're still working through plans for 2017 budget right now. But I think when you think, whether it's 2017 or 2018, kind of near to medium term for the Delaware Basin, you need to think about it very similar to what we've done in the DJ and Wells Ranch and East Pony, where we start building centralized infrastructure, where we can take advantage of those scale and efficiencies. We start building or drilling more multi-well pads, longer laterals, and we see a lot of those same efficiencies show up in the Delaware that we've seen in the DJ Basin.

So we'll continue to work the budget here for the next few months and talk about that when it's the right time. But I think we'll certainly see more activity in the Delaware next year than we've seen this year.

Scott Hanold - RBC Capital Markets LLC

Thanks.

Operator

And now we'll hear from Ryan Todd with Deutsche Bank.

David Lorenzo Fernandez - Deutsche Bank Securities, Inc.

Hello. This is David Fernandez filling in for Ryan Todd. Just first a question on the asset sale front. Just if you could remind us what the update is on the Tamar divestiture? And kind of like the timeline associated with that? And any thoughts around a potential IPO of the Midstream assets?

And as a follow-on – I guess not as a follow-on, but as a follow-up question. Any insight or color around the performance at the Mustang IDP enhanced completions would be appreciated. Thank you.

David L. Stover - Chairman, President & Chief Executive Officer

Okay. Let me start on Tamar. We put the announcement out on Tamar, where we reached agreement to sell 3%. And I think that's a great marker, that's a good marker for the asset. I think as far as the timing, I would expect the timing of that to close by the fourth quarter. So definitely before year end. And we'll just – we'll obviously announce that as it happens.

I think on the Midstream IPO, that'll be – we've kept the S-1 alive, so we've kept that available as to enter the market when the market conditions kind of dictate that. So we'll – that's about all I can say on that at this point. But that's something we're keeping alive.

I think on Mustang, that's an area, it's probably our next IDP area. Gary can mention a little bit on that. But I think just the initial results, very encouraging there.

Gary W. Willingham - Executive Vice President-Operations

Yeah, David, I think very happy with the first results. It's, like we said, a 10-well pad, seven of which tested enhanced completions. It's one part of the IDP, obviously with it only being one pad. So but very, very encouraged with what we've seen so far. It's only coming on right at the end of 2Q, so a bit early to start putting numbers out there.

But I think when you look at how much the enhanced completions have improved, the performance of the wells in Wells Ranch and East Pony, and again that's on one of the slides in the pack. And you can see how much uplift we're getting from that. You can see why we're excited from similar level of improvement in Mustang with just the first pad there.

David Lorenzo Fernandez - Deutsche Bank Securities, Inc.

Thank you.

Operator

And now we'll take a question from Arun Jayaram with JPMorgan.

Arun Jayaram - JPMorgan Securities LLC

Good morning. Perhaps, Gary, I was wondering if you could maybe help us understand a little bit about some of the trends, production trends you're seeing in the DJ Basin. I guess I was wondering, you had the turnaround in Q2 plus some unplanned downtime. But you did indicate that you'll have less workover activity for verticals. I was wondering if you could help us think about how the DJ may progress on a sequential basis for the balance of the year?

Gary W. Willingham - Executive Vice President-Operations

Yeah. No. I mean I think we've said for quite some time that in the DJ Basin it takes three to four rigs to keep production flat. We've been running two obviously for a while now. Balancing part of that is clearly the fact that we've seen better results from these enhanced completions.

I think in 2Q you had the issues that you mentioned, the turnaround at the Wells Ranch Central Processing Facility, as well as some third party gas plant downtime that impacted volumes. As we mentioned and you reiterated there, we've also held back on some workovers and repairs, especially on vertical wells that just don't make sense in this price environment. So those have impacted vertical volumes.

I think when you look at our level of activity going forward with the type of performance we're seeing on these enhanced completions, even with two rigs we're probably flat on horizontal production through the end of the year. Vertical will decline a bit. So overall you'll be declining through the end of the year, as we've kind of suggested in the past. But the horizontal program is holding in there quite nicely with just two rigs.

David L. Stover - Chairman, President & Chief Executive Officer

I think to that point, Arun, and it's worth emphasizing. And Gary mentioned it. Is we're actually on the horizontal program doing as well or better with the amount of capital that we're spending than we would have laid out before.

What's masking it a little bit is some of these decisions, which are the right economic decisions. And the fact that everybody is looking at everything as a business decision on some of these vertical wells. And some of that production can be brought back at a later time in the right price environment. But now is not the right price environment to be trying to maximize the vertical production up there.

Arun Jayaram - JPMorgan Securities LLC

And that makes a ton of sense. Thanks for clarifying that. And just, Gary, one of your peers has highlighted in pretty close proximity to you guys some optimism about the Third Bone Spring interval in the southern Delaware. Any plans to test that over the next call it 6 months to 12 months?

Gary W. Willingham - Executive Vice President-Operations

We've got plans to test it. We've got one Third Bone Spring well that we'll spud around the end of this year. We won't have any completions on this year, but we will spud one towards the end of the year.

Arun Jayaram - JPMorgan Securities LLC

Okay.

Gary W. Willingham - Executive Vice President-Operations

I think with everything we've seen from offset operators and our own mappings, we believe that the majority of our acreage we would consider probably Tier 1 prospective for the Third Bone Spring.

Arun Jayaram - JPMorgan Securities LLC

Okay, great. Thanks a lot.

Operator

And now we'll hear from Irene Haas with Wunderlich.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Yeah. So congratulations on all the good work you've done in Texas in specific. And I'm curious as to on Wolfcamp A, how many zones have you decided to tackle? Would you consider Wolfcamp B? And importantly, at which point – how much time would we need to really get some clarity on interval spacing and sort of completion design too for you to sort of update your drilling inventory in the Delaware Basin?

Gary W. Willingham - Executive Vice President-Operations

Yeah. I think everything we've done so far is Wolfcamp A and really the upper part of the Wolfcamp A. As we get into the latter part of this year, as I mentioned, we'll test the Bone Spring. We'll test a Lower Wolfcamp – or we'll spud a Lower Wolfcamp A. It probably won't be on this year. So we'll continue to delineate through that vertical section.

I think it's probably a bit early to zero in too much on how many wells or what spacing we think we'll ultimately end up at, given that we've only brought our third Noble operated well on so far. I think it's a pretty wide range we're looking at right now, when you consider all the way from the Third Bone Spring through the Upper A, the Lower A and maybe even into the B. It could be as many as 15 to 25 wells. I know that's a wide range. But give us a bit more time than three completions, and we'll narrow that going forward.

Irene Oiyin Haas - Wunderlich Securities, Inc.

May I have one follow-up question? How much money did you save from using a slickwater versus hybrid in Delaware Basin?

Gary W. Willingham - Executive Vice President-Operations

The Delaware Basin, I don't know the exact number, Irene. I mean what we've seen in the DJ Basin with those fracs is it's $300,000 to $400,000 savings from slickwater. It's probably on the same order of magnitude in the Delaware.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Thank you.

Operator

And now we'll take a question from Doug Leggate with Bank of America Merrill Lynch.

Doug Leggate - Bank of America Merrill Lynch

Thanks. Good morning, everybody.

David L. Stover - Chairman, President & Chief Executive Officer

Hey, Doug.

Doug Leggate - Bank of America Merrill Lynch

David, I wonder if I could ask you about the type curve trajectory you see in the Delaware Basin? I mean clearly it's early days. But when you look at the offset operators and obviously the myriad of industry data out there, what do you guys need to see before you revisit what is clearly looking increasingly like a kind of stale assumption at this point?

David L. Stover - Chairman, President & Chief Executive Officer

I think Gary touched on it. We just need to get more wells on production. And we need to get more time and history on the wells we have on production, some more extended production periods. Not only ours, but even the offset operators, even some of the more recent wells there that have been highly encouraging.

We're not going to rush to revise the type curve and then have to rush to revise it again. We'll get a little longer extended production period both for ours and offset operators. And watch them both and then get some more wells online.

Gary W. Willingham - Executive Vice President-Operations

And...

Doug Leggate - Bank of America Merrill Lynch

I guess what's behind my question – okay, go ahead, Gary. Sorry.

Gary W. Willingham - Executive Vice President-Operations

No, I was going to say, I think what's encouraging for me, Doug, is again, even though it's only three wells, it's three wells that are spaced across the acreage and all are above the type curve, which is obviously intended to be an average of the acreage.

So I think we'll continue to see improvement in the completion designs there. And once we get a few more than three under our belt, we can talk about what that 700,000 [barrel equivalent] goes to.

Doug Leggate - Bank of America Merrill Lynch

Yeah. I realize it's very early days. I guess what was at the back of my mind was, when you think about incremental rig adds, obviously the type curve economics that you currently have, as your current well, if you like, has very different implications as to whether you would add in the Delaware versus the Eagle Ford. That's really what I was kind of getting at.

David L. Stover - Chairman, President & Chief Executive Officer

Right. And to the same extent, we're looking at that same opportunity in both, where they're both well outperforming the type curve. So we have to take that into account as we look at setting our plans for next year.

Doug Leggate - Bank of America Merrill Lynch

Got it. Thanks.

Gary W. Willingham - Executive Vice President-Operations

Yeah. I mean in the Delaware, where you look at a well in the Delaware that's 75% above the type curve in the early days, obviously huge impact on the economics of that. But as Dave points out, we're seeing very nice improvements in the economics in the Eagle Ford too, which were already very robust.

And when you look at the 500-foot spaced wells that are in line or above with the 3 million barrel type curve that was based on spacing twice as wide as that. When you look at Northern Gates Ranch, where we're above a 3 million barrel type curve, which is three times what we assumed when we did the acquisition. And when you look at Briscoe Ranch, where we're significantly above the type curve that we assumed at the type time of the acquisition, and we haven't even brought those enhanced style completions to all the areas yet. I think there's tremendous upside potential in both of these areas that'll be very economic even in this price environment.

Doug Leggate - Bank of America Merrill Lynch

A nice problem to have, fellas. Dave, my follow-up is maybe a little bit of a standard question nowadays. But with the signature deadline coming up on the 8th of August, I'm just wondering if you could share your latest thoughts on the Colorado setback rule? And I'll leave it there. Thanks.

David L. Stover - Chairman, President & Chief Executive Officer

Well yeah. I think extremely glad we put the work in that we have over the last couple years. I think we're doing the things we need to do. And I'm comfortable we're doing the right things to stay out in front of this.

We've stayed focused on – engaged on being out in front of and defeating any potential ballots, if they get enough signatures. And we'll wait and see where that – how that plays out. But either way, we're staying out in front of this.

The nice part is we've built a strong coalition in the business community up there. You've got landowners, farmers, home builders that all are affected by this, and greatly affected if something like that went through. So they're out in front of this also and working hard on this.

I think the government's been supportive of what we're doing and very engaged in this effort.

So the other part of it is the public education has worked. I mean you can see that from the polling. You can see that from the results. The increased support, awareness and understanding. So again I'll go back to where I started with, we're doing the right things, and we're in the right position to stay in front of this.

Doug Leggate - Bank of America Merrill Lynch

Appreciate the answers, guys. Thank you.

Operator

Our next question will come from Jeoffrey Lambujon with Tudor Pickering Holt Company.

Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

Thanks. Good morning.

David L. Stover - Chairman, President & Chief Executive Officer

Morning.

Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

In the Delaware can you comment more on what forthcoming drilling completions activity will be focused on this year? You mentioned the Wolfcamp zones and the Third Bone [Spring]. Is that the primary focus? Or could we expect some sort of aerial delineation as well?

Gary W. Willingham - Executive Vice President-Operations

No. I mean as I said it'll be – we'll test – drill a Third Bone Spring and probably a Lower Wolfcamp A later this year. A half dozen or so additional completions that we'll bring on production this year, I think are all Wolfcamp A Upper. And as far as aerial testing, they're all probably in that east to central part of the acreage block for the rest of the year.

Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

Great. Thanks. And then one on guidance. Just kind of going back to the ongoing outperformance across your U.S. oily onshore (52:50). Anything baked in on that front at this point? Or is it all still based on existing curves, the 700,000 [barrel equivalent] in the Delaware and so forth.

And similarly regarding Israel, is there anything being factored in for the potential for continued coal to gas switching? And again just with respect to kind of the full year and updated Q3 guidance numbers here?

Gary W. Willingham - Executive Vice President-Operations

Yeah. I mean I'd say both of those we've baked in some of what we're seeing. But given the early days on both of those, we've probably been a bit conservative in the guidance.

Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

Thanks for the detail.

Operator

David Beard with Coker & Palmer has the next question.

David Earl Beard - Coker & Palmer, Inc.

Good morning, gentlemen. Thanks for squeezing me in here. My question is a little bit macro-related in trying to better understand how you circle in on your budget for next year. And maybe even specifically if you look at strip, would you plan on spending at cash flow or above or below? How should we think about your process there? Thank you.

David L. Stover - Chairman, President & Chief Executive Officer

Well I think as I mentioned earlier, we're working through that process now. And obviously you're seeing a lot of volatility on the pricing still, when you see even 2017 outlook for prices continue to change.

But we'll – the benefit we have is we've generated excess cash this year. And as we look at that, and as we look to next year, we'll look at our cash flow projection and what other opportunities we have to support cash flow next year on various things.

So we'll look at the whole picture of things in setting the budget. And focus our capital activity on what we need to do to support the Leviathan development, based on wherever it is. And most of the rest of it will start with our onshore activity and how we allocate between the different plays, based on the things we've talked about this morning.

David Earl Beard - Coker & Palmer, Inc.

Okay. Thank you. Appreciate it.

Operator

And next we'll move to Gail Nicholson with KLR Group.

Gail Nicholson - KLR Group LLC

Good morning. In the presentation here you talked about how the larger, the bigger jobs in the DJ lead to longer cycle times and clean-up periods. So I was wondering if can you quantify that versus the old standard completion, versus the new enhanced completion?

Gary W. Willingham - Executive Vice President-Operations

It all depends, Gail, on how long the laterals are and how many wells there are on the pad. So it's hard to give you kind of an average number. What I will say is it did push some completions from 2Q into 3Q. We're addressing some of that by bringing a third frac crew out to help bring some more wells on before we get to year end.

But it's going to vary quite a bit based on how long the laterals are and how many wells that are on a pad. And it goes to really more how many stages or what the cluster spacing is, the stage spacing is on the wells probably even more than the sand concentration.

Gail Nicholson - KLR Group LLC

Okay, great. And then you also mentioned as you progress through the year a potential debt reduction as you get towards year end. When you look at that debt reduction, is there an internal target of absolute? Or is it more kind of a level of net debt to EBITDA that you'd like to be at? And then is there any thoughts about taking the cash that was generated and returning it back to shareholders in a potential increase in the dividend?

David L. Stover - Chairman, President & Chief Executive Officer

Well I think when you look at the debt piece, we look at a number of different factors. And we haven't set a specific number. The nice part about that is with how we've continued to build liquidity somewhat this year, it doesn't become an either/or discussion from debt versus investment in the business.

I think we'll have the ability to pay down some debt by the end of the year. And at the same time not reduce our capacity and maintain our capacity to be opportunistic, whether for accelerating opportunities in the portfolio as the environment dictates or other new opportunities. So the nice part about it is we've maintained the capacity to look at all those spectrums.

Gail Nicholson - KLR Group LLC

Great. Thank you so much.

Operator

We have time for one more question. That will come from Jon Wolff with Jefferies.

Jonathan D. Wolff - Jefferies LLC

Morning, guys.

David L. Stover - Chairman, President & Chief Executive Officer

Morning, Jon.

Jonathan D. Wolff - Jefferies LLC

A question around Delaware. The area you're in is obviously sizzling hot. I guess you're moving kind of as fast as you can practically. But do you spend a lot of time thinking about the potential for missed opportunities around acreage grab, given the level of activity there? And if – understanding that the DJ is better now, is there a way to go faster in the Delaware? Is that even a choice? Or is it constrained by something?

David L. Stover - Chairman, President & Chief Executive Officer

Well I think we've been following the plan we laid out for the year. As we continue to learn, we'll continue to adjust, especially as we're looking into next year.

But as Gary said, the performance has been better than we would have even expected. And the nice part about it is, it's been across the spectrum of the acreage.

I think when you look at other opportunities, yeah, we're looking at the other opportunities. If the right opportunity for the right price comes around, we'll move on it. But in the meantime we've got 1,200 locations on our position that we're focused on now.

And to your point, to the extent and how we manage that and how we set up that program is important. As Gary mentioned, we've kind of modeled this a little bit after some of the DJ portion, where we can use an IDP concept. We put the facilities in. And we make sure we're optimizing the value, not just the value for this year, but the value for the whole play.

Jonathan D. Wolff - Jefferies LLC

Great, I guess to add onto that, do you feel like you're at any disadvantage in terms of knowledge? Are you capable of bidding on adjacent acreage? Do you have the knowledge base as yet?

David L. Stover - Chairman, President & Chief Executive Officer

I'd say we're definitely not at any disadvantage. I think from what I've seen and our ability to execute and our ability to take advantage of the learnings and take advantage of the learnings quick, we're in a great position.

Jonathan D. Wolff - Jefferies LLC

That's helpful. Last one, Gulf of Mexico, Dantzler, Big Bend, update on how they're performing? And then Gunflint seemed to have come on about exactly where you thought – the timing you thought it would. And then obviously fields do decline, so any exploration plans?

David L. Stover - Chairman, President & Chief Executive Officer

I think on the three projects, to your point, we brought on three major projects over the last year on time. Performance has been as expected or better and on cost. So again that's a testament to our major project execution that's shown up here very visibly in the Gulf of Mexico over the last year.

I think, no. As we look forward here, I would expect some decline now that we've had Dantzler and Big Bend on for about a year. That's in line with what we've said originally. Gunflint, we'll see to what extent it ramps up after we get it ramped up. And as I mentioned before, we've built in some downtime expectations from some of that onshore facility coming back online or some of its downtime and some storm downtime here near term. So everything is performing as expected out there. At least as well as expected.

Jonathan D. Wolff - Jefferies LLC

Great. Okay. Thanks, Dave.

Operator

And this concludes our question-and-answer session. I'd like to turn the call back over to Brad Whitmarsh for any closing remarks.

Brad Whitmarsh - Director-Investor Relations

Yeah, thanks all for joining us today on the call, as well as your interest in Noble. Now Megan [Repine] and I are available for calls all day today. Appreciate your time.

Operator

And that concludes today's conference. Thank you for your participation. You may now disconnect.

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!