Recent Company Earnings:
November 3, 2016
Net Income Up 93% and Production Up 3% While Capex Stays Under Guidance
Spanish energy company Repsol (ticker: REP.MA) reported adjusted net income for the quarter of €307 million, 93% higher year-over-year. CFO Miguel Martinez San Martin cited the company’s improved year-over-year results as demonstrating “our resiliency in the lower part of the commodity cycle.”
Production from the Upstream division averaged 671,000 BOEPD, lower than the previous quarter average of 697,000 but 3% higher year-over-year. Average 2016 production is still forecasted to reach 690,000 to 700,000 BOEPD, in line with guidance.
Total CapEx for 2016 is expected to be below guidance of €3.9 billion as a result of “ongoing project optimization, strict cost control and the referral of non-critical in business.”
Updates on Key Assets
Production increases were supported by the acquired Gudrun assets in Norway, the ramp up of the Cardón IV project in Venezuela and Sapinhoá in Brazil, and higher production in Peru. Volumes were impacted by the ending of production in the Varg field in Norway and by planned maintenance in Trinidad and Tobago, Malaysia and Vietnam and a lower working interest in the Eagle Ford.
Fourth quarter expected developments include the start-up of Lapa in Brazil and the ramp up of production in Trinidad and Tobago.
2016-2020 Strategic Plan
Martinez also gave an update on the company’s 2016-2020 Value and Resilience Strategic Plan. “Year-to-date, our delivery on the strategic objectives has maintained a good pace and by year end we expect to surpass some of the principle KPIs set for the year. By the end of the quarter, projects have commenced that will secure our original savings target for the year,” said Martinez.
“The progress achieved in the first nine months of the year put us on track to deliver well over our previously revised €1.2 billion target for 2016. In fact, we now believe an accelerated target of €1.4 billion is achievable this year.”
Also in the quarter, synergy projects delivered 90% of the run rate target for the year, with more than 80% of the action required to capture the $400 million run rate for 2020 already in place.
The company’s divestment program has already has already surpassed the €3.1 billion target set for the end of 2017. The sale of its 10% stake in Gas Natural, a Spanish gas utility, to Global Infrastructure Partners puts total proceeds and benefits captured since the plan was presented in October 2015 at roughly $5 billion.
Q: Could you provide a bit more color on where you think you’ll end up for this year and in 2017 in terms of CapEx?
REP: I estimate we are going to end up this year around €3.5 billion. And regarding 2017, we have not finished yet the budget program, but I estimate that we are going to be around that figure as well, so €3.5 billion I think is a figure you can put in your models.
Q: On your North American Upstream segmental reporting. It looks like decent profitability in the third quarter despite some lower volumes and obviously lower commodity prices. Is that an improvement in the cost structure of that North American Upstream business? Could you say if it’s Canada or its U.S. specifically? And is an increase going to happen as we look into 2017 for the U.S.?
REP: I think that the advantage we have had in this year were based in prior decisions. I mean first, the impairments of the Mid-Continent that were strong and have reduced the depreciation. That has been a factor. So lower technical amortization. And in Eagle Ford is true that the agreement with Statoil which has been with the group, instead of having two operators, we have just one operator. And advantage per barrel we are obtaining as our first estimate is little around $10, $10 per barrel having just one operator and also having just one rig. So, I’ll say, we have lower volumes, but the cost structure is improving.
Q: On the upstream, where do you think breakeven can get to given the lower CapEx spend, and what is the split between sustaining and growth CapEx in the upstream?
REP: I think that that’s something that depends much on your CapEx program. So, it’s not an easy question to be answer in straight. I mean, any project that you develop day one, you invest and you don’t produce. So, it’s not that easy to say that’s my breakeven. We can talk about breakeven of fields that are already producing, we can talk about our breakeven thinking in the long-term, but it’s not a so simple as to say, well my breakeven today is $65. So, it’s not that easy. What I can show is that you have the results of the Upstream division this year and you have the average price. And you can see that we have been more or less even at today prices and this is the best approach I can give you. And the split between sustaining and growth CapEx, there we have a couple of advantages, I think in comparison with our peers.
The first one is that our growth has come a) because of the acquisition of Talisman, we have doubled our size. And I will say second, if you remember the 10 projects for former Repsol, they are either full invested or almost as Lapa and that will come on-stream by the end of this year. And [ph] Regen that will come – will produce their first gas next year.
But we have also the ramp up there. So, CapEx is going to be small, while increasing productions going to be important, this ramp up processes. But if I have to give a split of all the CapEx between what is growth and what is based on existing reserves, I’d say it’s a 40-60, 40 for growth and 60 for base reserves or 35-65 for Q1, two-thirds, one-third to the limit.
Q: Have you been able to get back into Libya at this point or was there any update on the stages of your facilities or operations there? And then more broadly just
REP: Well, in relation with Libya, there are no news. We have data that the installations remain stable. I mean there has not been any damage to those. And we know that politically talking especially the U.S, Italy and France are trying to put pressure in order to solve and help into a solution, but till now, no major changes. So, we keep it at zero production there.
Q: In the upstream, given some of the changes you’re making to the capital spending price fall for this year and to next year, should we be thinking about any decline rates or should we be thinking about decline rates differently?
REP: Our declined rate maybe for the existing assets a little bit below 4%. That’s the average. I think that is not that big, because a) we are quite gussy and B) some of our projects are – most of them are plateau. So, no major changes. And capital spending profile for the next year, I have to wait as mentioned before in relation with the question about the U.S. CapEx. I have to wait to answer the question till I have the final figures from 2017 budget.
Q: You had quite a big drop in your profitability in Latin America, in upstream, just wondering if it’s entirely related to reduction in gas prices, was there another item we should consider?
REP: The drop in profitability basically refers to in one hand Trinidad and Tobago, I mentioned that there was an adjustment from prior quarters that was executed this third quarter, and for sure also the impact of the oil price in the gas we sell from Bolivia, that is indexed to the oil price with a lag of six months going to Argentina and three months going for the gas that goes to Brazil, so this is the other factor that has reduced the results in Latin America.
Links to the company’s earnings release, conference call, and investor presentation are provided.
PDC: Ready to Integrate and Develop Permian Assets in 2017
PDC (ticker: PDCE) CEO Bart Brookman summarized Q3 as a “terrific” quarter for PDC on its 3Q earnings call today.
Brookman called for increased production and activity going forward in both the company’s core Wattenberg and Delaware acreage.
Third quarter production increased 39% year-over-year to 65,000 BOEPD, despite a 10% year-over-year decline in CapEx, which was $118.0 million. Per Boe lease operating expenses declined 27% year-over-year to $2.33.
Forty gross operated wells were turned online, including the company’s first two-mile lateral wells in the Core Wattenberg in Colorado.
The company spudded 16 extended reach lateral wells in the Wattenberg, continuing trends seen throughout the basin. Brookman noted that “these projects are becoming increasingly prevalent in our Wattenberg operating plan and will be a key part of our 2017 capital budget when blended with the recent acreage swap.”
PDC’s $1.5 Billion Core Delaware Acres are Transformative
The main transformative event for PDC this quarter was its acquisition of 57,000 net Core Delaware acres in Reeves and Culberson counties for $1.5 billion, to be closed by the end of the year. Roughly $1.2 billion was financed through a mix of public equity, senior notes, and convertible notes.
PDC Expects “Top Tier Growth” in 2017
While the 2017 budget has not been approved yet, the company plans to achieve 30% production growth. In the next year, one rig is planned to be added in the Wattenberg Field along with one in the Delaware, resulting in four rigs in the Wattenberg and three in the Delaware at the end of 2017.
The Wattenberg is expected to provide “reliable production growth,” supported by technical enhancements in completions and drilling, efficiency gains supported by the company’s recently completed acreage swap with Noble, and a larger focus on extended reach drilling.
In the Delaware, the company will be running Wolfcamp A and B horizontal drilling programs to hold acreage and better understand benches outside the Wolfcamp. Midstream asset strategy for the Delaware is expected to be fully defined by mid-year 2017 and multi-well pads are expected to become a larger part of the company’s operating model.
Q: You talked about the performance, how you’ve been varying the sand concentration in a lot of the Wattenberg wells. It sounded like you’re not seeing any difference in terms of the performance right now?
PDC: You are correct. You can see on the graph, we really don’t see a lot of difference between the two sand concentrations that we have on that LDS pad. It doesn’t mean that’s an absolute answer yet, but we’re definitely more focused on the other parts of the testing that we did there because of that, which puts us more pointed toward the shorter stage lengths and dealing with our different flow back method, both of which we think contributed fairly significantly to that uplift.
That’s what we’re really testing through the end of the year on the various projects we have are that variation of stage length and flow back method, but we’re also still running some tests at the 1,300 pounds per foot type range. We’re not planning to go up to those upper numbers the rest of this year but probably will reconsider that. I know some of our peers out there in the Wattenberg and obviously down in the Delaware we’re seeing the same thing, increasing sand concentrations, but we’re looking at the data and right now it’s not encouraging us. It’s also the more expensive part of the additional costs associated with these tests we’re running.
Q: Do you guys have any update on the Raise the Bar initiatives? [EDITOR’S NOTE: “Raise the Bar” is the sponsors’ name for the initiative that is currently before Colorado voters proposing a constitutional amendment that will significantly strengthen the requirements for citizens groups to land future proposed constitutional amendments on the Colorado ballot—also known as Amendment 71. Raise the Bar was proposed after a number of citizen initiatives limiting oil and gas development in Colorado’s recent election cycles, most recently by imposing a 1,500 setback and giving local governments control over oil and gas development, came close to making the ballot. If voters would have approved the two amendments, the State COGCC showed how the oil and gas industry would have been essentially shut down in the state.]
PDC: We’ve been very involved in the campaign around Raise the Bar. The best I can say is things look slightly favorable in that initiative right now.
Q: You guys have everything’s held by production in the Wattenberg. Would that be where you would potentially ramp down if needed, if commodity prices don’t cooperate?
PDC: If oil were to drop into the low 30’s, and that was our outlook long term, we would use the Wattenberg as our flex capital point. Obviously next year are going to have more intense capital into the Wattenberg than the Delaware on a total basis, so the Wattenberg would definitely be where we would slow down if we need to back off on our capital spend, and once you cover what it takes to hold the acreage.
When we look at this overall, we really need to run those two rigs pretty consistently in order to hold the acreage. I feel like we can do that, well into the $30 per barrel range of pricing. At this point we’re still contemplating adding a rig in each area. We probably don’t need to add the third rig to hold the acreage in that area, and we obviously would not add a fourth rig in Wattenberg if prices were projected to be low for a long period of time. But it’s very flexible in Wattenberg. I would say it’s much more of a requirement in Delaware that we run at least the two rigs.
Q: Is there a difference in how those Wolf Camp A completions that you highlighted performing above the type curve were completed versus what was used to develop the million BOE type curve?
PDC: Yes. What we’re dealing with in terms of the type curve is many of the older completions still and these recent completions were conducted by Arris. But what you see there is a 2,000 pounds per foot of sand, 100 feet between stages and we really see that changing the productivity. But also, Arris’ flow back method, soon to be ours, approach to this has been similar to the way we’re approaching things in the Wattenberg.
Q: What’s the estimated cost for a two-mile lateral?
PDC: We’ve got about $9.5 million and that’s on a single well. When you look at the two mile multi-wells we think we will get down around $9 million. And again, that’s really early. I hope everybody recognizes we’ve got a lot to learn on that.
Q: Can you discuss what the cost of the three Wolf Camp A wells were and how that binds up to your expectations? And can you see yourself being able to bring those costs down once you take over operations?
PDC: I would believe they’re probably close to that $6.5 million kind of range that we put out for a one mile lateral. In terms of cost, even within what we’ve shown, we feel like we can drop several hundred thousand dollars off a well just by going to multi-well pads.
There’s room for improvement on getting a rig running consistently and getting the efficiency associated with that as a part of the equation. On the completion side, when you drill a single well you don’t get any efficiency on a completion, particularly when you’re doing a plug-in perf operation. It’s very inefficient on single wells.
Q: How do you expect the oil cut to vary over the life of these wells?
PDC: Thus far, the three-phase basis as we talked about is around 60% crude oil. We are very encouraged by that, and it’s in the range that we outlined as far as the oil mix with the roll-out. In this eastern area, we were anticipating between 50% and 70% crude oil, so it’s right in the range with that. There could be some variances a bit overtime, but where we sit today and thus far with the data that we have after the 120 days we’re right down the fairway with that range.
Q: I’ve heard that the higher sand concentrations may have a more favorable impact where the GOR is a little bit lower. Any thought as to where you are located in the play?
PDC: We’re going to be focusing most of our drilling in that blocked up acreage that we have after the acreage trade. LDS is very significant on how we see things going forward. As we move into the more oily areas we could see this change and need a little more sand concentration that near wellbore propped permeability. That’s a possibility but we really aren’t there and probably won’t be out in that area much if at all this next year. So it may not impact us as much as it might others.
November 1, 2016
BP: Cost Cutting and Asset Disposal Continue, CapEx down 63% Year over Year
In BP’s (ticker: BP) 3Q earnings call, CFO Brian Gilvary saw progress towards market rebalancing, echoing CEO Bob Dudley’s comments earlier this month at the World Energy Conference.
“The physical market appears to have moved broadly into balance with daily oil production broadly in line with consumption. Oil inventories remain at record levels and will decline gradually next year supported by continued demand growth and sustained weakness in non-OPEC supply,” said Gilvary.
“By 2017, the company aims to “reestablish a balance in our financial framework where operating cash flow covers capital expenditure and a current dividend in a $50 to $55 a barrel price range.”
Excluding Russia, 3Q reported production was 5.9% lower year over year. The company’s estimated share of Rosneft 3Q production was just over one million barrels of oil equivalent per day, a 2.7% increase year over year.
CapEx is expected to be roughly $16 billion in 2016, lower than original guidance of $17 – $19 billion, while improving capital efficiency will push 2017 spending towards the lower half of $15 – $17 billion, a 30% to 40% drop compared to peak 2013 levels.
Despite reduced CapEx, the company is currently on track to start up five major projects this year, with four already online, and eight on track to start up in 2017. “Looking out to 2020, more than 90% of the 800,000 barrels of oil equivalent per day of new production that we expect to bring online has passed through the final investment decision and are either being completed or are well under construction,” said Gilvary.
Deepwater Horizon Payments Supported by Asset Disposals
Charges associated with the Deepwater Horizon accident and oil spill continued to impact company results this quarter. These stem from the settlement of federal, state and local government claims in 2015 and additional provisions this year, when a reliable estimate for all the remaining material liabilities was determined. This was discussed with analysts on the call.
Q: “You talked about the offsetting the Macondo cash outburst with disposals next year. Could you just give a bit more confidence that can be achieved and a bit of flavor in terms of where you see disposals or disposal potential in the BP portfolio going forward?”
BP: “In terms of disposal proceeds, we’ve set a target this year of $3 billion to $5 billion. We have a number of projects in train that we’re comfortably get you to the $5 billion over an 18-month period. Some of those will flow into the first quarter next year. That will underpin $2 billion to $3 billion next year. A lot of the projects we’re looking at are midstream assets that we own globally. You will see that we announced the sale of our property assets down in Sunbury recently which we’ve sold with significant proceeds.
In terms of Macondo liabilities, this is a big, lumpy year with the settlements from last year that originally transacted this year and the private settlements that we’ve managed to resolve, along with the payments next year. And then we get into a steady state of $1 billion a year. Actually, you only need about $1.5 billion of disposal proceeds beyond 2018 to cover it, although, we’ll probably continue to churn at $2 billion to $3 billion. A lot of that churn just comes out of looking at the portfolio as we take options to move certain commercial projects, other projects within the portfolio may have lower returns. And therefore, we’ll look to move out of those assets.”
BP Quarterly Highlights
- Trinidad Onshore Compression project sanctioned, representing the third final investment decision this year.
- First platform jacket for Shah Deniz Phase 2 completed and installed, on schedule for 2018.
- Agreement announced for a second production sharing agreement with CNPC for shale gas in the Sichuan Basin in China
- Amendment announced of a number of concessions in Egypt that enabled the fast-track development of the Nooros field.
- Formation of their Norwegian joint venture with Det Norske completed in September.
- In Amenas Compression project in Algeria on schedule to commence operation in the fourth quarter, making it the fifth major Upstream project to start this year.
- Decision not to continue exploration program in the Great Australian Bight, off the south coast of Australia, announced in October.
Q: What can we expect going forward as the annual or quarterly run rate on Gulf of Mexico cash payments into 2017?
BP: We’ve got a schedule we’ve put out from all the various settlements from last year 2015 and from the criminal settlements back in 2012. There are specific payments in certain quarters going forward. The only uncertainty will really be around how the payments that go out associated with the class action lawsuit settlement, the PSC settlements, particularly business economic loss claims. We are accelerating a number of those at the moment.
We also resolved a lot of private claims through the second and third quarter of this year, which you will see come out in the payment schedules. They are likely to run down over the next couple of years, so they are the only things where there’s any uncertainty. But now into sort of final stages of that fund, I think we’re down from the peak on business economic loss claims. I think we had a 144,000 claims at the peak of which now we’re down to 25,000, but all 35,000 including claims linked to original claims. And they are being processed with a fairly rapid rate right now in terms of facility.
If the only uncertainty is around what the phasing looks like around the class action lawsuit settlements and how that payment schedule goes down, they are being covered by our disposal proceeds going forward. We already have close to $3 billion disposal proceeds along with the proceeds of next year. They will cover the bulk of the claims.
In terms of the forward trajectory on Macondo liabilities, the lumpy years of this year and next year and then we get in to the $1 billion a year, which is certainly those future schedules which will be sort of more like a sort of dividend for the Gulf State out to 2030 or so.
Q: On the U.S. onshore gas business with gas prices up at closer to the $3 level in the third quarter. Can you talk about the underlying profitability of that business given you have such a large kind of natural gas business there?
BP: In terms of Lower 48, we’re now running about five rigs the last time I looked, in terms of where the activity is. We’re continuing to reduce costs in that business, which is bringing the breakeven prices down. The key is really about what we learn about technology and how we run the business. We run it with a different financial frame to the rest of the group in terms of how it’s managed. And it is continuing, as you’ll see from the various quarterly numbers that we now start to release, get to be more and more profitable going forward. And of course, help somewhat this quarter by the prices if the prices come up. So, Lower 48, it really is about testing new zones, looking at innovative well designs. It’s really experimenting with that business and getting more comfortable with how we run the Lower 48 and reducing costs over time and the amount of capital that’s going in. But today, it’s running about 5 rigs, I think the peak last year is around 11 or 12 we had at one point.
Q: In a kind of sustained $55-plus environment next year, I know you have your CapEx range, but what’s the short cycle CapEx opportunity that you have? And how much capital could you put to work in a kind of $55-plus sales strong gas price environment if the opportunity arise?
BP: We’ve set a range on CapEx for next year. We’re now down at $16 billion for this year. We’re going to be below that in setting our plans for next year in the 15 to 17 range, and then, we’ll know that at 50/55, we’ll get back into balance. That means we’ve got about $1.5 billion of CapEx flex, which we’ll be able to deploy as opportunities arise, and those opportunities could be in terms of getting back to work on some of the onshore.
You have the obvious places you’ve looked out below 48 as you’ve flagged up in terms of where the gas price is. But that will be completely commercially driven. And then, of course, there may be other opportunities for us where we can access existing positions that we have where we can deepen, maybe going to some new areas. So, we’ve got flex within the capital frame to allow us to do that, which should of course, help with future growth beyond 2022 to 2023.
Q: On the $6.1 billion cash cost performance, are you able to break that down a little bit and sort of characterize where it’s coming from?
BP: On the cost question, they’re exactly the same. So, in the $6.1 billion, just over 40% is – actually about 45% come out of the upstream, 40% – 45% on the downstream and the balance out of corporate. Now, of course, some of the corporate costs are already sitting in the two segments, but they’re exactly the same in terms of the delta on the $6.1 billion.
There is still a big chunk yet to come through in the fourth quarter and into next year, which is really around the final upstream plan. But equally downstream has still got further restructuring plans in place. So, they’re about the same in terms of sources. That’s just symptomatic of how we’ve driven efficiency and reorganization across the whole corporation. So, it’s no surprise that they’re about the same. But you’re right. Previously, it was more driven by the upstream down downstream, but it’s now 50/50 now.
Q: As you wind down or normalize your exploration activity and go through this backlog of stock that’s still under appraisal, is there very much more to come in that, or will we start to see the exploration charge begin to of level out closer to the kind of level of activity that you’re actually now running at from a cash basis?
BP: In terms of exploration, as we’ve gone through the re-set of the company in the last couple of years, there is a big inventory of exploration intangibles that we’re working our way through. And you’re seeing that come through, if anything, it’s actually reduced compared to the run rate that we were seeing only in a couple of years ago.
We’ll try and give you more information around what that looks like around the fourth quarter results. But I can at this point say that we’ve reached a sort of stable steady state. Everything gets back to strategy and how we’ve reviewed what we’re doing around exploration strategy. We’re doing a lot less wildcats. There’s a lot more focus now on the infield developments.
The Great Australian Bight is a good example of this change. Ultimately, that was not commercial for the company. And if we stacked it up in the portfolio of options that Bernard and his team we’re looking at, the Great Australian Bight simply didn’t work and, on that basis, we stepped away. We’re still absolutely committed to Australia. It’s not about that location and we actually announced a license around a new access position we’ve taken in the North West Shelf.
It’s really about how we now sift and sort the portfolio of options we have. And as a direct consequence of that, some things we’ll view as not being commercial going forward. And, of course, they get taken through to underlying earnings in terms of exploration write-offs. But I can’t, at this point say where we are in the cycle given the size of the intangible asset base that we still have.
Q: Has anything changed in your mind about the Alaska LNG project, just based on looking at it in the last quarter and some of your partner’s comments.
BP: We still have 30 Tcf of approved resources up there, in terms of gas. I understand the most recent comments of some of our partners have made. I think gas is a great opportunity for Alaska going forward, and for those of us who have lived around and seen this project over many, many years, I’m sure we’ll have more machinations going forward. But there is nothing permanent at this point, in terms of where the point forward is, in terms of that stage in the resource space. But it is a great resource space, it’s covered, we know it’s being reinjected today. I think the short-term economics make it difficult, but in terms of long-term resource it may well be a great opportunity to bring it to market.
Q: In the U.S. onshore business, CapEx seems to be quite volatile from quarter-to-quarter and this quarter was particularly low. I was wondering if you could give a bit more color around what is driving that? And also what is a sustaining CapEx number for that number to the whole production flat over the next year or two on an annual basis?
BP: On CapEx, it’s down 63% year-on-year, which is completely driven by the planned investment schedule that the team had. They went through a period, where they did a series of experiments around particular types of activity around multi-laterals that they ran. That’s thought them a lot about some of the reservoirs. And actually, they are going to start revamping up and restarting investment in the third quarter. So, you’ll start to see some of the CapEx ramp up.
In terms of a point forward capital for that business, I was thinking something around $0.5 billion or north of $0.5 billion is what you’d expect going forward. And I think that when we first put the frame in place, we had up to $1 billion of capital allocated. But, again, it’s really a function of what are the options for us. That’s a great short-term opportunity. If we will have to ramp activity up quickly, let’s say, because of prices or because we have discretionary capital, that would be an obvious place where you’d start to do it.
So, it can take some of the float in terms of options for us depending on what’s happening in a short-term. It’s a great way in terms of getting short-term paybacks and high returns. And the more and more we learn about that business in a way in which it’s run, I think the more value we’re going to bring.
October 28, 2016
Records 3Q production of 3.8 million boe/d, $2.7 billion earnings
The world’s largest publicly-traded oil company gave its 3Q 2016 earnings call this morning. Jeff Woodbury, Vice President of Investor Relations, was on the call while CEO Rex Tillerson was not present.
The company logged earnings of $2.7 billion, a 38% decline from 3Q 2015, as well as capital and exploration expenditures of $4.2 billion, a 45% decrease from the same period. The corporation distributed $3.1 billion in dividends at $0.75 per share, a 2.7% increase compared with the previous year.
Total production was 3.8 MMBoe/d, with liquids down 5.1% and natural gas up 0.8%. In its Permian and Bakken assets, the company ran a total of 10 rigs in the third quarter with combined production of 240,000 bl/d.
A slide showing major upstream projects coming online in 2016 to 2017 is shown below.
Reserves Impairment Outlook
Woodbury further commented on the impact that low commodity prices will potentially have on reserves valuations.
“The low-price environment impacted our 2015 reserves replacement resulting in a 67% replacement ratio. This was the net result of natural gas reserves being reduced by 834 million oil-equivalent barrels, primarily in the US, reflecting the change in natural gas prices offset by liquid additions of 1.9 billion barrels.”
“Given that year-to-date crude prices are down further from 2015 by almost 25% on the SEC pricing basis, we anticipate that certain quantities of currently booked reserves, such as those associated with our Canadian oil sands, will not qualified as crude reserves at year-end 2016.”
“In addition, if these price levels persist, reserves associated with end of field life production or certain other liquids and natural gas operations in North America also may not qualify. We do not expect the de-booking of reported reserves under the SEC definitions to affect operation of these assets or to alter our outlook for future production volumes.”
Key 3Q Events for the Upstream Business
- ExxonMobil and InterOil Corporation announced an agreed transaction worth more than $2.5 billion, under which ExxonMobil will acquire all of the outstanding shares of InterOil. The acquisition will give ExxonMobil access to InterOil’s resource base, which includes interests in six licenses in Papua New Guinea covering about four million acres. The transaction is pending the outcome of a shareholder appeal of the court decision approving the transaction.
- In Guyana, the Liza-3 appraisal well was successfully completed in October, confirming a resource discovery in excess of 1 billion oil-equivalent barrels. Also in October, the Owowo-3 exploration well, located offshore Nigeria, confirmed a discovery of 500 million to 1 billion barrels of oil.
A slide showing a current schedule of projects in the pipeline is shown below.
During the Q&A session, the company answered questions on Capex allocations, potential U.S. shale acquisitions, macroeconomic fundamentals, chemicals demand, asset impairments, and the outlook for global LNG demand.
Q: Given the degree that CapEx is lower than you had guided, are you surprised by the degree of savings you’ve been able to achieve? And as we look ahead, where are we in this cycle of CapEx savings?
XOM: It’s trending towards an outlook of between $20 billion to $21 billion for the full year.
Q: What are you thinking about valuations in U.S. shale today?
XOM: We’re looking for opportunities that would create incremental value. These opportunities need to compete with our existing investment portfolio and provide accretive strategic long-term value to us.
Q: I know Rex had made some comments on London talking about a more subdued market over the next couple of years. Can you just talk about how you see the balances over the next couple of years, both from a supply and demand perspective?
XOM: Demand has been generally reasonably strong. I mean when you think about a 10-year average demand growth of somewhere between 1 million to 1.1 million barrels per day. Since 2014 we’ve seen demand growth in excess of that. So fairly reasonable demand growth in the recent past.
If you look, focus now on the first part of 2016, we still continue to be in an oversupply situation with production exceeding demand by about 1.1 million barrels a day in the first half. As we anticipated, we are seeing convergence in the second half. But I’ll tell you that as you continue to progress that, we’ll probably end up this year oversupplied by anywhere from a half million to 0.8 million barrels per day of supply. Now of course all this is going into commercial inventories. So as you move into 2017, you see that we continue to see convergence, maybe a little bit oversupplied in the year, but I’d caution that we’ve got to recognize that there’s still anywhere from 500 million to 600 million barrels of commercial inventory build since the end of 2013 that’s got to come out of inventory at some point. And then of course, there’s still uncertainties in the supply trend, some of the OPEC counties as well as the U.S. unconventionals, will have an influence on the supply and demand balance. So I think when you heard Rex’s comments, he was reflecting on all these factors as to how that will impact price in the near-to-medium term.
Q: Can you explain the rationale behind your new chemical complex in the Gulf? Is this due to liquids and other associated products coming out of your oil fields in the U.S. or is it just a separate economic decision?
XOM: Like most everything in Exxon Mobil, it all starts with our view on long-term energy supply and demand picture. And when you think about chemicals, the chemical demand growth based on our latest outlook has, from an overall perspective, chemicals growing about 1% above GDP; and from an ethylene perspective, we’re expecting that chemical demand will grow such that you add – need to add about 5 million tons per annum of new capacity per year. And to put that into hardware, that would be three to four world-scale crackers per year.
So that sets up the value proposition. First, as you know, we’re expanding the Baytown Complex to add another 1.5 million tons per annum of ethylene capacity, a corresponding investment at Mt. Bellevue adding derivative units to produce Exxon Mobil’s high-value metalycine and polyethylene. And then we announced, to your question, we announced a potential joint venture with SABIC to jointly own and operate a complex in the U.S. Gulf Coast that would notionally be an ethylene steam cracker to produce ethylene of about 1.8 million tons per annum and corresponding derivative units that would be built alongside that. I think we’re ahead of the game in terms of making some world-scale investments in this and a very strong component of our chemical business.
Q: Could you remind us what percent of your LNG volume is not under long-term contract? And given the slowdown in traditional Asian markets, particularly Japan, Korea and Taiwan, are you seeing more near-term opportunities in other regional markets? Do you have any incremental thoughts on European gas picture?
XOM: From our energy outlook we have gas growing about 1.6% and LNG growth just under three times where we are in current LNG capacity. As you go forward, our LNG business is a very important part of our portfolio. I don’t have a specific breakdown of our total gas production between pipeline sales and LNG contract sales, but recognize that a large part of our Asian gas coming from Cutter and Papua New Guinea is under long-term contracts and a good part of them are liquids-linked.
In terms of the markets, clearly the Asian-Pacific market is an important market for LNG. We’ve got a very expansive marketing organization to go and identify value opportunities. We are primarily interested in locking in long-term contracts, either a point-to-point or a portfolio sale. You may recall that before we take an LNG project to a final investment decision that we lock in a majority of those volumes in a long-term contract. We’ve really developed a very strong reputation and credibility with the buyers to our ability to deliver these projects on schedule, and our responsiveness to managing through the contract terms, we’ve got a new operation center that we put in place in Asia-Pacific to facilitate the transactions with our many buyers.
Q: With you effectively breaking even in the current environment, how should we think about how you managing additional cash flow into 2017 as the oil and gas price recovers? How do you prioritize an increase in activity levels versus growth and distributions versus reduction and leverage?
XOM: From our cash flow from operations, the first thing that the Corporation wants to do is go ahead and pay a reliable and growing dividend. The next thing is the remaining cash is put towards through to an investment program that has gotten to the point where we believe that we have maximized the value proposition for investment. If we’ve got enough cash to go ahead and invest it to fund that investment program, then the remaining cash we’ll either put forward to either stock buyback, share buybacks, or paying down our debt. If we don’t have enough cash, as you’ve seen us do in the recent past, is we’ll go ahead and further leverage our very solid balance sheet and debt capacity to take on some additional debt because the service costs associated with that debt is more than benefited by the return we get from these investments. So it’s important to recognize that while we are very mindful of prudently managing our cash, we also believe it’s very important for us to continue to invest through the cycle and we do that in a very measured way that we’re not leaving any value on the table. Therefore, my comments I made earlier about making sure that we’re optimizing value in the bottom of a cycle.
Q: Question with regards to the way you look at your asset impairments versus the way that you look at acquisitions. Just trying to square the fact that you haven’t written down assets in 2015, given you’ve got, I suppose, a fairly constructive view on commodity prices with the kind of the opposing fact that you haven’t done a deal over the last year or so, given that you haven’t seen attractive enough assets in the market. Can you just talk about how those two things work together?
XOM: There’s two separate processes. Our asset management activity is a function of making sure that we are capturing opportunities, as I said earlier, that are competitive to our existing portfolio. The objective here is making sure that we’re growing shareholder value. And if we think that we can acquire an asset like the InterOil transaction that we can add incremental long-term value, then we’ll go ahead and pursue those type of opportunities. Our determination of asset impairment is a comprehensive process that we follow. And, as I said, it’s detailed in our 2015 10-K and it’s a separate process. It’s not informing or influencing our asset management activity.
Total: “positioned to be the most profitable European major oil company”
French oil major Total (ticker: TOT) reported its third quarter earnings today. The company has continued to send the same message every quarter, focusing on increasing production and declining operational costs and capital spending.
“We expect the environment to remain volatile but based on our 2015 and first half 2016 performance, Total has been the best performing major whether the oil price is rising or falling. Our priority is to continue reducing break-evens and improving cash flow,” said Total CFO Patrick de la Chevardière. This quarter, the company is on track to surpass its goal of reducing operating costs by $2.4 billion, the company said.
Upstream production has grown more than 4.3% this year to 2.44 MMboe/d due to new start-ups and ramp ups, although third quarter adjusted net income fell 25 percent to $2.07 billion.
Strong performance in its LNG business has helped Total outperform its peers, Chevardière said on the conference call. “LNG volumes have grown 5% year-over-year for the nine months and represent more than 30% of upstream net results. This is part of the reason we have outperformed our peers.”
Key Third Quarter Events
- Production was restarted at the giant Kashagan field in Kazakhstan on the Caspian Sea, of which Total’s share of production is 16.8%. It is expected to reach its 370,000 bl/d target by year end 2017. The project made its first shipment of crude from its onshore processing plant earlier this month and has been plagued by billions of dollars cost overruns and delays.
- In September, the company exercised preemption rights to acquire Chesapeake’s Barnett shale gas assets with capacity of 65,000 boe/d in 2016.
- The company recently signed a memorandum of understanding (MOU) with Brazilian state-owned company Petrobras to cooperate on upstream and downstream projects, with the first phase of implementation focusing on gas and power.
- This morning, the company also announced an oil discovery in the Black Sea, 80 miles off the Bulgarian coast. Total is an operator on the block with 40% interest, with Austria’s OMV and Spain’s Repsol each taking 30% stakes.
In the Q&A session, the company elaborated on its LNG projects, expected CapEx for its recently acquired Barnett assets from Chesapeake, international agreements with other companies, and updates on country risk.
Q: Can you elaborate on the project delivery in 2017, particularly Ichthys? How that’s going in terms of delivery in 2017 rather than 2018?
TOT: The overall progress on Ichthys, where we own 30%, is about 90% at the moment. According to the operator, the startup is scheduled in the second half of 2017. Construction of the CPF and the FPSO is complete, and commissioning work ongoing, ready for sail away by end of 2016, and then sail away to the field at appropriate timing. Exact timing is yet to be confirmed by the operator, but according to this operator, we’re going to keep startup date unchanged. All modules for the LNG plant have been delivered to Darwin and commissioning is in progress. And the pipeline, I remind you, was completed in 2015. That was for Ichthys.
Q: You are developing a number of LNG projects, you know, Yamal, Ichthys, GLNG is ramping up, and obviously you have some greenfield optionalities, Elk-Antelope, or Papua LNG, you call it now. But in your view, what is the critical mass needed really to hit the sweet spot of value and risk in LNG and do you think you have a gap there right now?
TOT: On LNG, I’d like to remind you that LNG is representing 15%, one-five, of our production, is making 30% of the upstream net income. So it is a good business whatever you can earn as well. When we sign and launched an LNG project, we have contracted all the volumes produced or 95% of the volume produced by this project. This is the case for Ichthys, for GLNG, for Yamal when it will start. All the volumes are contracted. And I think we already have the critical mass. We are number two in the world. What matters is the portfolio size in trading and downstream and I think we have both. So we are profitable now and I would say very profitable because our scenario is different than other companies. We contracted long-term, we don’t play spot markets. We are profitable now and we will remain at the same level, being profitable.
Q: Some of the big Asian importing countries have been a bit soft in terms of their imports. Is Total still placing your volumes into those legacy countries? Or are you having to place them elsewhere despite some long-term contracts?
TOT: Yes, we had good volumes and good results. Usually we were selling long-term volumes to Japan, Korea, and Taiwan. We enlarged our marketing activities to mainland China and Indonesia. I think this is part of our business, to provide LNG to both new countries willing to buy LNG and I think we are flexible enough and we have a large portfolio which enables us to sell long-term or medium-term volume to so-called new countries in the market, like for instance Indonesia. And I remind you, we started to sell to mainland China also, obviously, which is a great importer at the moment.
Q: What are your thoughts on your strategic alliance with Petrobras and how you expect that to play out over the coming years? In terms of what you’re looking for in terms of new JVs or assets, are you looking for early stage appraisal activity or expiration or would you be interested in volume also?
TOT: Honestly, we at Total are very happy to enter into such an agreement with Petrobras. We do recognize Petrobras as being a good operator. They have great assets and we like to work with them. We have just signed this MOU for this strategic alliance. Obviously it opens new opportunities for us in Brazil. It joins them through participation in Libra where things are going well. We are in a call for tender process for the surface PSO awards. Remember too, if you consider the early production scheme being one FPSO. And we look for a while to build our relation with Petrobras on that.
We will pursue opportunities with Petrobras. We are discussing with them at the moment. The alliance is perfectly fitting our strategic targets. We are building our portfolio on technological strength that we can bring to Petrobras. And we are, as I repeat, very happy to expand our exposure to Brazil because not only due to the quality, the high quality, of the asset that you can encounter in this country, but also to the fact that we are glad to work with Petrobras, with a good operator and a good company. And they are, Petrobras, getting out of the mess that we’re facing in the past, and I’m glad to see that Petrobras is back to work with a major oil company like us.
Q: Can you talk about what level of CapEx is required to keep production flat at the Barnett Shale acquisition?
TOT: Yes, we took this opportunity to preempt 75% from Barnett. As I recall you, we own 25% before, which enabled us to preempt the deal. It has been – this transaction has been negotiated by a fair preserve affiliate for more than a year. The terms and conditions were extremely attractive. We believe that this deal is excellent and it’s rare for me to use this word. Acquisition is about $500 million. Midstream contract will be restructured. The Barnett is cash positive now at less than $2 per million BTU and [indiscernible] through this new set of contact.
We will establish a new operating company, basically hiring people coming from Chesapeake, and some manager that we will hire from the U.S. market. There will be no expats in this business. We are basically hiring from Chesapeake about 150 people to operate this transaction, and this deal is opportunistic, and we recognize it, and this new operating company dedicated to Barnett will be fully dedicated to this asset.
For CapEx, I honestly don’t know. I have an idea that it will be very limited. Basically that was related to well interventions, and somewhat covered to maintain the production I think. So, it is a limited number but I don’t have the exact figure for you.
Q: Can give us an update on what Total is seeing in Libya?
TOT: On Libya offshore, we are operating offshore, Al Jurf. As usual, normal operation. Offshore we have had some damages on our assets, so basically – and we have no people on the ground, I would say, at the moment. So, it’s too early for me to say anything on that matter. The production overall in Libya is reported to have increased to about a little bit less at about 600,000 barrel per day, I think. The National Oil Company has announced 900,000 barrel per day target. This would include the restart of El Sharara field in the south desert, in which Total has a stake. El Sharara would be present about 30,000 barrel per day net at plateau. But, I have no more to say. I mean, the current situation is difficult to assess. It’s a civil war situation. We noted this positive statement by the National Oil Company and we will follow closely what they are doing to recover operation on both fields.
October 27, 2016
Whiting says it will begin completing DUCs in Q1 ’17; would start adding rigs at $60 oil
On Whiting Petroleum’s (ticker: WLL) 3Q 2016 conference call, CEO James Volker stated that recoveries from enhanced completions and lower average well costs in the Williston Basin have made the Core Bakken “one of the highest return plays in North America.”
“Our enhanced completions in the Williston Basin range between 900 MBoe and 1.5 MMBoe, based on type curves. We’re getting these done at average well costs of $7.0 million,” said Volker. “Whiting is well positioned with a premier asset base, a strong hedge position, an enhanced balance sheet, and a highly efficient capital plan.”
The company will be ramping its activity in the Williston through the end of the year, increasing rigs running from two to four. Full year production guidance was also increased, with Q4 expected production increasing by 400,000 boe to 10.8 MMboe. Third quarter LOEs were at the low end of guidance at $7.98 per boe.
As shown in the slide below, Whiting’s wells continue to outperform all Bakken peers. Thirteen wells in Central Williston Basin testing at an average rate of 3,727 Boe/d. Three wells from the Bakken formation averaged 3,445 Boe/d and ten wells from the Three Forks averaged 3,812 Boe/d.
WLL Q3 Conference Call Q&A
In the Q&A, Volker further discussed the effects of Whiting’s enhanced completions and how the Bakken compares to the Permian.
Comparing Williston and Permian returns
Q: Can you discuss how returns for Whiting compete versus the Permian Basin? What is the opportunity set in front of you that you think investors might be missing?
A: We sold a fairly large acreage positon in the Permian. We felt that the results we and others were seeing were indicated some variability and that we wanted to focus on the more consistent Williston Basin. If I had to pick right now whether or not to buy down there at the kinds of prices necessary to buy acreage form someone who already owns it, I’d much rather be in the Bakken and Northern Niobrara.
Q: It’s shocking that you are able to get something down in 2.75 days. Will that change dramatically if service costs go up again?
WLL: Under the new design we’re using, after setting about 2,000 feet we’re able to run one string of casing the total depth and that’s really improved our times and cut costs. We would not like to see pressure on prices until oil prices get above $60. Based on the interest we have from major pumping companies as well as a great history of coordination and partnering with them, I don’t expect to see much pressure in pricing in the Bakken or Niobrara, until we get $60. I think these improvements that we’ve made gives us an opportunity to further drop our costs.
Q: Could you talk about the current DUC situation going into 2017? Is it still price dependent?
WLL: We’re going to begin completing them in the first quarter of 2017 and we expect to complete about half of them by year-end.
Q: Can we assume that you’re going to assume full rigs in the Bakken through 2017.
WLL: I would say if oil prices were to get back to $60, you’d see us add some more rigs.
Q: You mentioned it would take $600 million to hold flat from exit next year, has that changed with the improvement in completions along with the DUC backlog?
WLL: I’d like to watch prices to see how volatile they are before I provide guidance on the amount of 2017 Capex. Assuming the current 2017 strip price of $53, we could easily return to double digit production growth based on 2016 to 2017 exit rates and do that by spending near cash flow.
Q: Encouraging to see the uplift from the enhanced completions. Do you have any initiatives next year to test other areas of the Bakken? And are there any areas in your portfolio right now that aren’t amenable to these enhanced completions?
WLL: Virtually all of our Bakken acreage is amenable to these bigger fracs, so we believe that our whole acreage position will benefit. There may be some areas with slightly lower EURs just because of differences in the rock. But we believe in all cases they will be incremental to rate of return and return to investment ratio.
Q: Are you intending to move any rigs east and west in 2017 to test that concept?
WLL: We have the flexibility to do all of the planning that is necessary to stay on track for what I previously mentioned would be double-digit growth next year. So, plenty of flexibility across our acreage position, permitting wise and logistically. We have a number of great rigs up there that are built for purpose and manned by a number of great crews, and frankly overseen by as you can tell from – for example, I’m switching on you from the Bakken down to the Niobrara but as you can tell we have what I think there is some great engineers out there not only doing the drilling, but also the completion operations. We’re optimistic about seeing the length and breadth of our acreage react positively to these bigger fracs.
Q: What sort of returns would you get based on current costs and pricing strips?
WLL: In the 30% – 40% IRR range.
Q: Are you agnostic over whether you transfer the oil by rail or pipe?
A: Obviously the pipe differentials are better for us. We don’t actually determine whether it moves by pipe or rail, we sell prior to that and marketing folks make that decision.
Q: Do you have any concerns from a political standpoint with future pipeline buildout in the region?
A: The Bakken has plenty of capacity to move the oil that we would produce now or in the future between rail and pipe. We think the pipeline in question will ultimately be built, though there may be a little bit of a delay.
Q: How much are you going to be paying in cash taxes going forward?
A: We still have significant non-operated losses and we will again be generating non-operated losses in the future at least where the current projections look. So we don’t think we’re going to be paying any cash taxes for at least three to five years.
October 26, 2016
Optionality in Capital Spending and Marketing a Key Benefit of Memorial Merger
In its 3Q 2016 earnings call, Range Resources (ticker: RRC) CEO Jeff Ventura discussed the positive outlook for Range following the closing of its merger with Memorial Resources in September and the integration of the Terryville complex of Northern Louisiana.
Ventura highlighted five key positive attributes that the post-merger company offers, including “a high quality, low cost asset base in two complementary basins, improved capital efficiency, and a strong marketing effort able to sell products in multiple markets.”
Ventura also cited “top tier operational execution” and “a strengthened balance sheet with strong liquidity and a strong hedge position for the remainder of 2016 and 2017.”
The company expects natural gas pricing to improve through the end of the year and into 2017 on the back of declining U.S. production and increasing demand from Mexican exports, power generation, and LNG exports, and petrochemicals.
~34% Production Growth in 2017 with Louisiana Assets
Production and capex for the remainder of 2016 was unchanged, with 4Q production guidance at 1,850 Mmcfe/d. Although a capital plan for next year has not been announced, the company is expecting organic production growth of ~12% (2,100 MMcfe/d) in 2017 and 20% (2,300 MMcfe/d) in 2018 at current strip prices. In response to analyst questions, Ventura stated that capex spending would be “at or near cash flow levels.”
The company expects to average nine rigs running in 4Q 2016, with five in the Southern Marcellus Division and four in the newly formed Northern Louisiana Division. In the Marcellus, 23 wells were turned on line in 3Q with 99 expected to be completed by year-end, 13 lower than prior guidance. Sixteen wells were turned online in Terryville with 3 completions expected by year-end.
Louisiana Assets and Gulf Coast Proximity Improve Marketing Options
On the infrastructure front, all gas pipelines the company is contracted on are expected to be completed on schedule. The completion of the Gulf Markets Expansion pipeline in early October will allow an additional 150 MMcf/d of Marcellus production to go to the Gulf Coast. The company has also secured capacity on Colombia’s Lee Train Express and ETP’s Rover Phase II, which have received their first final EIS approvals and are expected to be operational in 4Q 2017.
Pricing differentials improved across the board due to increased access and opportunities in Northeast, Midwest, and Gulf Coast markets as well as growing Northern Louisiana production. Corporate gas differentials are expected to improve to $0.46 in 4Q 2016 and $0.33 in 2017.
NGL realizations are expected to increase to over 26% of WTI in 4Q 2016 and 2017. Condensate differentials to WTI are expected to improve to $6 – $7 per bbl below NYMEX in the same period, driven by long-term agreements with Midwest refineries and Gulf Coast proximity.
The company has currently hedged 80% of its expected 4Q16 natural gas production at a weighted average price of $3.32/Mcf and 50% of expected 2017 gas production at a weighted average price of $3.21/Mcf.
Operational Efficiencies Continue, Terryville Assets Show Promise
On the operational front, gains in drilling and completions efficiencies continued to drive peer-leading EURs and well costs in the Marcellus. Year over year, lateral feet per day per rig increased 22% while drilling cost per foot decreased 5%. Significant cost savings were realized by drilling from existing pads
In North Louisiana, the company twice recorded the fastest spud to rig release times in the field to date, while a recent well registered a peer-leading IP30 of 27 Mmcfe/d. Ventura credited “early success refining the targeting and landing in the lower Cotton Valley” as well as “very encouraging” results from three vertical pilot holes in extension areas south of the Terryville field that would provide “additional data that will be rolled into our planning for 2017 and 2018.”
Service Costs Expected be Steady in 2017
COO Ray Walker commented on service costs inflation for 2017. “The way prices on the service and supply side move is going to be very regional. In areas like West Texas and maybe the SCOOP/STACK areas where activity has ramped up more, you could see prices moving up. In the Marcellus per se we don’t see it.” “We focus in what we term long-term relationships, not necessarily contracts, and we don’t see any important or significant price increases going into 2017.”
October 21, 2016
But expect rising service costs and stricter return hurdles
Paal Kibsgaard, CEO of the world’s largest oilfield service provider Schlumberger (ticker: SLB), gave his assessment of the global oil and oil services markets during the company’s third quarter conference call.
“The business environment stabilized as expected in the third quarter, confirming that we have indeed reached the bottom the cycle. The current period of oversupply and inventory build is over and market sentiments should soon change, paving the way for an increase in oil prices,” said Kibsgaard.
Global Market Balanced, non-OPEC Production Expected to Flatten
Current global supply and demand of crude was described as “more or less balanced as evidenced by flattening petroleum inventory levels and the start of consistent draws towards the end of the quarter – particularly in North America.” Further draws are expected on the basis of upward revisions to 2017 oil demand and OPEC’s announced intentions to cut production.
Kibsgaard further commented that “declining non-OPEC production has offset record OPEC production levels” and predicted on that non-OPEC production levels in 2017 to be at best flat, on the basis of current investment levels. Production upside from the U.S., Canada, and Brazil is expected to be offset by declines in the rest of the non-OPEC.
Regarding 2017 E&P investment, Kibsgaard commented that “visibility on remains limited” as customers are still in the planning process. A V-shaped recovery in the industry is still seen as “unlikely given the fragile financial state of the industry,” although with the exception of Asia, SLB sees early signs of global improvement. Activity upside in 2017 will be seen in North American land, the Middle East, and Russian markets.
“If we offer capital and expertise, there has to be a return on it”
Despite no material movements on costs during the quarter, higher oil prices have strengthened the basis for pricing recovery discussions with global customers. This process is expected to take some time to work out but is “critical to recover the large pricing concessions made in order to restore investment in technology innovation, system integration, and operation quality and efficiency.”
Stronger fundamentals also necessitate higher rate of return hurdles. “At the bottom we were willing to compromise but coming off the bottom, expectations for returns need to be restored both at the company and among shareholders,” explained Kibsgaard. Company capital and expertise will thus be allocated to contracts and basins “that meet financial return expectations in the same way our customers allocate capital to projects in their portfolios.”
Kibsgaard noted that a large part of SLB’s contracts “did not meet our financial return criteria” and this will serve as the company’s “starting point for reestablishing sustainable customer relationships.”
North America: “We’re not in it for the commodity side of it”
Having successfully pursued international market share for the past 12 to 18 months, Kibsgaard said that the company has shifted its playbook from “holding the fort to going for market share in U.S. land drilling” to pursue opportunities in drilling and completions technologies.
“On the drilling side in North America, we now have a clear path towards profitability in U.S. land, based on the technology uptake we’re seeing linked to these super laterals. We have not yet done that for fracing because at this stage it is highly dilutive to our earnings,” said Kibsgaard.
The “Rig of the Future” program was described as “on track,” with two U.S.-built pilot rigs planned to be put out for operational evaluation in West Texas. Based on current capex and manufacturing plans, a complete version of the rig is expected to be rolled out in large numbers in 2017.
Kibsgaard: “Momentum Shift” in Mexico
The topic of Mexican oil and gas development was also discussed, with Kibsgaard predicting that drilling activity would pick up in 2017. “It might not be dramatic comeback and we won’t be back to 2013 or 2014 levels anytime soon, but I think there is a momentum shift coming in Mexico.”
This prediction was based on reductions in activity which have not been compensated for by investment as industry and Constitutional reforms have progressed. Recent bid rounds for acreage and the first round of deepwater bids in December were also seen as supportive of higher Mexican drilling activity.
August 12, 2016
August 9, 2016
- American Midstream Partners, LP
- Black Stone Minerals, L.P.
- Callon Petroleum Company
- Earthstone Energy, Inc.
- Energen Corporation
- Ensign Energy Services Inc.
- Erin Energy Corporation
- EV Energy Partners, L.P.
- Harvest Natural Resources, Inc.
- JP Energy Partners LP
- Par Pacific Holdings, Inc.
- PDC Energy, Inc.
- Resolute Energy Corporation
- Ring Energy, Inc.
- RSP Permian, Inc.
- Tesco Corporation
- TransMontaigne Partners L.P.
- VAALCO Energy, Inc.
August 5, 2016
- Apache Corporation
- Approach Resources Inc.
- Arc Logistics Partners LP
- Archrock, Inc.
- Archrock Partners, L.P.
- California Resources Corporation
- Canadian Natural Resources Limited
- Carrizo Oil & Gas Inc.
- Chesapeake Energy Corporation
- Cimarex Energy Co.
- CONE Midstream Partners LP
- Continental Resources, Inc.
- Dawson Geophysical Company
- DCP Midstream Partners, LP
- Delek Logistics Partners, LP
- Delek US Holdings, Inc.
- Denbury Resources Inc.
- Energy Transfer Equity, L.P.
- Energy Transfer Partners, L.P.
- Enviva Partners, LP
- EP Energy Corporation
- Gulfport Energy Corporation
- Hornbeck Offshore Services, Inc.
- Inter Pipeline Ltd.
- Jones Energy, Inc.
- Laredo Petroleum, Inc.
- Legacy Reserves LP
- Matador Resources Company
- Marathon Oil Corporation
- McCoy Global Inc.
- Oasis Petroleum Inc.
- OGE Energy Corp.
- Parsley Energy, Inc.
- Penn West Petroleum LTD.
- PennTex Midstream Partners, LP
- Rice Energy Inc.
- Rice Midstream Partners LP
- Savanna Energy Services Corp.
- Seven Generations Energy Ltd.
- Shell Midstream Partners, L.P.
- Sunoco Logistics Partners L.P
- Teekay LNG Partners L.P.
- Teekay Offshore Partners L.P.
- Teekay Tankers Ltd.
- Tesoro Corporation
- Tesoro Logistics LP
- Transocean Ltd.
- Trecora Resources
- Unit Corporation
- USA Compression Partners, LP
- Valero Energy Partners LP
- Veresen Inc.
- WPX Energy
August 2, 2016
- Atwood Oceanics, Inc.
- Cobalt International Energy, Inc.
- Crestwood Equity Partners LP
- Green Plains Inc.
- Green Plains Partners LP
- Holly Energy Partners, L.P.
- Magellan Midstream Partners, L.P.
- Mid-Con Energy Partners, LP
- NuStar Energy L.P.
- NuStar GP Holdings, LLC
- PetroQuest Energy, Inc.
- Rowan Companies plc
- Western Refining, Inc.
- Western Refining Logistics, LP
- Williams Partners L.P.