Equinor ASA (EQNR) 2018 Q1 法說會逐字稿

Ladies and gentlemen, welcome to Statoil First Quarter 2018 Analyst Call.

I'm Peter Hutton, Head of Investor Relations.

I'm pleased to welcome Hans Jakob Hegge, our CFO, who will run through the results and key issues for around 10 to 15 minutes, and then we will open up for questions and answers.

We expect this call will finish within the hour.

I'm also joined on the call by Svein Skeie, Head of Performance Management; and Ørjan Kvelvane, Head of Accounting.

So with that short introduction, I hand over to Hans Jakob.

Thank you.

Thank you, Peter.

Good morning, everybody, and welcome.

We present solid results and have very strong cash flow of more than $6 billion after tax in the quarter.

IFRS net operating income was $5 billion, and adjusted earnings, $4.4 billion in the first quarter.

IFRS net income was $1.3 billion.

Cash flows from operating activities before tax and working capital amounted to $7.1 billion.

And the net free cash flow in the quarter was $1.5 billion after dividend and the Martin Linge payment.

This is the strongest cash flow from operations after tax since the first quarter 2014 when the oil price was around $100 per barrel.

We clearly see the results of the improvement project over the last 4 years.

From a lower cost base, we have created more value at higher prices.

The first quarter is characterized by solid operational performance, record-high international production, and our projects are progressing according to plan.

Before we review the results in more detail, take a look at this picture of Aasta Hansteen, the world's largest power platform, arrived Monday at its final position, 300 kilometers west of my hometown, Fauske, in Northern Norway.

It will produce gas from a water depth of 1,300 meters, Statoil's deepest field development on the NCS to date.

In the quarter, we continued to develop our industrial position in Brazil and Gulf of Mexico, where we secured new acreage.

And we had 2 commercial near-field discoveries on the NCS.

Furthermore, Statoil increased its offshore wind portfolio to a 50% farm-in with a local company with plans to develop 2 offshore wind projects in Poland.

Before I continue with the results, some reflections on the macro.

We have seen a strengthening of oil and gas markets, with oil closer to rebalancing even with increased U.S. shale oil production.

We expect price volatility will continue going forward.

Still, Statoil's fundamental market view has not changed, and this is reflected in our long-term price assumptions.

Statoil's adjusted earnings of $4.4 billion, with a very strong cash flow and a reduced net debt ratio to 25.1% in the quarter, are strong group delivery.

This was achieved through solid operational performance, high production capturing higher prices, maintaining our cost discipline.

The projects are progressing according to plan and we are on track to deliver on our guidance and targets presented at the CMU in London.

We have made Statoil a more resilient company and better positioned to capture value.

The Statoil Board of Directors has decided that the cash dividend for the first quarter 2018 stays in line with the proposed increase dividend in the fourth quarter '17 at $0.23 per share.

Then to safety.

Statoil's serious incident frequency in the last 12 months was 0.5 million hours worked, the best we've had so far, down from 0.8 in the same quarter last year.

Safety is, and will always be, Statoil's top priority.

I am safety is the name of a safety culture program that we introduced last year to make safety even more personal and with strengthened personal accountability.

We never stop searching for better and safer, and we believe that our strong push on digitalization can assist us in further improving Statoil's safety record as well as making us even more efficient.

Let's now have a look at the financial results in more detail.

We delivered $4.4 billion in adjusted earnings before tax this quarter.

This is up from $3.3 billion or 33% from the same period last year, while Brent has increased 24%.

Strong operating results where high production, higher realized prices and sustained cost focus are the key contributions.

Adjusted earnings after tax was $1.5 billion compared to $1.1 billion in the first quarter of last year.

The tax rate in the quarter was 66.6%, reflecting low effective tax rates in DPI and MMP, offset by increased provisions at the group level.

We realized an average liquids price of $60 per barrel in the quarter, up 23% compared to the first quarter last year.

Realized European and North American natural gas prices were also higher, up 26% and 5%, respectively, year-on-year.

Statoil's OpEx and SG&A cost per barrel, measured in underlying currency, remained relatively stable, with a small increase of 3% due to new fields onstream compared to the same period last year.

Depreciation is down 1%, and the main driver is increased reserves.

However, a change in the depreciation basis for one particular NCS field increased the depreciation charge by more than $100 million in the quarter.

And normalizing for this, the DD&A would have been down 5%.

Now let's have a look at the segments.

E&P Norway delivered adjusted earnings before tax of $3.4 billion.

This is an increase of 29% compared to the same period last year.

Our improvement agenda, together with strong cost focus, is delivering sustained results.

The total NCS production at 1,381 million barrels of oil equivalents per day is roughly flat.

Underlying OpEx and SG&A measured in NOK was also relatively stable, with a slight increase as a result of new fields coming onstream.

Depreciation is up, as previously mentioned.

Achieved liquids price in the quarter was 22% higher than the same period last year.

Then to E&P international that delivered adjusted earnings before tax of $638 million, which has more than doubled compared to the same period last year.

E&P international delivered a record high equity production of 799,000 barrels of oil equivalents per day.

Adjusted for portfolio changes, this is up 9% from the same period last year.

The main contributor was U.S., both onshore and offshore.

The underlying OpEx and SG&A per barrel was flat.

The cash flow per barrel after tax from E&P International is strong at around $25 per barrel.

Our MMP segment delivered pretax adjusted earnings of $454 million compared to $500 million in the same quarter last year.

The MMP results are characterized by a strong result from the natural gas business, both in Europe and the U.S., high regularity at our plants, lower refinery margins and a lower liquids trading result.

During the first quarter, Statoil's total average liquids and gas production was 2.18 million barrels of oil equivalents per day, an increase of 34,000 barrels compared to the same period last year.

This is the highest production since first quarter 2012.

E&P International delivered record-high production in the quarter.

And on the NCS, uptime was high as new fields like Gina Krog and Byrding contributed positively.

E&P Norway continues to offset the natural decline with IOR projects, near-field tiebacks and infill wells.

Then to the strong cash generation.

We delivered a very strong cash flow from operations of $7.1 billion before tax and a free cash flow of $1.5 billion after dividends, tax in -- after dividends, tax, organic investments and after paying $1.6 billion for Martin Linge.

Combined with a reduction in working capital of $1.1 billion and stronger equity, we reduced our net debt ratio further by 4 percentage points to 25.1%.

Let me close with a few comments on our guiding, which is unchanged.

We maintain our CapEx guiding for 2018 at around $11 billion; 2018 exploration expenditure, guiding at around $1.5 billion; 2017 to '18 production growth of 1% to 2%, and 3% to 4% for '17 to 2020.

Key takeaways are Statoil delivers a strong quarter with a very strong cash flow.

We continue to deliver on our guidance presented at the CMU.

Then a quick reminder.

Statoil will be arranging its first SRI Day in London on May 4. We hope to see many of you there.

Thank you for the attention, and now I'll give the word to Peter, who will guide us through the Q&A.

Thank you, Hans Jakob.

And with that, I hand you over to the operators to open for questions.

Thanks very much.

(Operator Instructions) We shall take our first question from Biraj Borkhataria from RBC.

Just going back to your comments on being on track to hit your targets.

I wanted to take you back to what you said at the CMU, which was that the scope for buybacks was emerging.

At that point, you talked about the balance sheet being the #1 priority.

So obviously, the macro situation is better than you planned both in oil and gas, and gearing has come down quite a bit.

So question is, what more do you need to see to start the buyback program from here?

And then the second question, just quick clarification.

You talked about lower liquids trading.

Q1 is typically quite a strong quarter for trading, so I was wondering if you could give a bit more color on what drove that weaker result.

So thank you, Biraj.

On the buybacks, if I take you through to the CMU, we talked about an emerging scope as we said, and that was based on the macro environment and the portfolio developments and near-term priority to reduce the gearing.

And so we have been doing reducing it by 4 percentage points.

The macro has been positive.

But we also have seen volatility with prices down in the 60s and then above 70s, so we expect also volatility going forward.

In terms of priorities, it remains our near-term priority to strengthen the balance sheet.

We still have some payments on the acquired assets to be done, so no news on the share buybacks.

On the lower liquids trading result, overall, the MMP is within the guiding, in the higher range.

It's moderate on the liquids, but we have seen a backwardation market, and that is a bit tougher to make the huge profits.

Our next question is from Oswald Clint of Bernstein.

I'd like to ask a question on the OpEx, please.

You've obviously indicated underlying OpEx remains stable, which is good, and obviously in line with your plans.

But I do remember Torgrim talking about it, embedding some pretty material OpEx insulation assumptions into his business for this year.

So I guess the question is, if you're seeing those numbers in -- within the U.S. business and is there an offsetting decline in OpEx somewhere else within -- kind of within the business so the overall number is flat?

Yes, that will be my first question.

Second question, just really a bit of an update around the Roncador transaction.

Any update on when that might actually close, please?

So thank you, Oswald.

On the cost, one step back, we have seen a very positive trend over time, NCS being at a 10-year low, and we see improvements paying off.

We are still within the guiding.

If you look at the adjusted OpEx SG&A, it's plus 11% year-on-year, and 50% of that is currency.

Then we have new fields like Gina Krog on the NCS, the Byrding.

We have, in East Coast Canada, we have Hebron.

And we have Stampede in the U.S., and we have now onshore wells in the U.S. And as prices move upwards, royalty and production fees increase in line.

So this is partly offset by positive operational and production cost improvements.

But on specifically, on Torgrim's comment on inflation in the U.S., we have taken into account a 20% to 25% cost increase.

This is related to the drilling and well area and completions, and that is taken into account in our numbers.

On the project sides outside U.S. and in our global portfolio, we have not seen this cost inflation.

And so that's the status on the cost.

Then to Roncador.

The completion midyear, that's the latest update, so I could elaborate on Roncador.

It is -- this is an IOR value-enhancing, motivated transaction.

We did the $2.35 billion at closing, and there will be $550 million related to paying for IOR projects not expected during 2018, so we'll come back to that.

We shall take our next question from Anne Gjøen of Handelsbanken.

First question related to how much remains for the remainder of the year to be paid after acquisition is done.

I see that in third quarter, you paid $1.56 billion, so how much remain in second quarter -- fourth quarter?

And also question related to this, adjusted depreciation in Norway of $100 million.

I know that you're not willing to comment on the specific field as such, but what is the reason?

Is it lower reserves?

Okay.

I'll take the second question, and then Svein will do the payments.

On the depreciation in Norway, we, as you correctly stated, Anne, we have $100 million change.

It is related to a change of estimate on one field, where we are moving from expected to proved reserves.

So going forward, we expect high depreciation on this field for the rest of this year.

Overall, on the DD&A in Norway, we are at NOK 82 per barrel, which is plus 11% underlying.

This is due to production mix, investments and changes in the depreciation estimate.

On the payments, Svein?

Yes, thank you.

On the payments, the main payment is related then to the Roncador field in Brazil, as Jakob said.

On the $2.35 billion, that is expected to be closed then towards midyear this year.

There, we will then pay the outstanding issues, $2.35 billion.

But we will then, since we have effective date as of 1st of January, we will deduct the value of the production upon the closing.

So that will be deducted.

Also, later this year, we will also then pay for the exploration licenses that we acquired in Brazil now -- announced recently in -- during the Easter.

So that is also an important comment obtained later this year.

Our next question is from Rob West of Redburn.

I'd like to ask 2. The first one is about the rig rates coming through Norway.

There are some reports of some of those rates going back up a little bit this year.

So I was wondering if you could comment on what you're doing to protect against that coming through and just how much of your drilling is already locked in.

The second question would be on Oseberg, and if you could comment on the recent liquids production there.

It's been a little bit lower than previous quarters in terms of the decline.

And do you see the Vestflanken project stabilizing that or bringing it back up again?

Thank you, Rob.

So on the rig rates in Norway, overall, we see at the NCS an increase in tendering is observed.

The rig rates are in the range of 150 to 300.

We see that we could actually enter into better rates than the average rates that we have if we did new contract signings today because that market is still oversupplied, and that is expected to remain for some time.

So on the overall Oseberg production, we have a quite strong production on Oseberg on the gas side.

On the liquids side, there will be variations, I know from the past.

And you're absolutely right that the Oseberg Vestflanken coming onstream midyear will also contribute positively to the development of the liquids production.

The next question is from Halvor Nygård of SEB.

Regarding the U.S. production, we saw quite large jump in the Marcellus production, while back in Eagle Ford, was slightly lower compared to Q4.

Is this a deliberate choice to not grow in these areas?

Is it due to logistical issues on the completion side?

Or is it other factors?

And then secondly, on CapEx, Q1 organic CapEx at $2.1 billion.

Can you say something about the distribution of CapEx through the year will be very back-end loaded?

So thank you, Halvor.

On the U.S. production, it's record-high production overall onshore/offshore, 358,000 barrels per day.

Main explanation for this is well productivity, more completions.

We also have low breakeven on these wells and increased realized prices on the gas side by 5 percentage points.

So this is about cash, strong cash generation.

On the Appalachian and basin operated, we have high productive gas wells, not high drilling activity as we only had one rig.

We completed many wells.

The Utica wells have solid economics compared to last year, where we had some weather that also makes this quarter's production relatively stronger.

On the overall activity level, we are talking about 5 -- 4 operated rigs: 2 in the Eagle Ford, 0.5 in the Bakken and 1 in the Appalachian operated, plus the non-operated, so 3 completion crews.

Forecast, the beauty on onshore is that we can scale it up and down with changes in prices, but everything equal, might see a slight increase versus '17 due to more completions.

On the CapEx, we started the year on $2.1 billion.

That is not affecting or around $11 billion for the full year, maintaining strict cost and capital discipline.

Going forward, we have an increased Martin Linge.

We have Johan Sverdrup activity passing at 72% completion as of today.

We have Johan Castberg, we have Peregrino, in addition, the completions of Aasta and Mariner.

All right.

So we shouldn't read anything into the fact that Marcellus is very much up, but Bakken and Eagle Ford is down?

There will be variations, but we have, on the Eagle Ford, as you know, we are working on pilot well space, we do technology application and we have renegotiations, so we have improvement we are going on there.

But there will be seasonal variations between the 3 basins.

It appears there are no further questions at this time.

I would like to therefore turn the conference back to you for any additional or closing remarks.

Thank you, everybody.

Short and, hopefully, sweet.

As always, IR available for any questions or follow-up.

As Hans Jakob mentioned, we will have an SRI Day in London on the 4th of May, and I look forward to seeing many of you there.

So until that point, many thanks, and have a good day.