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Noble Energy (NYSE:NBL)

Q3 2013 Earnings Call

October 24, 2013 10:00 am ET

Executives

David R. Larson - Vice President of Investor Relations

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

David L. Stover - President and Chief Operating Officer

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

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

Evan Calio - Morgan Stanley, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

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

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

David Heikkinen

Peter Kissel - Howard Weil Incorporated, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Joseph Patrick Magner - Macquarie Research

Rehan Rashid - FBR Capital Markets & Co., Research Division

Phillips Johnston - Capital One Securities, Inc., Research Division

Operator

Good morning. Welcome to Noble Energy's Third Quarter 2013 Earnings Call. I would now like to turn the call over to Mr. David Larson, Vice President of Investor Relations. Please go ahead, sir.

David R. Larson

Thank you very much. Good morning, everyone. Welcome to Noble Energy's Third Quarter 2013 Earnings Call and Webcast. On the call today, we have Chuck Davidson, Chairman, CEO; Dave Stover, President, COO; and Ken Fisher, CFO.

This morning, we issued our third quarter earnings release, and hopefully, all of you have had a chance to review our results. A few supplemental slides for the call were also posted on our website. If you have not downloaded them already, you will want to do so as they will be good reference material for the discussion today. Later today, we expect to be filing our 10-Q with the SEC, and it will also be available on our website.

The agenda for today will begin with Chuck discussing our very strong third quarter results and providing an update -- updated view of the remainder of the year, including a number of significant exploration activities. Dave will then give a detailed overview of all of our 5 core operational programs and near-term plans. We'll leave time for Q&A at the end and plan to wrap up the call in less than an hour. [Operator Instructions]

I want to remind everyone that this webcast and conference call contains 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.

As a reminder, we will be hosting our 2013 analyst conference on December 17 here in Houston. This is going to be an opportunity for us to provide a deep dive into our core assets and our new venture exploration opportunities. We will have a number of our management team reviewing their thoughts and plans for creating differential, long-term value to our many stakeholders.

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

Charles D. Davidson

Thank you, David. Good morning, everyone, and thanks for joining us today. Before getting into our third quarter results, I thought I would step back and put things into a bit of a broader context. Some of these themes you'll hear more about at our upcoming analyst meeting that David just mentioned.

But first is that we're not where we are today by accident. We arrived here through a unique strategy, as well as unique execution. We have established ourselves as a diversified company excelling in 2 lines of business, the first being in onshore unconventional developments and the second in offshore exploration.

I believe we're positioned extremely well today in the onshore U.S. business with core positions in premier oil and natural gas plays, which are delivering huge and valuable growth for our company. You can see that growth delivery on Slide 4, which illustrates that in under 2 years' time, our horizontal production in the DJ and Marcellus has grown by over 60,000 barrels of oil equivalent per day.

In the offshore exploration business, we've also had tremendous success with multiple major discoveries now online and the next set of projects being sanctioned. These significant resources, including 35 trillion cubic feet in the Eastern Mediterranean, nearly 1 billion barrels equivalent in West Africa and, now, 2 more major projects in the deepwater Gulf of Mexico, are normally found in much larger companies. In addition, we have a lot of material exploration in front of us, which is providing huge running room for future growth.

This portfolio, coupled with our ability to execute, results in very unique growth for a company of our size. This growth is not a 2013 event alone, but, rather, a sustained, multiyear profile. So Noble today is a large company, growing value very rapidly. This is highlighted by our delivery of record volumes and record discretionary cash flow in the third quarter.

I want to stop for a moment and touch on the recent and devastating Colorado floods that affected many communities in and around our areas of operation there. We remain steadfast and completely committed to helping affected communities in Colorado recover. For us, this is an opportunity to live out our corporate purpose of energizing the world and bettering people's lives. And so we're doing exactly that, partnering with a number of support agencies across Northern Colorado and devoting significant human resources to help in the process.

Our teams did an amazing job in preparation response with safety always our highest priority. I think it's a tremendous accomplishment that we had 0 safety incidents related to the flood. And I want to thank our employees, not only for their work at a very challenging time for own business, but also for their outstanding community support shown to their neighbors.

Focusing in on our third quarter, we experienced great quarterly results. On Slide 5, you can see that our sales volumes were up 13% from the second quarter of this year. Discretionary cash flow was up 29%, and adjusted earnings per share of $0.97 a share was up 40%.

We had record sales volumes of 293,000 barrels of oil equivalent per day, with high quarterly marks set in 4 of our 5 core operating areas. This was a 26% increase versus the third quarter of last year after adjusting for the sales of certain noncore onshore U.S. assets.

Crude oil sales volumes were up 14% from the second quarter this year with significant contributions coming from the DJ Basin, the Alen project, as well as strong oil liftings at Alba. Our natural gas volumes were also up double digit on a percentage basis, driven by activity in the Marcellus, DJ and Israel.

Revenues were $1.4 billion for the quarter, up 21% from the second quarter this year, with 80% coming from liquid products. Discretionary cash flow from continuing operations was at a record of $984 million, and we ended the quarter with $940 million in cash, total liquidity over $4 billion and net debt-to-book-cap ratio of 29%.

The majority of our costs were in line with our expectations, including lease operating expense and DD&A. Continued success through the drill bit at Troubadour, the Cyprus A-2 appraisal well and our Diega appraisal in West Africa resulted in no dry hole expense for the quarter.

Our interest expense, shown on the income statement, increased this quarter due to the completion of Tamar and the early start of Alen. This lowered the portion of interest that we capitalized. Our effective tax rate for the quarter was a bit higher than our annual guidance range, largely due to a change in the Israel corporate tax rate, as well as adjustments related to our annual tax provision.

Before handing the call over to Dave, I wanted to provide some recent highlights and things to look forward to between now and the end of the year. I mentioned major projects earlier, and most people typically associate major projects with our offshore business only. However, we're also taking a major project approach to our onshore and conventional developments. We believe this is where we can drive differential value for our company.

Now this is all about our Integrated Development Plan, or IDP approach, which is being implemented in the DJ Basin. We have recently completed our first central processing facility startup at the Wells Ranch IDP and have a number of other IDPs identified for the DJ Basin. This strategy ties in very well with our recently completed acreage exchange, which will ultimately allow for a more focused and contiguous development in this leading oil play.

We believe that achieving significant scale will ultimately be a very competitive advantage in onshore resource plays. Small players with more scattered acreage positions may still be able to drill good wells, but, in our opinion, will lose long-term competitiveness through higher infrastructure and operating costs. That is why we see the trade with Anadarko as so positive for both of us.

We're applying this major project approach to our Marcellus acreage as well, beginning with our large position in the wet gas Majorsville area. And later this year, we should have our first pads online from the new areas in West Virginia and Southwest Pennsylvania, which will further delineate our large Marcellus position. Combined, between the DJ and the Marcellus, we'll have a deep inventory of high returns, lower risk unconventional opportunities representing years of drilling with a lot of value to create.

We continue to streamline our portfolio and reached an agreement to sell our San Juan assets in New Mexico for gross proceeds of approximately $65 million. Our portfolio optimization remains an important part of our strategy, and we're continuing to pursue the sale of our remaining noncore properties. In total, we have generated about $1.4 billion in gross proceeds from the sale of noncore assets since the beginning of 2012.

In our offshore business, we've now approved the sanctions of 2 deepwater Gulf of Mexico major projects: Gunflint; as well as the first phase of development at Big Bend, which is part of the Rio Grande complex. Two great projects, both showing really high value per barrel. Both are subsea tiebacks that could come online in an accelerated timeframe.

In West Africa, we continue to ramp up the Alen project. We're close to completing, commissioning and processing of the reinjection -- excuse me, we're close to completing the commissioning of processing and reinjection facilities. We're also making progress on the next liquids developments in EG at Diega with a flow test that's currently underway.

Moving to the Eastern Med, we couldn't be more pleased with operations at Tamar and how the field continues to perform. Beyond Tamar, which is primarily dedicated to the Israeli domestic market, we continue to work predevelopment on many fronts on the 18 Tcf Leviathan field.

We experienced a true breakthrough this past year -- excuse me, we experienced a true breakthrough this past week with the Israeli high court ruling in favor of the government, thus solidifying the natural gas export policy issued earlier this year. We can now move forward in a number of areas related to Leviathan. Leviathan is almost certainly going to be composed of multiple major project phases initially supporting the Israeli domestic gas market, which is expected to continue to grow.

In addition, we continue to have multiple discussions related to the development of regional gas exports to nearby countries, for both near-term interruptible supply, as well as long-term baseload opportunities. We anticipate having an LNG project as well, which could take many forms. The options being studied include stand-alone LNG in Israel, either onshore or floating offshore, as well as a possibility of a combined project with our large Cyprus discovery.

We don't want to forget, our portfolio also includes new high-impact exploration potential. We're in the midst of a number of important exploration test with our first wells currently drilling in Nevada, in Nicaragua and a large Dantzler prospect drilling in the Gulf of Mexico as well.

Off the coast of Nicaragua, the Paraiso prospect has been drilling for several weeks now, and we anticipate results by the end of November. The prospect ranges in size from 200 to more than 1 billion barrels of oil equivalent. We have recently completed an additional farmout of interest during the quarter, bringing our working interest down to 70% from the well with our paying interest substantially below that. Results from the first well will help to define the potential of additional oil prospects we've identified on our nearly 2 million-acre position.

Offshore Israel, we've moved our drilling rig to the Tamar southwest prospect, which is a standalone structure, with gross on those resource range of 500 billion to 900 billion cubic feet of natural gas.

Back in the U.S, as I mentioned earlier, we advanced our drilling currently in the Gulf of Mexico and are drilling our first well in the Wilson oil prospect in Elko County, Nevada. With several results expected in the next couple of months, I would hope we will have a very nice exploration story to talk about in December.

And we continue to move forward on a number of other opportunities for future drilling as well. We've recently completed 3-D seismic over the majority of Block 12 offshore Cyprus, and we're preparing for additional 3-D acquisition offshore the Falklands and Nicaragua as well, not to mention our ongoing deepwater Gulf program in the deep Levant opportunity.

As I mentioned earlier, the results we're realizing are not by accident or not just simply a result of the environment we're in. We've been very deliberate in our strategy, how we have optimized the portfolio and how we execute. Our teams are already busy preparing for the analyst conference in December, which will show, I believe, a very bright future for Noble Energy.

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

David L. Stover

Thanks, Chuck. As you highlighted, our onshore U.S. unconventional programs are delivering

[Technical Difficulty]

Charles D. Davidson

Welcome back. Sorry for the interruption. It looked like there was a technical difficulty there. I was just finishing up on my comments, and I believe where we lost it where I was turning it over to Dave. So Dave is going to start again at the beginning of his section.

David L. Stover

Okay, Chuck. Let me pick up where we left off there. As Chuck highlighted, our onshore U.S. unconventional programs are delivering substantial growth and value for our company. In the third quarter, our core positions in the DJ Basin and Marcellus contributed, on average, 125,000 barrels equivalent per day, an increase of 16% in just one quarter's time frame and over 35% from the equivalent period a year ago.

Our third quarter in the Marcellus continued to show the momentum we're building in the play. Production averaged nearly 170 million cubic feet equivalent per day, up 50% from the second quarter as a result of new pads and wells brought on production. In the wet gas area, as seen on Slide 9, the SHL 8 and WFN-1 pads commenced flowback during the third quarter, bringing 18 new wells online and production of over 90 million cubic feet equivalent per day gross. We've increased our operated rig count in the wet gas area to 5 with 2 rigs drilling in Majorsville and one rig in each of Pennsboro, Oxford and Moundsville delineating new areas. Combined with our partners activity on the dry gas side, we remain on target to drill approximately 120 wells in the Marcellus this year.

Capital efficiency continues to be a major area of focus, including the drilling of longer laterals, optimizing our completion designs and utilizing consolidated gathering and processing facilities. Slide 10 highlights the continued transition to longer laterals with our 2013 average, thus far, at approximately 7,000 feet versus 2012's average of 4,600 feet. This is resulting in lower cost per lateral foot drilled down approximately 15% this year. In fact, we've recently drilled some of the longest laterals in the Marcellus to date with 5 greater than 10,000 feet. Initial production from these 5 is anticipated late this year.

We're also continuing to optimize a number of wells per pad with all of our pads drilled to date including between 4 and 11 wells. Performance of our wells remains in line with or above our 5.6 billion cubic foot equivalent type curve, standardized for a 5,000-foot lateral. Late in the second quarter, we brought online the WEB 4 pad in West Virginia, which includes 11 wells on production with an average lateral length of 5,700 feet. These continue to perform consistent with type curves and show a recent flattening of decline, which suggests a potential for higher ultimate recoveries.

On the dry gas side, our partner CONSOL is drilling and completing some outstanding wells in Southwestern Pennsylvania and Northern West Virginia. Of recent note is the Nineveh 38 pad. These wells were completed with shorter-stage spacing of 150 feet between stages versus typical 300-foot spacing, resulting in elevated production rates. In fact, one well, the 38C with a lateral of 7,200 feet, IP-ed at 19 million cubic feet per day. In addition, late in the second quarter, CONSOL brought on the first joint venture Upper Devonian well, which was drilled in the Burkett Shale. Production started at 3 million a day with essentially no decline in the first 3 months of production.

Strong pipeline and market access to exit the basin, we have not seen the large differentials that have impacted operators in the northeastern part of the play. Factoring in our growth realized to date and the outlook based on drilling and completion activities, I feel very confident that we will exceed our prior projection of exiting 2013 with net production of 210 million cubic feet equivalent per day.

In our other core onshore asset, the DJ Basin, our production averaged over 97,000 barrels of oil equivalent per day for the third quarter. In just 1 year's time, we have increased our total production by 23,000 barrels of oil equivalent per day with 70% of the growth coming from oil.

On Slide 12, we have included an updated map reflecting the recently announced acreage exchange executed with Anadarko. You can see from the pre- and post-map that the exchange has resulted in much more contiguous acreage positions for both companies, with Noble receiving approximately 50,000 acres in the north and eastern areas of greater Wattenberg. We expect to realize significant efficiency improvements from the trade with benefits coming from centralized field facilities, streamlined operations and reduced sand work. The large contiguous acreage blocks will also provide the opportunity to accelerate and optimize drilling activities and add more extended-reach lateral wells to the program. Even with the 8,000 barrel equivalent per day impact of production near term, we expect our DJ Basin production to grow by at least 20% next year.

During the third quarter, we spud over 90 operated horizontal wells in the DJ and remain on target to drill close to 300 wells for the full year, representing nearly 1.5 million lateral feet drilled in the Niobrara and Codell formations. As a result of some logistics challenges in the basin following third quarters floods, we estimate that we'll exit the year with a number of drilled locations which have not yet been completed. This represents a near-term timing delay in bringing this production online, and we plan to be fully caught up on the backlog in the first quarter of 2014. Fourth quarter incremental operating costs associated with the flood repairs are estimated to be between $6 million and $8 million.

In support of our aggressive long-term growth for the basin, we're in the midst of seeing a number of significant infrastructure projects come online, expanding capacity on both the natural gas and crude oil side. Our partner for natural gas processing has recently started up the O'Connor facility, previously known as LaSalle. This plant is ramping toward initial capacity of 110 million cubic feet per day and will be expanding to 160 million a day early next year.

On the oil side, the Wattenberg trunkline, delivering crude from the northern part of the basin to our Platteville facility with access to the White Cliffs pipeline began line sale in early October. Property -- progress on the White Cliffs expansion is moving forward for completion in the second quarter of next year. Delivery to the Plains' rail facility is anticipated to commence in the next month or so. Combined, the White Cliff's expansion and Plains' rail project are increasing oil transport out of the basin by approximately 150,000 barrels of oil per day.

Standard- and extended-reach laterals throughout the basin continue to perform well. We have highlighted on Slide 13 the standard-reach laterals that have been brought to production in 2013 in our Wells Ranch and East Pony areas. The green line represents the 2013 wells, the blue is 2011 and 2012, and the dash line is the equivalent type curve. The 2013 wells continued to be consistent or better despite having averaged 20% tighter spacing. Same is true for extended-reach laterals program, where we continue to see ultimate recoveries in excess of the 750,000 barrel equivalent type curve. This continues to highlight the quality of our inventory.

The startup of our own Wells Ranch Central Processing Facility in the third quarter is a significant milestone for Noble Energy. Slide 14 shows these facilities, including oil, gas and water processing, as well as recycled water storage. This central facility is currently capable of processing 22,000 barrels of oil per day and 50 million cubic feet of gas per day with plans to double capacity by mid next year.

In Northern Colorado, our next Integrated Development Plan is the East Pony area, where we continue to see very positive drilling results. Earlier this year, we performed a 40-acre downspacing test in this area, drilling 8 standard-length laterals and a half section. Included in the 8 are 5 wells in the Niobrara B zone, one in the A and 2 in the C bench. Results have been very encouraging, and while early, the wells are performing at or above our type curve. In addition, we have just recently commenced production on our first long lateral in East Pony with a lateral length of approximately 9,000 feet. The well has been on production for 2 months and is currently producing 800 barrels of oil equivalent per day with 80% oil.

Shifting offshore to the deepwater Gulf of Mexico. Production during the quarter was 19,000 barrels a day equivalent, 90% was crude oil and natural gas liquids. Of specific note during the quarter, Ticonderoga #4 well was successfully completed and commenced production in late September. At full rate, it is anticipated to add over 3,500 barrels of oil per day net to our production.

Chuck mentioned our recent sanctions of both Gunflint and the initial phase at Rio Grande, which provides the next leg of production growth to our deepwater Gulf business. Rio Grande will initially be a one-well tieback of our Big Bend discovery with first production estimated in late 2015. Gunflint is planned as a 2-well tieback to come online in the middle of 2016. Combined, our initial net production from these 2 fields is estimated to be 20,000 barrels of oil equivalent per day.

Moving to our International businesses. In West Africa, the Aseng oil field continues to perform very well, having averaged approximately 47,000 barrels of oil per day gross in the third quarter with expected decline. At Alen, our production ramp has taken somewhat longer than anticipated as commissioning of the processing and compression facilities has been extended as we worked to operate both of our large gas compression trains in parallel. This should provide for a full test of facility capacity within the next month.

I've been very pleased with the integration of production, storage and offloading, utilizing the Aseng FPSO. Alen will be a significant contributor for 2014 liquids growth for Noble.

During the third quarter, we successfully drilled an appraisal at the Diega oil field. The I-8 appraisal well came in better than expected, encountering 39 feet of vertical pay and good reservoir consistency along our nearly 1,400-foot lateral. Reservoir quality is very good, and we're currently performing a nearly month-long flow test to assist in ultimate determination of reservoir size. Diega represents the next liquids development for us in West Africa and is likely a subsea tieback to existing infrastructure at Aseng.

In the Eastern Mediterranean, Tamar continues its outstanding performance as we set a record quarterly sales volume of 255 million cubic feet net per day for the third quarter, equivalent to around a gross volume of 775 million cubic feet per day. As we mentioned in our last call, the early part of the third quarter was relatively mild summer period and September was impacted by a number of holidays. Despite these effects, we did have some periods of very high demand during the quarter with a single day max of over 915 million cubic feet gross and certain intra-day peak load periods where the field averaged over 1 billion cubic feet per day. We continue to make significant progress on our compression project at the Ashdod onshore receiving terminal, which is designed to increase capacity and deliverability into the growing Israel domestic market.

Slide 16 is a walk-through from our third quarter to our anticipated fourth quarter volumes. On the far left bar, we've adjusted the third quarter volume for the production associated with the DJ Basin acreage exchange, as well as the sale of our San Juan assets. This accounts for about 10,000 barrels equivalent per day difference from the third quarter to our anticipated fourth quarter volumes. On this slide, you can see our significant underlying onshore unconventional growth, representing a combined DJ Basin and Marcellus 10% quarter-on-quarter increase and also higher volumes in the Deepwater Gulf as well. Natural gas demand in Israel is normally lighter in the fourth quarter than the third, and sales volumes in EG, that's Equatorial Guinea, are expected to be less than production as a result of the timing of liftings. We've also shown the impact of storms in the DJ Basin and Gulf of Mexico properties for the fourth quarter.

Our updated sales volume range for the fourth quarter is 280,000 to 285,000 barrels equivalent per day, and we expect to exit 2013 with production volumes in the range of 300,000 barrels equivalent per day. As a reminder, the portfolio adjustments we have made this year, including the DJ acreage exchange, as well as the sale of noncore properties through the year, represents approximately 4,000 barrels equivalent per day on an annualized basis.

In closing, there's certainly a lot to review and discuss in December at the analyst conference. This will include our updated thinking on accelerating our growth plans in the DJ Basin and Marcellus and how we're implementing our Integrated Development Plan approach. We'll also focus on our offshore core businesses and how we have uniquely created substantial value in the Deepwater Gulf of Mexico, West Africa and Eastern Mediterranean. In each of these positions, there's a platform from which to grow even further.

I'm also excited about our global exploration portfolio, which includes significant running room opportunities in many of our core businesses, material upside and multiple new venture projects, which have the potential to become new core areas for Noble. We look forward to the opportunity to share more about how we continue to build and unlock value as we discuss our business in greater depth in December.

With that, we'd now like to open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Doug Leggate from Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Dave, I'm guessing some of these questions will be addressed in December, but I'm going to try one and one follow-up, if I may. You mentioned that you're quite pleased as -- I guess, you're encouraged by what you see on the different bench drill tests in the Wattenberg. But I just wanted to get some clarification, are you assuming the same type curve for the primary zone as you are for the different benches? And that's my first question, and I have a follow-up on activity, please.

David L. Stover

Yes. The answer to the first one is pretty easy. Doug, yes, we are. We're basing everything off the same type curve, again, tied to different lateral lengths.

Charles D. Davidson

But as a reminder, we have multiple type curves throughout the field. So you can't go from one area to another and use the same type curve. It's a broad array of type curves.

David L. Stover

And as we've also talked about the benches, they have different impacts and contributions in different parts of the field. In other words, in some parts of field, we'll concentrate on an A and a B; in other parts, we'll concentrate on a B and a C, for example, based on their geology.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Got it, okay. So I'll look for clarification in December. My follow-up, I guess, is can you help us with what is the limiting factor for the activity level? I think you've talked about having 1 or 2 rigs over -- in last year's presentation. But is it actually a limiting factor or is -- are we likely to see you address the pace a little more aggressively as we come up on the Analyst Day?

David L. Stover

I'd say near term, it's getting these Integrated Development Plans in place and tying everything in from an overall facility structure and infrastructure, tying everything in together. I'd say in the long term, it's going to definitely accelerate the pace of activity when you look out over the next few years, and I think that's something that we'll talk even more about here in December. But what you're trying to tie in is everything from staying on schedule with your gas plants and staying a year or 2 in front on that, along with now these big central processing facilities, tying those in together and concentrating on the pace of development that you're looking at in each different area. What it's going to enable you to do as you pull these IDPs together is really get more efficient as we go down the road here. And so our anticipation is it will allow us to accelerate activity over time here.

Charles D. Davidson

I think also, Doug, we just have to keep reminding ourselves that while it -- we can change and pick up rigs with just a few months' notice that -- especially in gas processing facilities with the permitting and everything that goes along with it, those can be 2- and 3-year lead times. So we're working with our partner, our processing partner, to not only -- as we accelerate our activity to -- for them to also be accelerating theirs. But we have to take a longer-term approach when it gets to those big pieces of infrastructure.

Operator

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

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

Real quickly. Looking at CapEx on the quarter and relative to the slide you provided that showed 2Q as well, looks like it would be running ahead of kind of the guidance you gave back at your Analyst Day last December of $3.9 billion. How should we be thinking about that for next quarter? And generally, how should we be thinking about that CapEx looking forward?

Charles D. Davidson

Well, I think we're actually maybe closer to on track than what those numbers would show. And the key factor is that, as we noted with the acreage exchange with Anadarko, we're getting a refund of a little over $200 million of capital. That -- it will be cash. So this will -- that capital that we'll spend for those wells, it'll stay on the books. But really when you deduct that from our year-to-date capital, that puts us closer to about $3 billion year-to-date and with a run rate per quarter of about $1 billion. So the way we're looking at it, when we adjust for the refund that we got on the acreage exchange, we're at a run rate of about $4 billion, which is, I think, pretty close to on the money from our guidance of -- I think it was $3.9 billion.

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

Perfect, perfect. Well, I appreciate that clarification. And maybe switching over to the Niobraras, I think you're going to be sharing more on the -- excuse me, shifting over to the Marcellus, as I think you're going to be sharing more on the Niobrara at the Analyst Day. When you look at the growth that you're showing today and you project going forward now running 5 rigs in the wet gas area, any concerns with respect to the need to blend dry gas or be able to deliver that wet gas without experiencing any kind of ethane rejections due to the high BTU content?

David L. Stover

No, Dave. I mean, that's something we looked at pretty hard. And I'd say, at least for the next couple of years, we seem to be in pretty good shape there. We're -- one of the things, we're able to blend some gas that CONSOL has from some of their legacy piece, too. So I think when you look at it and you look at the pipes we're on and where we have our firm transportation and how that's all tied together, I think we're in good shape for the next couple of years, at least.

Operator

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

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

Yes. Just -- you just made an earlier comment about the possibility of joint LNG development with Israel and Cyprus. I was hoping you guys could expand upon that a little bit. Is that something you think that both governments are amenable to at this point in time, or is it still kind of in negotiation?

Charles D. Davidson

It's -- I think it is an open item for discussion right now. It's one that we have brought up, and certainly, the government of Cyprus has brought it up as well. There are benefits to both countries to interconnect their gas systems. Because we have to remind ourself gas can flow 2 different directions and so, in effect, you can end up with the discoveries in each country backing up each other in terms of their domestic needs. So there's some benefits on that, but it's by no means a decided path. As I mentioned, we're looking at several options as we go forward here, and that's one of them.

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

Okay, that's helpful. And I guess just jumping over to the Niobrara. Obviously, you guys have got some initial results there, kind of in the A to C in the Codell. In terms of how you guys think about it, I know it's probably early in the well results, but would you guys expect to see some interference between the traditional B zone or some of the other zones in terms of how you're thinking about it?

David L. Stover

We haven't seen it. I'd say, Leo, we -- at this point, we've not seen as we've gone down to 40-acre spacing and as we've gone to these different horizons. We just really haven't seen any production interference at this point.

Operator

And we'll take our next question from Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

I appreciate the update and good news earlier in the week from Israel. Just a question, if could you just provide any more color on the next steps or timing on the closing of the Woodside partnership and moving forward to development, and whether that -- the 40% export level is more reflective of the higher domestic demand? Or does that alter anyway that you think about -- a potential LNG project?

Charles D. Davidson

Well, I think on the latter part of the 40%, that was the adjusted policy that was issued by the cabinet and that's -- we believe that, that is supportive of all the export options that we're looking at there, which, as you know, include not only LNG, but also some regional gas sales also. So there's a lot that can be accommodated by that 40%. So I think we can certainly work within the framework, and certainly, the policy has some adjustments that allow you to move allocations between fields. And so when you go through that, it actually results in Leviathan being closer to 50% eligible for export. So that all fits with what we're planning. So as you pointed out, we received some very good news earlier in the week, and that's now allowing the parties to get back together to really see what our plans are next. I mean, this is not only the closing of the Woodside deal, which we're very eager to do, but also in moving forward with some of these projects. Again, there's a lot of work to be done. There's other government approvals that will be necessary in terms of how the fields are developed and where they will be delivered, how they will meet domestic gas needs. So we're -- we'll have to work through all those details with our partners and the government. But the big roadblock that we were facing, which was an export policy, was resolved for us earlier in the week.

Evan Calio - Morgan Stanley, Research Division

Great, great. And if I could, just to follow up on the DJ. And just to confirm the prior question, you were saying that you have not seen any communication, the 40-acre downspacing test in East Pony? Was that what you were referring to there? And then any color on the lower Niobrara liquid volumes in the quarter? I think it was 60% versus mid- to low-60s expected. Is there any -- I know there are a lot of moving parts in the quarter. Have you had any thoughts on how that might change the outlook or that was more of an anomaly?

David L. Stover

Yes. I'd say on the first part, whether you look at the 40-acre spacing in, say, Wells Ranch area or East Pony or any place we've tried it out there, we just haven't seen, with any extended production history here, any interference yet between -- so yes, very encouraged with all that. I'd say as far as the liquid volumes, there may have been some small impact from the flood piece and what was shut in for various pieces or whatever. But it shouldn't really have been a big difference one way or another.

Charles D. Davidson

We're not seeing any changes in trends in oil versus gas. This is -- with all the moving pieces we had in the quarter, I would view that as just...

David L. Stover

It can get influenced somewhat by where you're predominantly bringing wells on in each quarter. That's -- you remember, East Pony area is higher oil content than it is kind of in the Wells Ranch and so forth. So it's just the mix.

Operator

And we'll take our next question from Arun Jayaram from Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Dave, this one's for you. I know according to the '13 plan, you plan to do about 10 Codell wells and 80 Niobrara A and C wells. So I was wondering if you could maybe comment on how the Codell and A and C wells are comparing towards your B bench wells, which were the type curve in the 335 range.

David L. Stover

Yes. I mean, what we've seen -- I think the first couple of Codell -- and this one goes back to last year. We're kind of in areas that weren't quite as good as performance, but the ones we've seen this year that we've brought on have looked very strong relative to the type curves. I'd say the A and the C performance has been very similar to the B in the areas, especially where we're concentrating. As I mentioned, it varies as to what were concentrating on depending on where you are in the basin because the thickness of those 2 benches can vary somewhat. But we've been very encouraged by how well they've matched the B performance, if you will. Now we're just getting ready to bring on our first long lateral, Codell, I think, here shortly so we'll get some more long-lateral type performance on some other places. And then as I mentioned earlier, we've just started to bring on our first production on long lateral up in East Pony. So I'd say, going back to your original question or the AMC performance...

[Technical Difficulty]

Operator

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

[Technical Difficulty]

We'll continue with the Q&A session, and we'll go back to Charles Meade with Johnson Rice.

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

Let me just ask, I think, it'll be 2 questions. One, I'm sorry if we're torturing this a bit on the East Pony 40-acre spacing, but I just want to make sure I'm thinking about this right and have the right expectations for what we can learn. Is it right to think about that you're doing something close to 80-acre spacing in the B, and then you're doing kind of a sawtooth offset with the A and C? And if that's the case, are we really going to learn more about how the A and C zones perform there versus the B?

David L. Stover

Thanks. You're right on the aspect, Charles. It is somewhat of a sawtooth piece. So they're not completed right above each other, if you think about it. They are kind of offset a little bit. But I think we are learning a lot about the ability. I mean, you think about the ultimate development of these sections, and we initially talked about 16 wells per section when we were concentrating on one interval. I think what is, again, giving us information is that, eventually, we could easily have patterns out here that provide 32 wells per section, for example, where you're combining 2 intervals, 2 different layers in that type of sawtooth-type pattern, something similar to that.

Charles D. Davidson

I think this is -- and of course, everyone is interested in -- and we've gotten the question a number of times on just the fact that we're not seeing interference. And this will be something we will certainly be talking a lot more about in December because it's really -- the prize here is in how these wells are completed and their configuration across the patterns, and so that's the key to unlocking this.

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

Got it. As then as a follow up, if I look at your slide that you offered which was very helpful, Slide 16 on the walk up and the walk down on the quarter-over-quarter volumes. Just eyeballing it, it looks like that West Africa lifting aspects is -- it's roughly the same size as that DJ Basin bar on the right. So that's about 10,000 barrels a day, if I'm kind of estimating that correctly. And that strikes me as a little larger than the overlift that you had or twice as large as the overlift you had in 3Q. So I'm wondering, are you expecting to miss another lift at the end of the quarter, or is that perhaps also related to the slower ramp-up of the Alen processing.

David L. Stover

When you think about it, you've got to think about it from quarter-to-quarter. And if you were over 5 in third quarter and then you're under 5 in the fourth quarter, you got a 10 delta on quarter-on-quarter impact there.

Operator

And we'll go next to Irene Haas with Wunderlich Securities.

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

All right. Maybe 2 questions. Wattenberg, what's going on in the East Pony area now that you have core up your empire towards the north? Then secondarily, maybe a little color on Nicaragua. Have you drilled your second well yet? And that's all I have.

Charles D. Davidson

Well, I think, in terms of the -- you mentioned about coring up. The trade area was in the greater Wattenberg area, so it really didn't affect our East Pony acreage area. I mean, we're doing a lot of development in East Pony and things like that. I may have misinterpreted your question. But the trade was in the greater Wattenberg area, which is outside of East Pony. I think in terms of Nicaragua, what's happening there is we're just -- we're in the process of drilling the well, and we expect to have results by later in November.

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

You're drilling 1 or 2 wells?

David L. Stover

We're still drilling the first well.

Charles D. Davidson

I'm sorry. I thought...

David L. Stover

We don't -- we won't have to make a decision on whether we want to drill a second well or not until after we reach TD and have a chance to look at things.

Charles D. Davidson

Yes, I apologize. I was talking about Nicaragua, and you were talking about...

David L. Stover

Yes. So we're not far enough along to make a decision on a second well yet.

Operator

And we'll go next to David Heikkinen with Heikkinen Energy Advisors.

David Heikkinen

Every time you drop off the call, your stock goes up. So we probably ought to just keep doing it. Thinking about the swap with Anadarko, how does that add to extended-reach laterals kind of in the Wattenberg and kind of coring up the opportunity set? Is that something that you saw as a benefit? And how should we think about that as kind of that blocking up acreage and now your success with longer laterals?

David L. Stover

Well, what it does is that you're not having to have sections that are kind adjacent to each other, where you operate one section and they operate the other and then you're trying to figure out how you're going to set that up from a development pattern. Now if you have control of the contiguous sections, then you can set that up ahead of time and plan for that. Like we said, especially these longer laterals take much longer planning. And if you know you've got this set up, you can lay that out so that you're considering both sections together.

David Heikkinen

And so do you expect to drill more long laterals as a result of the swap?

David L. Stover

Absolutely.

Charles D. Davidson

One of the real benefits of this transaction.

Operator

And we'll go next to Peter Kissel with the Howard Weil.

Peter Kissel - Howard Weil Incorporated, Research Division

Initially, I had one on the oil targets you've identified next year in the Eastern Med. And in particular, I was wondering if you could compare and contrast those versus the recent Yam wells that were drilled by another company, targeting oil down by Mari-B. Any sort of differences in source, rock, depth, location? Anything like that would be helpful.

Charles D. Davidson

Well, I think, first of all, we weren't a party to the Yam wells, so all we've got is basically what you've got, which is the public information on it. We don't see the prospects as related, and I think that's kind of the most fundamental thing on it. And I think going beyond that, it's pretty hard to make any comparisons between what they were exploring for and what we would hope to explore for deep in the Mesozoic. So I think we're treating it as basically not being either a positive or a negative to what we're exploring for in the deeper Levant Basin.

Operator

And we'll go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Back to Wattenberg area. You seem to be on track for 32 wells per section over 2 intervals in the Wattenberg oil window, and it seems like, based on your comments, that may be where you're heading for East Pony as well. I guess, is what you're seeing in both these areas almost connect -- obviously, there are some geological features in between. But do you have now a more widespread view of the potential for this type of development between Wattenberg oil and East Pony? And how are you viewing the northern and northwest portions of your Northern Colorado acreage?

David L. Stover

Yes. I'll tell you, Brian -- just to back up on that. I said what we're testing is the potential for up to 30-some wells per section up in the northern part, in fact, you said, in the more oily part of the play, in northern part of Wattenberg and up into East Pony. So still early in the production phase of that, and we'll continue to get more information on that. But again, that's all about how do we increase the recovery out of this. When you go back to what we've talked about on 16 wells per section and you're still getting probably less than 10% of the hydrocarbon in place recovery on that. And we continue to get encouraged on just how much of a hydrocarbons there are, actually, in the interval. So I think we'll continue to test that, especially in the more oily parts of the play. As you talked about, we'll continue to test it with multiple benches here. But we're still thinking we have some running room here that we haven't fully tested. And we'll continue to expand that, and we'll talk more about that in December. I think as you look up into the north and northwest parts of the field, some of things that we haven't really tested that much yet. We haven't been in a rush to test some of that yet this year as we concentrated on kind of optimizing patterns and setting ourselves up for these Integrated Development Plans in what we call our development area. But as we continue to go, we'll continue to push out on some of that. Some of the encouragement we saw earlier this year in that Cummings area, where we did some longer laterals in an area that probably wasn't quite as productive on the normal laterals as we've seen in some of the areas we've been focusing on. That was real encouraging. And so what we'll be looking at as we move forward to test some of these areas to the north and northwest is do we want to do that with a little longer lateral program, at some point, than the normal lateral. But again, it's not a rush. It's not a hurry. We want to work with at the point that we can actually test them and actually produce them with -- in the infrastructure. We don't have lease timing hanging over our head. So we'll continue to do some of that, and we'll probably do some more of that next year that we highlight as we talk about our whole program for next year in December.

Brian Singer - Goldman Sachs Group Inc., Research Division

That's helpful. Shifting to the Marcellus. You mentioned, I think it was Slide 10, the rising lateral length. What's your target lateral length and variability we should expect around that? And when we think about the relationship between EUR and lateral length, is it 1:1, or is there some other ratio?

David L. Stover

Yes. I'd start with the latter part of that. I mean, right now, we're still assuming a 1:1 relationship, but we need to get some longer lateral wells online and see how that changes. I'd say, overall, we've seen it move from, on average, 5,000 or so that we're now -- we're probably up closer to 7,000-foot lateral length on ours. We've actually talked about a pad where we've drilled 4 or 5 wells of 10,000 foot. So it kind of varies by area. Again, that's somewhat driven by land position out there and how much room you have as far as contiguous acreage around you. So it'll depend by area. But I kind of -- our preference, as you've seen from what we've talked about, is moving to longer laterals in the Marcellus as we've implemented out in the DJ where we can.

Operator

And we'll go next to John Herrlin with Societe Generale.

John P. Herrlin - Societe Generale Cross Asset Research

Yes, Societe Generale. Anyway, getting to the DJ, you have a lot of resource potential. You're doing more localized Integrated Developments Plans or a CPFs. Have you thought about plateau volumes, or how big your really could get your output to grow on the liquid side to then maintain it? Have you been thinking bigger picture?

Charles D. Davidson

Well, I think we're not in the -- thinking about plateau volumes. What this is really all about is managing multiple major developments and being able to do it in a fashion that you can do it in parallel as you move forward. So that you -- as we keep talking about, these Integrated Development Plans, these planning areas, which there's now several of them identified through the field, it's really -- it's all about being efficient, not only being efficient in how we develop them and the capital we use, but also being efficient in how we can operate them going forward and manage all the pieces associated with it. So it's -- I mean, it's -- I think from our view, it's a very exciting step forward in our thinking on how to develop a large resource play, such as we have in the DJ Basin. And I think it will -- as we talked about it, it will provide a lot of advantage as we go forward. But it's all about being more efficient and being able to put in place the infrastructure that will allow us, ultimately, to continue to accelerate this program.

John P. Herrlin - Societe Generale Cross Asset Research

But, Chuck, do you think that the sizes that you're gearing for now are optimal or they could be larger in terms of the CPFs and your planning needs?

David L. Stover

Yes, John. That's the nice part about the way we're designing this is that their scalable, I guess, is the way I would put it. So with additional opportunity as we go, we'll be able to tie in and expand these facilities in segments.

Charles D. Davidson

Yes. Some have -- it's probably -- train is not the right word. But they're certainly built into their designs, a capability to, as Dave said, add additional critical facilities. When we look at Wells Ranch, we're already planning an expansion there.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. How much do the CFPs run about, just gross cost?

Charles D. Davidson

Somewhere around, oh, $35 million to $50 million. You're just talking about the basic facilities?

John P. Herrlin - Societe Generale Cross Asset Research

Yes, that's all.

Charles D. Davidson

Or maybe about -- yes. For about -- that would probably handle about 700 wells. Hang on...

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me on the DJ. What were the number of wells that were going to need to be completed in the first quarter? You broke up.

Charles D. Davidson

Okay, let me back up. First of all, I misspoke on the 700. It's more like, maybe 300 for a thing. And then you were -- you asked another question, John?

John P. Herrlin - Societe Generale Cross Asset Research

Yes. You said that you're going to have some wells that weren't going to be completed, that were drilled in the fourth quarter that would be completed in the first quarter. Approximately how many will there be in the DJ?

David L. Stover

Yes. I think what the flood did, it put us back about 20 wells on the completion activity side. And that's what we'll be catching up in the first quarter. We've already brought a third frac crew in to help with that. So we're well underway on getting -- moving forward when that catch up, if you will.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me is on Nevada. Will you have any information to discuss in December or is it still too early?

David L. Stover

If any, it'd probably be very small amount information. Our plan there still to drill 2 wells to get some actual infield information, if you will. And based on the expectation of the type of reservoir and type of play we're dealing with, this will just be some information that'll help us design how we want to test this play going forward. So until we really get into that test mode, there probably won't be a whole lot to report.

Operator

And we'll go next to Joe Magner with Macquarie.

Joseph Patrick Magner - Macquarie Research

Just a few others. In addition to the longer laterals and the tighter spacing that you're testing in the DJ, can you provide any initial details or insights into other completion designs enhancements that you're adopting?

David L. Stover

Yes. Over time, and if you look back, you've seen some of the performance improvement over the last couple of years. A lot of that has come from the optimization of, not just longer laterals, but even the tighter spacing of fracs, of stages, if you will. And so we're continuing to look at that and continuing to optimize fluid capability. I mean, that's very sensitive out here in the basin in our minds, so we keep a very close eye on that. What we had gotten to in the basin was kind of a 200-foot interval, as we had started at probably double that and got down to 200. We've tried some at a little less than that, and we'll probably continue to work on that and tweak that a little bit as to whether 200 is optimum or whether there might be something maybe a little lower or tighter spacing even stage. But that's just something we'll continue to work at.

Joseph Patrick Magner - Macquarie Research

Okay. And in the Marcellus, I realize you've got some firm transportation laid out, and you're not seeing any impact on being able to get volumes out of the basin. But what have you done to protect bases and how are you thinking about that issue going forward or other types of firms, sales agreements that would go alongside those firm transportation agreements you have lined up?

Charles D. Davidson

Well, I think we continue to a look at whether or not we should hedge bases, but we haven't seen the need to do that so far, again, because of where we are located in the play and the fact that we're not having to complete as much for that northeast market that has seen some larger differentials going forward. But also, there's -- we're certainly hopeful, there's been a couple of attempts of -- by the pipelines to add some additional capacity. And of course, there is a lot of capacity being built in the Marcellus, but more importantly, for areas that serve us. And I know that in the past, we have looked favorably on those, and we'll continue to look favorably on them if they're proposed in the future. But right now, we're not hedging any of that bases.

Joseph Patrick Magner - Macquarie Research

Okay. And just one last one, Paraiso sell down at 70% level. Is that something you're comfortable with, or should we anticipate additional farm-ins there?

Charles D. Davidson

I think right now we're pretty comfortable with -- given the transactions we've entered into. And the fact that the well is drilling, I think it's -- we're all really now just want to get the well completed and see the results and carry forward. So that's what we're comfortable with.

Operator

And we'll go next to Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Just on Nevada. The path forward, so the initial program, is that just kind of vertical wells? And if so, when should we think about horizontals?

David L. Stover

Yes. That -- we're drilling -- we will drill 2 back-to-back vertical wells here. We're on the first well now, but we should finish those by the end of the year. And then we'll step back and look at -- actually the rig will go back to the DJ Basin is the most likely plan, while we take a short timeout to digest what we learned there and then decide how we want to go forward on a testing program. Do we want to come back and drill horizontal wells, concentrating on a particular interval based on what we see? Do we want to do something and actually test something, try to complete something on a vertical basis? And all depends on what we learned from these initial 2 vertical wells, but I would say we would be back in there -- with some infringement here, we'd be back in there by mid-year next year or so.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Okay, okay. On deepwater, real quick. Dantzler, fine. Beyond Dantzler, are there -- kind of how should we think about kind of relatively higher impact inventory that you might have that you could test sometime next year?

David L. Stover

Yes. I would think after Dantzler, we'd probably have at least a couple similar type-sized opportunities that we'd be moving to next year. But I think it'll be a real interesting, exciting program in the Gulf here for the next -- well, through next year, from what we see. Between these wells that -- the exploration program that now probably has, actually, a little more size to it on the next couple of wells and then the development activity that's going to be going on.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Okay. And Dantzler, if it's a success, is there kind of close by capacity to kind of process, produce?

David L. Stover

I'm sorry, I missed the question.

Rehan Rashid - FBR Capital Markets & Co., Research Division

So how would you develop Dantzler?

David L. Stover

Depending on the size, it has the potential size that it could be its own host, if you would. The nice thing, it's also in a neighborhood where you could tie back to a number of other potential opportunities. So it could go either way, depending on the size and it has the size potential to put it in either category.

Operator

And we'll take our final question from Phillips Johnston with Capital One Securities.

Phillips Johnston - Capital One Securities, Inc., Research Division

Just wanted to follow up on Brian's question. Wondering what current AFEs are running for your 7,000-foot lateral wells in the Marcellus? And I also wanted to ask just how AFEs are trending in your standard lateral wells in the Wattenberg as well?

David L. Stover

I think what we're looking at for 7,000-foot laterals in the Marcellus, when you consider pads, facilities, drilling and completion, not everybody reports those the same. But when you include all 3 phases of that, for us, it's about $8 million per well in the Marcellus for a 7,000 footer. I think in the DJ, on our typical 4,000 to 4,500 footer, you're in that $4.3 million to $4.7 million range.

Phillips Johnston - Capital One Securities, Inc., Research Division

Okay. And it sounds like this would be the last question on the East Pony 40-acre pilot. Just wondering what type of production history you guys are going to need on those 8 wells before we have any sort of conclusive results.

David L. Stover

Well, we've gotten a pretty good base over the first few months here. It's always nice to get out 6 months or so and see how things look. But -- and then get -- start to see some other pilot areas produce and compare results. I'd say we're -- we'll have an update in December on kind of all the activity and what we've seen. But whether you look at the pilot results in East Pony, whether you look at the continued results in Wells Ranch or even the extended laterals, we've been extremely encouraged with what we're seeing. And when you throw in the different performance from the different benches, it's -- we haven't seen anything to discourage us at this point. I'd say East Pony, in particular, will be -- we're looking through right now the programs for next year, and we'll talk more about that in December.

Operator

And this does conclude the question-and-answer portion for today's conference. I'd like to turn the conference back over to our speakers for any additional or closing remarks.

David R. Larson

Yes. Well, I appreciate everybody's interest in Noble Energy and really want to thank you guys for hanging in there with some of the technical difficulties that we had today. Have a good day.

Operator

Thank you. This does conclude today's conference. We appreciate your participation.

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