Ladies and gentlemen, welcome to Statoil's first quarter earnings presentation, both to the audience here in Oslo and to our audio and webcast audience. My name is Hilde Nafstad. I'm the head of Investor Relations in Statoil. Before we start, let me say that there are no fire drills planned for today. In case the fire alarm goes off, you will need to exit through the two back doors on each side and gather outside on the same side. This morning at 7:30 A.M. Central European Time, we announced the results for the first quarter of 2012. The press release and presentations for today's event were distributed through the wires and through Oslo Stock Exchange. The quarterly report and the presentations can, as usual, be downloaded from our website, statoil.com.
I would ask you to kindly make special note of the information regarding forward-looking statements, which can be found on the last page of the presentation. Today's program will start out with Statoil's CFO, Torgrim Reitan, going through the earnings and the outlook for the company. As usual, the presentation will be followed by a Q&A session. Please note that questions can be posted by means of telephone only, not directly from the web. The dial-in numbers for posting questions can be found on the website. It is now my privilege to introduce Chief Financial Officer, Torgrim Reitan.
Thank you, Hilde, and good afternoon to all of you here in Oslo, and good morning and good afternoon to all of you on the webcast following us there. It is a pleasure to present our results for the first quarter today. This is our best adjusted earnings ever. Eleven percent production growth, but that is as expected. We are continuing our exploration success, and we keep on streamlining our portfolio for the longer term. A strong quarter. Before I get started on production and financials, I want to start with the strategic progress. We made three new high impact discoveries this quarter, Norway, Tanzania and Brazil. Two of these three are operated by Statoil, and this means six high impact wells over the last 12 months.
We will keep on drilling for more, and I'll get back to this later today. This weekend, we signed a strategic cooperation agreement with Rosneft. This is an important milestone in our Arctic exploration program. This we will come back to later. We have the pleasure to have with us, Tim Dodson, our head of exploration, so he will be available in the Q&A session. I'm sure he looks very much forward to tell you all about this. We continue to streamline our portfolio towards being a technology-focused upstream E&P company. In April, we accepted a cash offer for our shares in Statoil Fuel & Retail. Couche-Tard is a strong industrial buyer. They're offering an attractive price, a premium of 53%. SFR will continue their strategic development under a long-term industrial ownership.
For us, it frees up capital, so we can put our money where our strategy is. The offer period will last until the 21st of May, and we expect to close the deal in the second quarter. We are maturing our project portfolio. We signed the pre-unitization agreement on Johan Sverdrup, and that means that we are operator up to the PDO approval. We started production on Marulk, where Eni is the operator, and Marulk is connected to the Norne FPSO. We also put the subsea tieback project, the Smørbukk Northeast, in production. That's only 30 months after discovery. That's a satellite to Åsgard B. Our PDOs for Skuld and Åsgard subsea compression were approved. First oil was produced from Caesar Tonga in the Gulf of Mexico.
That was one month earlier than planned, and a great job there by the operator Anadarko. We are making progress, and we will move ahead as planned. Over to production. In the first quarter, we grew production as expected, 2,193,000 barrels per day. That's an 11% increase over the first quarter last year. It's important for me to say that this is not more than what we need to deliver in accordance with our guidance. We see growth across the board. We have grown both our oil and gas production and our production in Norway and internationally. Gas is an important part of this story. We increased our gas production by 16%, and this demonstrates the capacity and the flexibility. You know our gas strategy well. We are using our flexibility.
In the first quarter, we have especially used the flexibility at Oseberg. Oseberg is the world's largest short-cycle storage, as I put it. We can produce Oseberg in 80 days. We have used the full annual production permit on Oseberg in the first quarter, picking the best prices. That demonstrates the value of flexibility. Liquids production has increased by 8% from 2011, and that's a stable liquid production on the NCS. We see increased oil recovery, and we see that that is paying off. On the Statoil fields, we now have a recovery more than 50% across the Norwegian Continental Shelf. In other regions, people expect around 35%, and 1% increase means actually 300 million more barrels of recoverable oil. In addition, we have started up and ramped up new fields internationally.
This leads to a record international production this quarter. Let me give credit to Total for the startup of Pazflor in Angola, which is performing really well. Pazflor started producing in August last year ahead of schedule, and that field has produced more than 40,000 barrels per day for Statoil in the first quarter. Also Bakken, the Bakken asset in the U.S. contributes well with production of more than 26,000 barrels per day in the quarter. So we have taken on our first onshore operatorship, and this is part of our stepwise buildup in unconventionals. But it is also my job to remind you of the uncertainties in the production going forward. BP, they have announced another delay on Skarv. They now expect production started in the fourth quarter of 2012. This will of course have negative impact on our production.
You know, the original Statoil capacity for Skarv was estimated at 50,000 barrels per day, assuming a startup last year. Now we expect low contribution from this asset in 2012. We are making good progress on the riser issues at Snorre, but there are still uncertainties related to this, and we are progressing with the buildup on Gullfaks, but it will still impact production in 2012 as expected. We will continue with our gas optimization. I said earlier that we have used our flexibility this quarter with a great gas machine like Oseberg. That also means that we have already taken out some of our gas potential. That will also impact coming quarters. To turnarounds. The yearly impact on production from turnarounds will be 50,000 barrels per day.
In the second quarter, the effect will be 40,000 barrels per day on a quarterly basis. In the third quarter, I expect the impact to be as much as 110,000 barrels per day on a quarterly basis. I also would like to remind you that the Centrica deal closed on April 30, leading to that will lead to lower production from these assets for the rest of the year. In the first quarter, the contribution from the Centrica package was around 40,000 barrels per day. To be very clear, there will be a significant growth from 2011- 2012, but first quarter is as expected.
We maintain our current guidance, and as I said, have said over several quarters, there are more risks to the downside than to the upside. To the results. In the first quarter of 2012, net operating income NOK 57.9 billion. That is up more than NOK 7 billion from last year or 14%. Net income NOK 15.4 billion. When you compare that number with the quarter last year, you should remember the large and almost tax-free profit we booked on the divestment on KKD. We do, as usual, make adjustments to better reflect our underlying operations. This year, the adjustments amount to NOK 1.2 billion, and that is mainly related to negative changes to fair value of derivatives. The adjusted earnings before tax was NOK 59.2 billion.
That's a record for Statoil in one single quarter. That's a 25% increase over last year. This stems primarily from higher prices and increased production. Production growth accounts for an increase of NOK 7.2 billion, and increased prices in kroner accounts for close to NOK 8 billion. Then the costs. SG&A and operating costs, they increased by 19% on a quarterly basis. I'll come back to that, but this increase mainly is related to increased production and higher prices. After tax, we made NOK 16.8 billion a quarter, and that is up more than 40% from the same period last year. All segments have delivered increased earnings this quarter. There's a lot to say about these results, but let me reflect on the cost development. The operating expenses and SG&A increased by 19% this quarter.
You know, cost, that is something that watch closely. Most of these cost increase results from production growth and higher prices and more projects underway. I'll take that segment by segment. Development and Production Norway, they had a result of NOK 47 billion, and that's an increase of 20%. The NOK 900 million in increased costs is related to higher production and increased well maintenance at several fields. International Development and Production had adjusted earnings of NOK 7 billion, and this is an increase of 35%. Here we see NOK 1.8 billion in increased operating costs and SG&A. And NOK 1.2 billion out of those comes from increased royalties. Increased royalties comes due to higher prices and higher production. You know, we like both higher production and higher prices.
The main contributors are Tahiti in Gulf of Mexico and the onshore fields in the US and Peregrino. Then you have NOK 600 million increase, which is linked to ramp-up from fields like Leismer, Peregrino, Marcellus and Bakken. Marketing, processing and renewables delivered earnings of NOK 4.6 billion, and that is up 68% from the same period last year. This is in spite of NOK 1 billion in lower tariff income due to the divestment in Gassled. That NOK 1 billion will impact the coming quarters too. For natural gas, the increase was mainly due to higher margins on gas and strong trading results using the flexibility we have in the upstream portfolio. For crude oil processing, marketing and trading, we have turned a loss in the first quarter last year to a gain of NOK 600 million this quarter.
A great job by our traders in the first quarter. We also see improved refining margins on oil products and very strong operations from our refineries. There is still a demanding market for the business. We will continue our improvement program with full force. You should note that you should expect fluctuations in the results from the MPR from quarter to quarter. You should also remember that a certain part of the result is actually volume driven. The first quarter had high volumes. The reported tax rate was 73.3% in the quarter. Based on adjusted earnings, it was 71.6%. Our guiding is a range between 70% and 72%. I've said earlier that you should expect it to be in the upper part of that range, and this is still valid.
To the cash flow. This quarter, the cash flow from operations was NOK 70.8 billion, and that is up from NOK 56.4 billion in the first quarter last year. We paid NOK 19.4 billion in taxes. We received proceeds from the Gassled transaction that provided NOK 13.9 billion. On April 30, we closed the agreement with Centrica, divestments of NCS assets. That has brought $1.525 billion to our accounts. That will show up in the second quarter cash flow statement. We expect to close the Statoil Fuel & Retail transaction by end of second quarter. This will provide an additional NOK 8.3 billion when we adjust for dividend received.
SFR will be deconsolidated from our balance sheet at completion, and we have also stated in the report that we expect an accounting gain between NOK 5 and a half billion and NOK 6 billion on that transaction. That is to come. As you know, we pay tax in Norway six times a year. In the second quarter, we will pay two installments of around NOK 17 billion each, and then we will pay more than NOK 20 billion in dividends this quarter. There will be a lot of money coming our way, and there will be a lot of money going the other way during the quarter. We have quite a comfortable position with a strong balance sheet.
We have a net debt ratio of 15% that has been reduced significantly over the quarter, and I expect it to be further reduced by year-end. Financial robustness is still a very important and strategic issue to us. We will continue to run Statoil with a strong balance sheet. We will keep on putting our money where our strategy is. We will develop our portfolio of 150 new projects that we have in the funnel. You know, this will take considerable investments over this decade. This will lead to an attractive growth. You know very well that we have an ambition to produce more than 2.5 million barrels per day in 2020. We will deliver visible and high quality growth.
Let me go into more detail on another building block in our strategy. A great oil and gas company must be good at exploration. I dare to say that we are progressing well. We had 22 wells with drilling activity in the quarter. We completed 12 wells with eight discoveries. We made discoveries in 67% of all of our completed wells. Last year was a pretty good year for exploration. We added a total of 1.1 billion barrels from exploration in new resources. During the first quarter of 2012, we have already added more than 500 million from exploration so far. A lot of that comes from the three high impact discoveries.
Havis, in the same license as Skrugard in the Barents Sea, and combined, these two hold around 400-600 million barrels of recoverable oil. This is the second high impact discovery in the North in 9 months. Zafarani, meaning saffron, is a gas discovery offshore Tanzania. So far, proving up to five TCF of gas in place. This is the first Statoil-operated discovery in East Africa. This will be important for the future development of Tanzania's gas industry. Pão de Açúcar, the Sugarloaf Mountain. That's a Brazilian pre-salt oil discovery. This discovery is operated by Repsol. It is 200 km from Rio at 2,800 m of water. The hydrocarbon column is 480 m and a total pay of 350 m. This indicates that our exploration strategy is paying off.
Simply put, our strategy consists of two elements, early access at scale, and then taking more risk, prioritizing high impact wells. During the quarter, we have accessed new acreage, as well. In January, we secured 11 licenses on the NCS, and we will operate eight of these. We then farmed into a license in West Greenland, P2 in the Baffin Bay. In April, we entered our first acreage in Ghana, farming into deep water license just south of the Jubilee field. Not to mention the seismic preparations for drilling sub-salt Angola. We have secured new acreage in Russia through the agreement with Rosneft. We will continue with momentum. We will drill around 40 wells in 2012. There will be around 20 high impact wells around the world in 3 years.
We'll continue to drill the NCS, both mature and in frontier areas. We are also stepping up our operated activity internationally. You know, we look at the cold parts of the world, Barents, Alaska, Canada, the Faroes and Russia. We are positioned in the Gulf of Mexico and pre-salt Brazil. There are also other important areas to watch going forward, like Angola, Tanzania, Ghana and Indonesia. Let me give you the names of three wells to watch in the near future. Kilchurn in the deepwater Gulf of Mexico was spudded in January. This well is expected to be completed towards the end of second quarter. We have Lavani in Tanzania. That is in the same block as Zafarani. The well was spudded late April, and we expect it to take around two months.
This prospect is very interesting based on the Zafarani discovery. You know, as with exploration, oil exploration, there are many uncertainties. King Lear in the mature North Sea is coming towards a conclusion. Based on Statoil's high equity, this is a potential high impact discovery for us. The structure is large, so several wells may be required to appraise the whole prospect. This is high temperature and high pressure. We also plan to spud the Kakuna well in the Gulf of Mexico in May and the Peregrine South appraisal in mid-June. We are looking forward to a lot of exciting exploration activity this year as well. Now let me describe another key building block, and that is to continue developing our international portfolio.
Towards 2020, we aim to establish material positions in three-five offshore clusters outside the NCS and step up our shale gas and liquids production. We aim to produce more than 1.1 million barrels per day in 2020. Actually, even if 70% of our production is coming out of Norway currently, actually 50% of the resources sits outside Norway, and that resource base has grown significantly. Much of our growth will take place internationally in places like Gulf of Mexico, Angola, Azerbaijan and Brazil, and onshore in North America, where we are expanding stepwise in the unconventionals. As you can see, we have increased our international production significantly. In 2001, the international production of Statoil and Hydro combined was less than 100,000 barrels per day.
In 2007, when we merged, we produced around 400,000 barrels per day abroad. This quarter, we produced 662,000 barrels per day. That's more than 50% growth over 5 years. We intend to almost double this by 2020. We are investing for growth. In the next 5 years, 40%-50% of CapEx will go to international projects. Around 90% of our CapEx will be upstream related. 70% of investments will be in greenfield, and there's a clear bias towards liquids. Around 60% of our investments will go towards liquids. We will grow with quality and profitability, and we are already doing quite okay. The international segment contributes significantly to cash flow. In the first quarter, it amounts to 17% of EBITDA.
We are positioning Statoil for the long term, and we are building our resource base for future production growth. To the agreement with Rosneft, this is big, more than 100,000 sq km, and that's an area that equals around 200 blocks on the Norwegian continental shelf. Two-thirds of all Arctic resources are expected to be found in Russia. The agreement is an excellent strategic and technological fit, and it builds on existing positions in the Arctic, Faroes, East Coast Canada, Chukchi Sea, Beaufort Sea, Barents Sea, Shtokman. It strengthens the relationship between Rosneft and Statoil and Russia and Norway. Under the agreement, Statoil and Rosneft will set up joint ventures with Statoil holding 33%, in each, and the established joint venture relationship will govern the asset cooperation.
We will enter into a phased work program commitment, and this means a stepwise approach, enabling us to phase expenses over time. The acreage will provide drilling targets in the medium term from 2015 to 2020, and this will bring new high-impact opportunities. Finally, the agreement also provides Rosneft with an opportunity to acquire interest in Statoil assets in Norway and internationally, and this will be under negotiated terms. This is an important long-term agreement for both parties. Going forward, we are progressing as planned, and we expect to spend around $17 billion in investments in 2012. If we continue with exploration success, we'll end up capitalizing more of our exploration costs and that actually could push up that number.
Actually, I can live with that as long as Tim keep on discover oil and gas. We also maintain an exploration level as last year, around $3 billion. We will complete around 40 wells this year, and we have actually an inventory of drill-ready wells that is larger than this, so it can be optimized. There will be around 20 high-impact well from 2012- 2014. I see no reason to change our production outlook, but I have reminded you on the uncertainties, so I don't want to go through all of them once more. Just remind you that guidance remains firm, but there are more risk to the downside than to the upside.
In summary, it has been a very good quarter with significant progress for Statoil, our best adjusted earnings ever, significant step up in production, continued exploration success, and streamlining our portfolio, putting our money where our strategy is. Thank you very much for your attention. Then, Hilde, I'll leave the word to you to guide us through the Q&A session. Thank you.
Thank you, Torgrim. For the Q&A session, Torgrim will be joined by the Executive Vice President for Exploration, Tim Dodson, who will be able to expand on the cooperation agreement with Rosneft for you. He will also be joined by the Senior Vice President for Accounting and Financial Compliance, Kåre Thommessen. We will take questions from the audience and over the telephone. I will first ask the operator to explain the procedure for asking questions over the telephone. Operator, please.
Thank you. Ladies and gentlemen, for those on the audio, if you wish to ask a question over the telephone, please press star one at this time. That's star one to ask a question over the audio. Thank you.
Thank you. We'll start out with questions from the audience here in Oslo. Torunn, you're first. Can Torunn have the microphone, please?
First congratulations on the very strong result. Of course, a lot of it is also on high gas offtake. There seemed to be some comments earlier by Hilde that some volumes may be moved to 2013. Can you have some comments on your view on the gas market at the very high level? Also, of course, you had a higher production permit for Troll. Can we assume that that will be, as expected, prolonged into the next gas year?
Okay. Thank you, Torunn. We have a lot of flexibility in the gas machine, and, you know, we intend to use that to earn more money. To us, money is actually more important than counting barrels, and so on. If opportunity arise to move gas production in time, we will do that. We have that flexibility as we go, so if price curve changes and so on, we might elect to say, "Okay, we don't want to produce, for instance, that much Troll this summer. Let's sell it forward into next summer if the prices are much better, there." We did that, you know, significantly in the summer of 2009. Then gas prices was 20 pence per therm, and the next summer was 40 pence per therm.
We turned it down and sold it forward, and we gained 100% premium on that gas. That brings me into a related issue, and that is, you know, the importance of carving back flexibility because, you know, we hold a lot of flexibility in our portfolio on behalf of the long-term customers. We have taken back quite a bit of flexibility that we now use ourselves as a trading tool. We intend to use that going forward as well. When that is said, currently the prices in the U.K. are strong, 60 pence per therm, around that. That is strong prices in a historical context. We see actually a quite firm gas market in Europe going forward.
We see LNG heading in other directions to Asia, and we are actually taking our own LNG from Snøhvit to Asia from time to time, South Korea and other places, realizing significantly higher prices than in Europe as well. You know, I have quite an optimistic perspective on European supply of gas. When it comes to the uncertainty in the short term, it is very much dependent on how the market will develop, especially in the summer period. That is something you can watch. On Troll permit, we have in place the full permit, and you can expect that I don't expect there to be any changes in that going forward.
I also have one question on the Rosneft deal. Of course, the this is an enormous opportunity set, but could you also talk a little bit on your view on the risk of changes in fiscal conditions and whether you see any changes in that in the legal framework in Russia? Could you also, maybe that's to Tim, there seems to be on Rosneft, they published some yet-to-find estimates seem to be 15 billion barrels and 65 TCF of gas on that. So, is that based on how much seismic has been shot? There's also in the Rosneft release that says that Statoil should pay historic costs on these licenses. Are those major expenditures?
Okay. I'll start with the tax and then sort of, Tim, you continue.
Mm-hmm.
Country risk is something that we are facing, you know, across the portfolio. We have it actually in the U.K. We have it in Ireland. We have it in the U.S. We have it in Angola, in Brazil, in Venezuela, Algeria, Azerbaijan, and of course, in Russia. This is part of running an oil and gas company. Government take is, of course, a key element to that country risk and predictability, and in what you can believe in is very important. In Russia in particular, it's quite special in these days. Politicians clearly signal improvements in the tax terms and also providing sufficient predictability to facilitate offshore developments and so on. Russia is actually moving in another direction that quite a few other countries are doing currently.
We welcome that, you know, very much. It will be very important for us to have those frameworks in place before we make any, you know, investment decisions and so on. Currently we have to live with some uncertainties, and for us it's very important to be able to do that and then see to it that things are coming together before we start investing and so on. There are positive signals currently from Russian politicians and so on, and we all know that there's a large incentive in Russia to attract international capital and competence and making all of these resources happen. Tim.
Okay. Let me address the yet to find estimates from Rosneft first. I think it's important to say these are very immature frontier exploration acreage. By that I mean all of the four licenses, not just the three in the Far East. Rosneft have studied these to a much greater degree than we have, albeit on a pretty sparse database of 2D seismic of varying quality. I think when we think about these resource estimates, we should liken them with the resource estimates for the rest of the Arctic, and that there is considerable uncertainty related to these estimates.
Having said that, you know, sort of this acreage is so vast that, if you were to prove up oil and gas in these acreage, you would basically open up not just a new play, but a new basin with all the potential that that might imply. Let's say it's very early stage. There are no wells drilled in any of these license. In fact, the license with the least data over it is the Perseevsky license in the northern Barents Sea. When it comes to the historic costs, then they are limited. There is a small signature bonus which is paid by the equity holders to the Russian state. Otherwise, there is basically no license history there.
That there are the historical costs are expected to be very limited in nature.
Do we have any further questions from the audience? Yes. Please state your name and the company you represent as well.
Espen Hærner from DNB Markets. Regarding the cooperation agreement with Rosneft, I wonder if you could provide some details regarding timing and size of those potential asset deals, including NCS assets.
Okay. I can at least speak on the Russian side. The commitments which we've entered into are related to the exploration program. For the four licenses in question, we will have to drill a total of minimum of six exploration wells. That's six for all of the four licenses, not six times four. That is the minimum commitment. In the case we make a discovery, which we think is worth appraising, then we will also have to finance a limited amount of the appraisal program. In terms of timing, the first well has to be drilled.
I can't remember which license it is, but it's one of the licenses in the Far East by 2016. When it comes to the Perseevsky license in the northern North Sea, then the first well has to be drilled by 2020. These are very long-term licenses, much longer term than we're used to. That's actually good. It again gives us a lot of flexibility. It gives us a reasonable amount of time in order to acquire the necessary seismic data to interpret that, and then to be able to place the wells in an optimum position. This six-well program will be spread over the period from 2016 until 2021.
I guess, you know, sort of, depending on success, then, you know, there will be an appraisal program following on from that. The license period is 30 years. These licenses were awarded. The ones, I guess, both in the Barents Sea and the ones in the Okhotsk, they were awarded on the 29th of December 2011. The licenses will run until 2040-2041. In terms of the assets on their side, I'm not at liberty to disclose names on that. As you've seen then, Rosneft had the opportunity to negotiate further equity interest in Statoil assets, both in Norway and internationally.
We will also be forming a couple of joint technical studies, that's also been communicated on to Russian onshore assets. The one is the biggest greenfield in West Siberia. It's not unlike Troll. It's a huge gas cap with a very significant oil lake. The other one's in the Stavropol area, down towards the Caucasus, and that's a shale oil opportunity, not unlike a couple of the fields which we're exposed for in the onshore in the U.S.
Do we have any? Yes, please.
Hi, this is Kim Iversen, ABG. Just a quick question on the jurisdiction of any conflicts arising from the Rosneft agreement. Where would that take place and what are the mechanisms?
I don't know the specific answer to that. As I say, we will, we've now entered into a strategic cooperation agreement. There will be joint ventures established for each of the different assets, both in Russia and outside of Russia. We expect that to take some 8 months-9 months. I think we're targeting a signing date, you know, for all these detailed agreements in March 2013. That would equate to the period with ExxonMobil have used to finalize all the detailed agreements on the Kara Sea deal.
Do we have any further questions here in Oslo? No. I actually can't see any questions on my screen. Operator, do you have any questions?
Yes, actually now,
Yes.
Now I can see Brendan Warn from Jefferies. Please go ahead, Brendan.
Yeah, thanks, Hilde Nafstad. It's Brendan Warn from Jefferies. I think you'll have more questions. The questions weren't registering. Look, just firstly actually to Torgrim Reitan, just I think appreciate your comments on the European gas market, but I was wondering if you can actually give us some more insights into any of your longer-term sort of gas contract negotiations. I know it's a regular question you get, but I appreciate there's a number of gas contracts up for renewal this year. Just any sort of call or push for breakage of linkages with oil. And then benefiting from having your exploration team there, just in terms of your farm into Ghana, just what in terms of what discovered resource have you farmed in on?
What sort of activity in the near to medium term are you looking for, Tim?
Okay. Thank you, Brendan. On the long-term gas contracts, change is happening. On continental Europe, the structures in the gas markets is changing. We are in the middle of a transition, as I see it, and we actually very welcome a change in the market dynamics. The long-term contracts with our gas customers have served us well for 30 years. We have renegotiated with them every third year. What we are discussing currently is something that we are used to discuss. In 2009, when the financial crisis hit the first time, we said to our customers, "Okay, let's renegotiate now, and then we don't talk to each other in 3 years." That's 3 years ago.
Two thousand and twelve is a year where we are in discussions with a lot of customers. The key points to take away from what's going on. We are selling energy security, and we are selling flexibility. We are willing to make changes to the long-term contracts and put more spot indexation into the contracts, but we are not selling a spot product and so on. What is very important when we do that is to carve back flexibility from the contracts and also having access to the liquid hubs. These contracts can be served in the liquid market as any other contracts, and so on. That flexibility is extremely valuable to us.
You know, currently, we hold capacity both in the transportation systems and in the production systems for the customers to nominate on a daily basis between 40% and 110% of the contract value. When we put spot indexations into contracts, we take back that flexibility and then we trade it, and then we pick the best prices, and then we decide ourselves where the gas is going and to where that is going to head. All of this is ongoing. I think it's fair to say that the negotiations are progressing well. We are preparing ourselves for a different gas market, building up our own end-user portfolio. That has doubled over the last few years. We now sell directly to the end user.
Statoil, power plants, industrials, large industrial customers, and so on. We see that the liquidity on the various hubs are increasing. This is progressing well, and we achieve good prices on our gas, as you see in this quarter. We are well equipped to handle the European gas markets in the future. Remember that, you know, we have pre-invested everything that is needed to handle our gas. We are close to the market. Our gas has to travel one-fifth of Algerian gas distance, 1/8 of Russian gas, and 1/10 of Qatari gas and so on.
I think I dare to say that we have one of the very, very best gas organizations in Europe, so we are set up to handle this. Then flexibility comes back to where it belongs. It's actually with the producer, and we will make money out of that. There's a lot of discussions with the customers currently, progressing well. We actually see that not all of them would like spot products. Actually, customers that want oil-linked gas contracts still.
Okay, maybe I should just take the Ghana question as related to the resource potential. What I can say on that is that we've committed to drill at least one well. That well is drilling already and progressing very well. That well will be testing a new play. It's a high impact well in a proven hydrocarbon province. That's, I guess if we wanted to add to the list on the wells to watch, then that more than likely will also be one that we will know the result of by the end of the second quarter as it looks at the moment.
Sure
Being a new play in Ghana. Appreciate it.
No, I can't. I don't want to disclose that because, if this works, then I would like to exploit it further.
Fair. Fair comment. All right. Thanks, Tim. Thanks, Torgrim.
Thank you. Next question goes to Jason Sch from Santander. Please go ahead, Jason.
I was wondering if you had a net reserves estimate for the Brazil pre-salt find? I noticed you mentioned reserves with the other two high impact finds in your commentary. Secondly, on what could be a potentially significant excess cash flow, I wonder if you could just rank again the possible options for this going forward with be it special dividends or share buybacks or simply maintaining a higher cash balance on the balance sheet. Finally, if you could give me some guidance on the exploration charge. Certainly a lot lower in the first quarter than I was anticipating. I wondered how it might pan out for the rest of the year.
Mm-hmm.
All right, Tim, I suggest you start on.
On PDA?
on the Brazil question, and I'll take the rest.
Okay. Yeah, Torgrim basically told you what we can tell you at this point in time. The only thing we've said that this is most definitely a high impact discovery, i.e., greater than 250 million barrels. As yet, we're not in a position to disclose the more specific numbers than that. As Torgrim also alluded to, we have a very significant, both gross and net hydrocarbon column on PDA, so I'm afraid you'll have to be patient on that one.
Okay. On the cash flow. It is a strong cash flow. We have a net debt of 15%. By year-end, I expect it to end around 13%. If the Statoil Fuel & Retail transaction goes ahead, the net debt at year-end is expected to be reduced by another, you know, around 4 percentage points by year-end. It is strengthening the balance sheet further. As I said, to us, it's extremely important to run with a solid balance sheet. Good company or a great company must be able to take long-term decisions and strategic decisions, even if the weather is poor, even if uncertainty increases and/or prices drop, and so on. We will carry out our strategy even if the weather becomes worse.
To be honest, on that note, we use quite a bit of resources and energy to understand what's going on around us. To be honest, it is very hard to estimate where it ends. A lot of the experts that we use was the same that didn't see what was coming in 2008, but were perfectly able to explain it afterwards. My conclusion is the best that I can do or we can do is actually to be prepared. That is what we can do. Very much about that is to run with a solid balance sheet and significant liquidity on our hands. When it comes to the share buyback, we are asking the general meeting next week for a mandate on that, like we have done for many years.
That is for us to have the toolbox in place if that is found appropriate to use. No decisions to use a share buyback program has been made at all. This is just to have the toolbox in place. That's on the cash flow. Then on the exploration charge. That is low in this quarter due to exploration success. The guiding we have given is that you should expect two-thirds of the exploration activity to be expensed in general terms. With significant exploration success, I mean that expensing will be less and more will be capitalized.
I have no reason to change that assumption going forward, unless you, Tim, here and now can promise that everything that you do will still be a success.
Okay. Many thanks.
Thank you. Our next question comes from James Milligan from Olive Tree Securities. Please go ahead, James.
Yes. First of all, congratulations on a great quarter. I have a quick question on Marcellus volumes and pricing. Given that Cove Point has received the LNG export authorization, can you use your existing relationship with Dominion to access better prices?
Okay. Thank you. Dominion Energy is operating the Cove Point plant in Virginia. That's a regas facility for importing LNG to the U.S. Very little gas is going in that direction. We hold capacity related to Snøhvit. We also have some capacity on Cove Point expansion. We are not using that terminal currently. We are rerouting the ships typically to Asia to take better prices. We appreciate $80 per MMBtu, better than $2. That is good money. It's actually shipping it the other direction. We have a good and long-lasting relationship with Dominion Energy, working very constructively together. They are evaluating to make investments there to make it a liquefaction plant to export LNG instead of importing LNG.
This is something that we follow closely. You know, it takes quite a bit of investments to do something like that. You need to believe in a spread of gas prices around $4 per MMBtu over 20 years to justify an investment like that. There are several initiatives in the U.S. currently in that respect, and then we are following the development closely. You touched upon Marcellus in that respect and our Marcellus asset is producing well, close to 50,000 barrels a day currently. As you know, it sits in an area, you know, with low break-even prices and all of that. We are adjusting production together with Chesapeake, taking down the rig counts somewhat.
Chesapeake is acting as, you know, as we like. Then there is a, of course, big, important issue related to Marcellus gas, and that is to take care of your gas. I know I can keep on going for a couple of hours because I worked with this earlier. It is extremely important to take care of your gas. You know, we have entered into transportation capacity to Canada and Toronto. Currently our Marcellus gas from October will go in that direction to a different price than actually around Marcellus. All right.
Thank you. Our next question comes from Jason Gammell from Macquarie. Please go ahead, Jason.
Oh, yes. Thank you very much. Noted the progress that you made in your Bakken production. Was just curious if you could share the rig count that you've been running in the Bakken to achieve these higher levels of production and whether you're seeing any inflation on the cost side of things. Also if you could just address the type of pricing differential you're receiving there relative to either Brent or WTI, and what sort of transportation arrangements that you have in place in the Bakken.
Okay. Thank you. We have stepped up the rig counts. When we acquired it, I think it was 12 rigs that were operating there. Currently 16 rigs are working for us. It's actually progressing very well. Good results so far. When it comes to costs, it is developing, you know, fairly okay. We see that suppliers actually would like to work with a company like Statoil due to that we take a long-term perspective and the predictability for a long period in that relationship. We are able to attract high-quality counterparties, and that is very much appreciated. When it comes to price differentials, that is the case currently.
We expect that to continue for a while still, and that was also the assumption we used when we acquired the assets. The key is of course to look for transportation solutions, and we are looking for opportunities to use rail or train transportation of crude from Bakken and down to the Cushing area. There are initiatives going on to do that as well. That is ongoing. Producing well differential, yes, we expect that to be in place for a while, but we're dealing with it.
Great. Could I just ask one quick follow-up? Is there any word on when or if you'll be taking over any operatorship in the Eagle Ford acreage?
Operatorships in Eagle Ford? Yeah. We have, you know, that is, together with Talisman, and we plan to take over operatorship of half of that in next year.
Thank you.
Thank you. Next question from ourselves, Oswald Clint, Sanford C. Bernstein, please.
Oh, yes. Thank you very much. I would like to just ask a question on your improved oil recovery activities in the quarter. You mentioned the relatively low decline rate. Can you give us what that number was and how that compares to the first quarter of last year?
I see.
To get a comparison? Thank you. Just you mentioned your Kilchurn well coming up sub-salt Gulf of Mexico. Tim, is there any read across from yesterday's Kakuna well with Nexen? Thank you. Torge, I'm sorry, just one final one on Iraq. A couple of steps to start exiting Iraq. Tim, can you say what those steps are, and will there be any fines or cost implications of coming out of Iraq? Thank you.
All right, increased oil recovery and decline rates. We see decline developing as expected. We estimate it to be around 5% on an annual basis, and that has been so for many years. It is still the case. There will be fluctuations from quarter to quarter on increased oil recovery, but we are, you know, monitoring very closely the long-term trends on this one. We don't see any reason to change that guidance. However, we see, you know, very positive contribution from increased oil recovery. You know, those projects are typically very profitable to realize as well. A lot of efforts is put into that. Before you start on Kilchurn, Tim, on Iraq, exiting Iraq.
That is progressing as planned, and we see that is progressing well. When you come into, you know, specific issues there, I'm not ready to comment on that.
Okay. I think your question was related to two wells in the Gulf of Mexico. Statoil operated Kilchurn, and the comment I have on that is progressing more or less according to plan. As Torgrim Reitan indicated, we expect to finalize that well during the second quarter. When it comes to Kakuna, then the operator, Nexen, have announced that as a dry well today. That means that our share of the well costs will have to be expensed in the second quarter.
Okay. That's clear. Thank you.
Thank you. We'll take the next question from Haythem Rashed from Morgan Stanley. Please go ahead, Haythem.
Thank you, Hilde Nafstad. Good afternoon, all, and thank you for taking my questions. I have three quick questions, if I may. Firstly, just on going back to the costs in Q1, which I understand in some part was impacted by higher royalties there. Can you give us any color or indication as to how we should see these costs progress through the rest of 2012? I mean, is it likely to be sort of linear in line with production increases, or is there some volatility here that we should sort of bear in mind? Secondly, just on Johan Sverdrup, just an update there would be very helpful, particularly with regards to the appraisal program. I...
Lundin have sort of indicated in past releases that they're unlikely to provide any update to estimates until later on in the year, but just wondered from your side what the sort of latest plan was there and when you'd be ready to perhaps provide an update to the market. And then finally, just on rig availability, just wanted to clarify with some of the upcoming wells you have, particularly Peregrine South, and some of the appraisal work on Johan Sverdrup, what the rig availability was. Do you have those rigs in place, or is that something that yeah is still yet to be sort of completed? Thank you.
All right, Haytham. Thank you. I'll take the cost, and Tim, on Johan Sverdrup and rig availabilities and so on. You should expect quite a bit of the costs to be a function of production, as such, but also prices. I mean, royalty is very much driven by prices. That is something you should take with you. When it comes to whether this is linear or not, I think it's too hard for me to say that. I think it's fair to say that when it comes to the international segments, we tend to have, you know, costs from time to time that is not directly linked to the operations.
Like we had in the last quarter related to Angola and Nigeria, where we sort of you know put aside accounting-wise for claims from authorities and so on. That will impact the cost picture. There are none of that in this quarter, but you should expect you know from time to time there to be some elements within the international segments. When it comes to the underlying unit of production costs as such, you should expect that to going forward you know continue to increase slightly more or less on according to inflation. That is what you should expect and of course linked to production.
You should also expect us to be, you know, a first quartile company when it comes to unit of production costs. We were that in 2001. We are still that, and we, you know, aim to maintain in such a position going forward as well.
On the Johan Sverdrup question, our plan for going forward is we've agreed to at least another four wells for further appraisal wells, or in fact, one of those will be an exploration well. Three of those wells will be drilled in the Statoil operator license, the PL 265. One of those wells will be to test what was previously the Aldous North segment. That has the potential to prove up new or additional resources. The two others are appraisal wells. In order to reduce the uncertainty in the resource estimates which we have for 265, and in order to gain important and relevant information for choice of our development concept.
Lundin Petroleum has approval for 1 more appraisal well in PL 501. That is how it stands at the moment, and for us, it makes sense to complete this program before we provide a new resource update. When it comes to rig availability, we have secured rigs for the appraisal program, the three wells in the Johan Sverdrup license. We also secured a rig for the Peregrine South appraisal.
Great. Thanks very much.
Thank you. Next question comes from Blake Fernandez from Howard Weil. Go ahead, please, Blake.
Actually guys, most of my questions have been answered. The only one I wanted to go back to Ghana if I could. I was just curious if you could disclose the price tag that you paid in order to enter that position.
Blake, can you help me with repeating that question?
Sure. I'm just curious if you can disclose what you paid in order to enter Ghana. Was there any kind of financial-
Mm-hmm.
Transaction associated with that?
All right. Tim, please.
Yeah. It's a fairly simple agreement. It's a promote on the well cost. I'm not at liberty to share, yeah, so the magnitude of that.
Okay. Thank you very much.
Our next question comes from Hootan Yazhari from Merrill Lynch. Please go ahead, Hootan.
Hi there. I just wanted to refer back to some tax disputes, or the like that you had on agreements with Angola and Nigeria, which weighed on your DPN international results in Q4. Are these continuing to weigh, or has there been a resolution there? What should we expect going forward on that front? The second question I had was regarding Tanzania. Obviously the next well coming forward there. Can you give us some guidance in terms of at what stage you would look at making this a standalone development, i.e., not necessarily having to cooperate with your partners or your peers across i.e., BG and Ophir? Whether that's what you're aiming for right now, or are discussions with BG and Ophir progressing well there?
Thank you.
All right. Thank you. I have with me Kåre Thommessen. Kåre, can you address the Angola, Nigeria question?
Yeah. We had in the fourth quarter we made a provision based on updated assessments, and we have continued based on the same principles also in the first quarter to make the necessary provisions. The accounts as such reflect our best view also for the first quarter. As you have noticed, there are no bumps or jumps in the accounts as such, so it's more like reflecting the quarter as such. Okay. In Tanzania, as Torgrim alluded to, we are now drilling our second exploration well on the independent structure called Lavani. Our goal is to prove up sufficient volumes to be able to support a standalone development based on our own resources.
In terms of guiding, then we expect that we will need to prove up something like 8-10 TCF of gas in order to support an onshore-based LNG development solution. We are currently looking into other options for more rig capacity towards the end of 2012, 2013, so that we are in the position to drill up additional targets. To that question, then, yes, we have addressed additional targets so that we think the block has the potential to produce or to the resource base which we need for a standalone development.
Understood. Thank you very much.
Thank you. Before we go to what I can see as the last question on my list, maybe the operator could remind the audience on the procedure for asking questions.
Certainly. Ladies and gentlemen, again, if you wish to ask a question at this time, please press star one on your telephone keypad. That's star one. Thank you, ladies and gentlemen.
Thank you. Our next question comes from Michael Alsford from Citi. Please go ahead, Michael.
Good afternoon. Thanks, Hilde. I've got two quick questions if I could. Just firstly, given that Tim's on the line on exploration plans for the Barents Sea, could you maybe give a follow-up on the timing of I guess follow-on drilling after Skrugard and Havis, and maybe a little bit more on the sort of development plans, how they're progressing and I guess timing on those potential developments. Then just secondly, on the taxation guidance for international E&P. It seemed quite low in the quarter, and I'm just wondering if you could give a bit more color as to where we might see that charge going forward for the rest of 2012. Thanks.
All right. Thank you, Michael. Tim, if you can answer this, the Barents question and, Kåre, on international taxation.
Okay. If I take the Barents Sea first, I think I will have to refer you to more information on this, which is planned to be communicated this week on Thursday in conjunction with the energy seminar in Bergen.
The tax for the international segment, we have guided 50%-55% tax rate for the adjusted earnings, and that guidance still remain for 2012. We expect the tax rate over time after 2012, the average tax rate to come down more to the level we had in the past years below 50%. For 2012, it will be in this range. Between the quarters, we will see variances, and that depends on many factors. In short, it's the combination of or the composition between what you can call high and low tax regimes, which might vary over the quarters. We will also get some now and then, some one-off effects like we have in this quarter.
We have won a tax case in Norway for a foreign subsidiary which influenced the tax rate for this quarter, where you see that that's down to 37%, exceptionally low. This is not a trend. The expectation should be between 50%-55%, but might vary between the quarters.
That's great. Thank you very much.
Thank you. Next question comes from Peter Hutton with RBC. Please go ahead, Peter.
Hi, thanks. Yes, two quickies. First of all, I mean, you're talking about the flexibility on the gas volumes and selling into future summers. Can you just confirm whether there's any commitment this summer from arrangements made previously to sell at a fixed price as was pertaining in, you know, say, a year ago? What are the already contracted volumes for this summer in European gas? And the second one in Tanzania in the Lavani field, can you just remind me, is this targeting Cretaceous or Tertiary? How does that link with the Zafarani?
Okay. Thank you, Peter. On the gas side and flexibility, you know the commitment we have to deliver that is towards the gas customers in a way, if we have sold things forwards, there are not a commitment to deliver. You can source that in the market, if you like and so on. In the trading organization, they do quite a bit of transaction in the forward market, but then you can actually source the gas either through the market or you can put your own gas behind there. When it comes to the flexibility strategy, there are no commitment to deliver this summer as such that can be sold through the market, if you would like to do that. Yeah.
Okay. On Tanzania, the Lavani Well is testing a Tertiary target with a very strong amplitude response. It looks very similar to the Zafarani, but the Zafarani is almost certainly Cretaceous. There is deeper potential on the Lavani. We won't be able to test that with this well. The structure is segmented, and the plan would then be given a discovery in the Tertiary interval that we would come back and appraise that and drill to the deeper level with the next well.
Okay, thanks.
Next question comes from Nitin Sharma with JP Morgan. Please go ahead, Nitin.
Afternoon. Two questions, please. There's been a strong momentum on the portfolio front, as you mentioned, streamlining, lining of portfolio. Now that you've divested some significant chunks of assets, businesses over the last few years, how should we be thinking about the agenda on asset divestment front? Second one in relation to North America. Now that you've got a critical mass in North America, what are the next steps for you in unconventional space in that geography? You've already given an update on assets, but more from a portfolio angle, more growth or acquisitions or focus on development now. Thanks.
Okay. Thank you. First, on the portfolio management perspective, you know, we have worked diligently over the last 10 years to streamline the portfolio, selling assets that we don't consider core, like, you know, shipping activities, Gassled, Statoil Fuel & Retail. We are in a process with petrochemicals, and so on. So you know, we will continue with looking critically at our portfolio if money can make more use of themselves other places in the portfolio than where they sit currently. That is something you should expect a certain turnover in the portfolio going forward, as well. Then, you know, we use M&A and business development to acquire assets, as we go.
You know, we do that all the time. For instance, in 2011, we announced divestments or closed divestments of $10 billion, and then we acquired assets for $5 billion. This is a natural part of how we deal with portfolio management. You should expect that to continue going forward as well. Within North America and unconventionals, we are very satisfied with the three positions that we have in Marcellus gas. We have Eagle Ford liquids, and then we have tight oil in Bakken and so on. Then, of course, we will always look for good opportunities to grow even further, but we are quite comfortable with the positions that we have.
You asked specifically about other geographies when it comes to unconventionals. I think there's a lot of opportunities around the world. What is special with the U.S. is that you can actually buy things, you can actually transport your hydrocarbons, and there's a traded market for it, and there are users of the products, and so on. It's a very available market to grow that business. There are interesting opportunities in other places as well. Thank you.
Thank you. We have the two last questions. The first one comes from Rahim Karim with Barclays.
Hi. Good afternoon, gentlemen. First question was for Tim. I think it was just a clarification. I think last time we met, you talked about testing a deeper target on the Zafarani well. I was just wondering if you could make any comment on that front. The second question was for Torgrim, just around taxes. There was a talk from the potential increases in the CO₂ taxes the company might be facing offshore Norway. Just if you could give us any color on that and whether this would be impacting the way that you're thinking or developing some of the fast-track or projects that you're looking at.
Okay. Maybe I can take the Zafarani well. That's you remember well. In fact, we did drill somewhat deeper on the Zafarani well, not because we saw a great lot of potential there, but we wanted to check the stratigraphy below the main target, and we didn't prove up any additional reservoir deeper. As I just alluded to on the Lavani well, then there are indications that there could be hydrocarbons at both levels, both in the Tertiary and the Cretaceous. Okay, thank you. Then on the CO₂ taxes. The offshore in Norway, the CO₂ tax will increase from NOK 180 per ton to NOK 380 per ton. As an operator, we emit 9 million tons. Our share of that is 5 million tons.
If you multiply 5 million tons by NOK 200, I think you get to NOK 1 billion. That is the pre-tax cost related to that new legislation. Whether this will impact any developments going forward is hard to say. It will, you know, on the margin, reduce profitability of new projects and give incentives to invest in lower CO₂ emissions as well. I don't expect it to have a large impact on the development of the shelf going forward, but it is an additional tax that we need to relate to.
Great. Thank you very much.
Thank you. We'll take the last question from Teodor Nilsen with Swedbank. Please go ahead, Teodor.
Yeah. Good afternoon. Just first one question on the realized prices. It seems like the discount to the average Brent throughout the quarter has increased both for the DPN Norway and the International the past few quarters. I guess that's related to high ethane NGL. What should we expect in terms of the discount to the Brent price going forward? Second question is related to Marcellus. Torgrim, you have already mentioned that you have reduced the rig count in Marcellus, but still the production is increasing. What should we expect in terms of production growth from Marcellus for the next two quarters? Thank you.
All right. Thanks. When it comes to the realized liquids price, it is the NGL part of it that sort of explains that. Going forward, you should follow NGL prices and look for the content of LNG into our liquid production. When it comes to Marcellus going forward and rig count, we had 36 rigs working in Marcellus by year-end. That is now being reduced. We are at 24, I think, and then we should expect to be around 20 by year-end, maybe 18 by year-end. This is according to how we should operate in the current price environment. That is sort of the beauty of the asset. You can actually adjust your activity to the current price environment.
To us, it's important to drill to sort of keep land and keep the right to the land. When that is said, you know, we have currently, let me see, 300 wells producing in Marcellus, and then we have 400 wells waiting for completion and the gathering systems. Those 400 wells are, as you know, extremely cheap to put into production. That sits there. There's quite a bit of inventory of wells there. You should expect production from Marcellus to continue to increase. Yeah. Thank you.
Okay. Thank you.
Thank you. That concludes our Q&A session and our event for today. The presentations and the Q&A session can be replayed from our website and in a few days you'll also find the transcript available there. If you have any further questions, please don't hesitate to contact the investor relations department.