Ormat Technologies, Inc. (NYSE:ORA) June 13, 2012 8:45 AM ET
Yehudit Bronicki - Chief Executive Officer, Director, Chairman of Compensation Committee, Chief Executive Officer of Ormat Industries, President of Ormat Systems, General Manager of Ormat Industries and Director of Ormat Industries
Yoram Bronicki - President, Chief Operating Officer, Director and Director of Ormat Industries
Bob Sullivan - Vice-President of Business Development - U S
Gillon Beck - Senior Partner
Ami Boehm - Partner
Joseph Tenne - Chief Financial Officer, Principal Accounting Officer and Chief Financial Officer of Ormat Industries Ltd
Gillon Beck - Chairman
Are we ready? Good morning, everybody, and welcome to Ormat 2012 Analyst and Investor Day. Okay. This is very important, the most important part of the presentation in the day is of course, the disclaimer.
Some of the information provided today will contain forward-looking statements. Please remember that our expectations may not be correct and actual future results may be materially different as a result of certain risks and uncertainties. Please refer to the description of risk factors in our annual report on Form 10-K filed on February 29, 2012.
Let me start by introducing the team that is with us today. I'll start with the speaker, Gillon Beck, who is our newly appointed Chairman; Yoram Bronicki, President and COO; Smadar Lavi, Vice President Corporate Finance and IR; Rahm Orenstein, Director of Business Development, I would suggest that you all stand up so that everybody would recognize you. Bob Sullivan, Vice President of Business Development; and Joseph Tenne, our CFO.
Others that are here today from the company are Ami Boehm, a newly appointed Director; Hila Ganz [ph], Assistant to the IR Manager; Eyal Hen, Director of Finance; Eram Karim [ph] and the KCSA team to whom we thank very much for organizing or assisting us in organizing this event.
As we were preparing for our meeting today, we try to compare the company we were at the IPO less than 8 years ago, and some of you are with us since that time, and the company that we are today. And I must admit, that even we were surprised by the differences.
Market cap increased from $0.5 billion to close to $1 billion. Installed capacity nearly doubled. Annual revenue increased to almost $0.5 billion, which is the guidance for this year. We have built an impressive exploration team, very important for future growth. Our land position for future growth increased substantially. Our Product segment is stronger than ever. Our vertical integration was expanded by our drilling capabilities with 9 rigs that we now own and, more importantly or as important, from the technology side, we increased our power generation module to a 20-megawatt in a single module.
The business environment became much more supportive for renewable energy. In 2004, the LPAs program in the United States was at its infancy. Today, we rely not only on the 33% LPAs in California for our growth, but very aggressive renewable energy policies throughout the world.
During the last few years, we benefited in the U.S. from the ARRA legislation, which is about to expire shortly, or at least, this is our working assumption. But unlike wind, geothermal, we continue to be developed and grow even upon expiration of those incentives.
A word about the low natural gas environment. Natural gas prices today in the United States are in the order of $2.5 million BTU. By the way, we have hedged, for this year, our capacity to expected capacity to $3.08 million BTU, a little better than what it is today. But the point I wanted to make is the difference between the $2.5 and $15 million BTU, which are the prices in Japan. We don't believe that this difference is going to remain for a long time. But what we will share with you is what we are planning to do in the interim and we do have paved some plans in the interim, and this is going to be part of the agenda today.
Other items on the agenda, should have rehearsed it before, I'm sorry. Other items on the agenda today would include the presentation of our operations by Yoram, Gillon will make a short presentation on FIMI; Nadav and Rahm will discuss PPAs and standard offer number 4, the contracts that are impacted by natural gas prices; Bob will describe the history of the McGinness project, one of the announcements of the day. And Joseph will provide some useful modeling information on interest expenses and on tax aspects of our activity.
We'll conclude the day, after Q&A, with a -- in closing remarks with lunch, and you're all invited. What I would ask you is to note your questions during the presentation and save them for the end when we will all come up and be available to answer questions.
Yoram, your turn.
I need to do anything? So good morning, everybody, and thanks for coming. Really, what I would like to, as you've seen in the agenda, there is a -- we're trying to provide sort of a continuum of updates, especially on the business development side and how projects are coming together. But what I would like to do is take a chance, to take the time today to review what happened in operations. A lot of this is really since our last Analyst Day, which was in April 2010, but I will make reference to how we really evolved our operations from 2007 onwards, and I think that we're very pleased and I think that you'll be impressed actually taking this -- looking back and seeing how far we have progressed.
I think that when we look at our operations, of course, we have currently about 580 megawatts of capacity. This generates a steady cash flow for the most part. And a lot of the results are really hidden in all the good things that we have done there. And it's -- sometimes, when you look at specific ratios like our cost to operate on $1 to megawatt hour produced and so on, this is when you can actually see all the work and all of the learning that went into the product. As most of you have heard time and again, Brawley has been a big impact and somewhat a mask on all the good things that we have done in operation. We've made steady progress in Brawley and I'd like to really address that. Talk to you a little bit about projects under construction and give some news in that area. And then, give you an update on exploration. What we have done in exploration? How things have changed in exploration? And why when you analyze Ormat, maybe a little bit in the industry, but especially Ormat, you should look at our recent accomplishments as a measure of what we have changed, both in the way that we do exploration and also in the way that we do field development. And then I would like to touch a little bit about our Product segment, which has been very strong or we expect to be very strong in the next 2 years. But really, as much as it is fluctuating, if you look -- if you take a 5-year look, then you can see that this is really a very impressive segment by itself.
So really, just 2 numbers, looking at our actual generation, not nameplate capacity but actual generation from 2007 through 2011, you can see the substantial growth. It does come a little bit in steps. If you look at 2011 and 2012, during those 2 years, we're working on 3 very important projects. Some of them have been completed already. Some of them will be completed later on. And so, you can expect the jump from a certain capacity to another capacity. But if you look at the trend, we have made a lot of progress. And the interesting thing about choosing 2007 as the beginning of this chart is that we haven't done any substantial acquisitions since 2007. Actually, we lost a little bit of capacity with the end of our BOT contracts in the Philippines. So all of this is being accomplished by improving plants, expanding fields and by greenfields.
But as you know, operations, in general, the operating plants cannot control their contract rates. Their way to increase revenue from an existing facility, an existing contract is typically by making sure that we maximize the use of the field and maximize capacity or generating capacity, capacity factor. What we do have control over, to some extent, are costs. And the slide on the right is also an interesting view of how in nominal dollars, our cost to generate the megawatt hour have changed over the years. If we focus first on the gray bars, which is really the full picture, then you can see that the cost to generate a megawatt hour in 2011 has been less than that in 2007, and this is without any corrections for inflation and general cost, which have escalated. So basically, we were able, with all challenges that we had in different projects, we're able to control cost and, actually, reduce cost in real numbers.
If you look at the 2 white columns, they are our cost without the impact of Brawley. If we actually take the impact of North Brawley away then you can see that the reduction in cost has been very steady, and again, very impressive. How have we done that? It's really 3 major elements. The first one is the strategy of developing scale both on a company level, on a corporate level, but especially on a regional level. Expanding operating plants by creating satellite facilities. Sometimes, if you expand an existing field, that's of course, it's a no-brainer in many ways. But even our development in Nevada, development in California and even the development of the heat recovery system, all of this has been done by creating centers of operations. Sometimes, people have to travel 30, 40, 50 miles from that center of operation, but using technology, we can actually leverage existing manpower into expanding generating capacity.
So this is the first element. It's development strategy of how we expanded our facilities. The other one is really leveraging technology, whether it's a technology that allows us to use less people for the same or to make more megawatts from the same number of people. But the other elements of technology are how to leverage things that we have learned on the performance of equipment, where do we need to improve equipment so that an issue that came up in one plant in Kenya is not only repaired in Kenya with upgraded
Equipment, but is also, we're also taking care of anywhere else in the fleet to prevent it from occurring and causing us downtime and costs.
And then, the third element is really leverage -- leverage the scale of the company either on the supply chain, buy smarter, buy cheaper. Or what has been more important is to find out areas where, yes, it's a small company or it's a standalone facility, it makes no sense to get those resources in place. You cannot control the resources and you have to buy them from somebody else. And to move into creating operating facilities or operating groups that provide shared services in areas that standalone facility or a small geothermal player just cannot afford to have.
So 2 examples, the first one is really a chart that shows that the 2 lines are pretty much the same. One is based on generation, the other is based on installed capacity. But just to show the transmission -- I'm sorry, the transition in terms of how many megawatts or how many megawatt hours with a single operator in our fleet responsible for generating in 2005 where the number is about 10-megawatt hour by employee. There's probably a factor of 1,000 there. It's probably somewhere around 10,000-megawatt hours, but just forget it for now. So 10,000-megawatt hours per employee to move into around 20,000-megawatt hours per employee, if I haven't skipped in order of magnitude. And with employees or people being our single most expensive cost in operating plants, this has been a very dramatic change.
The other area which shows what we can do today when we have the scale and also the expertise is what we have done on oil field maintenance. As Dita mentioned, we currently own about 9 rigs. They're used across the fleet for different activities, but among the 9 rigs, we have 4 rigs that are used for oil field maintenance,
Whether it's pump replacement or for the repair of existing wells. And back in 2005 or 2006, all of this work was contracted, all of this work was third-party work. And as of 2011, all of this work is done in-house. Why is it important? First, there's an element of price. As the oil field, oil and gas business was booming, prices went up, although just because the supply and demand, not because the work became more complicated and we were paying a lot more money for the same service in 2009. And this is one element, which sometimes you can address with your suppliers. It doesn't have to be like this, but this is one element. But probably, a more important element is the fact that there are not too many geothermal rigs, and they tend to be -- their owners tend to try and keep them busy. And so when the well fails or if the well requires work, somewhere in one of our operating facilities, often, we had to wait for a rig to become available somewhere and be moved by road for 1,500 miles or more than that. And this is all money that is lost. And so, when you do the analysis, actually, owning equipment and keeping it idle in many cases made more sense than waiting for 3 or 4 or 5 weeks for a vendor to come in and do the job. So many, many examples, but this is how we have leveraged both scale and technology to drive our cost of operation down.
I'd like to move into a little bit of an update on North Brawley, and for those of you who don't remember, in Brawley, we had really 2 separate issues. The first was very high cost to operate, which resulted in a negative EBITDA out of the plant. Where every -- or not every, but many of the line items, many of the activities that had to be done were more expensive in Brawley than anywhere else across our fleet. So this has been the first element that made Brawley challenging. The other element was just the ability to bring generation up. Brawley is supposed to make about 100,000-megawatt hours per quarter. As you see can see in this slide, it has been operating at somewhere between 50% and 35% of that in terms of capacity.
What were the issues that drove cost up? The first issue has been sand production, and I think that you heard that substantially. But the other part was premature failure of our production pumps. When the production pumps fail, 2 things happen. First of all, we cannot generate power, and that's a negative impact by itself. The other part is that the cost of replacing the pump itself was very high, both the cost of the pump, but also the work that is required in pulling the pump from around 1,600 feet deep in the ground, pulling it back to surface and putting a new pump in.
And our focus, if we look 5 quarters back, our focus has been to try and to reduce sand production or find ways to deal with sand production, so that it doesn't become so costly or prevents us from operating. And as we moved away from dealing with the sand, the issue has been how to increase the run life of our production pumps.
And what you can see is and if you look at -- I'm sorry, if you look at the bottom line, at the EBITDA, you can see the improvement that we have made that was done through, first, only choosing the right wells to operate, only the wells, because not all the wells are equal in North Brawley, I'm talking a little bit about it further. But only operate the wells that seem to be making money. And as we find solutions to the pump issues and as we got more confidence that the pumps that we were using were the pump assemblies that we're putting in the ground were good enough, basically we added additional pumps and drove generation up.
What you can see is that the fourth quarter and the first quarter, because of the nature of the power purchase agreement in Brawley had lower rates. And so, if we look at the results of our first quarter and apply the annual average rate for the plant, and assuming that we can keep the type of performance that we had in the first quarter, then we expect Brawley to be EBITDA neutral or EBITDA positive in 2012. Things can happen, there's a lot of work associated with it. But we see a very, very positive trend in Brawley.
Just a little bit to show you how sand production change, this is not a real chart in a sense that, of course, the sand did not fluctuate, these are -- this is based on data points. What you can see in the chart is very high sand make during the start up of the project as we were bringing more wells online, and this is the first 2 quarters of 2010. A reduction in sand make, coupled with our ability to dispose of the sand in a more efficient way. Then as we brought more wells online in the later phases of 2010 and early in 2011, there was again an increase in sand make. But as the well matured, sand production has gone down. And for basically in the last year, we can say that sand is not an issue for us anymore.
The issue has been production pump run life. And this is a little complicated, a little bit of a complicated chart but I think that the numbers that I would like you to focus on is, first, what has been the average run hours of all the failed field pumps by year. And you can see that we moved from 1,000 hours, 1,040 hours per pump in 2009, gradually moved to 2,900 hours in 2010. 2011 was -- the first part did not see improvements, so you can see that the numbers are trending down a little bit. But if we look at what happened among the failed pumps in the last 12 months, you've seen that we are very close to 4,000 hours per pump.
If you look at the ones that have failed in the last 6 months, we're already at 4,500 hours. And so as you look at this, you can see that there's positive movement there, positive improvement. That's of course not enough because our objective is to go beyond, call it, 8,000, 8,700 hours on each of the pumps. But now, look at the next column and on the next column you see what do we get out of the 5 best running pumps in each of the years, and you can see the improvement that we have seen there. But now, scroll or look at the bottom line, and the bottom line is all the pumps that are operating at this point, and you can see that we have 11 pumps that are operating. The best of them have accumulated more than 6,500 hours. This was prepared a few weeks ago, so I think that we're now well beyond 6,600 hours and the pumps are still running. And that's really the good news on the cost side of Brawley. We're not done yet, but the good news is that we are getting the pumps to run longer. The pumps are the biggest driver for cost in Brawley, and if this trend continues, we should meet our objective and our expectation to be EBITDA neutral this year.
But of course, controlling cost is only part of the element and our next challenge was first, to understand, so why did the Brawley field behave or performed the way it performed initially. We had sand issues, but you can see, we've controlled, we have good control over the sand now, and the sand is not so much an issue in more. We had an issue with production pumps. We're still working through the issue, but we now have reasonable run life for our production pumps.
And starting in 2010, we were looking at finding ways to understand why do we have some good wells in Brawley and some horrible wells in Brawley, which was expected to perform a lot like the Heber 2 field or the Ormesa's Field, where if the wells are dispersed from each other, a little bit in flow and a little bit in temperature, but basically behave a lot of the same. And we were looking for new tools because the tools that we had were not giving us any of the story. The tools that we had were basically the ones that had led us to the development of the field. And what we decided to implement in Brawley, we are not the first to use it on the geothermal side, but probably the first to use that tool on a similar scale and to find useful results out of it. And what we've decided to do was a 3D seismic survey of the field.
What is a 3D Seismic survey, I can only tell you a little bit about it. But if you look at Slide 8, that shows an array on our production and injection field, we have set an array of receivers. And as you can see, the trucks on Slide 9 have used an external source of noise or vibration, in that case, it's through those trucks, to generate a sonic wave that travels to the bottom of the ground. Of course, not to the center of the earth, but travel downwards. And is reflected by whatever rocks, sands, fractures are in the surface, in the subsurface. All these receivers receive reflections from that sound wave and using computing power, basically create a model.
If we look at the cross-section on Slide 10, if we look at a cross-section of the data that has been processed, and I hope that you can see it, but really, the data is presented in forms of layers and different colors. And each color would indicate basically -- the dark colors and the lighter colors would indicate the difference between the layer of sand and the layer of shale. The sand allows water to go through. The shale does not allow water to go through it. And not to try and interpret this, but if you can look at this area here on your chart, you can see that it looks -- over here, it looks very clear that there is a discontinuity between this black layer and the brown layer, and you can actually see that it has been moved. And so in the interpretation process, the geologist looks at this and says, oh, there is a fracture, or there is a fault line that passes in this location that actually moved the layers. This whole area was a sea or an ocean in the past. So basically, these are all sedimentary rocks, sedimentary layers. And basically, they should be continuous. In Ormesa they are continuous. But what we found out about the Brawley field is that it's a highly complex field, highly fractured and all these layers that were supposed to be nicely layered, if you like, have been moved.
Just a little bit more graphic. How do I control -- can you turn the clip on from your end? No, not this clip. Okay. So just go back to the presentation if you -- anyway, if technology was on our side, you would see this small x should rotate. So this is actually a 3D depiction of the field, all layers. And what you see in terms of the blue lines over here was we have basically layered our existing wells on this model. And really, the focus on this work was to say, we know that some wells are very good, some wells are okay, some wells are bad, but let's try and find the hints using these tools to tell us why the good wells are good and the bad wells are bad and how can we make bad wells work better.
We added plenty of more information, the temperature data, and I will not -- it's really to impress you, but will not try to go into this. And really Slide 14 is a cartoon form of explaining the situation that we have found in Brawley. Our expectation was for this sample to be continuous and so that injection into well #3 would actually find itself as production coming out of well 1, which is the whole balance of geothermal. But as you can see, on the yellow sand layer, there is maybe some connectivity around well 2. But if we look at what is defined as the sand 2 layer, there's really no connectivity between the sand 3 layer on well 3, the sand 2 layer in well 2 and the sand 2 layer in well 1. And this is really our current understanding of why other performance has been so different from what we've expected, and so disappointing.
And so, now, we take this data and go back. You can see this in Slide 15 and look at the wells. And what we can find, for instance, is that this well, which is called 1815 actually has a very good flow and very good both thick layers that you can see here and also continuous layers that connect it to wells 17, 18. But it's completely broken apart from well 2816, which is about the same distance away, not dramatically different from well 7816, but it's separated by all these fault locks that does not allow the fluid to come in. So you need to use these tools tomorrow to help us fix Brawley, probably not. But I think that the important part of this presentation is really to tell you that we have learned things using these tools. It's not just the 3D Seismic, but taking this 3D Seismic, applying all the operational data from the wells that we have drilled, applying all the well logs from the wells from drilling those. And basically, we're using this to guide us better into developing this field. And this is why we expect to take the plants from operating at about 25 megawatts to date to a higher capacity. Could be 50? It could be 50. It's a very strong field, but what we would have to find is find those or match those wells, whether it's couples or more than couples of wells, then create or define those zones inside the well field that work well together.
And again, this is not what we expected as we move into exploration, the discussion of exploration, it's really, it's not so much a question of what we expected. It's a question of why didn't we get to what we expected and how can we find tools that would allow us both to interpret this in order to fix Brawley, but more importantly, to prevent this from happening in different fields and I'll touch a little bit about that.
So just to wrap up our existing fleet that Dita mentioned and we discussed in our earnings calls, we expect a short-term impact of the transition to SRAC prices and the drop in natural gas prices today, we expect that transition to impact our revenues and we'll quantify that for you later in the presentation. But we have done enough things on our -- on the operational side. First, moving Brawley from a negative EBITDA of about $14 million a year. If I got it right, move it close to a breakeven EBITDA, so just by that, a lot of the impact -- the short-term impact of the transition to SRAC will be taken care of. And beyond that, there's new addition to our fleet that will increase revenue from the fleet itself. And we think that the SRAC issue is bound to be resolved. Some of it soon, some of it a little later, but we don't think that the impact will linger forever on our facilities.
So I'd like to move into Slide 17 and talk a bit about our construction, our accomplishment on the construction side. We have added, since we last met in our Analyst Day, we've added 3 greenfield facilities, 1 expansion to an existing facility and we have 1 expansion in progress. So moving from top left to the right, the first facility that was added was the Jersey Valley facility. We added it in the end of 2010, early in 2011. Jersey Valley in terms of development still follows a lot of our old development pattern. The plant is great, but the way that we have done the exploration and the development of the field at Jersey Valley is something that we're not going to repeat and we have moved it away from that. But as a facility, the facility operates well.
The next facility on the right, the one in green is the expansion, the 8-megawatt expansion, of our Puna facility, has been operating since the end of 2011, operating great. It's a dispatchable facility, but the off-taker, basically, keeps it online for as much as it can.
Next facility on the bottom left is our Tuscarora facility. We started that facility up the day after Thanksgiving. We have passed the commercial operation test, so that facility, in the beginning of January, finished all the paperwork with our off-taker as far as we understand that. Although we haven't shown that in our earnings so far, we actually expect to have a sort of a catch-up and enjoy the commercial rates from that facility for the most of the year. I think that January 12, right Bob? That's a due date. So retroactively, to January 12 -- January 1? Within the margin of error of 11 days. But anyway, facility has been operating very well. The well field has been operating very well. There's more things that we would like to do in that area, but from greenfield to an operating plant in a very successful way. And probably, our best news for today or one of the good news for today is this facility on the bottom right of the slide, this is our McGinness Hill facility. Bob will talk more about this facility, but the facility is, as of today, in its commercial operation testing. And if all goes well, we should complete this towards the late evening, New York time. And hopefully, we can declare that as a commercial facility as well. Generated the full power, well field operating very well. So great news out of the McGinness Hill facility.
The one that is currently under construction is an expansion, it's a third plant or a third phase that we're building in our Olkaria facility in Kenya. It's a great well field, it's a great environment to generate geothermal power. It's been a very good project for us. We've been working on expanding the well fields for about 1.5 years. By now, we have developed all the required production for the next phase of the plant, for another 36 megawatts that you see here in the equipment just before shipment. We found all the resources required for that, both production and injection. And we're continuing to assess what is a good size of the field. And a few months ago, we've broken ground and we're working on completing that plant in the location. Drilling is interesting, logistically, very interesting in Olkaria. You can see the rig here drilling. And we also have on Slide 20, you can see the work on the foundations for the air coolers of the plant, waiting for the equipment to come on site. It's a location that offers interesting scenery and interesting animals for those who would like to visit. And I think, that probably the exciting part about Olkaria is when you compare the advantages of building, expanding a facility that is already in operation. There are the benefits that you have seen, if you like the scale, the benefits and the operating cost, and those are very clear and tangible and I think that all of you can understand that. But the part that is also very interesting and very beneficial is how we have changed our approach to the well field development in Olkaria just because we have the experience. We know, for instance, that there's very little value in drilling as deep as we have drilled in our early phases. The wells there has been drilled to about 9,000 feet. But what we discovered is that really the production zone, there's plenty of production between 6,000 and 7,000 feet, so we can save the last 2,000 feet of the well that are very, very expensive. So well is not exactly linear when it comes to the cost per foot.
The other thing that we've discovered that those zones are very prolific and we can reduce the number of wells that we're drilling and drill the wells with larger diameter completion and get more from this single well. And if we can turn the video now, you can see the first well that we have tested, the well is called A9. We're now, the operator is now opening the master valve just to get the steam flowing and seeing a little bit of the drilling fluid out of the well. And the idea is then to run it into a testability and measure how much steam is coming out and how much water is coming out. So the well is cleaning out. And as you can see, the steam is white now. So we got all the drilling mud out. And now we're flowing it into these separators. The reality, you can see very quickly now, the reality is that although we were expecting a good well, we were surprised by how good this well was and very quickly it overwhelmed the test equipment. And this is worth 20 megawatts or whatever it's equivalent but 20-megawatt of electricity is what it looks like. So very, very successful and it's really from not -- where I should say that all geothermal fields are different. Sometimes, a little bit different, sometimes a lot different. And the advantage of developing a field in the next phase of the field, once you know, the advantage is huge.
So just an updated table on the projects that are under construction, as you can see, we've updated our expectation on McGinness Hill because it is in commercial operation testing now. We expect the next phase of Olkaria to occur by mid-2013. We don't have any updates today on the other rest of the projects. They stay as we've described them in our earnings call. But overall, the list of activities that are shown here and other activities are expected to be -- to cost us about $370 million in the next 12 months, and we feel comfortable that we can complete those.
Moving to Slide 23. Just a little bit of an update on what's happening, how have we changed our approach to exploration. And if you remember, in exploration, we're looking first for temperature because it's pointless to build a geothermal plant with cold fluid. But then we need to find permeable rock and we need to find that there's actually geothermal fluid in that permeable rock. so a rock could be hot, permeable but dry. And then, a good plant cannot be built. And since this industry was dormant for a long time, we really restarted our own activities. And for the most part, most of the activities for that industry around 2005, 2006 when we started -- restarted doing greenfield exploration, and we've learned a lot of things. We've learned that you cannot rely on each of these factors, just very good temperature in an area that is expected to be permeable and have water, it's just not enough and you actually have to prove all these elements.
So how do we do this? First, it's what we call the data mining. It's finding records of surveys that were done by people looking for geothermal or by people looking for other things and have recorded that an area could be interesting. And then we go through reconnaissance. Looking at the sites, trying to find out what of that information is correct, how much of it is real and how much is relevant for us. And then sometimes, we have to use remote testing, sometimes we actually see all of this on the ground, use tools like geochemistry to try and, again, learn from what's on the surface, or learning from what is on the surface, what can it tell us, what's 3,000 or 6,000 feet below the surface. And then, we use geophysical tools. The seismic survey is a geophysical tool, but we use other tools to try and create an image or a model of how the fractures in the different blocks are at the surface, but especially, at the areas that we expect to be the relevant production zones.
Just a little bit of a picture, if you like the outdoors, you should be a geologist. So this is really a reconnaissance trip in Chile of some of our geologists. I'm jumping to Slide 27, and the Slide 27 is what you can actually find in a reconnaissance trip. In that case, the geologists were able to find 2 hot springs, they can sample the springs. And looking at the chemistry of the water, they can say not what the temperature is on the surface, but what the temperature is actually at depth or at the origin of this. And if the chemistry tells us that the temperature is 300 degrees or greater at 4,000 feet, then there's very good reasons to think that a project can be developed there. Sometimes, we can't find anything on the surface, and Bob will tell a little bit about the case of McGinness Hills and how this was addressed.
Slide 28 is the sampling of the Hot Springs. And at the end, using the geophysical tools, we come up with the model that we think represents the well field. In the past, both us and others have skipped some of the steps or moved very quickly from finding encouraging temperature data or encouraging chemistry data into drilling. The drilling is really the right side of that chart. The drilling is easily $5 million in the field, especially if the field is remote, you have to bring all the equipment. The changes that we have made on our exploration side is to spend more time on the first $1 million dollars and decide which are the fields that carry all the interesting information, so that we should go ahead and drill in them. But then we made more changes and this is how we drill. As we learn that it's not enough to have encouraging chemistry data and encouraging temperature data, but that sometimes you may find that the rock is either not permeable or is permeable but doesn't have the water, we were looking for better ways to drill and confirm that, indeed, this is the right location to drill a geothermal well. If you look at our history, and this is based on Jersey data, Jersey Valley data, we were spending to drill a 6,000 feet well, we're spending somewhere between $6 million and $8 million on an exploration well. And that's at a stage where you really have no guarantee, no assurance that a field can be developed there.
And so we're looking for a different tool and different tool was to drill using still similar rigs, but to drill a slim hole. And as you can see, not all of our slim holes actually went to the same depth, but you can see that the curve or the angle of the green line is a much shallower angle. So you can get confirmation using slim holes, you can get confirmation on your wells, especially an indication you really don't want to develop that field at this point for much less money. But that was not enough, and then we moved into what we've been applying in the last 2 years, which is core well drilling and that's the red line. And you can see how shallow that curve is and how much more information we can get or how much less we need to spend in order to get the same information.
How is it done, that's on Slide 33, you can see the physical difference in the size of the rigs as you move from left to right. And having a little truck for reference in the front, you can see how, basically, we moved from drilling 10-inch holes to the drilling 2.5-inch holes and those holes are drilled with a track-mounted rig, very small, doesn't require big well pads, doesn't require roads. All this investment in locations that are really exploration locations and it's a waste to build a well pad if at the end there's no -- a project will not be built there. And that's really the change in our strategy. Exploration is not or has a lower probability of being successful, why spend the money, all that money, in the front end. Spend it once you've actually confirmed that there is resource and that you can run it. Just a little bit about cores but, again, what it allows us to do, this is the core that has been retrieved from, in this case, on Slide 35 from 2,051 feet, so we actually see what the rock looks like. You can see on that core a fracture. So we know that there is a fracture that support what the geological model, or the geophysical model said that will be there. And we can test -- we can bring fluids back to the surface, test for their chemistry, do an injection test, a lot of things to confirm that indeed, this is a worthy location to go ahead and drill a well. And then we can drill it. And because we know what the geology is and what the rock formation is like, typically, we can drill that well for a costs that is closer to the cost of the commercial well and not the cost of an exploration well.
So instead of going and drilling a $6 million well there, we could probably drill, once we know where we're going and what we're trying to address, we can drill that well for $3 million or $4 million. And again, that's a huge impact on the ability -- a company with the cash flow like our company, but the ability to continue and fund exploration and continue and fund our growth.
The next area is how do we -- so this would allow us to spend our money on the right fields, not spend too much money on the fields that are not going to produce geothermal fluid. But then, we implemented a methodology to prevent us from having to deal with situations similar to Brawley or situations similar to Jersey Valley which is, yes, we have production wells, yes, we have production wells. Individually, they all work very well, but as a complex system, they do not work very well.
In here, 2 case studies, I will not spend too much time on them. But basically we have set up in McGinness, we've set up a system that allows to do a longer-term test. When you can see -- and you can see in Slide 38 what we have done.
Actually, excavated very large pits. This is about -- it's about 20 feet deep, that pit. This allowed us to flow water from a production well for a number of days so nothing was going back into the reservoir and then we injected all this water into an injection well using tracers to find out is it affecting production, is it affecting the injection, how well does it operate.
All these information is relevant when you have -- you start from a model that tells you what you expect based on the rock formation, everything that you've learned there. Then you do the actual test and if the data from the test confirms the model, then you know that you are on better footing in terms of developing the field. This is a picture from the test. Now the pit is almost full and we are ready to do injection.
What we've done on the later phase, and this is on our Wild Rose project was to turn this into a more industrial structure. Instead of excavating the pit, finding ways actually to run the test. In this case, the 29-day test, where all production and injection is handled and carried more on a continuing basis. And again this provides confirmation to the model. And you can never say absolutely, but this reduces dramatically the risk of developing a field, building a plant and not getting from the field what we were hoping for like us and other industry players had in the past.
And last on our exploration side, Olkaria is also an example for us as a test case on how to conduct exploration away from a good supporting infrastructure. Nevada is vast and you can travel many hours on the road to reach a field in Nevada, but equipment is generally not more than a day away when you're working in Nevada. The case in Kenya is equipment is generally 60 to 90 days away, depending on what you need. And so what we developed is a technique. We're perfecting it in Kenya and we will use it elsewhere as we move into development of greenfield or geothermal field outside of the United States. All the lessons that we have learned in Kenya are going to be applied there. And again, it would allow us to reduce the cost of exploration.
So what's in store for greenfield development? We feel very confident that our success in Tuscarora and in McGinness in developing those greenfields are not a coincidence but really prove of the change in our methodologies and a sustainable way of developing greenfield projects.
BLM land is more accessible. The permitting side remains sometimes a difficult or a challenge and you'll hear a little more about that. But we're confident that we can apply these tools, techniques and the experience of our people in developing the prospect that we currently have at hand or new prospects that we'll acquire as we learn more.
And we're very, very excited about some properties outside of the United States. Many reasons why development outside of the U.S. would be interesting in the next few years.
On Slide 45, I'd like really to finish off with the Product segment. As you know, we have been the leader in our technology also the most -- probably the most successful developer. But beyond being a developer, a very good supplier either of equipment or projects for other customers.
When you look at our Product sector in the last 5 years, you could see that on average, we've had about $100 million of business every year, which is very impressive. And when we look at what is happening or expected to happen in 2012 and 2013, it's actually a much bigger chunk. Part of it is because we have one order in this mix which is a very large order, and pushes this number higher. But we had a lot of success in our typical size, typically-sized project in the last year. We had a very nice addition in the past quarter, it's actually this quarter, but we disclosed that in our last earning call. It's a very nice addition in North America of the $61.2 million EPC on the geothermal side. But all these numbers are made of $20 million to $30 million to $40 million chunks in different projects. And what has been happening outside of the United States is that the high oil prices of the last 10 years, and high oil prices doesn't have to be $120 a barrel. Even $30 a barrel, which we've seen in 2001, 2002, I think. This was enough of a driver to cause a development, real development of fields outside of the United States, areas that are not tied to natural gas, not sitting on the natural gas infrastructure. And some of them actually coincide with the Ring of Fire, and so work was done there to develop field driven to maturity where we can actually compete or bid on power plants that are being built. And we think that this trend will continue. We don't have control over the development phase, but it's being done. And we are really equipped with the best technology and best experience to supply our equipment and our services to customers who are knowledgeable enough to actually care about buying the equipment that is going to make their cost of the levelized cost of operation the one that is the best.
We are also involved in a very large project in Indonesia. And this is Sarulla project. These slides and these expectations are ones that do not address what may happen when Sarulla actually moves to the next step. And that impact will be very substantial both in our ownership side but mostly on the Product side. And we hope that the positive movement that we had in that project in the last year, in the last 6 months will continue and we can add and surprise you with even better numbers.
So really to wrap up, I think that I'm on Slide 47, what we wanted to share with you all the tremendous progress that we have made in the last years, how unique the company is with its abilities and scale, which really sets us apart from our peers, not only on the geothermal side, but also on the renewable energy side as a general. This ability, the fact that we have 580 lab -- laboratory of 580 megawatts that generates learnings every day that we can then go and find the right technological fix to make it better, not only where that lesson was learned but elsewhere on the fleet. And having -- being a technical company with engineering abilities, scientific abilities, execution abilities, just go ahead capture that knowledge and implement it. And that's really what makes Ormat very, very unique and different from -- sorry, if you're unique, you're different.
The other part is I hope you have seen at least a little bit of how we've changed our exploration techniques and why things that happened before should not happen again. Not on the same level or same magnitude. How we've changed our way of confirming the size and the viability of our prospects. And I hope that you can share our excitement about the future of the business, the Product business, which we think is very interesting.
And I guess at this, I'll let Bob Sullivan explain a little more -- a little bit in details what it took to take McGinness Hills from a slide into an operating plant that was making as much as 35 megawatts last weekend.
Okay, thanks, I appreciate the opportunity to be here. That's so much better. Okay, I'll use a pointer. Okay, so, I appreciate the opportunity to speak to you today. We thought -- and I see you're on -- discuss -- we thought it would be very interesting, both interesting and informative to talk about our competitive advantages and our ability to execute on a project by presenting a case study of a recently successful project, our McGinness project, a 30-megawatt geothermal project located in Nevada. Recently, I think synchronized on the 26th of May, already a full power and as Yoram talked already in commercial operation testing. Or in other words, greenfield operating power plant, the ingredients for a successful geothermal project.
So these are some of the ingredients. I'll talk about each one. In particular: Prospect due diligence, exploration and field development, construction and financing, and finally, operations.
On prospect due diligence, where does a project like McGinness come from? This is a discipline that I personally spend a lot of time on. We have a rule that a successful geothermal project starts by not starting an unsuccessful one. So we literally have dozens and dozens of prospects, and somehow out of that came McGinness, which is extremely successful greenfield project, the most challenging type of a geothermal project.
Literature searches. Huge amount of work has been done over the last 4 decades with oil companies, other developers, even university doing geologic investigations. We have a knowledge of that, literature searches and in fact, McGinness began partially from this. But also we like to call this OPW, other people's work. Also from a geologic matching, Ormat's unique, and the fact that we operate numerous well fields and resources around the world and been doing it for some time. So we have a feel for the geologic constructs that produce a reservoir that has those 3 things that Yoram talked about -- permeability, water and temperature. And McGinness had that, those characteristics of what we thought would be a successful project. So both previous work, OPW and a geologic matching.
Permit in environmental, it's critical that we have high confidence. All 3 of these resource permit interconnected, we can get to the finish line. If you can't get to the finish line, you might as well spend your resources on a project that can be successful. There are issues that will kill a project, but it will kill it slowly. And you can spend, invest, an unusual amount of time and man-hours, our most critical asset, spending time on a project that is not going to get to the finish line because of an insurmountable permit issues. Personally, I think most are surmountable. Occasionally, there I'll be wrong.
Interconnect transmission. Some of other permitting there are issues, congestion, distance to interconnect, access to markets, so they'll make a project uneconomical. So it's important to identify this before you launch into development.
Here's a -- this is approximately a 20-square mile map, showing a topographic map, showing the McGinness project area, right smack dab in the middle of Nevada. This is a tighter shot, about 7 square miles showing the project area. This is all BLM land except the funny inset at the bottom which is private acreage. It's about 7,600 acres, and if you -- you can see this inset we are right in the middle of Nevada. I think near the town of Austin, if everyone's familiar with that, I'm sure you're not. I think maybe -- is it hundreds or thousands lived there? Hundreds of people live there in Austin.
It is connected by the loneliest what's known as the loneliest road in there.
And so this is described as Nevada. Very lonely in the East. Okay, here is a very interesting graphic. It shows the major steps in the project development, both sequential and parallel. And I'll talk about -- I'll show this graph again and again. But it starts from acquiring land, which is what we're talking about now, which we started in McGinness through that OPW and geologic matching. We had an interest in it and we nominated the BLM lands in April 2007 and then acquired them at a competitive bid in later that year in August.
This moves through pre-drilling exploration Yoram talked about, permitting, exploration drilling, the construction of the power plant, plant permitting, construction of power plant, and finally operations. And also the parallel steps, although occasionally the ones below can be parallel as well and I'll talk about that. The transmission interconnect, you see the long lead time items, and the power purchase agreement and finally the financing.
Now moving to Slide 6, pre-exploration activities. These are specialized techniques that we have a lot of experience in, and one of our significant competitive advantages. Again, we have a constant feedback loop. We look at prospects continuously. We drill and explore continuously. Some prospects continue on, some don't. So -- but you build a knowledge base. And we constantly have an interim feedback loop and improve our ability to execute on successful projects. Now as a company, we love lessons learned. If you didn't get this from the first presentation, we do love lessons learned. We live and die by them. We maintain a competitive advantage and we always improve by them personally. I would like to have a project that doesn't have lessons learned. But we have another rule, my boss' rule, which is we always have lessons learned. So we always have a lesson and I only can hope that they're positive that we want to repeat.
So again, our vertical integration allows us, in all these steps, a constant feedback loop to improve from the previous prospect. We're not a one-off developer, we continuously develop, so we can continuously improve and maintain that lead we have on our competition.
The other goal of pre-exploration drilling, one is you want to do a risk reward assessment, on whether or not you want to get to spending bigger money as you're rolling. So this is one goal. The second goal is a big milestone for us. It's not on here, but provide drilling targets. And once we have drilling targets, this is something we are always asking, "Do we have a target? Do we have a target yet?" Once we have a drilling target, we can release permitting. It's a very rigid role, so we deal with the BLM or the forest service or the local jurisdictions like county. You need a drilling target to start permitting -- a point on the ground. So the pre-drilling exploration, we build models, we provide targets and we release our permitting group to begin permitting.
Now McGinness, we -- a lesson learned from McGinness, it took us almost a year, a little bit short of a year, August 2008 to April 2009, to permit the drilling. Now since that -- typically, it takes about 12 months. Since that time, we've developed other techniques, permitting techniques like categorical exclusions, and people are familiar with that. And combined with drilling techniques, such as the drilling rigs that Yoram talked about, driving the rigs you don't need roads. Shallow sump-less drilling allows you to minimize the impact and environmental analysis. So combining those 2 things and we can get permits now in 3 or 4 months and perform shallow drilling. What it does for us is it allows us to get a very, very good look on whether a press prospect has a viability that we want to pursue and move forward and sink more man-hours into it. Which is our second rule, identify unsuccessful projects sooner so we can focus on the good ones.
I didn't know about this animation. There. Typically a 12-month process, in McGinness, we permitted about 15 gradient holes and a dozen exploration sites. The difference is the exploration sites will drill hole sites as well.
Exploration drilling, Slide #7. This typically proceeds in a logical manner, with temperature gradient holes having defined a temperature anomaly. In McGinness, we drilled 4 temperature gradient holes which don't connect to the resource and are relatively inexpensive and about 500 feet deep. That moves us to slim hole drilling, which is basically inexpensive slim full-size well. And we drilled our first slim hole in May 2009. This is sort of our discovery well, confirmed temperature and gave us an indication of permeability. And then we followed that quickly in September 2009 with the first full-size well. Now by June of 2011, we had drilled 6 wells and I'll talk about why and how we did that in a moment.
So exploration follows a very logical pattern, as it did in McGinness. You build the geologic model based on those specialized techniques that we live and die with, with our resource group. It gives us targets we performed and they're low expense, low risk initial. Here is our geologist in the field sampling -- Ben, who is sampling a -- getting temperature on a geothermal map station or a creek here in the -- I think in Pittsburgh it's a creek.
Moving on to exploration permitting, which we now we use categorical exclusions. Typically, initial exploration drilling, temperature gradient holes shallow, the inexpensive full-size wells and then they did a feedback loop to make sure the model is correct before you move to the big stage, which is the x to the full-size wells.
Now drilling the full-size wells confirms productivity/injectivity, basically how much flow you can get out of a production well. It's important, but it doesn't tell you the whole story. What it doesn't tell you is how many of those wells you can drill, and so, or ergo how many -- how much power the resource will support. It also doesn't tell you how close these wells can be so they don't interfere with each other. So to do this step, you need to go a little bit further and perform testing.
Now this is a critical, critical step that we've learned with blood, sweat and tears. You have to be very diligent as a potential significantly impact the project ROI, you don't want to overinvest in the surface power plant. You don't want to build more kilowatts than you're going to get out of the well field. And more importantly, you don't want to overdevelop or overinvest in the underground development, the high-risk development, the well field, and have wells that each time you drill well, you get less and less production out of it. So this is critical. And in McGinness, we did this by June 2011 under the exploration permitting, we had 6 full-size wells and a few slim holes and we've performed rather large scale testing not once, because after one-time it didn't quite click with the model that we had, we performed it 2 or 3x, involving 6 to 9 wells. It's a very extensive testing. Yoram had the pretty pictures, I don't. And it basically changed our thinking on how to develop McGinness, so this is very important.
The critical piece, as we learned in Nevada and most well fields, is not finding a hot production well that flows. It's very pretty when steam flows out. The hard part is less apparent, and this is finding the injection capacity and then the injection scheme that allows long-term sustainable power development. This is the key and it's the real art of geothermal development.
Okay, moving to Slide 10. Okay, plant permitting. You'll see here sage-grouse issues were challenging. It took us almost 2 years to permit this plan, about 20 months. This is a very long time. If you look at the slide. We built the plant on the ground in 12 months, about half the time it took to permit. And a lot has to do with sage-grouse issues. Some hydrology issues, but I think sage-grouse are more interesting, certainly better pictures to talk about on this projects. But the issue, the thing, that really can slow down the project is the plant permitting. And we have a very experienced permitting group that's now, I'd say, tested by fire through numerous projects and especially now in the new sage-grouse area in the west.
Moving to Slide 11. Okay, plant permitting. When we look at the previous slide, it's sequential. What we do is actually permit and parallel the plant construction. Not with plant construction but project release. It's -- we typically release plant permitting. We have some indication of resource to try to compress our development schedule. By doing this we can shave up towards a year off of the cycle by beginning permitting in parallel plant construction now it's risky, but we mitigate that risk as an experienced developer.
We released a project, to release plant permitting with as little as 30% of well field developed, but we already have a good indication, the size of the resource. We still have to develop the rest, drill out the rest of the well field, 70% which comes -- you have permission to do this with plant permitting. You can't drill a hole to our well field with exploration permit to be on, it's clever enough to catch you doing that. So with 70% yet to develop, you can imagine there'll be changes with the blended and input to the plant, specifically temperature, maybe chemistry. So our technology and specifically our control to supply chain, allows us to control that risk, so we can make changes late in the manufacturing process to adjust for temperature changes, some chemistry changes. We've even done it at the power plant site during construction to make minor modifications to the heat exchangers for example.
This is something other developers don't have access to. Of course, if they choose -- or matters to their supplier then they of course can get access to that as well.
Just a little bit further on -- this is a layout -- production and injection field layout from McGinness. This is what it initially looked like before we did the extensive testing we talked about. The red dots to the -- I think I have a laser pointer here. This indicates one production field in the northern and this is the southern and then the injection field. This is how the model is laid out initially. And if we weren't smart developers, maybe this is how we would have built the field initially.
The testing that Yoram referred to, not as a nice picture as Yoram's, but this is the test -- one of the testing going on and of course our drill rig. And then this is the final well field development. Here, we've completely changed it. All the production is to the north and the injection is to the south. I constantly see other developers where -- and you see it in the news yourself, where injection is being changed, production is being changed. They're trying to control declines of the operating oilfield. We did this already for due diligence on testing. So when we did this, all those very expensive and extensive testing, we felt we gathered all the data, input it into a numerical model, a simulation, a model that we can run for, for 20 years or 40 years, frontwards, backwards, adjust and keep fine-tuning until we find a sustainable development program. So this is what we did at McGinness and this is ultimately what we came up with. And this is how we developed the well field. And again, amazingly successful project, synchronized on the 25th of May. We are full powered within a week and already now on -- I'm not sure what today is, the 13th or something, in COD testing. So from greenfield to operation, again, the most challenging type of project, the greenfield plant, very, very successful.
Moving to Slide 15. Another -- I want to stop on this slide because of the next slide. Let's go back though. This is a drill rig which might be interesting to everybody here is the habitat in front of it. This is sage, like the spice you put on some dishes. But this is sagebrush, and then there's some rabbit bush in here, too. Rabbit feed on the sage, and the sage, the sage-grouse, like the sage. And I know this one, I was looking at this picture, this area right here, I'm not saying this is a lek. Is anyone familiar with the word lek? Okay, in the west, you would be. A lek is a strutting ground. This is like the end-all for mating for sage-grouse. So they get in these little open areas around plush sage-grouse and they strut and attract females and teeter other males away from the females. And they're very shy creatures. So they're probably not using this lek because we have this big drill rig looking down on it, so they're probably using something else. But this is what I talk about when I say lek and sage-grouse. Now here's our buddy. This is a sage grouse in full love stripe. I mean, if he wasn't all excited with his chest puffed out and his feathers sprung, he look like a dirty chicken, a small chicken. In fact, I tried to correct him, our project manager from McGinness, calls him chicken. "What about the chickens?", he said.
So this is a sage-grouse. It's a very pretty bird. Some factoids. I guess they're the largest ground bird in North America. I'm not sure about that. No one is writing these notes, is that right? I think there's about 200,000 of these in North America. They're warranted but precluded, is the term, so which means they're essentially on the endangered species list, but not yet there because there's more important guys in front of them, I guess. They like sage, they eat sage, and when they pop their chest in and out they make this grunting noise you can hear for a mile. And I'm searching all my facts. They like to strut in the spring. For example in McGinness, we cannot access the plant until like, I think 10:00 or 11:00 in each morning, because early in the morning is when they're out there strutting. So you can't bother them. And they're very shy, they wouldn't do good in clubs, when they like to do it in private.
Okay, we had a movie but we didn't have the copyright, so -- now this map reminds me of a temperature contour map. This is actually a sage-grouse map.
In McGinness, one of the reasons it took us a long time to permit, although 20 months is not very bad, maybe a few months along typically to our experience. But sage-grouse is an accelerating issue in the west, as all the states, the wildlife agencies and the environmentalists struggle to keep it from being listed. No one wants it to be listed. They want to keep it like this. So our project and Tuscarora -- McGinness and Tuscarora have kind of on the tip of the spear, trying to figure out how to mitigate impacts to not only sage-grouse but their habitat, which is very difficult, because all of Nevada looks like that picture I showed you. Sage-grouse, that means on my back door it's sage. So all of Nevada looks like this and BLM of course is very particular about endangered species habitat. So even if you don't have a sage, when you have a sagebrush, you could see impacts to your projects.
This is a sound survey. So a sound contours from our noise emission points drilling in the power plant. And it's not at the human frequency hearing range, it's the sage-grouse hearing range which I think is a little bit lower than humans. And again, they're shy birds and they don't like noise. They don't like people looking at them, and they don't like high structures. So when we started this, I don't think -- I'm not aware of any other sound survey ever taken for sage-grouse or mitigation associated with it. And this is the point I'm trying to make is this new ground that we developed through Tuscarora and McGinness, and it's another tool on our tool belt for the next project. And the next project on our prospect due diligence, we have an actual column, sage, yes or no, whether or not there'll be impact to sage. From that -- from the mitigation plans we developed for McGinness, we know we have a fairly good idea on how and how much money, how long it's going to take to get to through the process. So on this, to make a long story short, we modify, we actually did modification to the plant layout, the plant equipment, to mitigate sound impacts for the sage. Enough said about sage-grouse.
Okay, this is Slide 18. Power transmission -- the power purchase agreement first. We signed the power purchase agreement with McGinness on November 2009. Our point here, first of all, this is very good because you see in November 2009 as before, we sink a lot of money into the projects. So were able put a lot of money, the big investment in the project with the back stop of the power purchase agreement.
The other nice point to make on this project is we started this process back in 2008, late 2008 through competitive process with NV Energy. So what does that mean? One, that was before we have significant resource information. We have good information but one of the things the utilities look at is project viability. So you're always in there trying to convince them that this is the best thing since sliced bread, this -- without a well. And here, we have some wells that we're actually able to convince them that we have a very viable project. And we moved forward in the competitive process.
The other thing that's important to this is in November 2009, when we signed it, we still had not drilled out those 6 wells. We still didn't have that firm grasp of the ultimate megawatt plant we support. So we have a power purchase agreement from a lot of work, mostly it's from Yoram. We have flexibility in the power purchase agreement, so we can expand that and contract that without penalty. This is something I'm working with NV Energy, a very close relationship with them and also with California Utilities. The works their power purchase agreements also have some of these attributes, very important to geothermal that you have that expandability, that flexibility in the power purchase agreement because as the project development cycle, that ultimate megawatt will change over time as you build out your well field. So having the flexibility and power purchase agreement is very important, a significant competitive advantage.
Interconnect and transmission. The transmission as you see in the graphic is correct. This is the longest lead time item typically in any project. We started with an application for interconnect with NV Energy in November 2007 and we finished only about 3 months prior to synchronization with the actual constructional line. Again, we are little bit of trailblazers on this. We only made the schedule for a couple of things: One, NV Energy has selected the shortest path, which went right through sage-grouse and archeological issues and forest service ground. So we had the opportunity here, we had the chance that we could finish with the BLM and start over again with the forest service with much more significant environmental document. So we permitted -- although, it costs us more in time and money, we permitted multiple options. So we would finish when we had to finish and keep the schedule.
Ultimately, the inexpensive short line was the one that we're selecting. We were able to mitigate concerns with the forest service, so we're able to stick with the initial line. Some of the things we did, we signed engineering procurement contracts with NV Energy which we weren't used to doing to release engineering on our dime, release engineering and procurement along lead time items for the transmission line even though it wasn't clear ultimately where we would connect. But those items are along lead times. We've got those released early to keep the project schedule.
On Slide 19. Financing and operations. Okay, we closed financing in September of 2011. A very extensive team effort by all our group to get everything closed on time. It was subject to DOE loan guarantee and with John Hancock.
Operations. Operations group is in place. I won't talk a lot about this. Yoram highlighted it fairly well. But operations is taking over right now from the project group and it will be integrated into our rather extensive Nevada operations. As Yoram said, a satellite, almost a satellite facility, a very effective way to leverage our base of operations in Nevada. So they get integrated already and get advantage of this knowledge base that we have and also the existing assets that we have. Typically our plant operations are grouped geographically but it's all one group and they all share from the -- our benefit of our lessons learned. And I think that this it. Thank you. Oh and I'm sorry, I apologize you reminded me, and I have a movie.
It's a very, very pretty plant. I did not select the music.
[indiscernible] Thank you.
We are ready to resume. If you would kindly take your seat. It's my pleasure to present Gillon Beck, who will tell us about FIMI, a new shareholder at the parent level. Gillon, please.
Thank you, Anita. Okay. Good morning. Thank you for attending. I hope we'll make the most out of the day. My name is Gillon Beck, I'm a Senior Partner in Senior Opportunity Fund and the Chairman of Ormat. Senior recently joined the controlling shareholder of the parent company and in the next slide, I'll walk you through and try to demonstrate the unique offering and positioning of FIMI.
Okay, in general, about FIMI. FIMI is the leading private equity and the largest in Israel. So we are the leading and largest private equity fund in Israel. We invest in Israel and Israeli-related company. We were established about 16 years ago in '96. And we have an excellent performance in local and global standouts. We were just ranked by Bricklin [ph] Database in a consistent performance ranked #1 rest of first world and #4 including U.S. out of 5,700 funds. In Israel, we're the partner of choice for Israeli and business community and we are well recognized by substantial operational and added value we bring to our portfolio company. We are very, very high disciplined to our investor.
Okay track record. So we have a proven track record for the past 16 years, we have successfully completed 66 deals and we've completely sold over 36 exits. Total transaction value was above $1.7 billion and we successfully raised 4 funds with the perfect loyalty of investor which people who know private equity is quite unique. And now, we also completed the 5th fund of $800 million and closing schedule to be next month. In terms of strategy, we have a very solid investment strategy I'll outline at the next slide. And also we have a very strong relationship in the Israeli and international community and capital markets.
Who are our investors. Our investors are mainly Israeli and the U.S. investors. For example in Israel, the biggest 5 banks, the biggest 5 insurance companies and most of the pension funds and usual investors in Israel are investors in the FIMI. If we look at the U.S. Investors, so we have a plentiful investors. And let's look the insurance companies such as Allstate; Mass Mutual, since the inception; New York Life Insurance; Hamilton Lane, a very big gatekeeper and worldwide investor in FIMI -- Citibank, Jefferies, our investors also since the inception. You see Leucadia, West Virginia Foundation, a lot of other reputable investors around the globe and the Israeli institutional investor.
What's our strategy of investment? We do control investments -- control of the boat and turnaround is better situation is also some amazing investor. But most of our investments are taking control company. Key criteria of investments are mature companies, revenue is above $75 million, significant growth potential, very important we have to identify before coming in the growth engine of the target company. And also, we don't do investments if we don't see that we can have a meaningful added value to the target company. We also look for companies with a solid and good management in place. We do all kinds of industry of interest except we don't do real estate and we don't do financial institutions such as banks and insurance companies, et cetera.
Very important part of our philosophy is the risk mitigation. So in terms of leverage, and this is in the past 16 years, not only after the 2008 crisis, is that we do a very low leverage when we do deals, a very low average leverage in the past 16 years is 25% to 30%. For example, the Ormat deal currently is not levered. And mitigating risk by revenue which is also like Ormat, 80% of the revenue at least outside of Israel, mainly in U.S., Europe and the Far East. And we have a diversified portfolio. Another thing, the mitigating risk is very, very high discipline in entry evaluation. Very high, very strict and we continue that further in the past 16 years. And we also do very comprehensive downtime analysis when we evaluate companies. This is very important part of what brought Ormat to what it is.
I didn't tell you before but when we were ranked #4 Bricklyn [ph] -- average IRR for the past 16 years is about 30%. In terms of the team, we're a small team. I'm a senior partner. I joined 9 years ago and graduated engineering and honor and then secondly MBA in finance, worked in operation before the company is trading in the stock exchange at the global company including -- we had a headquarter down here in Fort Worth, Texas and many subsidiaries around the world. As a senior partner in the fund, we take control over the portfolio company, serve as chairman, board member [indiscernible] in Tel Aviv, maybe traded in NASDAQ or had the chance to do some of the private company and take responsibility about the company from the due diligence and beginning the deal until the exit. Ami, go to here, Ami. A few word about yourself.
Sure. I'm Ami. I joined FIMI in 2004. I manage the turnaround division in the same group for about 4 years and very successful. I've been on several Board of Directors, aside from that before going to FIMI I was the head of research at an account at Capital Markets. [indiscernible] best known discount bank [indiscernible]
Okay. I have a few case studies, I'll go very quick through them because it's a different -- but just to get a taste and a flavor of what we do and perform, how we reach IRR in the past history of ours. So just generally, this is a company that's about ILS 1.2 billion sales. What's interesting here is that we came in, the margin is 7.5%. Now the margin is 15.5%. 15.1%. It's very important and it's complicated. It's hard work, it's management and this is a company that in the defense area, we saw -- in the NASDAQ, and we came in it was 117 revenue with a 15 EBITDA. We sold it and it was $65 million and 260 revenues we did about $100 million profit in that deal.
Also the IRR was very high, 46% IRR. And Littman, we sold to very firm traded here and New York, and we came in it was $86,241,000 when we sold it. Hopefully, we did 80% IRR 9x -- 6x on the cash and almost $100 million profit. I feel we just sold last year to Newport traded on NASDAQ. Also here we bid 2.5x in the cash and 36% IRR was fully acquired by Newport. It's also in a precise IRR amendment. One of the best in the world. And this is an example of taking a good company and transforming it to an excellent company. Good buy by the EBITDA margin was 15.4%, so you ask yourselves how can we improve in such a company that presence in economics? Nevertheless after 4 years, 22% margin.
And this is a company we sold saw just a few months ago to CHF, a Fortune 100 company. It was the first purchase out of U.S. of that conglomerate and it's in the [indiscernible] Ami was responsible for that deal. We did a 30% IRR and 3.2 was fully acquired out of the public market.
So we have lots of examples. Statistics 66 [ph], for example, Starplex [ph] is there, company traded in NASDAQ. We still hold it, we are the controlling shareholder of the companies -- a very good company, lots of other portfolio companies. I won't go through all of them.
But just to conclude and summarize. FIMI and myself have proven a very good track and unique track record in Israel and U.S. and in global standards. So where we and FIMI, we expect and we believe that such added value will bring to the company, such ability to change, such a crave for excellency and performance, together with the company with Yoram and Dita, valuable experience will be part of our influence, will be part of our performance and will be part of our working together in Ormat. So thank you very much. Smadar, please. Thank you.
Thank you, Mr. Gillon and good luck with your new position. I got the past picture, right? Exposure to SRAC was discussed previously in our earnings call and with some of you in person. But they want to show here in the presentation that the part of SRAC is really a small part in a very stable and relatively very predictable stream of revenues that our operating power plants are generating. And they -- we will see how it impacts -- I'll try to walk-through the slides and help you understand how SRAC impact our operation.
Let's start to look at the PPA structure. We have a bunch of PPAs for each of our power plants. And generally, we can divide them to 3 groups. The first group includes PPAs that most of them, we inherited when we acquired the assets in Nevada and California. Brady, Steamboat 2 and 3 and Steamboat Hills. All of those PPAs have fixed capacity and fixed energy until the end of the contract, with some reduction in capacity payments in previous years in one of the 3 PPAs. But the capacity until the end of the expiration of this contract is fixed and the energy as well. The energy is either linked to a certain index and/or escalate by a fixed escalation rate. In this group, we also have the PPAs for the operation outside the U.S.: Guatemala, Nicaragua and Kenya. Again, those PPAs have fixed capacity and fixed energy. No exposure to any commodity.
The second group, our fixed energy rate contract, they have only the energy component. These PPAs were signed since the RPS was enacted. And in some of them we had escalation, in some of them we don't. But like the other group, no exposure to any commodity at all.
The third group, this is the group that we will discuss in length, are PPAs that we have a capacity fixed until the expiration of the contract, but the energy rate is changing. It's changing and it is linked to that local commodity alternative. We have those PPAs in California for Ormesa, Heber and Mammoth, and the commodity that they are linked to or impacted by is the natural gas prices. And the PPA in Hawaii for the Puna project.
But if you look at the entire portfolio, you can see 387 megawatts out of the 586 that has no exposure to commodity at all. The other, to some extent, have an exposure. All right. And the 387 megawatts you can see reflects approximately 66% of the entire portfolio. And if you look at the chart in the right, the revenue breakdown, we can see that less than 30% of the expected revenues in 2012 relates to the viable portion of the PPAs, and even this portion is -- the exposure is limited. Because as Dita and Yoram mentioned in their presentation, we were able to hedge also the exposure to gas at least for 2012. And as you already know, the Puna rates will also hedge in -- for 2012, we are covered -- and we can say that for 2012, almost all our revenues has no exposure.
Let's start with Hawaii and see and walk through the PPAs. So we have 3 PPAs: one for the 25 megawatts, one for the next 5 megawatts, and the third PPA is for the rest of the generation that the Puna project generates up to 38 megawatts. The only PPA that has an exposure to commodity is the 25 megawatts. We got a capacity payment fixed, but the energy rate is linked to the avoided cost of the local utility, and the alternative in the island is oil. So we are linked to oil, but the link -- we don't have a 100% correlation to oil because the formula of the avoided cost takes into account also the inventory that the -- a local utility has. So we sometimes see a gap between what the oil prices, how they trend and how the energy rates are impacted. In any event, we acquired 2 swap contracts to hedge this -- to try to mitigate or to reduce the fluctuation of revenues from this power plant. And these swap contracts secure an energy rate, an on-peak energy rate of $188 per megawatt hour, approximately $188. So for Hawaii, until March 2012, we are hedged against any reduction in oil prices. And by the way, since we acquired those contracts and made this transaction, oil prices went down. So we are covered until the end of March 2012 -- 2013, sorry.
Let's talk about the California PPAs, the SO4, this is how we call them, PPAs. These are standard PPAs that have a standard structure, and they were signed in -- between the middle of the '80s and the middle of the '90s. We have 6 contracts from the same structure. Capacity is fixed. We got also bonus in certain conditions. And this is fixed until the expiration of each of these contracts. The energy rate was fixed until May 1, and since then, it's either exposed to gas through the Short Run Avoided Cost. This is the way, now, the off-taker is calculating each month the energy rate. And the Short Run Avoided Cost is determined in the beginning of each month, and it takes into account gas prices of the previous week.
And now let's talk about, let's say, in my explanation of the formula. Those fixed PPAs, Ormesa, Heber, and Mammoth PPAs, we expect them to generate 1.25 million-megawatt hour in 2012. And the related energy rate average over the entire year of about $59 per megawatt hour. Out of which, $38 per megawatt hour, this is the portion that is reflecting the variable part of the revenue. It means that $21 per megawatt hour is fixed, and it will stay fixed until the expiration of the contract.
And if you look at the chart, you can see a kind of a snapshot on how the PPAs -- what are the expiration of each of the PPAs as of today. I'm saying as of today because that may change and/or -- Rahm Orenstein, that will present right after me, he will talk about the opportunities that we have to re-contract these PPAs. So this is what we have to-date. And that may change or will -- we will address other opportunities.
Let's understand what is the sensitivity of the energy rate for a change in gas prices and for that, we have to understand the SRAC formula. The Global Settlement that was recently signed, this is a settlement that changed the program, the PURPA program, that was until that sign. The PURPA is Public Utility Regulatory Policy Act, and it changed it with the state program and that provides to our SO4 contract, which are QS Qualifying Facility, an option to choose between 2 SRAC formulas, and we have option A and Option B. We try to estimate what is the NPV that we can get from each of the formulas because as you can see in a minute, they are different, especially with the heat rate that is different between the 2. But in any event, we came to a conclusion that Option A provides the highest estimated NPV for the project Ormesa and Heber. And Option B, it provides the highest estimated NPV for the project Mammoth in California.
And how does it work? The formula has 6 components, as you can see here. The heat rate, as I said, is different between Option A and Option B. It is higher in Option B. It's multiplied by the gas price. Now the gas price is determined, as I said, every month and the off-taker is taking the average of 3 indices: Natural Gas Week, the NGI of So. Cal. Border and the Platts. And the average of these 3 indices determines the gas price that will be used in the formula. In our formula, we took Option A heat rate for 2012, and we multiplied by the gas price that we hedged, means that the minimum gas price that we will get for our revenues in 2012 is $3.08. We add to that O&M, which is fixed, generally it's fixed, it has a certain escalation, but it's not a material. And that -- the outcome is multiplied by the time of use factor of the utility. It depends on the time that we delivered the energy to the center load. It showed it in our example, June mid peak factor. And that -- to that, we add the location adjustment, which compensate or penalize a project, depends on the area location relative to the load center. In this example, we compensate, and that would make that a -- we had a little glitch in this formula because in the case of Heber and Ormesa, we are penalized with the same amount, it's not material. But just in case you take note and try to calculate the energy rate, that should be taken into account. And to that, we add the GHG. Now, GHG, as you probably know, California had -- for years, tried to introduce a cap-and-trade program. And the policy was approved in November 2011. The cap-and-trade that's based on the current program will be implemented in the beginning of 2013. If that happens, Ormesa and Heber will benefit from a GHG ether [ph], and how it calculates -- how we calculate it, we take them -- in my example, we used $16 per ton CO2, and that is equivalent to $7 per megawatt hour. So taking these assumptions, we get to an energy rate of $36.8 per kilowatt hour, where the weight of natural gas is approximately 70%. If there will be no GHG, the energy rate is $29.8 per megawatt hour, and the weight is 85%. It means that with no GHG, the weight of gas prices are higher -- is higher and it is getting higher as gas prices are increasing.
A quick look on how energy or how revenues in 2012 looks like. We're expecting 70 -- in minimum, $74 million in 2012, taking into account the $3.08 per million BTU of gas price. Gas prices will be higher as they are expected in the recent future record. We may see and we may benefit from higher revenues. You can see also the breakdown between the quarters. In the quarter chart, these are the revenues from the contract. The $74 million takes into account also the cost we had on buying the hedged transaction, it's about $1.7 million. And how this base case, the $74 million changes, so each change in -- each $0.5 change in 1 million BTUs impact the entire portfolio by an annual revenues of $5.1 million or $5 per megawatt hour. And if GHG or if cap-and-trade program will be implemented, we -- Ormesa and Heber will benefit from it. And each $5 per ton CO2 is equivalent to about $2.2 million.
Okay, before I get to the specific of this chart, it's very important to understand that since the RPS was enacted, SRAC was never a good measure for -- to what utilities are willing to pay to long-term renewable contracts. And here in the chart, you can see the gap between what was the average of the contract that were signed between the years 2003 and 2011, compared to the average SRAC of our take-off -- off-taker in California. And you can see that gap.
So I hope that the slides that I showed, you understand how SRAC impact our revenues. But it's very important to remember that SRAC is limited in terms of its impact on our revenues, but at the same strength, it is limited in the time that it will affect our revenues.
And I think it's the right time to go to Rahm presentation to show us and to present opportunities that we have to mitigate the short-term impact that we expect on our revenues.
Good morning. My name is Rahm Orenstein, I was in Business Development. And as Smadar presented, I'm here to share with you some of our perspective and thoughts on the opportunities in California. Smadar explained some of the challenges we faced with some of the existing power purchase agreements. And I will talk about the opportunities.
First, I'd like to ask you to look at this picture for a second from 2 reasons. One, it's because the only picture you're going to see in my presentation. And the other is because of, what you're seeing here are our Mammoth facilities, near Mammoth Lake in California. This is our -- the smallest one, G1; this one, we call G2; and this is G3 here at the bottom. And I will make some references to this project later on.
So let's start by looking at the California utility market. Three large investor-owned utilities, namely Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, serve roughly 3 quarters of the load in California, with the rest being served primarily of what's called a POU, the publicly-owned utility, largest one being Los Angeles Department of Water and Power, and few dozens of smaller municipal utilities, and a fraction is served by what's called Energy Service Providers.
What drives utilities to buy renewable power, in general, and geothermal, in specific? I think it's fair to say that it is primarily the Renewable Portfolio Standard, or the RPS, that was enacted around 2003 in California.
If you look at this chart that I put in, taken from a recent California Energy Commission report about the RPS in California, you can see quite a few pieces of information here. The black line shows the renewable generation over the years. So it's currently about 40,000 gigawatt hours a year, which is around -- generated by quite a few thousands of megawatts. Total load in California, to those of you who like numbers, is more than 200,000 gigawatt hours a year, and this is served by almost 60,000 megawatts in California. What you can also see on this slide -- on this chart, are the RPS targets right now. These are the red triangles, are the target for 2013, which is 2011 through '13, which is 20%. Those blue dots are the targets for 2016, which is 25%. And 2020 goes up to 33%. And again, the percentage is -- the percentage of the total served load -- sorry, served by the utility that needs to come from eligible renewable resources, there's -- for each milestone or target, you see an upper value and a lower value. This, of course, is derived from the expectation of load growth, loaded higher than that renewable portion becomes higher. What you can also see here is the forecast. So the black solid line is the actual historical data on renewable generation. And then the dotted lines are the expectation. Starting with a brown dotted line, that's the generation that is expected if all the power purchase agreements that all the utilities have signed will come to fruition. And as you can see, if it happens -- and they pretty much are already contracted to meet the RPS requirements on a macro basis. However, more importantly, you should look at the green number. The green number as the slide explains, is representing a 40% discount, meaning an expectation of 40% of the total PPAs in California that have been signed, some of them, not even approved yet by the regulatory agencies, will fail. And that's a reasonable number explaining that California Energy Commission report, based on historical data. So with this reasonable assumption that 30% to 40% of future PPAs will not generate what they are supposed to generate, when you can see though on a market level, utilities are still in good shape to meet the first 2 targets, but there's a significant gap here towards the 2017, 2020 timeframe, which translates to around 25,000 gigawatt hours a year, which is thousands of additional renewable megawatts that utilities will need to contract, and this all opportunity for us and for other renewable developers.
And also, our specific programs within the RPS, like the renewable energy -- the Renewable Auction Mechanism or RAM, not to be confused with my first name, that can sometimes trigger purchasing, even beyond those minimum targets. And to those of you who follows -- follow for example, the statements by the Governor in California, unlike some other states, in California, the RPS targets are strictly seen as a minimum and not at as a maximum. So on occasion utilities will contract even above that minimum.
More about RPS program. It seems several phases of its evolution over the years. Some of you may know, it's originally only mandated for the investor-owned utilities and the Energy Service Providers to meet those minimums, but not the Publicly-Owned Utilities, the POUs, that as we've seen before, serve about a quarter of the load. But this has changed over the years, and the current program applies to all kind of utilities in California: IOUs, POUs, ESPs and all the other acronyms. And as we're saying in the previous chart, it prudently has -- it currently has 3, what they call a compliance period. The first one, which we're in it right now for 2011 to '13, that we reach 20% on average every year. And the second compliance period, by the end of 2016, each utility has to have at least 25% of its load served by or generated by renewable resources, going up to 33% by 2020.
What the current legislation also includes is distinction between different products, the renewable products or it's called portfolio content categories or PCC. The first one that you can see on the table is for bundled products, meaning what the utility buys, the energy and the renewable credits, what's called the RECs, the renewable energy certificates. And specifically, this category is for generators that are in California, meaning they have their point of interconnection at the power plant to a California balancing authority, California utility or they could be out of state, but still in the West where the energy is being scheduled without substitution, I'll explain a little bit further, into California. As you can see on the right, the RPS of the current RPS program really try to encourage that kind of product, and they set a limit at least 50% of all the RPS forces of each utility have to be from this type of product today, going up to at least 75% in 2020. The reason the RPS will be out there to try to encourage this type of product is both the reliability that is associated with having resources in state and also the economic benefits, so they're trying to stimulate developments in California.
On the same token, the same RPS are trying to limit the other types of products, the second and the third. The second being still a bundled product of energy and RECs, but that comes from out-of-state resource, but is scheduled into California while being what's called firmed and shaped. Firming and shaping basically means, when you have an intermittent resource like wind and solar, that never really delivers what the preschedule expect are always inherent fluctuations, significant one. Firming and shaping meaning -- means taking a supplement resource, like a national gas power plant, to compensate for when the renewable resource underperform or to curtail when it over-performs. And the RPS will be out there to try to limit that because in essence they're saying, when utilities sign these type of contracts, some of the energy they're getting is actually not green energy. So this is limited to not more than 50% of each utilities RPS mix today, and will go down to not more than 25% by 2020.
And the third category that the RPS are really trying to limit is the REC only deal that was there a couple of years ago, but now, it's limited to not more than 10% by 2020. And this is all good news for Ormat because all our facilities, be that our existing plants in California, our existing plants in Nevada and the plants that we're developing in California and other Western states like Nevada and Oregon, they are all eligible for this desirable product content category, and we see that's where our interaction with the utilities. And it gives us a significant competitive advantage over some of the competing resources, primarily over out-of-state wind and solar that were very popular a few years ago, but now, they find it harder to compete with resources like ours.
Now I'd like to briefly go through the various market segments and point out where we see the opportunities. Even though you saw on the previous slide, the utilities have done a good job in meeting the RPS requirements in the next few years, but we still have spotted some significant opportunities. So starting with a big market, the investor-owned utility market, the IOUs. You can see on the top left, the 3 utilities pretty much have met the current target, which was 20%, some of them, like Edison, significantly by more than 1% point. They also claim to be pretty much on track to meet the second compliance period target, which, as you remember, is 25% by 2016.
However, let's look now on how exactly -- which programs do they have to purchase power. The 2 main ones. One is the yearly RPS request for offers, where all the Big 3 have a big RFP, where basically they decide what kind of resources they want to contract and for how long in order to meet their RPS plan. It's supposed to be annually, but in fact, in practice, it's not going to have it every year. For example, in 2010, they didn't have one. But then recently last year, they implemented a new program called Renewable Auction Mechanism that was kind of pushed by the CPUC, the California Public Utility Commission. And this is a program that requires all 3 IOUs to purchase about 1,000 megawatts of what's called distributed generation, which is defined as project within 1 and 20 megawatts. In the near future, there's going to be 4 rounds of these Renewable Auction Mechanisms, the first one took place last November, the second one last May, and there's 2 more this November and next May, where altogether, it's -- they're supposed to purchase these 1,000 megawatts, and this is supposed to be for either existing facilities or shovel ready facilities that have to come online not later than 2 years from contract approval. So even though those utilities don't necessarily need power right now, to meet their overall RPS targets, the CPUC enacted this program to stimulate smaller project, local project that have to come online quickly and now.
Now eligibility of project is also restricted to not only do they have to be in California, they have to be within the specific service territories of the 3 IOUs. You can still bid a project even if it's in PG&E service territory, you can bid if it's in San Diego or Edison, but if it's located outside their territories, like in [indiscernible] division district or out-of-state, then it's not eligible. But all plants in Mammoth, for example, are eligible because, as you know, they're within the Southern California Edison service territory.
So this creates a nice opportunity for us, even more this program, it's very interesting. I like the big yearly RPS where each utility is free to -- the RPS going forward, each utility is free to select what kind of resources they want and how much. The RAM program is more specific, where there are specific targets for each utility for 3 different types of products that are called baseload, like geothermal and biomass, what's called intermittent peaking, which is primarily solar, and intermittent non-peaking, which is primarily wind and also some small hydro. So this really sets baseload, which is pretty much almost entirely geothermal, apart and gives them specific targets even though they're pretty modest, we're talking about maybe 100 megawatts altogether that they're expected to purchase. But this is like the unique opportunity for someone like Ormat to compete.
And indeed, in the first round that took place last November, we were able to win a very nice contract for one of our existing plants, Mammoth G3, the one that was at the bottom of the picture. This contract was approved by the CPUC last May. And it's expected to come online under this new contract with Pacific Gas & Electric. And again, it's a fixed RPS contract, much, much better than the standard of the 4 contracts that Smadar presented. It will come online under that new contract by beginning of next year. Of course, assuming we'll complete successful termination of the existing contracts with the existing off-taker. And we believe that the second, third and fourth solicitations of this RAM program present additional opportunities for us that we are planning to enjoy.
Moving onto the next important market segment, the public utility -- the publicly-owned utilities, the POUs. Here, we also spotted some near-term opportunities. Again, even though on a market basis, there's not a huge demand right now for renewable, we believe that there are quite a few cases. And again one of the reasons, if you remember my introduction, in the early years of the RPS, the POUs were not subject to it, so some of them went ahead and signed the RPS contracts because they wanted to, maybe the voters wanted, but didn't have to. Now they have to. And some of them that did not contract in previous years now have significant shortfalls even for this current compliance period, the 20%, and definitely for the 25% by 2016. So there's an opportunity there for all renewables, but specifically for someone like us because as I explained before, all our resources qualify for what's called the Portfolio Content Category 1, which is really what they need, they need at least 75% to be of that product. And many of them, definitely by talking to these utilities, I can say that they see the value of a geothermal product that is baseload, meaning there's practically 0 integration cost for them to integrate that into the grid. And again the smaller you are with the smaller number of backup resources, the harder it is to integrate an intermittent resource and the more value they see in the baseload resource. And again this gives us an advantage over some other resources that are harder to integrate and cause more challenges to the utility.
And looking more into the long-term, the third compliance period of 2017 to 2020 and beyond, as I saw on that chart, on a market basis, both IOUs and the POUs, again assuming a reasonable 30% to 40% signal [ph] rate in the current PPA, they have a significant demand of thousands of megawatts of more renewables to meet their 33% target. Another reason -- this, of course, will create an opportunity for all the geothermal, all the renewable players. But then there's 2 factors that are specifically advantageous to geothermal owners and developers like us, the second bullet on my slide is there are currently some initiative underway in the various levels in California, primarily led by the California Independent System Operator or CAISO, the CEC or California Energy Commission and the Public Utility Commission that is looking up -- now that California has a significant amount of renewables in its mix and more to come as they approach the 33% target. Now there's time to look at how much does it cost, that's not only to pay for those -- for that energy in RECs, but indirectly to integrate all those resources into the grid, and as you know, the grid was not designed for renewables. It was designed for fossil fuels, generators that are placed where the utilities wanted them. Renewables are built where the resource is, not where you want it to be. And they're starting to realize that there is significant cost associated with, primarily, with integrating intermittent resources that don't necessarily show up on your screen when you want them. Sometimes they show up when you don't need them and sometimes they don't show up when you need them. And this has cost in terms of more backup generation. Utilities are now using peakers, not only during peak, but also to compensate when some other generators, like wind, don't generate and they have to keep up generation to match the load. In some conference, we even came across, there's a new term, they're not called peakers anymore, they're renewable integration plants -- sounds much sexier for something that burns fossil fuel and even less efficiently than the regular fossil fuel power plant because they're always in the transient mode, where just like in your car, when your engine is cold, it pollutes more than when it's on steady-state. Same goes for the gas turbine. So on the California policy level, they're starting to realize that. And we believe that in future solicitation that we'll see in the coming years, utilities will put more focus on technologies like geothermal, they don't have any additional indirect cost because we deliver exactly what we tell the utility we're going to deliver. So we expect some sort of innovation adder or some sort of other mechanism to incentivize geothermal, and this should help us enjoy these opportunities in the longer-term. And the third trend that I think is relevant is the fact that over the coming years and decades, there's a thousands of megawatts of traditional baseload facilities, primarily coal and nuclear. And some of the ones through cooling, to those of you who have heard one of those pretty old facilities that use ocean water as cooling and there's a decision in California to phase them out because of the environmental impact, basically it destroys the fish and some other habitat in the ocean. So these 3 types of generators, coal, nuclear and ones through cooling are expected to be phased out. And most of them are baseload, which will create a specific, again, on top of the RPS, that creates a demand for renewables in general, this will create specific demand for baseload resources. And as some of you may have noticed, some utilities, like Los Angeles Department of Water and Power and some other southern cities, are publicly stating in conferences and elsewhere that their strategy is to -- for example, LADWP is saying specifically, their strategy, long-term, is to replace coal with geothermal. So again, this creates specific opportunity for geothermal players like us, on top of the general renewable energy opportunities.
So in summary, it's sort of we have some challenging contracts in California. And it's true as you saw on my slide that market, in the coming years in California, is more challenging than it was before in terms of the good job utilities have already done in purchasing power, meeting their obligations. However, we believe we've spotted some very good opportunities for our products, both in the short-term, the next 5 years, and definitely in the longer-term. And especially because we're uniquely positioned, as explained, not only do we have renewable products, but there are also this premium Portfolio Content Category 1, which is desirable and they're baseload, and there are specific opportunities for baseload. And we think that the fact that we successfully re-contracted Mammoth G3 recently is an example of our ability to take advantage of these opportunities. And we hope to be able to share some similar success stories with you in the near future.
So that concludes my presentation. I'll be happy to take questions at the end. And Joseph, please come to the podium.
Thank you. Sorry it was changed. The purpose of my presentation is to help you to analyze better and project our interest expense and tax provisions. Especially after the December 2011 evaluation allowance, I know that it's more difficult for you to project our tax expense. And I'll try to walk you through and help you in that. Also, Ormat is an IPP developer, and EPC contractor is different from other peers, and I think you'll need from us more, and that's the reason why I'm doing this presentation.
So let us start with the interest expense. And we have, in general, 3 components in interest expense. This slide just shows the last quarter interest expense, gross and net. But let's go to the next slide, and you'll see our -- the components of our interest expense, and we have more than $1 billion of debt. Out of it, $477 million, project finance, and corporate debt of more than $0.5 billion. And you see the average rates of each of them. So the blended rate is about 6%. And this is the interest rate that we are using for capitalized interest. And the component of capitalized interest is different from quarter-to-quarter, from year-to-year. And if you want to go back to 2009, we had a very big component that was capitalized because in those -- the project was under construction for a long length of time. So this is something that I'll try to show you in the next slide, what is included in the capitalization of interest.
In addition to debt, we have interest expense on the taxes that we had -- that we did in 2007 and 2008. The average rate is 8%. And the average between the original transaction with Morgan Stanley and Lehman Brothers will be -- to the investor was lower. And the last deal we did in February 2011 with JPMorgan, when the yield was much higher. In between, we made a gain on that transaction when we bought the units from Lehman Brothers at a very low price.
So on what we capitalize interest. We capitalize interest only that we -- as we -- with under construction, 2 components: one is expiration and development, which is relatively small component. Rahm talked about these in the past, and usually we try to expand as low as we can in this part. And once we drill the full commercial well, we're in -- under construction and in that stage, we bear more expenses, more costs. And on those costs, we capitalize interest. So these are the components -- and these is an excerpt from the PP&E note from the last time 10K, and you can see that this component is subject to interest capitalization, with one exception, and that is when a construction is delayed because of permits and other things. We might stop capitalizing interest during -- at certain period of time. But usually, we capitalize on the cost interest. So this is the part of the interest expense capitalization. As I told you, currently, the rate is 6%.
The more complicated part is the tax expense. And we operate in different jurisdictions. Even though most of the revenues are derived from the States, about 75% of our revenues from the power generation segment, we still have other jurisdictions. And I will go through each of them.
So in the States, on top of the Federal tax rates of 35%, we have additional 3%, which is a blended rate of the state that we operate in. California -- sorry, California, Hawaii does not have any state tax, so the blended rate is 38%.
And I think this is an information that we shared with you for the first time. At the beginning of the day, Dita showed a big slide about disclaimer. I must repeat it. This information is based on our current projections, they may change based on our growth plan and other factors. And therefore, take this information in that way.
So we're not going to be a tax payer in the next few years. So we -- based on our current projections, we'll start utilizing our NOLs in 8 to 10 years. That means that we will pay alternative minimum tax, which is not a big amount. And we would actually pay taxes, that means that we will utilize all our NOLs in about 15 to 20 years. The reason -- the main reason for the NOLs, as you know, is the accelerated depreciation and, of course, also the PTCs that we earned during the years.
So what are we doing with depreciation in order to make our tax planning as efficient as possible? So assuming we don't have a tax equity transaction, and we had one in the past, because of the high NOLs this year, we are amortizing -- we are depreciating the plants over 12 years compared to 30 years GAAP. And we can choose instead of that, 5-year MACRS. We don't do that because there is limitation on utilizing of NOLs, and we try to postpone it as much as we can. But if we'll do a tax equity in the future, we'll probably choose this. We'll choose the 5-year MACRS. On intangible cost, you can choose between expensing them in the first year when they occur or amortize them 5 years straight line, and for accounting purposes, it's still 30 years.
We -- the election of 5 years that we made is not only because we want to postpone NOLs, but also because for cash grant purposes. If we don't do the election, under Section 59E, we'll not be able to benefit from grant on this part of the cost. In case of ITC cash grants or ITC, 50% of the credit or the grant is subject to additional depreciation of 50% of the grant, which is another benefit that we have from them.
After the PTC -- again, it's new information that we share with you. I don't think I need to repeat how our PTC is calculated, I think it's easy to deal with that, you are familiar with that. But what is important is we give you the information of our future PTCs, and this is all, assuming that, of course, our production of electricity will be as we projected. We did not elect PTC in the last few years because they we are benefiting from the ITC cash grant, so all-in-all, we have earned about $60 million of PTC that we have against that full valuation allowance. The reason why we have a full valuation allowance against the PTC is because the way you utilize NOLs and PTC is that PTC is the last one to use, and therefore we have a full valuation against that. Of course, these are the PTCs that we are going to benefit from the next few years. Starting in 2016, the amounts are going down. If PTC is extended, of course, we will get more from that, but the assumption now that 2013 is the last year of placings -- placing financing service when you can benefit PTC, and we are not going to do that. Of course, the big amount of $350 million of NOLs that will expire between 2015 and 2031 against that we have a full tax asset. We did not have any valuation allowance against these amounts.
The effect of the valuation allowance that we have in Q4 of 2012 affects in the future our tax provisions in the States. And until we are in 3 years, pretax book income in the States, you can assume that we have a 0 tax on pretax income or loss in the States. And I just gave you the example and I'll give you the numbers from Q1. So what we do technically, we calculate the income tax benefit as there is no valuation allowance, and that amount was $6.4 million in Q1. And you allocate to that a full valuation allowance, which brings you at the end of the day to a 0 tax rate -- or a 0 tax in the States.
Going to the rest of the world, let's start with Israel. Israel is the main generator of income for Product Segment. There is a very, very attractive tax regime for companies, which are industrial companies, that produces product and that exports at least 25% of its product. And we are exporting from Israel 100% of our products. So instead of corporate rate, which is also very low compared to other jurisdictions, of 25%, and it might increase to 26% next year, we are paying now 15%. And this segment is profitable, we are paying 15% now. And in 2015, will be subject to 12% tax only. Also dividend distribution from such an income is subject to 15% withholding only instead of 25% on regular income.
The next jurisdiction is Kenya. In Kenya, we are operating as a branch, and therefore the tax rate, the overall tax rate, is 37.5%. No taxes on distributions from Kenya, that means no withholding. And the benefit that we have from in Kenya is 100% in investment deduction, which is similar to accelerate the depreciation in 1 year and debt -- of course, instead of a 30-year straight-line depreciation for GAAP purposes, so expect no tax payment in the next 4 to 5 years, and that includes the expansion, the expansion that we will be placed in service next year. And of course, it does not include additional 13 megabytes that we have on option under the PPA to build. That will even additionally extend the tax payment in Kenya.
In Guatemala, we are benefiting. The enacted corporate tax rate is 31%. We have been benefiting from 2 kinds of tax auditing, but we do not expect to pay taxes in Guatemala until 2017. And fortunately we'll never pay taxes on the term on the current PPA.
In Nicaragua, the effective tax rate is 25%. We paid that, but this plant is going to be transferred to the local facility in mid-2014.
And I'll give you a summary of all the tax rates and the cash taxes in all the other countries. I don't need -- I don't think we need to talk about that. No deferred taxes. We do not accrue for deferred taxes on earnings of foreign subsidiaries, because under GAAP, if you do not intend in the fourth period or future to distribute them, you don't need to accrue for them. Our plan is to use those earnings to reinvest them in new projects in rest of the world, so that's the reason we do not include any deferred taxes on that. Just for you, it's about $250 million, that means that if we would decide to do something else and to distribute them, the additional tax expense would be $100 million. No cash impact because we have more than that NOLs but that amount will be utilizing the NOLs with a 40% tax rate, which is very high. So our decision was not to do that. And of course, the average rate on our foreign subsidiaries is 30%, less than the federal tax rates in the States.
Let's conclude my presentation. I've included, too, an appendix. You can look at the presentation. I don't have anything new. I just put it in one -- in the presentation to help you go over it after my presentation. And of course, if you'll ask questions, feel free to contact me. I know that it's complicated, not more complicated than construction of power plants, but still something complicated for analysts and investors. So feel free to contact me and I'll be happy to go over it in details. Thank you very much.
[indiscernible] So with a lot of information I'm sure there are questions. Feel free.
My question is for Gillon, can you describe what you can add as a more intimately involved private investor in Ormat Technologies, what specific opportunities do you see to improve the business and perhaps where it wasn't as effective in the past and that you can really do to add some value there?
Okay, it's quite a deep and comprehensive question. And we think that it's a great company, unique and a market leader in the world. It's very, very important, lots of knowledge, lots of IP, lots of patents, and we saw very interesting presentation today of how the company started to -- or continue to learn to change, to improve. Now I showed you in our presentation not related to Ormat, but related to our DNA of FIMI. How we approach companies, how we are in the top tier of the private equities in the world, not only in Israel. And we are hands on. We tried to be involved in the strategy, in the high level when it's needed. So I think what we managed to implement during 16 years, and it's not the 2 terrific [ph] deals, that's 66 deals, there's 36 good exits that we started. The very, very loss ratio that we have, very, very low loss ratio. So I think if we do the same, and we continue, we have the same people, so I think we will achieve the same results also here.
I have a question for Gillon as well. Can you talk a little bit more about your investment criteria in terms of required returns and then also maybe the life cycle of your investments, are they with a particular horizon and an exit, or do you sort of grow in your investment over time? Or how do we think about that?
Again, if this is one of the investments that is less more or less what you started in what I've mentioned before. Again, we think it's the best company in the world in this segment, and is a huge opportunity in energy, and I think you know better than myself about that segment. But in terms of analyzing the deal before in the private equity, what we -- and you saw the slide of mitigating this, what we do usually, we analyze mostly and from all aspects of the downside. So we look at the model in the downside, and we analyze the cash flow, the DCF of each power plant and the downside that can happen, the $4.5 billion signed contracts. We look carefully at the cash flow, compared to the entrance level, which is about $20 more or less when we came in and this gave us a very comfortable entrance level and pass our criteria, and as you remember, what we said that we are very strict and very disciplined in this entry level that we do. So mostly the answer is that we analyze the downside of the deal through the cash flow and through a certain scenario that can happen in the business. Now compare -- now your third question was about growing in the future and time, I think it's too early to talk about it, and I think we have to grow the company now. And about exiting, [indiscernible] still down the road and it's a long time to do that.
My question will be more for Rahm and Smadar, if you are looking more at Nevada versus a lot of the details you gave on the California PPA situation, obviously, the Nevada PUC had a problem with some PPA -- send something back for reworking can you talk a little bit about that process and how you see the market in Nevada specifically versus California?
I'll actually have Bob answer that. He's more savvy on Nevada than I am.
Yes. The -- I think you alluded to the recent PUC actions, this is just an action by the PUC to make sure they have control of the utility and beating the approval process for understanding the need for renewables in Nevada. So there's not a question of whether there's a need. It's the PUC acting to make sure that they were in the loop in helping determine that need. As you can imagine, there's a lot of opinion that goes into forecasts for renewables, so the PUC wanted to be in the loop and making sure their points were made with the utilities well. Now the market for Nevada, we feel very good. Right now there's a little bit of a lull because of this action with the PUC, and Nevada NV Energy right now is compliant similar to the California utilities. But Nevada is right now seeing the benefits of the high prices of minerals, gold and silver, in particular, precious metals, and are being inundated right now for request for interconnect for drilling for a mining expansion. So they expect to see significant load growth in Nevada, and of course, we benefit from that, because as the load goes up, the requirements for compliance for the renewable portfolio standard in Nevada increase as well. So we expect that there'll be continued opportunities for PPAs in Nevada, relatively in the near future in the next 6 to 12, 18 months. And NV Energy, once they clear with the PUC, will continue there, basically, it's almost an annual process for RFPs in Nevada. So we feel pretty good that Nevada is going to -- may continue to be a good market for us.
Going back to Smadar's presentation, you showed the Mammoth 3 project, G3 had an expiration of the SRAC PPA in 2020. And when you talk about being able to auction that in the RAM or you successfully did, so how does that work? Do you cancel the contract with SCE and then sell it to PG&E or what's the mechanism there?
Yes, so the -- Smadar's -- just to clarify, Smadar's presentation was a base case, so nothing happens and obviously, we have other plans. And yes, we are working with existing off-taker for that contract to find a solution that works for them as well as works for us. It's not done yet but once it's done, we'll share the relevant details from that.
A question for -- another question for FIMI, I'm just curious of your thoughts on the valuation differential between the U.S. traded and the Israeli traded stock and how that played into your decision-making process in your initial investment and whether or not you ever see that closing.
I don't think the impact to our decision. We are, and mainly, it's about Ormat Technologies. And your question about the DRIP a few times during the negotiation, it was up, it was down, so I think it's not an issue, and it should be normalized but again it's DRIP and it didn't influence.
You're talking earlier about the gap between long-term RPS contracts versus the SRAC prices. Maybe if you can comment on how you think lower renewable -- alternative renewables, such as solar, have impacted or you think may impact that gap, and why we shouldn't expect it to narrow with what's been happening in the solar market?
I think that, and Smadar alluded to this, really, SRAC is not a measure of anything that is relevant to us other than the unfortunate fact that when the SO4 contracts were devised, that was what the contract with the energy rate was supposed to flip to at the end of the life. But it's really -- it doesn't reflect what the utility would have to pay to get to renewable power or anybody else. It was not really affected by the reduction in solar project. So it's natural gas driven, driven by big supply and reduction in demand for all kinds of reasons, and unfortunately for us, all of this happened right at the time when the energy rate was moved from fixed to SRAC. Now in terms of solar, I think that the solar prices really, have really come down in the last, probably the last 4 years was very dramatic. But a lot of the prices is driven by processes that I think are not sustainable in the fight between, or put it this way, a lot of this was accomplished by the increasing production ability of the increase in silicon manufacturing, increase efficiency in making panels, and that's all true. And that's very impressive and very good, but if we look at what happened in the last probably year or year and a half, I think that a lot of this is actually the bleeding of the different manufacturing center actually killing each other. And I think that this is not sustainable. Also there's some anomalies at the ITC cash grant in the way that it was applied to solar. Some anomalies that this created, and what developers were able to ask for solar PPA's in the last 1.5 years. And again this, I think, is an anomaly that goes away. If you strip this, and I think that you can do, you can do the analysis but better than we do. But when we do the analysis and we strip, the, I guess, preferential subsidies for solar because of all kinds of reasons, that you see that solar cannot compete with, long-term, cannot compete with a good geothermal development. Yes, geothermal development has its own limitation at sites but it's specific and so on. And we do not -- we cannot address the same size of the market, but I don't think that it can compete with geothermal development. And if you add to these the components that Rahm described on the realization that the California regulators have come to, that really intermittent resources should be somewhat penalized compared to the [indiscernible] nature of geothermal. I think that we are in a good spot, and I think that it's a matter of being patient in contracting our existing capacity at the right time, but I think that we will benefit from this. We have a premium product, it is more competitive. It is site specific, that's the nature of the beast, but I think that we will see very good contracts for future development.
I think you touched on this for a moment, Yoram, just the [indiscernible] is involved in this process of think about incentivizing baseload products and particularly the RPS gets to higher and higher levels in actuality, is there any indication yet how they're going to incentivize baseload products through capacity market or otherwise?
So I can take that. Maybe before that, I just have a quick remarks to the previous question about SRAC being a comparable for renewable RPS contracts. But actually, if you -- those of you who know the system in California, actually the reference that's usually used on the utilities is called the MPR or the market price reference, which is actually based on not SRAC, the short run avoided cost, but more on the long run avoided cost. In the case of California and PUC, they actually look at the cost, the levelized cost of building and operating a new 500-megawatt combined cycle natural gas power plant as the comparable. And they actually update that every year, and this is used as the reference to the price of renewable. So again another indication that it's the long-term cost and not the short-term. And if you look at Ormat's contracts, we have always been able to beat that MPR, and we have always been able to be cheaper than the MPR. While solar, for example, for many years was always above MPR and only recently is getting there.
Now to your question, it's a great question and there's no answer yet. We could -- it's still work in process, and we are spending considerable resources monitoring those, and even influencing. We have representative participating and there were groups in the [indiscernible], et cetera. As far as I know, the leader is really by the CPC, there are currently doing 2 proceedings that are relevant. One is called the LTPP, which is the long-term procurement plan proceeding, which basically that's a process that looks every year or 2 years on how much is California spending on buying power, both renewable and nonrenewable. And they constantly try to improve that. And there's another initiative that's called the RPS proceeding in the PUC, and there's a process there called the cost containment. And as far as I understand, both of these somewhat overlap, both of these are now -- actually, interestingly enough the question on the total cost of renewables was brought in front of the PUC, I think as early as 2009, but back then they decided those are too complicated to quantify. And also the flavor of the month was let's just bring more renewables and ask the questions later. So they didn't want to address that at the time.
But now the combination of they're being flushed with renewable, it's no longer a question of can we stimulate the renewable industry. The renewable industry is there, and it's alive and kicking and in greater numbers plus the economic situation, which is different now than it was a few years ago in terms of the recession, et cetera. But now they're asking theirselves these tough questions. And they tasked [indiscernible] to do the scientific work of trying to quantify. It's still a work in process, so I don't have a definite answer. But what I do hear from people is, if you're familiar with the way utilities do their ranking right now and they have a big RFO and they compare proposals, so they take like the price per megawatt hour that we offer and all the others, they apply it by the time of use factor to see how much it will cost them in any given hour, which is -- basically, it's a function of our generation profile. Then they add additional cost. The main one that they do today is what they call the transmission adder, which is as some of you may know, the California system, a significant portion of the upgrade cost, to upgrade it to investment grade to accommodate a new resource what they call the network upgrade, which is like if they build a new substation or a new significant transmission line or transformer, that may be triggered by a certain developer. But they realized it will help multiple power plants, then they socialized the cost. And it's not the developer who's paying for that, it's ultimately the ratepayer. So when a utility is looking at the cost of signing a new PPA, they have to look not only about the proposed energy price, but the levelized cost of that transmission adder, because this is another cost that will ultimately be conveyed to the ratepayer. So they took the energy price, they add the transmission adder, then they add or subtract what's called the resource adequacy, some utilities call that resource adequacy, which is a fancy word for capacity. Some call it an adder, some call it a discount but -- or some called it a value, but they add that, too. Because some -- the way the system works in California, the more a power plant is closer physically to the load with less risk of congestion or failure when you need the power the most, at peak, the higher value it has. The more remote it is or the less the plant like a wind farm that is not really there during peak hours which are the hot summer days in California, the lower that RA value, resource adequacy, so they add that. But today, that's where it stops. They -- what I'm hearing is a thought of introducing in future solicitation like a third adder, which may be called something like a renewable integration adder, which again I don't know if it's going to be like a discount to someone that has low or 0 cost like us or a penalty on ones that do trigger. But this will probably how it will take place and again it will give us some sort of an advantage.
What was your summer [ph] technology against some other occurring or emerging renewable technologies such as a solar thermal, which can address some shortcomings of the traditional PV solar technology?
Are you asking about how do we rank among the rest of the technologies? I think that there's -- and it goes back to the previous question. It really depends on -- oh, let me go back. I think that the beauty of solar photovoltaics is how they have brought the price down and the fact that maintenance is a very small factor, hardly any maintenance costs. So if you can control theft, which I think is really the big issue on solar, and if you have good guarantees, good warranties on the degradation of the panels, photovoltaic is really a great thing. As you move away from the simple photovoltaics into the different solar thermal or concentrated photovoltaic systems, then O&M costs become a bigger factor. You have to maintain many components of -- I think, it's thousands of components. And the fact that, I mean, again very impressive how prices have come down on the cost of the trackers, but you still have thousands of moving pieces of equipment that you have to look after. And this requires manpower and this becomes expensive.
And I think that, and again, that's my view, it's not -- we're not exactly from that industry, but I think that as we move, as you move away from the simple flat panels, then the solar is not as advantageous as it was before. Now there's the question of whether the intermittent factor of solar is going to be -- would hamper our pricing and would provide us with a bigger advantage? And I think that this is where we're comfortable that geothermal has a very unique place in baseload generation, not only in renewable but in baseload generation in the world. Hopefully, a lot of this would remain. There's a lot of growth that we can see in North America, but the North American market is only one market. And again, what we are doing in Kenya in terms of baseload generation, green or not, is a tremendous thing. So technology wise, I think that the big change is flat panels, and I think that if you move away from that, we're in a very good spot. What we've tried to show with you today is really the uniqueness of geothermal, and this is the 5 years of work that goes into developing a field before you could actually contract the power. And so these are 5 years where you spend money. Certainly the time goes by, and you need to have a good sense of somebody who will take the power at the end of the day. If you are a young developer, a startup company, I think that this is a very -- it's a very -- it's a high risk period for that company.
For a company like Ormat that has cash flow and has the expertise who can do this, the real question is how do we use those 5 years in a best way, how can we prepare as many fields for an opportunity that as Rahm mentioned, we expect to be in California in 2016 or 2017. So how do we work now so that we are ready at that time. So that we compete on our own. And I think that our challenges are really more clarity, and I guess, more clarity and more certainty on the front end of the development. But after that, if we got to a good field, if we've proven a good field, I think that we have the best technology to make a cost-effective power.
Question for Yoram, on the Product Segment side notwithstanding the recent win you had in North America, you've seen a shift to more wins internationally, I was hoping you could maybe discuss, maybe some of the nontraditional regions where you see some opportunity longer-term, and what you are doing proactively to help stimulate that demand?
So for us, the areas outside of the United States where we're very successful on the product side are areas where you have developers. Sometimes small developers and sometimes larger corporations that were sometimes fortunate enough, but I think that are generally diligent enough to develop well fields to the point roughly of what we have shown about McGinness. They have gone not necessarily in our -- at the same way that we have done this, but they have gone to, or do you have gotten to the point where they have done a multi-well flow test and got comfortable that they can issue a tender to -- for a $60 million or a $100 million project. Unfortunately, this had not happened in the United States. There were a group of companies that were really hoping to do this and that's I think is the story 5 years ago. But I think that the companies outside of Ormat that actually did it, actually brought the fields to fruition are much smaller group. And I have, I guess, that I have my own views on why it happened like this in the United States, but it doesn't matter, it just happened.
But if you go outside of this and you look at certainly in New Zealand, but you look at some fields in Africa, you look at Southern Europe or Northern North, Western Asia, then you could find countries where there is actually diligent work that was done. We are very hopeful that Indonesia, that place were more of the identified geothermal systems are actually developed to the point where it's real fields because there's -- everybody knows, there's huge potential in Indonesia, the question is how do you turn this into real field. And for us these are all opportunities. We are -- we only get to participate there probably 4, 5 years later than what we do in North America, but these are all opportunities. And we would like to take a big, the biggest part of the action that we can there.
Another question for Gillon, I guess a lot of us are not used to seeing equity investors take positions in public companies unless they take them out completely. But I'm curious to hear a little bit more on your thoughts of what do you think public investors haven't seen yet on Ormat that you see in the company, and what's going to make them see that within your investment horizons?
Okay, again, it's quite the same question, and I answered that. We are watching this company for the past 6 years, and there, for us, it's a little bit different in Israel. If it's public or private, it's not such a big difference for us. And we did it a long time in the past. We have to see that the company is good and positioned very well for growth. And continue on the same for public and private companies. And again, we monitor this particular company in Israel for many years and we had the opportunity last year to join. I was just recently was there closing in last May, and we like the company very much. Again, I told you before what we see and what we like, and we just have another interesting question about the international market, which is huge and also awaiting for markets, I did mention it before. So this is also a great way to grow, and again, being a market leader can give you lots of opportunities down the road.
Missing in terms of price of the shareholder or missing of what?
Exactly, exactly. Would you see a lot more value here than the public investor that's there?
And then what specifically [indiscernible]
I think we have to be careful how much we go with this discussion. We're still a public company. Sorry.
Do you have any plans to expand into parts of Africa. And if so, which countries are you focusing on?
Basically for us, wherever there are documented fields and there is a likelihood of being able to sell power under -- in any one of the structures that were employed in the past, then we would like to go there. And so the answer on Africa is that along the Syrian African risk zone, there are a lot of indications on geothermal systems. Kenya is one, but there are other countries along that zone, and now it's a question of, can we get the right to the field, is that really a country where it makes sense to own a power plant or whether they are more likely partner if you'd like not as a partner, but the more likely partner is a local utility that's interested in developing and owning and operating a facility. We are somewhat indifferent to this fact.
We're happy to own plants when we can, but we're also happy to build them to utilities or other players. So there is -- it all begins with a field. And there's a lot of work that we do on fields. Without the careful analysis of the business environment, but before we spend a lot of money, we move into the business environment, can we own -- can you own land or can you have exclusive rights to leases in those locations. And if you go back into other permitting issues, transmission issues and can you sell the power. But Africa is a great opportunity. Africa does not have natural gas for -- or doesn't have natural gas on pipelines in many locations there. Of course, there are gas producing countries in Africa, but you have the many countries that are outside of the natural gas pipeline system. And therefore, your alternative cost of power or form of power is typically oil, which means a highly interesting environment for geothermal power plant.
Just a question for Yoram. If you could talk about some of the junior developers in North America, their status, kind of competitions there are for BLM leases. And do you think that Ormat could grow through acquisitions over the next 5 years versus the previous 5 years or it's mainly organic growth?
I'm not -- I'll be lying if I said that I don't follow what they're doing, but not to the point that I would like to share numbers and opinion with you on that sense. I think that certainly -- it's certainly true for all of them that they are doing things that we don't know about, or neither you or us. And I hope for them that some of the fields that they're working on would actually turn out into a good field. I think that if you look at what happened in the last 5 years, the enthusiasm both on the investment community and also the willingness I guess, the availability of funding programs are mostly federal money. Those did not translate into operating or let's say a confirmed fields like we have shown about McGinness or Tuscarora for instance. And therefore it prevented the ability to take most of the projects into the next steps.
Some of them have signed PPAs, but will have to forgo the PPAs because they were not able to complete the development cycle to the point where they can actually release this. And because of this, we don't think that, so far, there has been enough fields that were developed to the point that it becomes interesting for us. We were -- compared to very high competition on BLM leases in 2008, I believe, and a little bit into 2009. And this, by 2010, this was mostly gone, which I think is a very good thing not because we can get what we want but because everybody came to realize that unless you have done a lot of specific work on a certain lease, you can't afford to pay huge bonuses on getting the land, because you really don't know and there's a high likelihood of much higher likelihood that nothing will come out of that lease than a geothermal power plant. So that, in that sense, the industry is much more lucid today in a good way. We don't see a competition there. And for us, and again, I think there are presentations where touched upon it, though it wasn't the focus of the presentation. For us, since once the PPA is signed, I mean, signed PPA is really a -- sets the upper mark of what you can get from a power plant, and if you do this without a good understanding of what the field can do or what the power plant can perform, then the PPA becomes a hindrance and not so much an asset. And this is why we think that organic growth for North America is really more interesting for us. In locations where people would bring fields to a point where they're willing to cash out and let somebody else turned this into a power plant, we'd be very happy to step in when it makes sense. But a contracted facility that is not performing where it is and especially because of well field conditions, that's typically not a good opportunity for growth for us.
Just back on the Mammoth PPA, can you describe or talk about what has to happen for that to be renegotiated? It seems difficult to believe that they would have a really good price PPA and then they would give that up, so what's their incentive to do that?
I think that the answer is -- I mean first of all, we don't know. We have to complete these, and things could change over time. But I think that the situation is that most of these PPAs are actually, I guess, the bulk of the megawatt hours that are expected to be produced by those PPA's will be generated during the first and second compliance period for the IOUs. So for them and in their mind, it's great, it's renewable power, it's priced competitively compared to what they have signed on solar 2 years ago. But they get this power at the time that they don't really need it and where they would like to get this power is 2017 and onwards. And I think that this is, without getting into the details specifically, but I would say that this is where there's actually a commonality of interest between us and the off-takers. It's a fact that's maybe not so interesting now, but it is interesting in the future, and its working together to find something that works for us and works for them in terms of looking at the future.
I guess that we're ready for lunch. One more? Okay.
And you may not even be able to address it, but can you talk a little bit about what's happening right now, probably with Sarulla, and sort of where you are with the negotiating?
I thought that we are going to have one, and then now a question on Sarulla. I think Yoram alluded to is that we are, today, we're way more optimistic than we were not only a year ago, but even a month ago. Things are moving. Now things are moving, we know that it is not done until it is done. And we don't have any specific news to share yet, but we are optimistic.
So let me summarize this day. I hope it was informative to you. There were a lot of information that we try to share with you in order to provide a better understanding of what Ormat is today, and certainly how different is Ormat today from Ormat even a year ago or even earlier. Brawley which overshadowed our performance or maybe the sentiment of the investor base to Ormat in the past 2 years is expected to be EBITDA positive this year. If you have seen, it required a lot of financial input and certainly the technological strength of Ormat in order to get to this point, and not many, if any, other geothermal companies could do it, both on the financial side and on the technological side.
But as important are the lessons learned from the Brawley experience. And we shared with you today the implementation of the changes that we are doing in our development process in order to apply the lessons learned from Brawley.
We have definitely again demonstrated our capability to develop greenfield projects. We have heard in the past from some of you some questions, "Are you really a successful developer?" I think that is Tuscarora in the final commercial operation is [indiscernible]. Tuscarora in commercial operation. McGinness in final commercial operations phase, Puna enhancements in operation. We have shown that yes, we are a successful developer, and even in the past we have the balance sheet that can support the continued development based on our plans that we didn't go too much into detail today, you are all familiar with our growth plans. We have made a substantial improvement in the way we operate our operating power plant. This is important to the bottom line as much as to the growth -- as much as the growth of the company. And I hope we've been able to give you a little taste of how much improvement and how much progress was done in this area.
The low natural gas prices that were a challenge when we first realized the abundance of shale gas in the market today became an opportunity, from a challenge to an opportunity. And we think this natural -- the portfolio today is dependent on natural gas is a big opportunity in the very near future, either for re-contracting or otherwise when those power purchase agreements are going to expire and be available -- the power plants are going to be available for new PPAs at the current or new portfolio standard rates. So there is a lot of upside potential in this contract.
And finally, our technological leadership is the key to a continued strong product segment that is still only at 30% or 25% of our revenue, but a big support for our stability and for our growth. So we thank you for joining us today, thank you for the good conversation that we had. And we'll be happy if you could join us for lunch at the end of the hallway. Thank you very much.
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