XOM adds a $12.7B Guyana offshore project

850,000,000 * $87 = 74 billion. 12.8 billion investment. 74-12.8/12.8 = 477% profit margin.

Not bad.

There was IMO an interesting exchange on that very topic during SDRL’s Q4 CC:

“ Kurt Hallead"

So maybe on a follow-up to that, right, in the context of economics, right? So we've seen a lot of third party data out there that shows that ultra deepwater projects in multiple basins are generating 30% plus returns at $70 Brent and are breakeven at $40 Brent and below, again, I've heard numbers lower for Guyana and Brazil, et cetera, right? So another set up here is that beginning some questions around how much pushback will the offshore drillers get on pricing improvement in the context of how that impacts overall drilling economics. So can you give us a refresher as when you think about the all-in spread rate for an ultra-deepwater rig, what is the percent of project economics that the rig represents?

Simon Johnson

Look, it's a difficult question to answer concisely, Kurt. I think the issue is that the operators, there's a wide variety of projects in their portfolios, some near term tieback opportunities that are much more driven by rig rate. And then you're looking at big multiyear field developments where the rig rate is relatively unimportant as a proportion of the total cost. So typically, the rule of thumb we use is that the spread rate these days is typically about $1 million a day. And with rig rates tracking as they are at the moment, close to $500 a day, we represent about 50% of that total cost mix, but it does vary according to the project. What I would say though is and what I think is more important than how much of the spread cost is in the rig rate constitutes? What I think is more important is the fact that all the understanding that the operators are constrained in terms of their capital allocation by their desire to return money to their shareholders. And I think that really is the more important thing rather than any sort of ultimate rate level. So they're wanting to reward their shareholders and some of our major suppliers are in a similar boat. And increasingly, as you've seen with our share repurchase agreement, we're also focused on that, too. So I never have seen such synchronicity through the value chain in that regard. So when we're thinking about how our rates might sort of drive activity, will demand get pinched out at some point? Well, conceivably, yes. But really, I think we're more focused on how these project economics stack up relative to the return profile that our principal customers are offering their shareholders. So yes, I didn't quite answer the question, Kurt, but hopefully, that gives you a bit of color.

Kurt Hallead

Now there is one more follow-up, if I may, right, is that the other dynamic here, I would have to imagine, right, is that when an oil company is assessing their future projects and assessing -- the guy says, okay, what rigs are available that have the spec that you want et cetera, et cetera. I really have to assume when they go through that budgeting process, they're not looking in the rearview mirror with respect to potential price of a rig, right? And I have to imagine that they're looking at different ranges, right, and what they may be willing to accept, right? But I have to imagine that they're not looking at these projects and saying, I can only do them at $400,000 a day. So again, you have some like -- am I completely off base in that process? And I guess the real answer to that question is are customer, the oil company customers factoring in? I have to imagine they're factoring in some sort of price increase for rates, so when they assess these projects. Any -- do you want to set me straight on any of that?

Simon Johnson

No, no. I think we're in all agreement with you. What I would say is different technical specifications, the customers' ability to make active choices there declines as the market gets tighter. And I think you also see less price discrimination between rigs of differing specification in a tight market as well. So care to add anything, Samir?

Samir Ali

I'd say the clients claim that our rig rate makes a huge difference to their project FIDs. But in the reality is no, they don't, right? I mean, the projects work, it's just making sure that they can get all of their other equipment put together and through the process. And to Simon's point, it's a return on capital for them, right? It is, does this make sense for their capital. But in terms of rates, we'll get beat over the head that it makes a huge difference, but the reality is it does not really move the needle.”

Looks like XOM wants to buy all of Guyana's offshore black gold. Also, my guess, these estimates are low balled.

And now this...

Cost estimate for Exxon’s Whiptail project slashed by US$200 million
By Kemol King - April 14, 2024
oilnow.gy/featured/cost-estimate-for-exxons-whiptail-project-slashed-by-us200-million/

Kemol King is a journalist with six years of experience in Guyana's media landscape. He covers the oil & gas sector and its impact on the country's development.

ExxonMobil’s cost estimate for the Whiptail development, recently approved by the Guyana government, has been slashed by approximately US$200 million. The project is targeting production of 850 million barrels of oil at 250,000 barrels per day (b/d).

At the stage of submission of the environmental impact assessment (EIA) for the project in the second half of 2023, the document had indicated an estimated cost of US$12.933 billion. However, at project sanction, ExxonMobil Guyana said the project estimated cost was slashed to US$12.7 billion.

Development   Estimated Cost $  Production (b/d)

Liza 1                 3.5 billion             160,000

Liza 2                 6.0 billion             250,000

Payara                9.0 billion             230,000

Yellowtail            10.0 billion           250,000

Uaru                   12.7 billion           250,000

Whiptail              12.7 billion           250,000

TOTAL                 53.9 billion         1,390,000

Table shows estimated costs of each Stabroek Block development

Exxon had also slashed development expense estimates for the Liza project, from an early US$4.4 billion to an eventual US$3.5 billion. The oil major, along with Stabroek Block partners Hess and CNOOC, had therefore saved approximately US$700 million on the first oil project’s development.

The Exxon-led consortium has now committed almost US$54 billion in development costs alone to six projects in the Stabroek Block, aiming to produce more than 1.2 million b/d once Whiptail ramps up to its target production of 250,000 b/d. While current numbers show combined production offshore Guyana could produce almost 1.4 million b/d by 2027/2028, ExxonMobil intends to pursue production optimization which could take output closer to 1.5 million b/d.

The Stabroek Block partners are also considering a seventh project.

Enjoyed freakmaster's excerpt from the SDRL CC above.

I agree that producers negotiate with an attitude of frugality, but in the end,
their reserves, in the aggregate, are declining and they need the rigs to drill
for oil to replace their depleting oilfields. Drillers are increasingly exploiting
a developing "seller's" market for rigs as availability gets tighter and tighter
short of paying for reactivations.

Reading Blitz's post above about the cost and production figures for the 6
Stabroek developments, it helps to put them in perspective when you consider that
once all 6 are producing, they'll be generating between $35 and $40 billion per
year in oil revenues before production costs. What's interesting, is that the first
Liza development cost only 27.5% as much as whiptail is going to cost and, adjusted
for it's lesser production, it comes to 43% the cost of whiptail, barrel-for-barrel.
But considering that drillships that were going for $200k per day 4 years ago this
coming summer are now hitting $500k/day now, that sounds about right, assuming that
other ships like tenders, etc. have proportionately higher dayrates as well.

Blitz's table of the 6 projects provides color into the impact of higher dayrates and 
other costs on project economics, but when you consider the revenue those 6 
projects will produce, one can easily see why $500k/day drillship rates still works.

not sure about the sky but definitely a double by the end of 2025

"The sky's the limit" is a pretty stratospheric phrase ( ) but I would certainly posit
that a "seller's" market will continue the march toward higher dayrates and some 
eventual customer-paid or customer-contributed reactivations.  

Rising dayrates are essentially a "barometer" of an increasingly seller's market.  In
a buyer's market, dayrates would be under pressure.

So far, "buyers" have been putting up a lot of resistance.  Recall Jeremy Thigpen's 
comment last fall that customers are "violently opposed to $500k dayrates", yet 
here we are, with a number of 2024 contracts coming in above $500k.  Customers
have been reacting by pushing project timelines, which is evidenced by steadily
lengthening lead-times for new contracts.

  As an example, they finalized the contract for Invictus in Mexico last summer, but that
project doesn't begin until well over a year from now.  That's why they're teasing the
market with these onesey-twosey contracts for Invictus and trying to take advantage of the 
increasingly seller's market for rigs as high-tech as Invictus.  There are only 14 
drillships on earth as capable as Invictus.

Another example of that is that Petrobras began inserting enough time for rig 
reactivations into their E&D timelines last year.  Doing that also doubles as providing
enough time for long lead-times, but at this point, lead-times for hot rigs and 
lead-times for reactivating a rig are becoming one in the same.  In fact, if Invictus
is anywhere near where lead-times are going, it's getting to the point where a 
customer will have to wait a lot longer to spud with a currently hot drillship than they
would if they contracted to re-activate a cold-stacked one!

Another counter-measure customers are using to help forestall the seller's market
is to settle for lower-spec rigs in situations where they would rather rent the best.
Given Transocean's overwhelming leadership in floater technology, as evidenced by 
it's dominance in drillships with main-hoist hookloads at 1,400 short tons or higher, 
it's actually detrimental to have customers substituting lower-tech rigs in order to
save money.  That's why I'm a bit perplexed as to why the 6th generation Inspiration
drillship still remains warm-stacked.