OMV AG

Gerhard Roiss - Chairman and Chief Executive Officer David Davies - Deputy Chairman of the Executive Board Jaap Huijskes - Executive Board Member Manfred Leitner - Executive Board Member

Thank you, warm welcome from Vienna, at last to present the results of 2014. I will give you a more broader look into our strategy as in an environment of $50, things should be more informed.

Let me start with our deliveries in 2014. We have a strong growth in production 8% year-over-year.

This is much more than the industry and this is despite of the shortfall that we had in Libya. The shift - our strategic shift of our asset base to upstream, this was achieved ahead of schedule and the reason for doing so, again, is to have oil product that is in a global market and that is in a closed market.

On the other hand, our downstream business is in a regional market, which means Europe and Europe is in decline. What we also did on refining and marketing, we concluded our optimization.

We finished our divestments. We have taken out diversion capital and we also have now merged R&M and gas and power into one single downstream unit to get into further optimization.

The result is that such has been impacted, of course, of our low oil price and of Libya shortfall and what is positive of the strong contribution enough of our downstream business mainly in the fourth quarter. Dividend, what we will propose is a dividend of €1.25 per share.

Key for us is how we manage safety of our people. It’s our top priority and you see here, we performed quite well.

Better than some industries, and we have improved the performance compared to 2011 going down to 0.4, which means 0.4 accidents per 1 million work hours. The market environment is such is still difficult, as you know.

The collapse of Brent price impacted us. The European gas price is continuously weak, again, having a warm winter affecting volume and price.

The instability in the Middle East and North Africa is affecting us more than others like Libya, the shortfall in production. And the positive issue is that refining margins have increased due to falling oil prices and this, together with our finalization of our investment in Petrobras, had a positive impact and we also had a strong depreciation of euro versus of euro versus dollar.

The result is such that clean CCS EBIT went down by [Technical Difficulty] despite of the production increase we have due to the oil price and due to depreciation production costs, we had some impact in our results in the gas and power business. The positive impact is the renegotiation of gas prices.

Gazprom had an impact of a two-digit million number. Lower gas sales margin volumes, negative impact and we also are facing a difficult environment in the Romanian power business.

Refining and marketing, of course, higher indicator margins, much higher than the year before, and we also have a positive impact of our petrochemical business which is very stable. Difficult regulatory environment we have been facing in Turkey, but beside of that, we still have an EBIT, a three-digit million number in terms of Petrol Ofisi EBIT.

Deliveries, you might remember we announced our strategy in 2011 in Istanbul and they had the first target set 2014, second was 2016, so what was the targets in 2014? Prime target was to stabilize production in Romania and Austria, this is two-thirds of our production in the range between 200,000 and 210,000.

The actual figure is 204,000. R&M divestment program of €1 billion was difficult at that time to believe that we could realize this €1 billion, we did it, mainly driven by Bayernoil divestment of Croatia and of Bosnia and a lot of other projects.

Energize to improve the ROACE by 2 percentage points; this was successfully delivered. This is key that we have done it before the $50 environment, but this year, we will have another problem for this environment.

Now the gas-fired power plants, we have finished and they’re running. Nabucco pipeline, we failed, the political decision taken in Europe didn’t support this project.

2014, significant milestones achieved, on the one hand is the upstream growth, we brought up Norway production to 50,000 barrels a day mark. You also have this exploration success in Wisting.

Overall, again allow me to mention that in Norway, we did not go into production. We built up over the years a portfolio, a portfolio of 40 exploration licenses, a portfolio for development projects, includes the British part of North Sea, and to production to generate the cash flow that can support the investments ongoing.

This is a lifecycle project and this is seen in the whole portfolio. Black Sea, we are running now it is ongoing, the third exploration well being drilled.

Downstream, downstream focus is on consolidation, first of all, the merger of R&M and gas and power, two divisions to be merged. This is an ongoing successful negotiation with Gazprom.

You will hear more about it from Manfred Leitner. And the modernization of Petrobrazi refinery, where we have invested €600 million, is finished.

More detail you see here. Gudrun is on stream since April 2014.

And you see here, Gullfaks is showing a strong performance and the cash generation 2014 was already was €500 million, will go up in the future. In terms of Petrobrazi, you might remember the huge loss maker in Romania.

Sometimes loss is more than €200 million. This was because of this huge energy consumption when we took over, the energy consumption, 70%, using their own oil, own crude to run the refinery.

Our Schwechat refinery, for instance, is 8%. So this is now reduced to about 10%, and the same time we changed the yield.

So nowadays, we have a diesel yield of 45%, which is European standard. Before it was 35%, so this will impact, and you will see 2014 first-time positive result.

Let’s come to our priorities, 2015. Cash and dividend, upstream growth and performance, on the cash, our target is, that’s quite ambitious, to have a free cash flow neutrality after dividends and to maintain our dividend policy, as I have mentioned before.

Upstream, we want to deliver our growth. We have all our development projects in the pipeline to achieve our target.

And we also want to preserve the option for the long-term growth, which means exploration and appraisal. Performance, we have to, and we will review all our non-core assets, and on top of it, we will run -- start a new program, what we call, Fit for $50, fit for an environment of a midterm $50 scenario, and of course, to manage CapEx and OpEx.

In detail, this means reduce capital expenditure by 20% to 35% from what we had before, €3.9 billion going down to €2.5 billion, €3 billion. Reduce exploration appraisal for the year 2015 by 25%, going down to €500,000.

Key focus is here on the Black Sea and the North Sea region. And to manage costs, to reduce OpEx, continue the tight personnel policy.

For instance, we have reduced, over the last five years, our personnel by 5% to 6% every year. And we also want to reprioritize all our discretionary spend.

We see ourselves resilient in difficult times. On the one hand, if you see our portfolio gas and oil production, you have to know that in the area of gas, 80% of our gas production is not 100% dependent on the oil price.

On the one hand, the Romanian production is regulated partly. And if you take for instance New Zealand, where we are second biggest gas producer, here the price is linked to the consumer price index.

Then if you see our integration, if you take just the fourth quarter result, you see the strong contribution on the downstream business is 42% compared to E&P 48%. And on the North Sea part of what we have saved, you have to see the portfolio to understand our strategy.

Even this year we had €500 million of cash flow to invest in the region out of the two productions and it’s still growing. Key, the current production portfolio is resilient at long-term oil price of $50.

Substantially all of current production is operating cash flow positive. More than 80% of current production is EBIT positive.

And looking forward, substantially all projects under execution are value creating in the long term. To hear more about this, listen to my colleague, David Davies.

Thank you, Gerhard, and good morning also from my side, ladies and gentlemen. Let me start my presentation with the normal comparison of the business divisions’ performance for the quarter just ended.

We clearly closed the quarter with €545 million, 23% up above the same quarter last year on a clean CCS EBIT basis. E&P was broadly flat, €262 million against €257 million.

This despite production being higher by 15% at 318,000 barrels a day. Of course, against that the oil price was down to $77 for the quarter on average, which is 30% reduction.

This didn’t impact us badly as it could have down, however, given that the dollar was also stronger against the euro during the same period which obviously partly compensated that. So net-net, slightly ahead at the E&P side, also helped by the fact that lower exploration expenses helped to offset the higher depreciation and production costs, given the higher mix towards the Norwegian production.

The gas and power result was lower than the previous quarter - previous year’s fourth quarter, €41 million against €80 million. In particular what you see here is the depressed -- continued pressure on sales margins, and volumes to a lesser extent, but certainly on margins.

And of course, we concluded the final negotiations now with Gazprom to move the gas deliveries onto a purely market price basis. The similar negotiations we had had a year earlier which didn’t quite get us there, led to a one-off payment as compensation for the losses that we had been incurring on these contracts.

That compensation was not as high this year as last year, given that the previous year we gone on such a long way to resolving the issue. Now we’ve gone all the way and that problem, such as it was in the past, is now behind us, thankfully.

As Gerhard has already mentioned, refining and marketing had a good year and a particularly strong second quarter, given the very strong recovery in refining margins, €114 million against €27 million from the refining side within these results. So the major contributor of the good downstream result was the improved position on refining, helped very much by the improved refining margins, more of which both myself and Manfred will say in a moment.

We closed the year with the gearing ratio at 33.6%, that’s an improvement from where we were at quarter 3, as we indicated would be the case. Our net debt now stands at €4.9 billion per year and, as we also indicated in the conference call around the trading statements a few weeks ago, we are proposing an unchanged dividend at €1.25 per share to our Supervisory Board at the meeting in March, which will then subject to their approval, be presented at the General Assembly.

The next slide shows the economic environment, left hand side shows the dollar and the oil price. There the dollar has moved in our favor and, of course, has continued to move in our favor beyond the end of the year, currently around about $1.15 to the euro.

Quite the opposite, of course, is the case as regards the oil price where we had a very strong decline in both quarter 3 and more particularly quarter 4 down to $77 as an average. And then, of course, you’re well aware, this decline has continued, such that we are now trading around about the $60 level rather in February.

Obviously, a few weeks ago, we were as low as $48 for Brent. The gas prices in Europe in megawatt hour are shown in the middle chart.

We will be simplifying this going forward, because the relevance of the orange line and particularly the comparison between that and the yellow line is no longer valid, we’re delighted to say. The orange line was a reference for what was being paid to bring Russian volumes into Germany.

The yellow price was what was actually happening on the market. It is interesting in that you see, in quarter 2 and quarter 3, because of the very strong supply of gas following the warm winter of the previous year, this excess supply led to quite a strong collapse in the gas market price, that didn’t quite have the same effect on the Russian import price.

So, once again, we have the difficult situation of paying the Russians more for the gas than we could actually sell it for. But now, I’m delighted to say that that is resolved and the relevance of this orange line will now move and what will be of relevance then is simply the absolute level of the market price, because that’s the market in which we’re operating.

The bottom line, here the brown line shows you the developments of the Romanian gas price, the regulated domestic non-households, so industrial users’ price in Romania, which you can see now for three quarters has been relatively stable and much higher than it was some years ago. This situation, obviously, we’ve explained at length, but where we are right now, the industrial market in particular, is more or less liberalized, albeit at a level somewhere below the Central European gas hub price here in Central Europe.

On the right hand side, you can see the improving situation as far as the refining margins are concerned. Our indicator margin for quarter 4 was $5.20 per barrel, this is on the new basis of calculation which we implemented in quarter 3.

Hence the very strong increase in quarter 3. This, of course, is being now calculated taking effect of the changed and improved product slate out at the revamped Petrobrazi facility.

Were we not to have done that and kept the indicator refining margin the same, then the blue line is of relevance and we would have had $4.2, which is nevertheless still quite a strong increase on the performance that we were having a few quarters earlier and that obviously reflected in the results as well. One the next slide, Clean CCS net income attributable to stockholders were up by 95% at €348 million.

A couple of points I will draw your attention to here. One particular complication has been the effective tax rate during the quarter.

Clearly, the quarter was impacted by special items, which I’ll come on and explain in a moment, which distorts the tax rate quite considerably. What also has an effect is, I’m going to have an effect going forward, is that as E&P’s contribution proportionately gets lower compared to the downstream business, then the tax rate would also benefit from that because our downstream business clearly is predominantly in Australia and Romania, which are markets where the level of taxation which is obviously typically lower than your average E&P territory.

So as more production comes in - sorry, as more profit contribution is made by the downstream proportionate to the upstream, you will see that going forward. We had said a couple of years ago, when we completed the transaction with Statoil, that our tax rate was likely to be around the 40% mark when everything was stabilized.

Of course, it’s anything but stable at the moment with Libya not being around and the oil price now being much lower. We would expect then the similar circumstances to those currently prevailing that our tax rate on a clean basis on the current year is actually going to be slightly below 30% rather than the 40% we previously indicated.

Minorities and hybrid capital owners, you can see a relatively low number here, €35 million, and this is due to the fact that, of course, the contribution of Petrom in quarter 4 had been equally as impacted by the reduced oil price and, of course, as a consequence, the minority interest has also come down quite substantially. I turn to the next page now to talk about special items and the CCS effects.

We had a clean CCS EBIT in the quarter, as we talked, of €545 million. Within that, we had clean €296 million, almost €300 million of CCS effect.

Of course, this is a consequence of the falling oil price. These losses which were shown in the reported EBIT but we take out for the CCS calculation.

Then you come to unscheduled depreciation of €590 million of which we informed you in the fourth quarter trading statement. The biggest items here have been a provision of €370 million taking against Petrol Ofisi, as well as €144 million which was provided against the Brazi power plant.

There have been no significant E&P impairments. I explained that in the trading statement why in terms of the assumptions we’re assuming going forward.

Clearly, however, should our assumptions for the oil price be subject to any amendment going forward, then the risk does exist of further impairments on the E&P side. Reported EBIT, after all those adjustments, was a €424 million loss.

We come now to the cash flow. Here you see the full-year picture.

On the left-hand side, the net income, that we generated on a reported basis to which we add back the depreciation which was over €3 billion then for last year. Clearly, a large part of it is the special items that we wrote off at Petrol Ofisi, in the power plant, as well as bookings that we made earlier in the year against Kazakhstan, New Zealand and Gabon.

You add those together, it produces an operating cash flow, if you will, of €3.7 billion and against that, we stand the investments, which during the last year amounted to about €3.9 billion, which is entirely consistent with the guidance that we had previously been providing. Of course, following the decline in the oil price, our guidance has now been substantially amended, but I’ll come on to say more about that in a moment.

After cash inflow from divestments, the largest part of which was the disposal of the Bayernoil interest and dividends in total of €650 million, which includes not only the OMV dividend paid last year, but also the dividend of Petrom, which was distributed to the minority shareholders. Our net debt, as a consequence of all of that was increased by about €377 million.

That leaves us with a gearing, as I mentioned of 33.6% at the end of the year and a net debt level of approximately €4.9 billion. Coming now to CapEx and our operating profit - or rather the EBITDA, our total CapEx, as I mentioned was €3.9 you see a slightly lower number.

That’s just the accounting difference between cash CapEx and accounting CapEx. €3.8 billion of CapEx booked compares to €4.1 billion of EBITDA earned.

Clearly the lion share of both the EBITDA and the CapEx went into the upstream business. Romania and Austria were the lion’s share of that something like €1.3 billion in both of these markets with regard to drilling, workovers and field redevelopments, as well as the capitalized cost of the exploration in the Black Sea in Romania.

In Norway, field developments in Edvard Grieg, Gullfaks, Aasta Hansteen, and Gudrun amounted to a little over €800 million during the year. Another big item was the Schiehallion field redevelopment in the UK, as well as, of course, the Maari Growth project in New Zealand.

Single biggest item in the Downstream business during the year just ended was the finalization of the investment in the butadiene facility, which cost something of the order of €120 million. Coming now to the business divisions, going through their quarterly results, starting with exploration and production.

On this chart here, you see on the left-hand side a reconciliation between the quarter just ended and the previous quarter of 2014, whereas on the right-hand side, you see a similar reconciliation between 2014’s Q4 and 2013’s. Why are we down this quarter, sorry, this year in quarter 4 compared to where we were in quarter three?

Principal reason is the oil price, realization something of the order minus €240 million. Volumes were slightly higher, more in Norway than in Libya.

Basically, you see the strong contribution from Norway overcompensating the negative from Libya, with the production coming down dramatically in quarter 4. Exploration expenses compared to last year’s quarter four were, sorry, this year’s - last year’s quarter three were also better by about €75 million.

Depreciation was higher, and this is a common fact. You see, of course, that more and more production is coming from our relatively young activities in Norway, there clearly is a degree of associated depreciation with that as well.

That brings us to a Q4 clean CCS EBIT of €262 million. A similar reconciliation looking at the same quarter last year, realization is a rather similar effect, oil price down from $109 to $77, compensated partly by the dollar, but clearly not enough to actually cover all of it, so €209 million net-net.

Volumes, however, were much higher and here, again, you see a very strong contribution from Norway being by far the lion’s share of this €234 million increase, just little under €200 million of that is associated with our increased production in Norway versus the Q4 period in 2013. Well, write-offs in Q4 2013 obviously burdened the results of that year.

That didn’t happen this year, so clearly, there is an improvement there in exploration expenses of €158 million, and as I mentioned already with the previous bridge, as it were between the two quarters depreciation in Norway, in particular, is obviously coming through into our overall result, as you see here as well. So that gets us back to the €262 million clean CCS EBIT.

The next chart shows our production, which was up slightly by 2% over the year. You can see quite a nice trend despite the complications and volatility around Libya.

Norway production once again ramping up, two new Gudrun wells coming on stream. Also higher production in Romania, albeit only by a couple of thousand barrels, but that’s quite a good contribution given the maturity of the portfolio in Romania.

Operating expenses increased slightly in the quarter. You have higher maintenance costs in New Zealand contributing to this and, of course, the change in the country mix as more production comes in from Norway against, of course, once - against once again Libya coming out and clearly the effect is fairly clear.

These impacts, however, were partly offset by the favorable FX effects as the cost base that we have includes a lot of non-dollar costs, Romanian leu and euro, in particular, whose dollar value in terms of this KPI have obviously gone down. Coming to Petrom, I mentioned already that production increased, you see that also here.

A broadly stable picture slightly higher, very encouraging, given all the activity we’ve been engaged in trying to maintain it. Clearly, oil has been declining slightly, while gas has been increasing, but overall production has stayed slightly higher than the previous year.

Clean EBIT €128 million is down by 59%, compared to Q3 2014. Despite the higher production volumes, of course, the lower oil price and higher depreciation, because clearly, here we’re also investing to maintain this production at this level, have both impacted the overall position.

OpEx here also increased slightly, up from $16.37 in Q3 up to $17.02. This is down predominantly to increased service and material costs, partly offset once again by the favorable FX effects, as well as the slight production increase.

That brings us then to gas and power. The next chart - slide, a relatively straightforward one to explain.

Our profits, clearly, are down, predominantly because of the supply, marketing, and trading position. And here, you see the two factors, both of which I’ve mentioned; predominantly the lower gas margins, the lower benefit of the agreement with Gazprom this year.

Our LNG results with the Gate terminal has also been somewhat down on the previous year. And this has really been the challenge during the current quarter €41 million down, compared to the previous year, which together with one or two minor other variations across the other divisions within the business, produces a Q4 2014 clean CCS EBIT of €41 million.

I’ll jump over the next chart just in the interest of time and come straight to refining and marketing. Here you see quite a positive picture €91 million was the performance in 2013’s quarter four.

Clearly, the big step up to 2014’s Q4 number of €187 million is predominantly down to improved fuel margins. Petrochemicals broadly neutral, although petrochemicals had quite a good year, marketing slightly higher as well, and overall a very solid performance from the refining and marketing business helping offset in part the declining performance of E&P, given the oil price situation.

The next page just gives you a couple of KPIs on refining and marketing. You can see, in particular, following the much lower utilization in the East in Q2 2014.

We are now at super levels of utilization of the Brazi plant in excess of its - marginally in excess of its nameplate capacity. Overall, refining utilization, however, in total was down to 86%, down by 9%.

Marketing sales volumes decreased due to the Bayernoil divestment clearly, which was closed during the 2014 year. We also had a slightly lower Borealis result as a consequence of a weaker Borouge contribution, which is also impacted by the oil price, in terms of its profitability.

Allow me just to focus a little on what we are doing following the change in the oil price, this follows on from what we were saying at the trading statement. Our primary goal, as we look forward in a more difficult environment is to try to maintain free cash flow neutrality after paying our dividend.

That is the primary goal that we’re working towards. As I mentioned already in the training statement we have - there is no intention reducing the dividend.

And we’ve proposed exactly the same dividend for 2014 to be paid in May 2015. Our long-term payout target ratio of 30% also remains intact.

Maintaining a strong investment credit rating is entirely consistent with all of this. We have recently had our credit rating confirmed by both Moody’s and by Fitch.

Both have given us a stable outlook, although clearly, the environment is anything, but stable and one has to take cognizance of that. We have a very strong balance sheet.

Our gearing ratio is just slightly over the 30% level. We also have a very comfortable liquidity position.

What we’ve done through enhance cash flow clearly the first thing that we did was step on the brakes in terms of capital expenditure, the guidance that we had previously issued of around about $3.9 million per year, which of course, what we did in 2014, as we indicated. We’ve not shaken down quite substantially to between $2.5 billion and $3 billion.

Within that CapEx, however, the largely matured projects in Norway, that’s Aasta Hansteen, and Edvard Grieg plus Schiehallion in the UK and Nawara in Tunisia will be continued. And, of course, as we go forward, they will also contribute to our production in the short and medium-term, which will obviously be a benefit to our cash flow as well, because those projects will move from cash consuming to cash generating.

Divestment options are under review. We indicated in quarter three that our portfolio in gas and power was clearly coming under some examination.

We’ll have more to say about that as the year unfolds. What is important to us, as I mentioned a number of times in our organization integrated business model Strong downstream performance clearly supports our cash generation, and it’s obviously something we’re very grateful that we’ve maintained.

A long-term $50 per barrel stress test is something we’re working to. We worked on a number of assumptions.

This is the most aggressive scenario in terms of preparing ourselves and even on the less scenario our target remains broad cash flow neutrality. And that’s something which is clearly, a challenge, but it’s something we’re working very hard to do.

In doing this scenario one of the things we did was look at our current production, how much of it is profitable under $50. And I’m delighted to say that the vast majority is, comfortably more than 80% of current production generates EBIT.

The division would be profitable at $50 at the EBIT level. What’s important also is that substantially all of our production generates cash at $50.

We may be marginally profitable with $50, but we’ll be strongly cash generative in the upstream business at $50, which is also very important. Also important is that the projects we are executing, and I mentioned just four of them a moment ago are substantially all value creating going forward at $50.

Clearly, were we to assume $50 forever, a serious question mark would have to be asked about the level of investments we’ve already executed, as it were in terms the book value whether or not it needed to be impaired. But as you look in terms of value creation the cash that we still need to spend to bring them on stream, compared to the cash that we would generate at $50 per barrel, the vast majority of our projects remain value creating, and therefore will be continued.

Given the reduction in CapEx, however, although we will be bringing more production on stream as these developments are - come to fruition. The growth plan will be deferred somewhat, because clearly, we are looking at every opportunity to push back other initiatives, and that will clearly have an impact overall on our core production as it were.

And that will clearly, need to be taken into account in terms of looking at our overall targets. And then finally, just to the sensitivities.

You see here we’ve decided to show Libyan production at something between 0% and 100%. It’s clearly not something we can control.

You can see how significant it is in terms of EBIT. $1 on the oil price is equivalent to €50 million of EBIT, if we have 100% of Libyan production, if we have 0%, it’s only equivalent to €40 million, so it’s a very significant part of our operating profit.

If you look, however, at the operating cash flow, the significance has gone down quite considerably, because, of course, the tax rate in Libya is so high that the impact is reduced quite considerably. I must point out, however, that these have been calculated around about current oil prices.

If the oil price starts to rise or fall significantly from this, some of these sensitivities, particularly the cash flow numbers start to be quite significantly impacted. One case in point, for example, is our activities in Norway.

Clearly, in Norway, it’s a relatively high tax country. However, with the book values that we have in Norway, we can have an oil price of around about $75 and be paying no tax because of depreciations that we can actually charge.

So that even under a relatively tight oil price environment, those assets are still very strong in cash positive to us. And that’s starts to change quite significantly if the oil price then goes up, the incremental tax taken of the oil price over $75 would then start to be quite substantial.

So one has to use these numbers with a degree of caution, but based on the current environment broadly where we are right now, they are a good indicator of just how sensitive we are to the key market indicators that can affect us. Thanks for your attention.

And at that point, I’ll hand over to Jaap to continue on the Upstream? Thank you.

Thanks, David. A couple of highlights for 2014 from me and then, in particular, we’ll - I’ll be talking about what the current oil price environment means for our investment plans and strategy going forward.

On this slide, just a few numbers. They’ve been mentioned by and large, so a few more details.

Q4 2014 production wasn’t 309,000, it was actually 318,000, so we ramped up during the year. Unfortunately, that corresponded with the oil price going down during the year were timing.

A couple of more highlights around productions. In Norway 50,000 barrels a day by the end of the year, that was, of course, the largest part of our ramp up during the course of 2014.

Also a highlight is the production in Romania where for the second year in a row, we had a small marginal increase in production 171.4 average for the year. Increase in production in Romania was never the aim.

The aim in Romania was to stabilize production but then, of course, a small increase really illustrates that that stabilization is being successful. We’ll talk later on about what we see happening going forward.

Two bits of not so good news, you see the three-year average reserve replacement rate, that’s normally how we report these things, and this three-year average exploration rate dropping and it’s because of 2014 performance. In particular, on reserve replacement rate, you start to see the bite of not taking FID on new projects, and you should expect a similar or a worse performance this year for exactly the same reason.

In an oil price environment of $50 a barrel, nobody is going to take final investment decisions for making new investments. SEC rules, therefore, determine that you would not be the booking reserves.

It doesn’t mean the projects are gone, it simply means that this year you’re not taking FID on those projects and therefore, you are delaying those decisions, and therefore also the reserve booking. Exploration success rate, a poor year in 2014, I think 21% is not something we aim for.

We’ve been running as high as 60% in some of the recent years. That’s why you still see three-year exploration success at a fairly respectable 43%.

We’ve seen the industry struggle with exploration in 2014. The FT had a good article on that last week.

That’s no excuse, but it does illustrate that clearly there is a problem. And you’ve also seen in the current oil price environment, this cutback on our exploration and appraisal program quite heftily.

And like the rest of the industry, in particular, the high-risk, high-reward wells are where you are going to see the cuts in 2015 and going forward. Libya, during 2014 we’ve seen an uptime of about 25%.

That’s not in days, that’s in the actual production versus what it could do if it was on 100%, so about 25%. At the moment, Libya is not producing, Yemen is fully on.

Some further operational highlights, some pretty pictures. You see Gudrun there, the key to our production ramp up during the year.

And you also see Maari in New Zealand with a drilling jack-up sitting next to it, that’s still there. It will be there for the first-half of this year, at which point, we’ll get rid of it for, again, cash management reasons.

We could drill further wells, but in the current oil and price environment, that doesn’t make sense, so the current plan is that that rig leaves in the middle of the year. It’s s drilling; first well is on stream.

Gudrun, as I said, ramped up in April, or started in April, ramped up during the year. In Yemen, we put two further early production systems in.

We’ve been adding early production systems, because clearly Yemen, it’s been difficult to finish the big central processing facility even more difficult now we’re in the final throes of taking the last of our expats out of the country at the moment. We are still producing, but any construction activity has stopped and drilling activity is being suspended, should stop this weekend.

In Nawara, we are executing. We started executing the project.

There are basically three bits to it; a gas plant in the desert, a 400-kilometer pipeline and an LPG plant on the coast. All three of those are starting, in particular, the pipe, about half of that’s now in-country.

In exploration, not too much there about key successes last year. We already mentioned that, but we have built our portfolio further out.

Clearly, exploration is a long-term game and getting access to licenses is not something that you stop trying because of the current oil price. We got into seven new licenses, together with Marathon as a partner in Croatia.

We finished shooting seismic in Gabon and East Abu Dhabi. That means we’ve got the time now to study that.

We won’t be drilling there this year, again good timing. We have drilled some successful wells in Norway.

In particular, Wisting appraisal was encouraging. And also, onshore in Romania, we’ve been drilling Newfield Exploration [ph] wells, all of which very quickly contribute to production.

That’s been key to our successful, strategy of keeping production stable in Romania. At the moment, we’re still drilling high-impact wells in the Black Sea, where the deepwater Neptun drilling is ongoing, and in Austria we’ve got a deep gas target we’re still drilling, we’re currently quite deep; should know any day now.

As per my colleagues, upstream priorities, the first one hasn’t changed, but the other two have swapped position. Safety remains the first priority.

It will continue to be the first priority. It’s one of our core values to make sure that whoever works for us or at least next to us stays healthy.

But the second priority is new. That used to be production.

That’s dropped to third and clearly managing cash flow in a in a $50 per barrel oil price environment is absolutely key to the long-term health of our company. We’ve exercised a lot of flexibility, optionality, much more so than simply canceling things.

Clearly, what we are trying to do is retain our options in case the oil price goes back up, but also have further options in case the oil price goes further down, both of those scenarios are being addressed. So we can adjust further should the business drive the need.

Let me give you a little bit more detail around where the CapEx reduction drops. You’ve seen a group CapEx, a lot of that is driven by a significant drop in the E&P CapEx over the next three years average.

So you drop from €3 billion to about €2 billion to €2.4 billion, €2 billion at $50, €2.4 billion at about $75 a barrel. We’ve averaged the split out over the next three years, so it’s not necessarily strictly identical in each of those three years, but let me talk you through where some of the key changes in expenditure are.

Exploration, you see a reduction in the exploration pot from about €700 million a year to about €0.5 billion a year. And what you see in this blue bar at the top there is the capitalized part of that, clearly therefore, also reducing.

The key bit that you can then see in particular reducing is projects that are pre-FID. You see that in the reserve replacement [ph] rate and you see that in where the money goes going forward as well.

You will also see that of course in production in years to come. The next wave of projects is simply not taking FID in the current environment and therefore, that’s where you’re also spending or taking away most of the funding.

You then small cuts in drilling programs and projects that are in execution. Clearly, projects in execution, we looked at whether or not it makes economic sense to continue them.

It does, but where possible, you do try and slow them down for simple cash management reasons, again. So you do see that the gray bar dropping in size, but clearly that’s much less of a reduction than in the pre-FID projects.

In the pie charts, you see where in the world we see those - we do those cuts and a clear message there is that we’re not cutting one region to leave the other region alone we’re cutting in all the regions. This cut is not driven by geographic or political preferences.

Cuts are really driven by the relative economics of the projects that you’re looking at, that’s what’s driving where we’ve taken the money out of the investment program. And, of course, the second thing that’s driving where you take the money out of the program is this optionality that I mentioned before.

But we’re trying to avoid is canceling things that you can’t put back in the program at a later date, should the environment improve. On OpEx, you see a set of benchmarks.

[indiscernible] lines continue into 2014. We actually look in great detail at each of our peers as well, but we base that on their annual reports.

So clearly, that’s work on their 2014 numbers we will see in the next couple of months, as and when annual reports come out. But what you see and hear is in blue, the cost curve.

In dark blue, the area, you see a set of peers that we’ve kept constant over the last 10 years. And then you see, in green, our performance.

In dotted, you see the median of the peers. So I would argue that our cost performance has been very good.

You see an increase in 2014, that’s, in particular, driven by a couple of very clear things that have happened to our portfolio. We’ve got the implement of an infrastructure tax in Romania, which turns up in OpEx.

In the total OpEx for the whole group, that’s going to have an impact of about $0.75, so that’s quite an impact. Then you see a portfolio impact, which is really then the bulk of the rest of the increase.

If you look at the fact that we’ve added Norway and subtracted Libya, those two changes together add about $2 a barrel to our portfolio. You’ll see slight reduction of that next year, because Norway, of course, we had the full cost of Gudrun for the year, but goodwill started ramping up during the year.

So you should expect a drop off in production costs in Norway next year, again, at similar cost, albeit we’re managing those down, but you got production for the full year. Clearly, also for 2015, we’re sitting down and taking a very long, hard look at our operating cost, including personnel expenses external, but also internal.

And, in particular, also, we’re looking at renegotiating some of our suppliers’ costs. And you do see those coming down.

Clearly, what we get charged in a $100 a barrel environment can’t be what we get charged in a $50 per barrel environment. And that’s a conversation that we’re having with all of our suppliers.

So what’s the impact of all that? If you go back to the strategy as we originally rolled it out, key to our growth strategy was actually keeping the base stable.

I can’t overemphasize that. Clearly, growing the international portfolio is nice, but if [Technical Difficulty] we set that target in 2011, stay within 200,000 to 210,000 extended that out to 2016 [ph], last year.

Clearly, what you’re seeing now though is that, at $50 a barrel, drilling activities, workover activities in Austria and Romania, don’t make economic sense. Although those are associated with incremental reserves, but quite a few also with accelerating tail-end reserves and clearly, when the oil price does what it’s done, accelerating production doesn’t really make much economic sense economic sense, so you push some of those activities back.

What that does mean is that we do expect production to decline in the core. How much precisely, I would like to tell you, but I don’t know either.

It really depends on the oil price going forward [indiscernible] it will go down further, if it comes back up it will stay stable at [Technical Difficulty]. David already mentioned that there is a certain mechanical aspect to what’s going to happen to our total production over the next couple of years if we look in detail at key projects that [Technical Difficulty] in Romania.

Again, by and large, you would continue what you started, with one [indiscernible]. What we try with these projects is we try and manage our capital expenditure over the next couple of years, in particular, in 2015.

And what are you going to see or what you see reflected in this slide is an expectation that that will result in slight delays to some of these projects. These are planned delays, we are actively pushing expenditure backwards.

It doesn’t mean the projects don’t come, but some of the data you see reflected here assume, clearly, a reduction in spend this year, also next year. And, therefore, a slightly later startup date than some of the dates you would have seen previously.

If you then put that together, you get what is, by its nature now, quite a fake graph, obviously. You see in blue, our production, excluding Libya and Yemen.

You see in gray, Libya and Yemen, clearly, the political situation, security situation in Libya and Yemen has not stabilized, far from it. Most people would argue it’s getting materially worse.

So in gray, you see that slice of production. Very roughly, you would put that at about 40,000 barrels a day for the two combined.

Original plans, that would have been actually more, but you would have seen material increase in production in Yemen. We’ve long ago dropped that out of our plans.

And what you do see is the midterm production growing, in the blue bar. That’s those 80,000 barrels a day that you saw on the previous slide.

There’s no year below there, previously we aimed to get to that 400,000 barrels a day in 2016. We still expect with the portfolio that we’ve got to get to in that order, but when precisely really depends on oil price development this year and the years to come.

That will drive what happens through the base production in the core That will drive how much CapEx we’re trying to cut out of projects that are already in execution. And that will, therefore, drive the pace of production increase.

Next slide is really a summary. The blue bar is, of course, not the telling, what the telling - what that simply illustrates is that we aim to keep cash generation and cash spend the same in E&P.

Dividend still needs to be covered. Manfred will talk about that.

What we do aim to do though is make sure that we don’t spend and we don’t earn in E&P over the next couple of years. Clearly, difficult in a $50 per barrel oil environment and, clearly, something that we’re working very hard.

If you look at where the cash comes from, about half the cash out of our core operations, Austria and Romania, and then you see a bit more than one-third coming out of the North Sea; and a bit less than one-third out of the rest of the international portfolio. If you then look at where we spend that, just want to point out that the green bits are the same.

When we did the Statoil acquisition last year, we talked about the fact that, that package was self-funding. What you’re actually seeing here is that not only that package, but our entire North Sea activities are self-funding at a much reduced oil price environment, that’s important.

What you’re also seeing is that, in the rest of the portfolio, the dark and the light blue bits, they shrink a bit in size. What you’re seeing there is that the core operations in Austria and Romania, in fact, pay for our global exploration and appraisal program, most of which, in the next year, is actually executed in Austria and Romania.

So, in summary, going forward, the left bit of this slide hasn’t changed. Our strategy is to have zero fatalities and continuously improve our injury frequency; become safer, in other words.

We want to deliver growth from a stable core, from the North Sea and, in the longer term, in the Black Sea. We’ve got an exploration portfolio focuses on those same areas, plus Sub-Saharan and Africa.

In the mid-term, though, there is a new side to this slide. We’re very actively managing our cash flow, very aware of the fact we can’t spend what we don’t earn.

We’re going to optimize how we execute that spend in particular in the portfolio we’re clearly screening and making sure we spend where it’s best spent, in other words, the most economic activities. To the maximum of our ability, we want to retain options, we don’t want to give anything away, drop anything out of the portfolio that we may want to start executing when the oil price recovers.

And, clearly, also, within the exploration and appraisal pots we’re high grading. And where possible, we’re even exercising that CapEx flexibility in projects already in execution.

Thank you very much. Manfred?

Thank you, Jaap. We have managed now, as well, to change places, because my mic didn’t work.

Ladies and gentlemen, as you’re aware, the divisions refining and marketing, and gas and power, that had been managed separately until the end of 2014, have been combined into the new OMV downstream division, with the start of 2015 under my lead. So, therefore, I have the pleasure for the first time to cover both areas.

Coming to the key achievements in 2014, clearly, there are two sides of it, downstream oil, former refining and marketing. And here I’m proud to say that the year 2014 has been the year of successful delivery of all strategic targets that I have communicated in 2011.

We have reduced the refining capacity by one-third. We have reduced the marketing assets, just to remind you it was already mentioned Bayernoil last year.

We have stepped out of Cyprus, Bosnia, Croatia. We sold the Petrom LPG business.

We have sold the OMV lubricants business. We sold a lot of non-core assets, approximately 100 plots in all the countries over the years.

And so finally, we have delivered the divestment target of €1 billion successfully. The performance has improved, mentioned as well already by Gerhard.

The Petrobrazi modernization project had been completed midyear 2014, thereby increasing the refining margins in our Petrobrazi refinery by $5 per barrel. And I can tell you that 2014 was the first year where Petrobrazi or Petrom refining has contributed significantly positive EBIT on a clean CCS basis.

We have reduced the working capital b more than €1.8 billion and we have delivered in the energize OMV project virtually all the impact, the whole impact on the group ROACE has been contributed by measures in refining and marketing. We have, as well developed - further developed the petrochemical integration that had been defined as a strategic target with especially two projects, one in one in Schwechat, one in Burghausen to increase the butadiene production capacity.

Schwechat part has always been taken into operation. Burghausen is closely before, so both projects are ahead of time and will be delivered very much below the investment budget.

At the same time, the startup operations in the Borouge 3 project of Borealis are underway. The cracker has been in operation since June 2014, and until the year-end, three out of the five polyolefin plants have been going into operation as well.

On the downstream gas, we have, and this has been mentioned as well, finalized the negotiations with Gazprom on the long-term supply contract successfully. So nowadays, EconGas is in a position to earn a margin again on the supply contracts.

They are not based on oil any more, but actually based and related to current market dynamics. The first step in the gas transportation business in Austria in the direction to restructure has been done.

The merger of BOG, this is the West Austria Gas pipeline company has been merged into Gas Connect Austria and the operations of the Trans-Austria gas pipeline transferred into TAG GmbH. Next slide shows you the market environment, and this is especially interesting to see if you look on the left part of the graph here, that the blue part is the OMV reference refining margins.

And as already mentioned, you clearly see here, the benefit of an integrated strategy that we have been defining for OMV, because at the second half of 2014, there is a steep increase in refining margins, which goes in parallel to the huge drop in the oil price. So this means that part of the financial performance that has gone away in E&P could be compensated by R&M here.

The green line shows the monomer margins, C2 and C3. And here the picture is - or the constant is more or less that you see a very stable margin environment over the last three years.

So this is a pretty solid and a very stable contributor to the financial performance in R&M. On the right-hand side, the main message in the graph here is that you clearly see that the sales price, which is more or less the green line, in the European gas market are not any more below the import prices.

So this means that we are going now to achieve a positive margin in the new market environment in Central Europe. This means as well that the border contract tracker and the comparison actually is obsolete now for the year 2015.

Next slide shows you the downstream business supports OMV’s resilience to lower oil price environment. It has already been mentioned that there is a compensatory impact of falling oil prices in the downstream result, mainly driven by increase in refinery margins.

Here you can see on the left-hand side that this is a pretty stable downstream contribution on clean CCS EBIT terms. The average over 2011 to 2013 was close to €600 million.

And in 2014, where the oil price was, on average, only $11 per barrel lower, this is already going up to well above €600 million. The share of downstream in the clean CCS EBIT of the group, in average 2011 to 2013 was 20%, in 2014 already 14%.

And if you take into consideration that the favorable tax rates in the OMV downstream countries and as well as the substantial financial contribution of our share in Borealis that is not consolidated on an EBIT level, the share of the downstream contribution to the group net operating profit after taxes even higher. The average for 2011 to 2013 amounts to some 30%, in 2014, this has reached a level of 40% already.

Next page, very briefly, this is just showing the stability of the petrochemical financial contribution into the R&M results on the left hand side, so you see the 30% approximately are coming out of the petrochemicals part of refining. And this is exactly the reason why we have decided in 2011 to improve and to increase the investment into that part of refining, which will be, and I have mentioned that before, in operation very soon now.

I want to add here that these are figures again where the Borealis - our share in the Borealis net income is not shown because it is not consolidated on an EBIT level. The downstream priorities in 2015, apart from safe operations clearly, we are focusing on a very strong free cash flow again, Jaap has mentioned that E&P or upstream has the target to be cash neutral.

So this means that we will take care of the cash flow to pay the dividend if you want. In terms of integration in refining and marketing, we have come very far already.

I will come thereafter to what I have been telling you last time as well. In the strong value chain integration, this will be to include as well the downstream gas into the whole downstream organization.

In terms of performance, clearly what we are currently doing is we are analyzing the assets in the gas and power, to identify non-core assets. And we have a strong focus and will have a strong focus on efficiency and operational performance, as is the case in refining and marketing already.

The integrated downstream oil, former refining and marketing, the integration level, I have mentioned it last time already, is to the upstream production, which is close to our refinery locations. We sell a lot - a very high percentage of our refining production in the stable retail business.

And you have seen as well that the integration into petrochemicals is giving a high degree of stability to our business, and that is the reason why we are very much better integrated here as well than the competition. We currently are working on a cross-site integration, so means more or less to run all three refineries, all three locations as one refinery and take out all the efficiencies therein.

We try to enhance now the position in the core markets, which we have achieved during the last couple of years. And we focus on strict cost and CapEx management, on the left-hand side, you’ll see the cash generation, which is up and down, specifically up in 2013, because of the divestment proceeds and at the same time that we have reduced the asset base significantly.

And clearly, this will be more or less the example that will be actually played now on integrated downstream gas as well. So focus on cash generation, we will review the asset base, we are currently defining in which way we’re doing that.

And we will be improving the core business. So this is maintaining our gas sales market position in a weak demand environment, optimize margin.

To maximize the value of equity gas means to sell the gas production of our upstream division at the best possible price, as we are doing that for the oil already in refining and marketing. Strict cost and CapEx management, there’s a lot to do here.

And actually, develop an action plan until the mid of 2015, which will go into implementation in the second half of the year. Thank you.

Before concluding our presentation, let me give you the outlook for 2015. On the oil price, we expect a range between $50 per barrel and $60 per barrel.

The gas markets we see remaining challenging portfolio will be under review. Refining margins, expected to come down from recent highs.

On the marketing volume, we see lower product prices, but we expect support of demand, what we see nowadays in our retail, that we see an increasing demand by 13% in Austria and Romania, and we see an increase of 11% in Turkey. This is January figures of our company.

Production is 300,000 barrels a day to 340,000 barrels a day depends on Libyan production, if it’s 300,000 barrels per day, 340,00 barrels per day. CapEx is €2.5 billion to €2.8 billion for this year, 80% goes in upstream.

And exploration and appraisal expense is about €0.5 billion. In a nutshell, we will focus on cash flow and dividend; we will continue to deliver the upstream growth and we have a strong focus on CapEx and OpEx efficiency.

Thank you. We are pleased to answer your questions now.