Cobalt International Energy Management Discusses Q1 2014 Results - Earnings Call Transcript

May. 1.14 | About: Cobalt International (CIE)

Cobalt International Energy (NYSE:CIE)

Q1 2014 Earnings Call

May 01, 2014 11:00 am ET

Executives

Joseph H. Bryant - Chairman and Chief Executive Officer

John P. Wilkirson - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

James H. Painter - Executive Vice President of Execution & Appraisal

Van P. Whitfield - Chief Operating Officer and Executive Vice President

Analysts

Evan Calio - Morgan Stanley, Research Division

Al Stanton - RBC Capital Markets, LLC, Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Richard M. Tullis - Capital One Securities, Inc., Research Division

Operator

Good day, everyone, and welcome to Cobalt International Energy's First Quarter 2014 Conference Call. Just a reminder, today's call is being recorded.

Before we get started, one housekeeping matter: This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and in Cobalt's SEC filings, and we incorporate these by reference for this call.

At this time, for opening remarks and introduction, I would like to turn the call over to the Chairman and Chief Executive Officer of Cobalt, Mr. Joe Bryant. Please go ahead, sir.

Joseph H. Bryant

Good morning, and thank you for joining us for the Cobalt International Energy first quarter 2014 earnings and operation update call. Joining me on today's call is John Wilkirson, our Chief Financial Officer. I'll make a few introductory comments, and then I'll turn the call over to John, who will discuss our first quarter financial results. Of course, we'll then be happy to answer any questions that you may have.

As you read in our earnings release this morning, 2014 is shaping up to be another very active and impactful year for Cobalt, with multiple value-creating catalysts already delivered and more planned throughout the year, both in West Africa and in the Gulf of Mexico.

I'll first talk about our West African operations followed by a discussion on our Gulf of Mexico activity. In the first quarter of this year, we have announced 2 significant discoveries in West Africa: Bicuar in Angola Block 21 and Orca in Angola Block 20. This morning, we announced the exceptional results of the drill stem test that we performed on the Orca #1 well and can say with confidence that Orca is clearly our largest discovery to date, with resource range of 400 million to 700 million barrels of oil. In fact, as excited as we are about our Cameia field, which I'll talk more about in a few minutes, we believe that Orca is now clearly our crown jewel in this basin, in that the rock quality, fluid properties, flow capacity and overall scale of the Orca structure, when combined, exceed the high potential that we see in our Cameia field. Orca is a black oil discovery, with structural closure of nearly 50 square miles, which for comparison is twice the size of Manhattan Island, making Orca one of the largest oil discoveries in Angola.

In addition to this exceptionally large footprint, Orca's structural thickness is approximately 650 feet. When developed, we have confidence that an Orca well will flow oil at rates equal to or greater than the per well rates that we anticipate at our Cameia field. The Orca well results provide tremendous insight into our understanding of the Kwanza Basin reservoir properties. And as such, the implications on the rest of our Angolan portfolio, including our discoveries to date and our undrilled exploration prospects are significant.

After we completed the Orca DST operations, we moved the SSV Catarina rig to our Cameia #3 well in Block 21 and operations are continuing. We plan to utilize the Cameia #3 well as a development well in the Cameia field development. The results from Cameia #3 will be used as a final validation for the facilities designed prior to sanctioning our Cameia field development project, which we, and our Block 21 partners, are actively pursuing this year. Once sanctioned, we will embark on the development of Cameia in order to achieve first production from this field as early as 2017.

Our continuing analysis of the Cameia field provides evidence that the lower limit of our estimated resource is now approaching 300 million barrels of oil. And we believe that this number can grow with additional appraisal drilling and analysis.

Our track record of success in the Angola Kwanza Basin has been tremendous, and that all 5 of the prospects we've drilled offshore Agnola have resulted in discoveries. As we continue to evaluate the appraisal and development options for our Angolan resources, we can see that these discoveries are logically fitting in to a hub development philosophy that maximizes the capital efficiency of developing the massive potential of these discoveries.

Given our current discoveries, we think that we could have a minimum of 3 development hubs. For instance, we clearly see a Cameia hub development, which should include Mavinga and potentially Bicuar in addition to Cameia. We believe that the Cameia hub would be a nominal 100,000 barrel-a-day facility. Secondly, we see a separate Orca black oil development hub with substantial production potential. Given that we see Orca's resources as likely being 2 or more times the size of Cameia's. And third, we see a Lontra hub development that continues to evolve in our thinking, but will likely initially include liquids production and gas reinjection.

Also in Angola, the Angola Ministry of Petroleum granted Cobalt a 2-year extension of our Block 9 license. After drilling operations are finalized on Cameia #3, we will move the Catarina rig to drill our large Loengo prospect on Block 9. And then following Loengo well, we plan to move the Catarina rig to drill our Mupa exploration well on Block 21. Both prospects are stratigraphic structures, and if successful, have broad positive implications for numerous similar prospects we see in the remainder of our Angolan Pre-salt exploration inventory. We look forward to sharing the results of both of these wells with you.

I'll now move to a discussion of our Gulf of Mexico activities. As mentioned earlier this year, we are currently participating in 2 wells in the deepwater Gulf of Mexico. These include the Shell-operated Yucatán appraisal well, which will appraise the Inboard Lower Tertiary horizons found in the initial Yucatán discovery. Cobalt owns a 5.3 working interest -- a 5.3% working interest in Yucatán, and our participation is important due to its close proximity to our Shenandoah field.

In addition to Yucatán, Cobalt is participating in the Chevron-operated Anchor #1 exploration well, which is an Inboard Lower Tertiary test with additional Miocene potential. We anticipate results from both of these wells in the second half of 2014. Also in the Gulf of Mexico, Anadarko as operator will commence Heidelberg development drilling sometime this summer. First oil from Heidelberg continues to be on track for 2016.

At North Platte, our team's ongoing analysis of our newly-acquired 3D seismic data over the area has increased our confidence in the field's structural closure, with potential for growth when the analysis is completed. We plan to spud our first North Platte appraisal well in early 2015 with the Rowan Reliance rig.

In addition to our ongoing Gulf of Mexico operations on our existing acreage, Cobalt participated in the recent Gulf of Mexico Lease Sale 231, and was the apparent high bidder on 44 of 46 bids submitted. We are very pleased with the results of the sale, and if these bids are awarded, we will have acquired these leases at a low cost of entry. Lastly, we look forward to our Analyst Day on June 4 in New York. As mentioned in our previous call, we see the day as an opportunity to spend time reviewing how our exploration success translates into shareholder value.

We will discuss our operational performance, upcoming exploration catalysts and our development plans. We will also describe our plans for the future of the company. We hope to see many of you there.

I'll now turn the call over to John to update you on our financials.

John P. Wilkirson

Thanks, Joe. Our balance sheet remains strong, with cash of over $1.6 billion. As of March 31, we had approximately $1.4 billion in unrestricted cash and investments and approximately $260 million designated for future operations held in collateralizing letters of credit.

During the first quarter, our restricted cash balance was reduced as we received release funds associated with 2 exploration commitment wells in Angola. We expect an additional move of about $110 million to unrestricted cash by midyear, given the recent completion of other Angolan exploration wells. In addition, we have not recorded on our balance sheet of a drilling promote fund of about $76 million for our Gulf of Mexico program with TOTAL.

As announced this morning, Cobalt's first quarter net loss was $57 million or $0.14 per basic diluted share. For the quarter, our accrued capital and operating expenditures were approximately $178 million. This is consistent with our speaking expectations for the first quarter and in line with our full year capital and operating expenditures forecast of $750 million to $850 million.

The capital and operating expenditures forecast excludes interest payments, Angolan social contributions and items amortized in future year's operations that could total an additional $200 million of cash this year.

Our estimate for the second quarter capital and operating expenditures is $200 million to $230 million, excluding the items that I mentioned. We remain focused on ensuring Cobalt has a strong balance sheet to support our operational activities and projected growth.

Given our planned exploration and development spending, our balance sheet will carry us well into 2015. However, we continue to evaluate 2 primary means to maintain ample liquidity going forward.

First, the depth and quality of our discovered resource base gives us the opportunity to prioritize our holdings to ensure our investments are directed to the highest-return projects. This analysis may lead to initiatives ranging from joint ventures to partial and complete divestitures.

Second, we continue to monitor the capital markets with a preference for structures that minimize carrying cost, while providing long-term flexibility. And as I've stated on previous occasions, the issuance of any primary common equity remains our least preferred capital markets alternative.

I'll now turn the call back to Joe.

Joseph H. Bryant

Thank you, John. Operator, we'd like now to open the line up for any questions that our participants may have.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

You guys have discovered a lot of oil in Angola, and I get questions here. So could you just confirm that development rights are not dependent upon any gas monetization?

Joseph H. Bryant

Yes. Thanks, Evan, for the question. Because I do think over the past 6 months, there does seem to be a lot of confusion and, frankly, misinformation about our development rights for oil and liquids versus a positional long-term solution to monetize the gas molecules associated with those liquids. So let's just review the facts. As we've stated, we believe that we've discovered something between 1.1 billion and 2 billion barrels of oil and condensate in our initial 5 wells. Now let me reemphasize that there are no restrictions on Cobalt immediately accessing those liquids, so long as we do not waste any resource. Now this is a routine oilfield practice and will be accomplished in our case by recycling any and all gas produced. As a matter of fact, these gas reinjection schemes actually will increase our value of our discoveries by increasing the oil recovery rates. Let me also emphasized that there is nothing new related to our discoveries or contracts related to this gas cycling idea. And this is very common today, even in Angola. As an aside, I was thinking that Angola today produces about 2 million barrels a day. And as far as I know, and I think we should assume, every one of those barrels has gas associated with it. So over the last decade, I guess, billions and billions of barrels of oil have been produced in Angola by doing the exact same thing that we will be doing in our developments. There's nothing unique in our contracts that is any different from any other contracts out there that will prevent us from doing that. However, I will say though that if we're given the commercial rights to the gas in our fields, which is possible down the road, we estimate that our resource barrels would approximately double. And I think, therefore, creating long-term high-value option for our shareholders. So that's kind of a long answer, but let me summarize it where I began. To date, Cobalt has discovered between 1.1 billion and 2 billion barrels of oil. And I think with growing confidence, we believe we're going to be at the top end of that range. And there is no dependency on our rights to develop those barrels related to a long-term gas solution, which may or may not occur down the road. Does that answer your question?

Evan Calio - Morgan Stanley, Research Division

Yes, very thoroughly, I appreciate that.

John P. Wilkirson

This is John. Let me add on just a little bit to what Joe described to you. We're estimating that the current value for both Orca and Cameia here in the upper-single digit, say somewhere around $8 per entitlement barrel, assuming current commodity prices and cost. As you're well aware, entitlement barrels are roughly 20% for something like Orca and 35% for Cameia, recognizing the differences that exist in Block 20 and 21. So obviously, both of these fields are very economic under current terms.

Evan Calio - Morgan Stanley, Research Division

That's direct and very helpful. Then my second question, the release discusses a potential first oil at Orca in 2017 on a 2014 project sanction. I see you have the appraisal well planned in 2015. So my question is, why do you expect that you don't have to drill the appraisal well like you are at Cameia prior to sanction? And why might that process be different?

Joseph H. Bryant

I think, unless I'm wrong, you twisted a couple of things there. What we said in the Cameia, first oil is 2017. And we're drilling that appraisal well right now, and we're using that information to rightsize the ultimate facilities that we put on that FPSO. And then on Orca, we said that we would drill an appraisal well next year. And I don't think we quoted a first oil date for Orca.

Evan Calio - Morgan Stanley, Research Division

Maybe just lastly for me. The reported flow rates were very positive today. Just -- can you just generally talk about reservoir quality as you compare the sag, syn-rift and the carbonate found at Cameia, and I'll leave it at that?

James H. Painter

Yes, Evan, this is James Painter. I'll handle that one for you. We look at the rocks out there. We're very comfortable that at Orca, just like in Cameia, that things are in that 20,000-plus range as we start looking at what these wells will produce. We see similar rock types in Bicuar. And we get more and more as we look at more data that Bicuar is very similar to that. As well as, you saw the test at Lontra which had great rock properties as well.

Operator

Our next question comes from Al Stanton with RBC Capital Markets.

Al Stanton - RBC Capital Markets, LLC, Research Division

You've been very consistent on your commentary of the oil discovered today, the 1.1 billion to the 2 billion is in line with your previous presentations, but I noticed in today's presentation that there's now a plus sign. So the Orca guidance is 700 million barrels. I'm intrigued by the upside that you're hinting at there. But equally, I noticed that Lontra in the cartoon is looking a bit skinny these days. And I'm just wondering if there's any changes you want to imply there as well?

James H. Painter

I'll do the Orca one. This is James again. I'll do the Orca one first. As you look at it, we have some uncertainty there on exactly where or if we saw the oil-water contact in the first well. And that's the greatest area that we could see growth that's lower, higher. That's where you're looking at that plus is where we think that will lead us in the -- in that reserve name of having the plus after the 700 million barrels. And as for Lontra, I just think you're reading the cartoon, there's no change. No intended change from anything that's there for many of the things you're looking at from a Lontra sizing.

Al Stanton - RBC Capital Markets, LLC, Research Division

Okay, fair enough. And can I just have one follow-up question on John's comment. Did I hear you right when you said that the present value of a barrel is about $8 on an entitlement basis?

John P. Wilkirson

That's correct, which is very consistent with what we have seen all along. And what we will continue to see, of course, is as we move these fields to sanction and we get closer to production, those values will increase as well. But today, given our current estimates of field sizes, development approaches, timing, price and cost, et cetera, that we're seeing about $8 for both of those fields on an entitlement barrel basis.

Al Stanton - RBC Capital Markets, LLC, Research Division

And if I tie that in with your comment at the end of your prepared remarks about JVs and divestments, are you hinting at all about a reallocation of resources from West Africa to the Gulf of Mexico?

John P. Wilkirson

We constantly look at how we potentially can prioritize our investments in our portfolio. I think we've been very clear all along given now 9 significant discoveries gives us a lot of flexibility to think about what those options should be as we prioritize. So it could be a broad set of different options that could occur over time. But yes, I mean, as I said, it could be anything from JVs to outright sale of assets. It's good, and we're going to see what we can to maximize the value of the assets to our shareholders.

Operator

Our next question comes from Ryan Todd with Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

A question on the Cameia development hub. I realize it's early, and you'll probably talk about more of this at the analyst meeting, but in talking about the hub and the potential tie-ins of Bicuar and Mavinga there, did you say you were thinking more of a size of 100,000 barrels a day? Is that a step-up from the earlier 80,000 that you had talked to? And that's -- is that referring to the first -- so the first phase of development is effectively getting upsized? Is that kind of the right way to think about it? And how does that impact the number of initial wells that you drill out of Cameia and the timing?

Joseph H. Bryant

Ryan, this is Joe. I don't think this really changed anything there. We've always said that a nominal FPSO sizing is around 100,000 barrels a day, and our current thinking is consistent with that. With regards to tying back Mavinga and Bicuar, I think, where I sit today, Mavinga is certainly a high-probability candidate to be tied back given its lack of scale that would be in standalone development. Bicuar, what we look at there pretty closely is how we can feather those barrels into the haulage in Cameia to improve capital efficiency versus the present value of building a separate standalone hub over there. We haven't done that work yet, but that's the way we think about hub-and-spoke developments is just how do you maximize capital efficiency and create the most value for the shareholders.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. I appreciate that. And then if I could ask -- in the Gulf of Mexico, the 5% interest pickup in Yucatán, can you talk a little bit more behind -- the rationale behind picking up that interest? And would you like to pick up more? Should we expect to see you possibly get more active in the Gulf in terms of picking up interest in existing prospects or blocks?

James H. Painter

I think the Yucatán is a very easy answer. We had a block of acreage that was potentially a part of that structure. And so it was more of a -- kind of a unitization of interest, rather than something we went out to go do. But as we looked at it, that was very attractive to us with the knowledge we have at Shenandoah to go become part of the Yucatán appraisal. And as we look around the Gulf, much like we do around the world, we'll do what we think is right for shareholder value as we go through there and look at things to make our portfolio better or as we do things, just to do the maximum value we can add for shareholders.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And so I guess, in your view, obviously, with Yucatán and Shenandoah, your view there is being a potential unitization, the advantage between...

James H. Painter

Not insinuating that at all. Strictly that we had a block of acreage that -- as Yucatán 1 and the new data and the maps we looked at became part of the outline of that prospective field. So strictly looking at blocks outside of Shenandoah that were part of Yucatán that we had a working interest in, that became -- the way to move those forward was to join with the Yucatán partners and make a unit for us to go together. And our percentage then of that unit is a little over 5%.

Joseph H. Bryant

So to be clear that we joined what in effect a Yucatán unit, but it sounded like your question is, do we think that Yucatán and Shenandoah are going to be unitized. We're not saying that right now.

James H. Painter

Exactly.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. Then I guess, one last one on the -- the information was helpful on Orca. The sheer size of the structure is impressive. I guess, the one question is, there always seems to be -- given the size of the structure, the resource estimate always seems to be smaller than I would have expected for a structure of that size. Is that -- is that purely a function of the oil-water contact? And they're relatively thinner in that pay column, up at the top of the structure? Or is that, you referenced some uncertainty around the oil-water contact, obviously. I mean, any thoughts around that, that could help?

Joseph H. Bryant

No, it's just simple math, is what it is. You have the things that go into recovery are the gross thickness, the net thickness, the number of acres and your recovery factors. And we factor all that together, you get, as we sit here today, it's 400 to 700. As James said, we're hopeful that, that will grow. But today, that's what we would kind of conservatively estimate as what the math will tell you.

Ryan Todd - Deutsche Bank AG, Research Division

And the 650 feet, you referenced 650 feet of thickness earlier, was that a gross structural thickness?

James H. Painter

Yes.

Joseph H. Bryant

Yes.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. At a high point on the structure or is that kind of an average gross structural thickness, I guess, if there is such a thing as an average?

James H. Painter

It's what we found in the wellbore at the point we drilled.

Operator

Our next question comes from Matt Portillo with TPH.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 quick questions for me. I was wondering if you could give us an update on how you're thinking about kind of your well cost trends, both in Angola and in the Gulf of Mexico? I know you guys have had some record-setting wells, particularly in Angola, so just want to get an update there on how things are progressing and how we should kind of think about kind of the development well cost?

Joseph H. Bryant

Great. Van Whitfield's here, and he'll be glad to address your question. Go ahead, Van.

Van P. Whitfield

Yes, just for your question, I think it's indicative of the fact that for example, in Angola, this is, well, our seventh well. And one of the things that we've said from the very start with the right people, equipment and focus, we should be able, and we fully anticipated being able to drive our cost structure down. So you're seeing us leverage our learnings through good technology and hydraulics and having equipment that maintains a higher rig time, that we are, indeed, able to drill these wells quicker. I want to emphasize, there is no sacrifice whatsoever though on our focus for safety or protecting the environment, but the team has managed to optimize the well design. And as we continue to refine it, we're just seeing better performance. It carries over into the Gulf of Mexico as well. These are all extremely complicated wells, but we tie together all of our subsurface and drilling expertise, and we just continually work on a realtime basis to optimize the performance and get these wells drilled.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a second follow-up question with regards to the Gulf. As you guys continue to progress along on your technical evaluation of the Lower Tertiary, I was wondering if there's any technical hurdles you're seeing right now just given kind of the depth and pressure and how you think about kind of any use or need of kind of proppant in the wellbore? Just wanted some additional color there, if you guys are seeing any technical hurdles?

Van P. Whitfield

We're not seeing any technical hurdles, Matt. This is Van Whitfield again. I mean, the obvious issue we're dealing with, we are seeing some higher pressures on these deep wells, and we're working with some of the wellhead producers to ensure that we can have something probably in excess of 15,000. But it's not anything we see out of the limit of existing technology. And it should not prevent us from drilling these wells safely, and that's our primary focus.

Joseph H. Bryant

I would also add that there's real advantage to us to be really participating in Shenandoah and following up Shenandoah with our Inboard Lower Tertiary developments at North Platte, et cetera. And we don't want to blaze the trail on some of this stuff, but we like participating with others as we all blaze the trail together. So we feel pretty good about where the technology is and where it's going.

Operator

Our next question comes from Richard Tullis with Capital One.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Joe, going back to the $8 present value estimate on entitlement barrels. How does that roughly change, say, with every $5 or $10 per barrel change in oil price? And what price were you using in that calculation?

John P. Wilkirson

Richard, this is John. The assumptions are pretty much today's commodity price assumptions for what Brent crude would be trading for in West Africa, which is a world benchmark. As far as other factors, what we'll do during the Analyst Day, we'll get into more detail on what's behind these numbers and give people an update on how we look at the -- how the economics are actually working and the differences between Block 20 and Block 21. But as I mentioned earlier, that's really where we are. As far as the overall price sensitivity, it's relatively insensitive to price. And again, that's one of the features of the production sharing contract is that -- the way the contracts work, we get a disproportional share of the returns early on, and it's relatively insensitive to price, especially compared to the Gulf of Mexico.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Okay. I see. Because I was looking back at some of the old data, and it looked like you're estimating $6 to $8, I guess, a barrel based on $75 oil. So I didn't know if there was much of an impact from current pricing. Also, I missed the very beginning of the call, Joe. When did Anchor and Yucatán well spud?

Joseph H. Bryant

Gosh, they both were in the first quarter. I can't give you the date. But they were -- I honestly can't remember. They've both been drilling -- I guess if I had our drilling report in front of me, I could tell you, but first quarter is the best I can do for you right now.

Richard M. Tullis - Capital One Securities, Inc., Research Division

Are these AFEs -- how the costs running versus the AFE so far?

Joseph H. Bryant

Oh, we don't have any worries right now. And specifically, we would refer you to the operators to talk about cost and what their AFEs.

Okay. I don't think there's any more questions in the queue. I do want to thank everybody for joining us today. And I hope you'd agree that we're off to a great start in 2014. We continue to deliver on the promises that we made to you all. And most importantly, we look forward to seeing you in New York on June 4 and answering more of your questions there. Good luck everybody and take care. Bye.

Operator

Thank you. This concludes today's call. All parties may disconnect. Have a great day.

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