Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

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

Evan Calio - Morgan Stanley, Research Division

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

John Malone - Global Hunter Securities, LLC, Research Division

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

Dan McSpirit - BMO Capital Markets U.S.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Noble Energy (NBL) Q4 2012 Earnings Call February 7, 2013 10:00 AM ET

Operator

Good morning. Welcome to Noble Energy's Fourth Quarter 2012 Earnings Call. I would now like to turn the call over to Mr. David Larson. Please go ahead.

David R. Larson

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

Earlier this morning, we issued our earnings release for the fourth quarter and hopefully, you all have had a chance to review our results. A few supplemental slides were also posted on our website. You'll want to download the slides, if you have not already done so, as we will be referencing them in today's discussion. Later today, we expect to be filing our 10-K with the SEC, and it will also be available on our website.

The agenda for today will begin with Chuck discussing the final quarter of 2012 and make some comments on '13. Dave will then give you a detailed overview of our operations programs, including a summary of our 2012 reserves and a breakdown of our activity levels for the upcoming year. We'll leave time for Q&A at the end and plan to wrap up the call in less than an hour. We would ask that participants limit themselves to one primary question and one follow-up. Should you have questions that we don't get to this morning, please don't hesitate to call, and we'll do our best to answer them.

I want to remind everyone that this webcast and conference call does contain projections and forward-looking statements based on our current views and most reasonable expectations. We provide no assurances on these statements as a number of factors and uncertainties could cause actual results in future periods to differ materially from what we discuss here. You should read our full disclosures on forward-looking statements in our latest news releases and SEC filings for a discussion of the risk factors that influence our business.

We'll reference certain non-GAAP financial measures such as adjusted net income or discretionary cash flow in the call today. When we refer to these items, it's because we believe they are good metrics to use in evaluating our performance. Be sure to see the reconciliations in our earnings release tables.

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

Charles D. Davidson

Thanks, David. Good morning, everyone. We appreciate you joining us today. I'm going to start out with a quick review of 2012, including the fourth quarter results and make some comments on our plans for 2013 and how I see things shaping up. Dave is going to finish with a walk-through of our global operations.

We completed a great quarter, and we're really excited about 2013. Some of you listening to this call attended our analyst conference back in December, where we presented a comprehensive review of our business and our growth expectations going over the next 5 years. The presentation material and the webcast recordings of the conference were made available on our website for those who want to review it.

We also released at that time our 2013 capital program outlining our spending and guidance for the year. I believe we presented a very exciting future for our company, a future that includes very strong value-creating growth.

The story of our future really starts with the great accomplishments we had in 2012. And as just a few examples over the course of the past year, we've dramatically grown the scale of our onshore resource plays in the Niobrara and the Marcellus. We've accelerated the pace of the Niobrara to a level that we could not have envisioned just a year ago, with production from our horizontal wells at the end of the year far exceeding our original targets.

But 2012 was not just about our unconventional plays. Our major projects in the Gulf and in international hit major milestones with the startup of Galapagos in the Gulf, Tamar on track for startup in April and Alen on pace for an earlier-than-expected startup in the third quarter of this year.

We also announced a strategic partnership in Israel, discoveries in Israel, in the Gulf and new exploration opportunities in Nevada, the Falklands and Sierra Leone and a successful divestiture of non-core assets with proceeds totaling over $1 billion.

Our sales volumes grew 11% over 2011. We project an even higher rate of growth of 20% this year after adjusting for divestitures. And finally, we issued our first Sustainability Report, an area that's becoming increasingly important to investors. At Noble, we're not only proud of our financial and operational results but also we're proud of how we carry out our business. These strong results have us well positioned to extend our success into 2013 and beyond.

So let's go to the fourth quarter. As I said, it was a strong quarter, so let me get to the numbers. Adjusted net income from continuing operations for the fourth quarter was $296 million, or $1.65 per share diluted. Excluded from the adjusted net income were unrealized gains from commodity hedges and an asset impairment associated with Mari-B offshore Israel. Mari-B has been an outstanding field that is rapidly approaching the end of its production life, although it could have an important role going forward as a gas storage reservoir. Our focus right now is to squeeze as much gas as we can out of these depleting existing reservoirs to bridge the gap until Tamar comes online in just a few months.

Revenues were $1.2 billion for the quarter, up 30% from the fourth quarter last year, with revenue from crude and condensate increasing 52%. Our sales volumes for the quarter were 255,000 barrels of oil equivalent per day, a 5% increase over the third quarter and a 14% increase over the fourth quarter of 2011. This number does not include 2,000 barrels of oil equivalent per day associated with our discontinued operations.

Sales of crude and condensate represented 98,000 barrels per day, or 38% of total sales. The overall volume growth was almost entirely due to increased crude oil sales, which, as I mentioned earlier, were up 17% over last quarter and up over 50% over the fourth quarter of 2011. The growth in crude oil was from the DJ Basin, Gulf of Mexico and West Africa.

Natural gas volumes were essentially unchanged from last quarter, with gains from the DJ Basin and the Marcellus offsetting the impact of non-core domestic divestments in the third quarter. Domestic sales totaled 149,000 barrels of oil equivalent per day, up 6% from the last quarter despite the loss of production from our divested non-core assets and was up 17% from the fourth quarter of 2011. Domestic results benefited from our horizontal programs in the DJ Basin and Marcellus, as well as growth from the Gulf of Mexico, which was impacted the previous quarter by shut-ins associated with Hurricane Isaac.

Internationally, sales volumes were 106,000 barrels of oil equivalent per day, up 5% from last quarter and up 9% from the fourth quarter of 2011. Strong performance from Aseng and Alba in West Africa accounted for our growth in international volumes. Noa and Pinnacle fields offshore Israel have continued to perform well and contributed to average gas sales in Israel of 118 million cubic feet per day net, essentially unchanged from last quarter.

Our discretionary cash flow from continuing operations for the quarter was a record $824 million, that's up 16% from the fourth quarter of 2011. Our liquidity position remains extremely strong at over $5.4 billion. Our cash position of $1.4 billion and our credit facility of $4 billion provide us with tremendous financial flexibility as we go forward.

Our fourth quarter was our highest sales volume quarter and contributed to our annual average volumes from continuing operations up 239,000 barrels of oil equivalent per day for the year. Having closed out 2012, we're now focused on 2013. We anticipate that our 2013 sales volumes will substantially jump in the second quarter with the startup of Tamar and continue to ramp up through the rest of the year. Dave will break down our guidance expectations for the first quarter later in the call.

The addition of Woodside as a partner in the Leviathan project contributes to our confidence that we can deliver on our development plans in Eastern Mediterranean. Our initial focus at Leviathan is delivering natural gas to the domestic market in 2016. That is a market where natural gas demand continues to grow. Longer term, our plans anticipate exporting gas via LNG. We expect that Israel will enact their export policy later this year, and Woodside's experience and expertise in LNG projects will contribute to our progress on an export facility.

In West Africa, Aseng and Alba continue to perform well, and we've been able to move up the expected date of first production from Alen into the third quarter of this year. Also, in West Africa, we discovered a new reservoir, Carla, and plan to flow test 2 intervals there.

So 2013 is in full swing. We're actively moving several exploration discoveries also towards full development. The major development projects that may be sanctioned this year, which could be as many as 5, will compliment our growing domestic horizontal programs.

In the Gulf of Mexico, we're working towards the sanction of 2 projects, Gunflint, where we're currently drilling an appraisal well; and Big Bend. In West Africa, after production tests, we anticipate that Carla should be ready for development. And in the Eastern Mediterranean, we're moving towards sanctioning a Phase 2 of Tamar, as well as the first phase of Leviathan. In total, these major project sanctions will likely include, in total, significant bookings of new reserves in 2013.

In the press release today, we included a summary of our year end reserves. Dave will review these reserves in more detail, but I'd like to add just a few comments. All of our reserve adds are from organic activity, not acquisitions. Excluding divestments, our reserves at the end of 2012 were up 3% over 2011. We added approximately 200 million barrels in the DJ Basin and the Marcellus and still have over 3 billion barrels of net risked resources still on book from these 2 plays. As Dave will discuss later, we're currently booking less than 3 years of proven undeveloped locations for our domestic horizontal programs.

Later today, we will be issuing our 10-K, which will include our year end 2012 SEC 10 valuation. Despite the soft domestic gas market, slightly low average liquid prices and divestments that resulted in over $1.1 billion in proceeds, as well as $3.5 billion in commodity sales net of production costs, even with all of these, our SEC 10 valuation ended up essentially flat to the prior years. This reflects the quality of our portfolio, demonstrated by the increased liquids reserves in the DJ Basin and the increased value as a result of the progress we're making on our major projects, Tamar and Alen.

Before turning the call over to Dave, I wanted to highlight some of our 2013 exploration activity. Exploration has been a true value creator for Noble Energy, and we believe it will remain a strong contributor to future growth of our company. To start with, we're actively appraising our earlier exploration discoveries. In the first quarter, we expect to have results from the Leviathan 4 appraisal well. Also, we recently spud the second Gunflint appraisal well, which may include an exploration tail to test the deeper myocene interval. And finally, we expect to drill the Cyprus appraisal well later this year.

We'll continue to mature our new ventures program, and we have a number of exploration wells planned. In Northeast Nevada, where we have about 350,000 net acres, we plan to begin testing vertical wells in the second or third quarter of this year. In the second half of the year, we plan to spud our appraisal prospect offshore Nicaragua, where we have a 1.8 million acre position and currently hold 100% working interest. A number of companies have visited our data room, and we'll be evaluating their proposals as we move forward to bringing a partner into this prospect.

In the Eastern Mediterranean, we plan to spud an exploration well at Karish, following the Leviathan 4 appraisal well. Karish is a 3 Tcf prospect with a high chance of success. Our new build drillship, the Atwood Advantage, is scheduled to arrive in the Eastern Mediterranean about the end of the year where it will drill the deep Mesozoic oil play at Leviathan. We're continuing our seismic programs offshore Falklands where we have a 35% working interest and a 10 million-acre position. We'll be taking over operatorship of the northern area licenses on March 1 of this year and of the southern area licenses no later than March of 2014. At our acreage position offshore Sierra Leone, a 2D seismic survey is being prepared. We currently hold a 30% working interest in those leases.

Throughout the year, our new ventures team will be evaluating additional areas that have potential to become future core areas for the company. This is a dynamic process that we believe will continue to fuel our long-term growth. So as I mentioned at the beginning, 2013 will be a very exciting year, one that myself and many others have been looking forward to. It will be a year of significant growth with new projects coming on stream. They'll be led by Tamar, which will not only have a material impact on our company, but just as importantly, a material impact on the state of Israel.

We're very proud of the role we're serving in developing the newly found resources of that country. It will also be a year of continued acceleration of our unconventional development programs led by the hugely impactful Niobrara program. This is a program that continues to deliver more positives every day.

And finally, it will be a year of moving major prior discoveries to development, as well as testing very material new exploration opportunities, some of which could be -- have a significant impact on the future of our company.

So now I'll turn the call over to Dave, who will give you more details on our ongoing operations.

David L. Stover

Thank you, Chuck. As you mentioned, it was an outstanding quarter, but the best is yet to come. Before I discuss the activities in our core operating areas, I want to start with a review of our reserves at the end of 2012.

We reported total proved reserves of 1.2 billion barrels oil equivalent, which is up 3% after adjusting for our non-core asset divestitures. Slide 6 of the supplemental materials shows the reserve changes from last year. Net of revisions, total company additions of 121 million barrels of oil equivalent replaced 136% of 2012 production.

In the U.S., net additions of 105 million barrels of oil equivalent replaced 207% of U.S. production. Domestic reserve additions were from our horizontal developments in the DJ Basin and Marcellus Shale. We booked only the proved undeveloped locations that are currently part of a specific development plan, which equates to less than 3 years of drilling in each horizontal program. Additional locations will be booked as future drilling plans are developed.

Included in net additions were reductions of 26 million barrels of oil equivalent due to negative price revisions from lower natural gas prices and 94 million barrels of oil equivalent due to the termination of the legacy vertical drilling program in Wattenberg as we concentrate on the higher-return horizontal program.

The reserves debooked due to the focus on the horizontal program, will likely be developed beyond the 5-year SEC window. The horizontal program reserve adds in the DJ Basin more than offset the vertical reduction. And despite debooking 94 million barrels oil equivalent, basin reserves increased 6% over the prior year. At year end 2012, we have booked 358 million barrels oil equivalent in the DJ Basin, only 17% of our estimated 2.1 billion barrels oil equivalent resources.

And in the Marcellus, we have booked 146 million barrels oil equivalent, which is only 9% of our estimated 10 trillion cubic feet equivalent resources. Our Marcellus reserves increased 61% over the prior year.

Internationally, net additions of 16 million barrels oil equivalent resulted from strong performance at Aseng and further appraisal at Tamar. As Chuck mentioned, we have not booked any reserves associated with the major projects we are targeting to sanction this year. We could book in excess of 200 million barrels oil equivalent reserves this year associated with the possible sanctions of Leviathan, second phase of Tamar, Carla, Gunflint and Big Bend. Also, with the startup of Tamar and Alen later this year, we expect to shift the bulk of their 400 million barrels oil equivalent of undeveloped reserves to developed reserves. As you can see, 2013 is shaping up to be an outstanding year of reserves growth.

Let's now review the operations in our core areas, beginning with the DJ Basin. We're excited about what the teams have been creating here, and our superior execution and results in the fourth quarter provides tremendous momentum as we move into 2013. We produced 86,000 barrels oil equivalent per day for the fourth quarter, a 30% increase year-over-year.

Slide 7 shows the growth in net production over the last 5 quarters. Horizontal production contributed 39,000 barrels of oil equivalent per day. That's a 2.5-fold increase versus the fourth quarter of last year. We exited the year with horizontal production above 42,000 barrels oil equivalent per day net from about 280 horizontal wells.

Liquids production from the DJ Basin in the fourth quarter was 51,000 barrels per day, or 59% of the total production stream. Oil alone represented 44% of our production for the quarter. Since we have been focused on developing the oil-prone areas of the play, our oil production has dramatically increased year-over-year by close to 50%.

We drilled 200 horizontal wells in the DJ Basin in 2012 and operated 8 horizontal rigs at the end of the year. Over 85% of those wells were in the oil areas of the play, which includes northern Colorado and the oil window of the greater Wattenberg area.

All the wells have been completed in our 15-well horizontal pilot focused on testing, recovery of 40-acre density in multiple benches of the Niobrara, as well as the Codell. Remember, we are testing 3 different development patterns here across the entire 300-foot oil-bearing section, with a potential of over 30 wells developed per section as shown in Slide 8.

All wells are being prepared to flow through our newly constructed EcoNode facility, and initial results will be available during our next quarterly update.

Looking at what we have learned over the past year, our base plan is to focus on 40-acre density across the oil window while accelerating activity and continuing to unlock ways to increase recovery. In 2013, we plan to add 2 rigs in order to drill 300 horizontal wells, all but a handful in the oil window.

About 60 will be extended reach lateral wells, with lateral lengths of 7,000 to 9,000 feet. Normalizing for an average lateral length of 4,000 feet, we'll be drilling close to 350 equivalent wells, up over 70% from 2002 activity levels -- 2012 activity levels.

As shown in Slide 9, the average production from 3 initial extended reach lateral wells is showing minimal decline and is tracking well above a 750,000 barrel oil equivalent-type curve. In fact, if you look closely at the last 2 months, the average, shown in red, exhibits essentially no decline. Obviously, we're excited about how this is evolving.

In one section of Wells Ranch, we're drilling 8 extended reach lateral wells on an 80-acre density pattern. We recently finished drilling 4 of the 8, with lateral lengths of approximately 9,000 feet. We expect to spud the remaining wells and begin well completions on this 8-well section by the end of the first quarter.

In Northern Colorado, we plan to drill 80 wells in 2013. This activity stems mainly from the exploration success we have experienced in the East Pony area. As noted on Slide 10, we now have 20 wells online that are exhibiting superior results, 24-hour peak flow rates averaging close to 800 barrels oil equivalent per day with about 80% oil. We plan to drill 55 to 65 wells this year in East Pony, incorporating some of the same thinking as we've done in Wells Ranch, laying out a very integrated development plan that will incorporate pipelines for water and oil transport, as well as multi-well pad drilling and centralized facilities to reduce our footprint.

To support our expected growth in northern Colorado, we recently sanctioned the Kyoto gas plant with a designed processing capacity of 30 million cubic feet per day. We will own and operate the plant scheduled for startup in the second quarter of 2014. This new plant alongside our 15 million cubic feet per day Lilli Plant allows us to control our own gas processing needs in this high oil area.

In Marcellus, production averaged 121 million cubic feet equivalent per day net in the fourth quarter. Wet gas production averaged 14 million cubic feet equivalent per day net from 3 pads. In January, we completed drilling the last of our 11 wells on our fourth wet gas pad and completions are underway.

We drilled 11 wells in the fourth quarter and operated 3 rigs. Two of the rigs are in Majorsville, and one is delineating our acreage position in Normantown, West Virginia. We plan to add a fourth rig in the second quarter in the Pennsboro, West Virginia area. The addition of a fifth and sixth rig later in the year will help us to drill 85 to 90 wet gas wells by year end.

In December, we showed the returns uplift from the liquids on our wet gas production. Slide 12 demonstrates that the value of the wet gas is about double the dry gas. It's easy to see why we are increasing our development in this portion of the field.

In the dry gas area, our partner, CONSOL, drilled 14 wells during the quarter and operated 2 rigs. For 2013, we have agreed to a 36-well dry gas program, down from 64 dry gas wells drilled in 2012. Our strategies are well aligned in this natural gas price environment, and we continue to focus on the high EUR and high net revenue interest areas of the play. Most of our leases are held by production, so our drilling plans are not being driven by lease expirations. Instead, we're able to optimize our development, and we are retaining the optionality to grow our program when domestic natural gas prices rise.

Moving offshore to the Deepwater Gulf of Mexico, we produced 24,000 barrels of oil equivalent per day, led by production from Galapagos. For the full year, production grew more than 20% over 2011 to nearly 18,000 barrels of oil equivalent per day. Our Gulf of Mexico production is approximately 80% oil and receives premium Light Louisiana Sweet pricing.

In the fourth quarter, we announced the discovery of Big Bend, with approximately 150 net feet of high-quality oil pay and the same productive interval as our Galapagos discoveries. The excellent reservoir and oil characteristics are similar to Galapagos, giving us confidence we will realize significant value from the development and production of this resource.

We have a 54% working interest in Big Bend, and we intend to sanction a development project later this year. Success at Big Bend has also derisked our adjacent Troubadour prospect, which we intend to drill this year. If successful, Troubadour could be co-developed with Big Bend, adding value to both projects. We hold an 87.5% working interest in Troubadour.

We're currently drilling our second appraisal well at Gunflint. Our first appraisal well established a commercial subsea tieback project. The second appraisal well will test the south side of the Gunflint structure and possibly a deeper myocene interval. A successful deeper myocene test could warrant a larger stand-alone development. After results of this well, we anticipate sanctioning Gunflint development as early as the second half of this year. The combination of Big Bend and Gunflint oil production will be a significant new source of cash flow in the 2015, 2016 time frame.

With respect to exploration in the Gulf of Mexico, we continue to mature both subsalt prospects as well as amplitude prospects. Later this year, we plan to drill another exploration well after we finish with Gunflint and Troubadour. We recently exercised a 1-year option on the ENSCO 8501 to support our expected drilling activity in the Gulf of Mexico and still maintained 3 additional 1-year options.

Shifting now to our International business, let's begin in the Eastern Mediterranean. Our existing production from the Mari-B facilities was essentially unchanged from last quarter due to the contribution from the Noa and Pinnacles fields. We've developed these fields with the intent that they would deliver natural gas until the Tamar field comes online, and they have performed extremely well. We're now only a few months away from first production at Tamar.

Slide 14 shows a couple of pictures of Tamar facilities. The installation of the jacket and platform was completed in December, and offshore hookup and commissioning operations are in progress. We're on schedule for first production in April, and we'll ramp up growth Israel volumes to reach full capacity, around 1 billion cubic feet per day, in the peak summer demand period. We expect to average gross sales volumes of approximately 700 million cubic feet per day the last 8 months of the year.

We spoke in detail in December about the growing demand for natural gas in Israel from electricity providers and industrial customers. To meet this demand, we're planning to implement a Tamar Phase 2 project to increase peak capacity to 1.5 billion cubic feet per day. The project consists of 2 components: installation of compression at the Ashdod onshore terminal to increase onshore delivery capacity, and storage at Mari-B to increase the offshore delivery capacity. With this increase in system capacity, we anticipate averaging around 1 billion cubic feet per day annual sales from Tamar in 2015.

At Leviathan, we're continuing the appraisal of the massive field and spud the Leviathan #4 appraisal well late last year. The Phase 1 development concept involves the use of an offshore host, likely an FPSO, to process the gas before bringing it onshore through a northern entry point. A portion of the capacity will be earmarked for domestic needs with the remaining volumes available for export. We expect domestic demand to continue its growth, resulting in potential sales of several hundred million cubic feet a day from Leviathan beginning in 2016.

In West Africa, crude and condensate volumes from Alba and Aseng were 36,000 barrels per day net in the fourth quarter. We continued to see strong prices on our listings with an average realized price around $108 per barrel. The Alen project, as we announced in December, has accelerated its schedule for first production to the third quarter of this year. Well operations are complete, and platform installation is scheduled for the second quarter. Initial condensate volumes are expected to be 18,000 barrels a day net, which will be transported to the Aseng FPSO for offloading.

At Carla, we discovered an additional reservoir in the fourth quarter. Our appraisal of Carla is in progress with the next step, a flow test of the original and the newly discovered reservoirs. The complete analysis of these results will guide our plan of development, which will likely be a subsea tieback to Aseng.

Before I open the call for questions, let me quickly touch upon our volume guidance. Our full year volume guidance of 270,000 to 282,000 barrels per day and all full year guidance ranges that we announced in December remain unchanged. We expect the first quarter to be our lowest volume quarter, and that production will increase significantly in the second quarter with the startup of Tamar and will continue to ramp up throughout the year, exiting around 300,000 barrels of oil equivalent per day.

We anticipate first quarter volumes to be 238,000 to 242,000 barrels of oil equivalent per day, essentially no different than what we expected when we provided full year guidance in December. This range includes the impact of underliftings of over 4,000 barrels per day in West Africa, maintenance downtime in the Gulf of Mexico, as well as normal depletion at the Mari-B field and the timing of pad startups in the Marcellus Shale. Offsetting the Gulf of Mexico downtime is several thousand barrels per day higher production from the DJ Basin.

In summary, we continue to execute and deliver on the plan we've laid out. Before long, the Tamar and Alen major projects will be online; we will have drilled significant appraisal wells at Leviathan, Gunflint and Cyprus; and we will be testing large oil prospects in Nevada, Nicaragua and the Eastern Mediterranean. It's no wonder we are excited about our company.

Camille, with that, it's now time to open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question from Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

My question is on the Niobrara, and then I know the production profile in Slide 9 continues to be flatter than your type curve after 3 wells. And while I realize it's early days here, is there anything specific to those -- these locations that could make them more outliers? Or any incremental changes on your view of the type curve and maybe how many wells you think you need to give you comfort to revisit that type curve?

David L. Stover

Yes. It's a good question. It's -- when we look at it, and particularly what we emphasized, especially as that production's continued from those longer laterals, you can see how flat that curve is. I mentioned in the last 2 months, really, if you look at the last 3 months, it's fairly flat. That gives us a lot of encouragement on what we're doing there. I would say, we've looked at -- is there -- is this really an outlier area? We don't really believe so. We think the real application of the long horizontals is up in this oil window and that northeast part of Wattenberg and then up into northern Colorado. So we're really going to test that this year. As I mentioned, we're going to drill close to 60 longer lateral horizontals. We've got an 8-well program or a section that we're completing drilling and completing now in that Wells Ranch area. So the real answer to your question in part is then we'll be real comfortable with how well do we understand this, it'll be towards the end of this year when we get more wells drilled in more different areas. But from what we've seen and where we drill these 3 wells, and you combine that with that initial long lateral that we drilled that's now over a year of production, we're really enthused by what we're seeing from this program.

Charles D. Davidson

I think it just points out once again how important it is on unconventional wells to really wait until you get extensive data and try not to make judgments too quickly. In the case of the Niobrara, it just -- certainly in the extended area, it's just gotten more and more positive as we've gathered the performance data on these extended laterals.

Evan Calio - Morgan Stanley, Research Division

If I could ask just one more follow-up to that, is -- I mean, can you just generally discuss the constraints for growth here in the Niobrara? I mean, is it midstream? Staffing? Otherwise? Or some combination? I mean -- I guess I'm looking at the 500 well rate in 2016, huge growth rate with still over a 19-year inventory. What's the limiting factor for faster growth? And I'll leave it at that.

David L. Stover

The one thing you want to do is you want to lay out a pretty thoughtful plan and lay it out at least a year or 2 ahead of time as you're developing this. I think when we look at it right now -- I mean, if you look at this year's activity, when you look at it on a normalized footage basis, we're up over 70% from what we did last year, heading towards, as you mentioned -- going from 300 wells to closer to 500 in a couple of years here. I think the thing that will play into this is the work we're doing on understanding the vertical recovery component of the Niobrara. In other words, where do we get to on -- how many different laterals do we need in any one particular area? Everything we're looking at and evaluating from that A bench down through the Codell. We need 1 lateral. Do we need 2 or even 3 in some of these areas to optimize that? As we start to unlock that and understand that, and if you get into areas where you're doing more multi-laterals, then you potentially have the ability down the road to be doing more off central facilities even than what we've got planned now, which could help accelerate some of the timing as we get into that. But I mean, that's some of the things that are going to have to play out over the next year or so.

Charles D. Davidson

I think also it's -- as you're probably aware, this plan continues to evolve. If you look at our -- the plan we laid out in December versus the 5-year plan that we showed a year before, our most recent plan had 1,100 additional wells over the 5-year period. So we continue to accelerate the program as results come about. And as Dave mentioned, we continue to look for ways to push it forward but to make sure that we are developing it in a very efficient way. So it's exciting to have that kind of potential. It's exciting to see the potential grow. And we know that we've got a lot of work ahead of us to continue to accelerate it.

Operator

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

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

See if I can get a little bit more color on some of the high-potential exploration. Wanted to get a sense if you guys thought you would have results from the well in Nicaragua by the end of the year. I just wanted to get a sense of when you thought you'd start drilling in Sierra Leone.

David L. Stover

Yes. I'd say, Leo, on Nicaragua, I'd say about end of the year is probably about the right timing for that if we get started by mid-year, a little after mid-year. So I think that would fit with what we're thinking right now. Sierra Leone, right now, it's a little bit further behind. It's earlier stages. We're just working right now on planning what the 2D seismic program will be, which then, based on what you see from that, you'd plan a 3D program before you get around to start drilling. So the drilling there is probably a couple of years off yet.

Charles D. Davidson

I think on the other high-profile wells, while it's a different type of play, keep in mind that somewhere around the middle of the year, we'll be starting in Nevada with that program, and that's testing a pretty sizable resource there. And that information will evolve over time. And then also, at the very end of the year, as we mentioned, the drillship will be moving back into Israel to start drilling the deep Mesozoic oil test. But we wouldn't expect results on that until early the following year.

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

Okay, that's really helpful. And I guess just a question on Israeli production. Just looking at your production guidance, you talked about some of the moving pieces here. Are you all expecting Israeli production to be down pretty significantly in the first quarter of '13 in your guidance?

David L. Stover

Yes, I think it will be somewhat. We kept it ramped up third and fourth quarter to meet some of the needs over there and supply everything we could as we're getting closer to Tamar. And actually, you're starting to deplete some of these fields a little more. You're probably -- I'd say, in the fourth quarter, we were running that net 270 to 300 growth range. We'll be down closer to 250 or -- plus or minus in this quarter. Probably 230 to 250 is what we'll run it at.

Charles D. Davidson

On a gross basis.

David L. Stover

On a gross basis.

Operator

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

If I could jump back, Dave, please, to the northern Colorado area. I think in the past you guys have suggested that the limiting factor was really more about large ranch stages and so on. I'm just curious, given the success that you've had, if you're able to still add acreage up there? And if so, is -- ultimately, what do you think the extent of this extended lateral area could be? I think that sounds maybe similar to a question you had before, but really more about the acreage adds.

David L. Stover

Yes. If you recall, we added a significant portion of acreage in northern Colorado last year, which help delayed some of the activity and the development of this East Pony area. I think when you think of north Colorado this year, it's really 2 pieces. It's moving into full development over in that East Pony area, and then it's probably, I'd say, testing and delineating probably another 100,000 acres up there with a number of wells. I'd say, 5 to 10 wells up in that area. So that's probably the 2 main focuses of the program in that area for this year.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

So you feel you've got plenty of running room in terms of -- are you still adding acreage? Or are you pretty much done?

David L. Stover

I mean, we add pieces here and there as it fills out drilling spacing units and so forth. But we're not adding big pieces of acreage. We still have -- I think if you remember, we still have probably 100,000, 150,000 acres that we need to delineate up there in the northern Colorado portion right now.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My follow-up is really -- you've had a pretty good clean up of the portfolio here in the last year or two but, Chuck, we haven't heard you talk about China in a while. What are your thoughts there in terms of potential disposal? And I'll leave it at that.

Charles D. Davidson

Well, I think we continue -- like you say, we continue to clean up the portfolio, and I think we would view that China would move into a category where it would be non-core. It's always a matter of matching up the right -- the buyer of the assets. We worked on the North Sea for quite some time till we found the right home from some of that because we do put a lot of value on focusing on our core area of businesses. So we've got a little bit left in the U.S. to finish up on that program. We got most of it last year, very successful program, but there's still a couple more packages here in the U.S. we need to clean up as well. So always moving it down the food chain, so to speak, and keeping it as clean as possible. So more work to come.

Operator

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

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

Real quickly, kind of thinking more about the service cost outlook. Last quarter, you guys had talked about thinking towards a 5% to 10% decline in 2013 in the DJ Basin. Has anything changed that landscape as you move more rigs up there and do more pad drilling? Do you have the right fit-for-purpose rigs? Are you able to get them at similar rates? Any kind of sense on where you guys are thinking in terms of continued cost compression that you've benefited from as well?

Charles D. Davidson

I don't -- I'll also ask Dave to comment, but I don't think we anticipate any changes from what we just talked about at the end of the year. But we do have to keep in mind that we are driving -- especially in the development programs, we're driving to a more efficient development program. The pad drilling, multi-wells on a pad, some of the things that we outlined in December that we're doing in areas such as handling of water, of more efficient movement of fluid. These are all built to get more efficiency out of the scale that the Niobrara program is going. But in terms of just looking at service costs themselves, I don't think we see any big changes in what we outlined before.

David L. Stover

No. And a lot of that is predicated on moving more to these fit-for-purpose rigs, which we've been doing too, Dave. So nothing's really changed on that outlook.

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

Okay, that's helpful. And then maybe kind of more of a housekeeping item, it looks like LOE for 1Q is kind of trending up versus where it was 4Q and is certainly above full year '13 guidance. Can you talk about what's kind of moving that around, just for that one quarter? Or is that a trend [indiscernible]?

David L. Stover

Yes. There is some -- in that first quarter, we're seeing some impact of some Swordfish maintenance cost on our Swordfish well out there. We had lost the power supply for a period of time so we had to bring in an additional power supply, and then we had some compression work that needed to be repaired. So a lot of it is driven by that, Dave.

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

Okay. So really one time in nature more than anything else.

David L. Stover

Yes. I think we'll see that trend down over the next part of the year and especially as you start to bring the Tamar project on, too.

Operator

[Operator Instructions] And we'll take our your next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

On the Marcellus, you talked about the liquids-rich components contributing about 12% of the total; and in your prepared remarks, talked about reducing, I think, the number of wells you're drilling on the dry gas side. Can you talk about how you see your mix changing in the Marcellus over the course of the year and how you see overall production trending, given the shift in activity?

David L. Stover

Yes. I mean, our production trend -- no different than what we laid out in December. So -- I mean, we'll be up still significantly overall. A lot more of it, as you allude to, Brian, will be driven by the wet gas portion. We'll be drilling, what, close to 85 to 90 wet gas wells this year compared to 35, 36 or so dry gas. But a lot of those pads really don't start to come on till second, third, fourth quarter. So it'll be more second half of the year weighted where you start to see the real impact of the more liquid portion of that.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then going back to reserve bookings internationally. Can you just refresh us on Alen and Tamar, what is booked now from the projects that -- at least the portion of Tamar that you have coming on in 2013, and if there's anything less to book? And then how we should think about reserve bookings, perhaps at year end 2013 internationally with some of the sanctions that you're planning?

David L. Stover

Yes, Brian. We've booked kind of -- if you remember, we booked the liquid portion, probably a fairly significant portion of that. I think as far as additional potential for bookings at, say, Alen and -- when I'm thinking about Alen and Aseng, we saw some improvement this year from Aseng from performance. We may be able to see some of the -- the same thing from Alen. When you think about what we're doing at Tamar, I think we've booked, if I remember right, about 70% of the total reserves there. And then we'll look at that as we get performance and get further along in development.

Operator

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

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

Today I wanted to focus my question mainly on marketing issues in 2 regions. Firstly, in the Niobrara, you guys generally are sort of a trendsetter and pace setter for the play. And I'm wondering where your crude is being sold to, a percentage into Cushing and then other Rocky Mountain area, and just really sort of a longer view as to how you're going to pace yourselves. Then the second part of this question is really offshore Eastern Mediterranean. I mean, surely, there's a lot of countries nearby that you can sort of export your gas to, and my question is how comfortable you are in terms of getting oil index-type pricing in light of the fact that some of the Gulf Coast projects are selling it at Henry Hub Index? So that's all I have for today.

Charles D. Davidson

Thanks, Irene. I think Dave and I will tag team on this a little bit. I think, in Niobrara, the one thing to keep in mind is that our marketing has greatly expanded over the course of the last, really, 1.5 years, 2 years. So not only do we market locally to a -- oh, it's actually a company that has 2 refineries in the area, but now it's broadened out to a number of customers in the region. And then also, we send a sizable portion of our crude down to the White Cliffs pipeline into Cushing. In addition, we're working with partners on a rail facility that will start up in the second half of this year, and that rail facility will actually allow us to move crude to multiple markets throughout the country. It's just not about moving it through the Gulf Coast. We can move it to the East Coast and the West Coast as well. It really opens things up for us. So as a result of all this, we're seeing a lot of flexibility going forward in terms of how we market our crude out of the basin. And with the capacity growing, with the expansion that White Cliffs has undertaken and with the rail facility, we're able to move these ever-increasing amounts of oil. On the Eastern Med, I would just say that on the export side of it, obviously, near term, we're focusing on this growing domestic market in Israel, which is probably going to support 2 more expansions, one of Tamar and a first phase of Leviathan so that we can satisfy that market. And then we'll be -- we continue to work the export process. There may be markets nearby, but I think we really see exports as being an LNG export project. And gosh, what kind of pricing evolution that will happen on that? We know we'll have European customers that have a different pricing methodology as some of the Asian customers and it all continues to evolve. And so that -- those will be all the pieces that will be continuing to work where countries are all different. The good news is, is that we're dealing with a resource that can be developed at low cost and can be competitive in a number of markets. I might ask David if he wanted to comment anymore on either of those.

David L. Stover

I'd say, when you look at our DJ Basin crude, I mean, we don't see that going forward, even with the rail situation coming in. We don't really see what you've seen as far as deducts from WTI really changing that much. I mean, we see, with the ability to move crude to a number of different places and a number of different markets, we still have a good plan there on how to continue to handle that. And that gets even better with some of these expansions that Chuck has mentioned.

Operator

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

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

I had a quick question on Tamar Phase 2. You mentioned there are 2 capital items around compression and storage. Will you need any more wells to supply that volume? And can you remind us on the nameplate capacity for the platform?

Charles D. Davidson

Well, the -- I'm not -- well, there are 2 platforms that are involved here. One is Mari-B that potentially would be used as a storage facility, and then there's the big Tamar platform that we put in. So right now, the nominal peak capacity of the Tamar Phase 1 will be around 1 Bcf a day, which is delivered out of 5 wells of which probably 4 could make that volume and the fifth is additional. The peak capacity for Phase 2 would be about 1.5 Bcf. And again, that would be achieved through probably some swing volumes from Mari-B out of storage, as well as utilizing the compression that we would install onshore to be able to enhance the delivery. So will there be another well along the way? We'll just see. I would speculate at this point that we'll want to see the performance of these wells that we have as part of the base development. They've been -- some have been flow tested. They're very high productivity. And then we'll just see -- we always want to make sure we've got some redundancy in the system as we go forward. But it's a very highly prolific field, very productive wells.

Operator

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

John Malone - Global Hunter Securities, LLC, Research Division

You mentioned earlier in the call that you think that you might get approval from the Israeli government for exports later in the year, if I heard correctly. Can you sort of walk us through what you -- the expected timing, the ideal timing post that approval? When do you think you might have some SPAs with customers and when you think the earliest date for FID is possible?

Charles D. Davidson

Well, on an export project, I think we still see -- a final investment decision is out into the future. There's a lot of work that needs to be done on facility design. And as you pointed out, just making sure you're secure on markets and customer. So that's not a -- that is not something that we would anticipate anywhere near this year. That's out some time. As far as the export policy, the committee that studied that in Israel made their final recommendations late last year. We would, as I think kind of anticipated because of the elections that were called in Israel, there was no final action taken on that. Israel is now building the new coalition government after elections have occurred. And I guess my anticipation would be is that, that export policy would be taken up after the new government is formed, which will be probably some time late this quarter, early next quarter. And then it will just go through its process. But again, we would expect that relatively soon, they would finalize that, because it does give us more certainty in how to plan and design going forward.

John Malone - Global Hunter Securities, LLC, Research Division

And just a follow-up to that, probably too early to answer, but Woodside in the past has gone to 2 FID on projects without having sold 100% of capacity on the idea that they can get some spot volumes sold as well. Are you guys thinking of these terms yet, or is it too early?

Charles D. Davidson

Well, I think it's way too early. But I would just say that as we've looked at the LNG markets, there is some strategic advantage to leaving some of your volume uncommitted for spot sales. And so, again, without -- we just haven't gotten that far. But we, at least philosophically, agreed that there's some value in doing that.

Operator

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

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

If I could go back to a sub -- comment that Chuck made in his prepared remarks, I think -- this sounds like this was a new prospect, this Karish, if I'm saying it correctly? And I'm wondering where that is in relation to your other prospects and what your work condition is, what a developed scenario would look like.

Charles D. Davidson

Well, it's not a new prospect, Charles. It's one of that inventory we had up there in the Levant Basin that we've seen -- as we've gone through all our 3D work. I guess it's about a 3 TCF prospect, and it's a very high chance of success. We think it can kind of help solidify the resource base there in Israel.

David L. Stover

Close to Tamar.

Charles D. Davidson

And it is. It is close to Tamar, probably a little east of Tanin, our discovery that we made. That was early last year. So it just fits in with that program.

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

Got it. And so that would just have some kind of the same sort of subsea development and tieback as you're using for Tamar?.

Charles D. Davidson

Oh, I would think so. Yes.

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

Got it. And then the follow-up. On Carla, on the cartoon map you guys have, it looks like the southern portion of that prospect hasn't been tested yet. Is that correct? And is that going to be part of your 2013 appraisal program?

David L. Stover

Yes. I mean, we've got a -- that sort of started out as a multi well with some additional sidetracks to more fully appraise this. So what we're going to do is kind of systematically appraise this now multiple reservoirs. And the next step here is actually flow testing a couple of these reservoirs.

Charles D. Davidson

Keep in mind, we did drill Carla earlier at a different location. And so what's happened with this most recent well, we didn't -- I don't think on our cartoon -- we didn't really show the well locations. But this latest well showed that we had some reservoir separation there. So certainly, there will be some more work to be done, and we show a fairly large range for Carla. Our latest on a P75-P25 shows that it could range anywhere from 36 to 136 million barrels equivalent, from about 80% being liquids. So it's a sizable feature, and it will probably -- again, after we do our well tests, we'll put together the development plan and we'll just see how we stepped through it.

Operator

And we'll take our next question from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Hoping to get your view on domestic NGL prices and what the options are to not price DJ Basin production off Conway. Just asking in an effort to better understand the impact of margins here going forward.

Charles D. Davidson

Well, I think the key thing to keep in mind that will, I think, give us some flexibility on DJ volumes is the new pipeline that's being built that will go into service, I want to say, early -- end of the year, of this year, beginning of next year. And that will move it away from Conway and start moving it down into the Gulf Coast. So you've got then more flexibility on the pricing there.

Dan McSpirit - BMO Capital Markets U.S.

Okay, great. And then as a follow-up, with respect to the new gas plant in northern Colorado, can you give us the amount of capital that will or has been committed to building, constructing that plant? And should we expect much by way of changes to the initial capacity of $30 million a day here going forward? And maybe as a follow-up to that, the amount of third-party volumes that may go through that same plant?

David L. Stover

Yes, Dan. I mean, right now, we're looking somewhere in that $30 million to $40 million range, if I remember it right, for that facility. And at this point, we'll see how it develops. But with our plans for development in that area, we're looking at it, filling that up with our gas. I mean, if there's any additional capacity, we'll surely look at any third party gas in the area. But our plans right now are based on our activity and what we're seeing up there to continue to load that up with our volumes and our activity. I mean, that's at least the emphasis upfront.

Charles D. Davidson

Yes. Just to keep in mind, that's a very low GOR area. So you don't need just a small amount of processing capacity. And again, we've got an existing Lilli Plant and then this Kyoto plant that we're building that -- that really helps us able to move things up there.

David L. Stover

When you have 1,000 GOR or so.

Charles D. Davidson

Exactly.

Operator

And we'll take our next question from Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just a question on the extended reach laterals. Have you tried that up in the northern Colorado area, given the higher oil cuts? And the follow-up question to that really is what's the difference in the economics uplift that you see with the extended laterals versus your average lateral based on your results today?

David L. Stover

Yes. Good questions. I think right now, we have not yet drilled extended laterals in northern Colorado. But our plan is to drill a handful of them this year up there, so we'll start to get a look at it up in that area, as you say, given the acreage position up there and the oil prone -- theres the high -- low GOR, high oil in that area, it's a natural place to move that program. When you look at the returns, we're seeing returns over 100% from when you look at these first 3 or 4 extended reach laterals. So when you look at what we've shown on our base program and that 40% to 60% returns, it's a pretty nice uplift here to go -- get up over 100% return from what we're seeing so far on these.

Charles D. Davidson

And just to add to some things that Dave was talking in the prepared remarks is that, that's -- 100% plus is what we are seeing based off of the type curve analysis that we had out there, and our performances is going well above the type curve. So we're probably -- even at the type curve, we're seeing F&D down about 20% on these. So that's probably -- with what kind of success we're seeing, that's set up to improve as well. So very, very high return wells.

David L. Stover

I guess the real story there is we don't really know yet what the limit to recovery from this program is.

Operator

And we'll take our next question from Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Most of mine have been addressed. But just a quick follow-up on the DJ marketing topic, just curious on the rail volumes. Have you actually contracted any capacity out of the basin on rail? And what might the per barrel cost be on that?

David L. Stover

Yes. On the rail capacity, we've committed 10,000 barrels a day, and I wouldn't be surprised to see us move up to 20,000 by the time it gets put in, given how fast our oil production is growing up there. When you look at it, as Chuck mentioned, it goes -- potentially can go to a lot of different markets to get better pricing than WTI. I think the costs we're looking at are in -- to deliver, it's probably $10 to $12 a barrel.

Charles D. Davidson

And the gross facility, the gross rail facility has a capacity of about 60,000 barrels a day, and there's another partner in it that's made a commitment for some capacity as well. So a lot of room to grow.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

And sorry, is that in northeastern Colorado? Or -- where I guess physically is the...

David L. Stover

No, it'd be in the Wattenberg area. In the Wattenberg area, probably closer to Platteville.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Got it. And then just curious, I don't know if it's necessary, a whole lot to be read from it, but just curious what your per well EUR bookings are on the horizontal program at this point on proved reserves?

David L. Stover

I think in the DJ you're around that 300 that we've been talking about. On a gross basis, you've got to net that down for our net revenue interest.

David R. Larson

Hey, Camille, this is David. It looks like we're -- we've reached our 1-hour limit here, so we are going to end the Q&A session now. And for those that are still on the call, I want to thank everybody again for participating in the call and really the interest that you have in Noble Energy. And have a great day.

Operator

This concludes today's presentation. Thank you for your participation.

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

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

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

Source: Noble Energy Management Discusses Q4 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts