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Executives

Ross Beaty – Executive Chairman

John Carson – CEO

Lynda Freeman – CFO

Paul Rapp – VP, Wind and Geothermal Power

Murray Kroeker – VP, Solar Power and Engineering

Asgeir Margeirsson – VP, Geothermal

Monte Morrison – Country Manager

Analysts

Jeremy Mersereau – National Bank Financial

Jared Alexander – Canaccord Genuity

Aram Fuchs – Fertilemind Capital

Alterra Power Corp. (OTCPK:MGMXF) Q2 2013 Earnings Call August 13, 2013 11:30 AM ET

Operator

Good morning, ladies and gentlemen, and welcome to the Alterra Power Corporation Second Quarter Results Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. (Operator Instructions) I would like to remind everyone that this call is being recorded on August 13, 2013. I would now like to turn the conference over to Mr. Ross Beaty. Please go ahead.

Ross Beaty

Hello everybody and thank you very much operator. Good morning. Welcome to Alterra’s Q2 conference call to discuss our financial and operating results for the last quarter. Thank you very much for joining us today. First, I wanted to remind you that we will be making a number of forward looking statements for which we seek safe harbor as described in our news release and web presentation. You can access the web presentation right now by going to www.alterrapower.ca and following the links included there.

Joining me on the call today are John Carson, our CEO; Lynda Freeman, our CFO; Paul Rapp, our VP of Wind and Geothermal Power; and Murray Kroeker, our VP Solar and Engineering. Standing by for questions are Asgeir Margeirsson in Ireland – in Iceland I should say and Monte Morrison in Nevada.

I would like to ask John, Lynda and Paul to lead us through our Q2 results and then I will wrap up and go to questions. Over to you, John.

John Carson

Thanks Ross. We just completed a quarter with extremely positive operating results. We were at 92% of plan and that’s with one of our facilities offline for repairs during the period. If that facility had been operating, we would have been at 103%. So it was really another good quarter for us indicative of our strong resources at our renewable energy power plants and of our well-run operations by our team. With that, I want to turn it over to our operations team for a review of those operations beginning with Paul Rapp. Paul is our VP of Wind and – excuse me, before we get to operations, Lynda is reminding me we are going to start with the financials. I am going to start with Lynda, our CFO to walk us through the financials before we turn to the ops.

Lynda Freeman

Thanks John and good morning to everyone. I am going to commence my presentation with a discussion on the second quarter consolidated results of the company. Consistent with the previous quarter ended March 31, 2013, and comparative quarter ended June 30, 2012, the company continued to consolidate a 100% of the results of HS Orka and Soda Lake while the company’s interest in Toba Montrose and Dokie 1 are accounted for its equity investment.

For those of you that are following the presentation on our website, I refer you to slide 4, consolidated results for the second quarter 2013. As demonstrated and explained on the slide, consolidated revenue is up 6.3% against the comparative quarter of $15.1 million versus $14.2 million in the comparative quarter. This increase is due to new power contracts entered into late 2012 and early 2013 at HS Orka and increased generation at Soda Lake due to an additional production wells that was put in service late in 2012. The gross profit margin decreased against the comparative quarter from 21.8% down to 13.2% due to workover and maintenance work required on two production wells at HS Orka.

During the second quarter, the company recognized a net equity profit of 7.2% against the profit of $2.1 million for the same quarter of 2012, representing the company’s interest in Toba Montrose, Dokie 1 and the Blue Lagoon. This increase in profit was predominantly due to the recognition of 4.1 million related to property insurance proceeds on the Montrose rockslide. In addition to higher revenues at Dokie 1 due to the timing of wind generation, as the pricing of the power purchase agreement fluctuates month over month.

The Montrose facility continued to be offline during the entire quarter due to the damage incurred as a result of the December 13, 2012 rockslide. Consistent with the prior quarter, the proceeds from the insurance claim will be recognized in equity income in Alterra’s statement of operations. A move reflects both business interruption proceeds and reimbursement of repair costs over and above the original cost of the penstock components. The original cost of the asset component was 0.8 million and was written-off at December 31, 2012. I refer you to appendix 1 which details more information regarding the accounting for the rockslide repair. For the three months ended June 30, 2013, 4.1 million and 1.9 million is recorded in equity income representing reimbursement of repair costs and business interruption proceeds respectively.

Moving on from the rockslide, Included within other income and expenses are general and administrative costs, which reduced by 32% from 3.8 million to 2.6 million against the comparative quarter. Recurring general and administrative expenses have declined quarter-on-quarter and this was primarily due to non-recurring costs associated with the reduction in personnel in the period, in addition to movements on the HS Orka pension liability.

Our consolidated results continued to be affected significantly by non-cash movements in the embedded derivative and bonds payable, both affected by the forward aluminum price. Movements in both these balances are also reflected in other income and expenses. The end result was a loss before tax of $3.9 million against an $11.3 million loss in the comparative period.

Moving on to slide five and six, and also contains in the company’s management discussion and analysis, we are demonstrating the company’s net interest in generation, revenue and EBITDA of our operating assets. These numbers reflect the company’s 66.6% interest in HS Orka, 40% interest in Toba Montrose, 51% interest in Dokie 1 and 100% interest in Soda Lake. As shown on the slide, we are continuing to demonstrate consistency at our operating assets and corresponding operating results.

Specifically, revenue and EBITDA increased marginally quarter on quarter, when including the Toba Montrose business interruption proceeds of $2 million, primarily due to higher revenues at HS Orka and Dokie 1. The EBITDA numbers reported [here in our slide] for Toba Montrose do include the 4.1 million in rockslide related insurance proceeds for repair costs of (inaudible).

Generation was down 3% quarter on quarter due to the Montrose Creek facility being offline for the entire period. However as John mentioned, on inclusion of the loss generation from Montrose Creek of 35,301 MWh which is attributed to the calculation of business interruption insurance proceeds, generation was actually up 8% quarter on quarter and 103% of budget.

The following slide on page 7 contains balance sheet highlights. It is worth noting the value of assets and liabilities fluctuate significantly as a result of foreign exchange, with the Icelandic Krona strengthening at June 30 against December 31 and the Canadian dollar weakening over the same period. Total assets increased by 2% in part due to foreign exchange in addition to an increase in tax in the period predominantly due to a draw on the revolving credit facility.

Total liabilities fluctuate significantly due to non-cash movements in the value of the embedded derivative, a movement of $27.7 million against December 31, 2012. Other fluctuations and liabilities are due to repayment of debt and draws on the revolving credit facilities. The reduction in working capital was primarily due to the classification of Alterra’s revolving credit facility to short-term liabilities at June 30, 2013. At December 31, 2012, this was recorded as a long-term liability.

The long-term debt position is analyzed on the next slide, slide 8. As of June 30, 2013, the company's net interest in long-term project debt was $345.7 million, showing a steady decline in project debt from $369.6 million at December. This project debt figure represents a $175.8 million held at Toba Montrose, $84.5 million at Dokie 1 and $85.4 million at HS Orka.

During the quarter, principal repayments of $2.9 million and $0.7 million made against the HS Orka debt and Dokie 1 debt respectively. And in accordance with the credit agreements of Toba Montrose, no repayments were made in the period. Interest payments of $4.9 million were made during the quarter, reflecting $2.8 million at Toba Montrose, $1.5 million at Dokie 1 and $0.6 million at HS Orka.

In addition to project debt, the company also holds $116.8 million in long-term bonds that were resumed and unsecured on the holding of HS Orka and $19.3 million in the revolving line of credit. That concludes my updates on the second quarter results, and I now hand you back to John.

John Carson

Great, thank s for that update Lynda and one of the things that you mentioned there that I’m pleased to see that during the first half of the year, to eco your statistics we have paid down $25 million of our non-corporate project debt, including significant pay-downs at our Icelandic subsidiary HS Orka and I would remind listeners to look at the appendix two in this presentation and if you do look at appendix two you’ll note that our HS Orka or Icelandic facility you will see significant debt pay-downs occurring over the next five years. And then you’ll see them dropping after that. What that significant for is that we will have a lot of cash flow coming out of the Iceland operations in about five years that can be retired the preponderance of the debt there, so again a good thing to see for our project debt.

With that I will move on now to operations and Paul, our VP of Wind and Geothermal, please give us an update from your side of the assets.

Paul Rapp

Thanks very much John and good morning to everyone. I’m happy to report on the continued strong performance at our Wind and Geothermal facilities. Starting with Dokie 1, Dokie wind farm performed well in Q2 2013, producing 64.5 gigawatt hours of electricity or 95% of the budgeted generation. Production remains on track and at the end of Q2 we were at 99% of our budgeted generation year-to-date. The Dokie wind turbines performed well in Q2 and our turbine operator, Vestas continued to exceed their contractual guaranteed wind turbine availability. The balance of plant equipment, such as our substation and transmission lines also performed well and have no issues.

At the end of Q2 Dokie received confirmation from regulatory agencies that we have met all our provincial environmental assessment certificate commitments for post-construction [avian fatal] or bird or bat monitoring. The monitoring results confirmed pre-construction estimates that the Dokie wind turbines would have minimal impacts on both birds and bats. We’re very happy to receive those final results.

Moving on now to Geothermal, the Soda Lake in Nevada as of the end of June, the plant is generating at 99.5% of budgeted generation year-to-date and all turbine generators in production wells are currently performing well with no issues. Really it’s business as usual at Soda Lake.

In Iceland, that our Svartsengi and Reykjanes plants, both plants performed well in Q2 producing 304 gigawatt hours total. The year-to-date production was at 101% of budget generation at the end of Q2. In Q2, a significant amount of work was carried out on the Reykjanes geothermal field. A new production well RN-31, which was drilled in late 2012 and early 2013 ,was connected to the Reykjanes plant and is producing. A second new well RN-32 was completed this year and is currently heating up prior to flow testing in September. This well is expected to provide additional reserve capacity.

Work-over or rehabilitation of an existing well RN-22 was completed. This well is also being allowed to heat up prior to flow testing and is expected to provide additional steam for the plant. Drilling for a fluid reinjection well RN-33 has commenced to the northeast of the existing field and will be completed later this year. And that’s my update for Wind and Geothermal, John I will pass it back over to you.

John Carson

Great, and then let’s turn to Solar -- to the Solar side of the business and Murray Kroeker, our VP of Solar and Engineering will give us an update there.

Murray Kroeker

Good morning, I direct you to page 12 of the presentation. The solar plant ABW which is a 50 megawatt plant at three sites in Southern Ontario is expected to close for purchase in third quarter of 2013. The current estimated purchase price for that project is $7.2 million. Just a reminder, the plant has achieved full commercial operation and that we will be co-owning the plant with General Electric Financial Services with Alterra having a 10% ownership stake in the project. We will be the – provide the administrative services for the project.

John Carson

Great, and we hope to close that transaction very soon. With that we’re going to turn to Hydro and our VP of Hydro Jay Sutton is actually in transit today and not able to join us so I will stand in for him around the Hydro assets. First of all, looking at the Toba Montrose plant, as we mentioned earlier, second quarter generation and actual generation was down and under budget for the period due to the penstock outage at the Montrose plant. However as we made clear in other presentations we are receiving business interruption proceeds for the attributed generation that would have occurred given the water flows over that period and that’s why we can tell you that though generation for the period was 92% actually with the inclusion of the attributed generation for which we do receive payment that number increases to 103%. And that’s a good indicator of the strength of the resource at the plant.

At the East Toba plant in particular, you see there that we are at 106% of our forecast generation and year-to-date and actually since early June all through the summer, both of our units at the East Toba plant which is the larger of the two plants at the Toba Montrose facility have been at maximum capacity. And there in the presentation, on page 13, you see a photograph of the East Toba intake there at one of the period of high flows there with water actually spilling over because there is so much water there. So it's great to see that both of the units have been at maximum capacity now for months and we hope that, that continues.

Let’s turn to Montrose penstock repair work. The work there is continuing and excavation to access the penstock is nearly complete as the damaged penstock is being and has been removed to allow for installations of the replacement penstock. To-date, about 30% of replacement penstock sections have now been installed and welded and we’re now backfilling. One of the key aspects that we’re doing in association with repair is the installation of protective berms. These will be in select locations around the project and this will mitigate against any damage that might be caused by future earth movements, rockslide, etcetera. So, we think and hope that these berms will prevent an incident like this from occurring in the future and indeed had they been installed prior to this rockslide, it may not -- the damage may not have occurred but certainly we are advised that the likelihood or the increased protection provided by the berms in the areas in which they are applied which are the vulnerable areas is about five-fold or 500%. So that’s part of the good news going forward in additional protections that we’re including here.

Our expected return to service is in second half of 2013 and it could be as early as September but we’re really just positioning for the second half. We do note that insurance costs are expected to rise significantly. We are in final discussions with our insurance broker to secure reinsurance of the plants including for landslide coverage and we expect to have a new coverage in place by our September renewal date. With that I’d like to turn to our growth opportunities.

And I’ll start again keeping the theme of Hydro with what remains our number one growth opportunity, the Jimmie Creek hydro facility. The Jimmie Creek facility is a 62 megawatt capacity plant and we believe that we’ll have a 114 gigawatt hours on an annual average basis to be produced from this plant. You’ll recall that this plant was earlier a 124 megawatt capacity plant, it was a two-fold plant much like the Toba Montrose facility. It was planned to be this facility the Jimmie Creek plus the Upper Toba River facility.

We’re now in negotiations with BC Hydro to actually reduce the size of our PPA. We’re currently drafting and finalizing an amendment which we expect to finalize here within a couple of weeks and that will cap the contract at 62 megawatts which will accommodate a full Jimmie Creek capacity. At this time we are not going to be building a plant under that PPA for the Upper Toba River facility. With that we’ve also agreed to a revise in service date for the Jimmie Creek plant of May 1st, 2016 and I’ll speak about that again in just a moment.

The other positive aspects of this project that we’ve emphasized before is that it is fully permitted, environmental assessment has been granted and it will have a lot of operating synergies with the nearby Toba Montrose facility. It will share, for example, staff and facilities, so there will be a plenty of synergies to be realized by being positioned at both these plants which literally overlay each other geographically.

I’d also like to reemphasize again, we have the rockslide occur at the Montrose facility which is a bit more subject to rockslides and again in response to that we’ve installed the protective berms which I described earlier. The East Toba site, a larger at the Toba Montrose facility that again has much less severe terrains, it’s really much safer in all respects though we’ve increased the safety as I mentioned before at the Toba site. I say all of that to underline the fact that the Jimmie Creek site is really much more analogous and similar to the East Toba site at the Toba Montrose facility i.e. it will be much less subject to landslides or rockslides in the first place.

As we look forward to owning a share of this plant we still project as we have that we will be a 51% owner in the end. Our estimate of equity required for that 51% ownership interest will be somewhere in the neighborhood of $20 million to $30 million. Our target source for financing Jimmie Creek Hydro remains the holding company financing and we are in advance stages at executing a holding company financing. It’s likely that the execution of that financing may dovetail with timing on Jimmie Creek but we will hold forth on that for now.

We’re currently in a limited notice to proceed for preconstruction activities under a managed EPC or Engineering Procurement and Construction contract situation which SNC Lavalin will manage on our behalf and the full proceed timing on that contract and on the full construction is to be determined at this time. One of the things that we have disclosed in our MD&A is that the increase in insurance costs at Toba Montrose will likewise have some effect on the Jimmie Creek costs. So we’re going to finalize what those costs will be to finalize our pro forma and proceed. In the meantime though we’re several turns into term sheets with prospective lenders for the Jimmie Creek project and we’re very positive looking forward to that.

With our revised in-service date of May 1st, 2016 we do have a bit of flexibility on timing the beginning of construction for the plant and that’s why we’ve indicated here that the full proceed timing or that is the notice to proceed and full construction is to be announced. With that let’s go to slide 15 and talk to our other growth opportunities.

First in Iceland, our Reykjanes units three and four expansion which has been planned for some time, we have an 80 megawatt project design there and we have actually have the 50 megawatt turbine for the first part of that project design on site fully purchased. We’ve – as we’ve stated before the permit has been finalized and environmental impact assessment has been finalized, all good to go there. However the timing for start of construction there depends on a few items. Number one, this has been a longstanding item, we need to finalize our power sales arrangements with the local aluminum smelter there Norðurál, which is a subsidiary of Century Aluminum. We do have an existing PPA but it needs some amendments or adjustments before we finalize it and move forward.

Once we’ve done that we will move immediately into project financing which outside of there is another item, we don’t feel that project financing will be overly daunting once we have the PPA adjustments in place. However we’ve also listed a third item there, as Paul has mentioned earlier in today’s presentation as we’ve disclosed in our financials, we have begun a reinjection program at the Reykjanes Geothermal field this year. We do want to see what the results of that reinjection program are before we finalize the project design and just how and where production wells will be located etcetera. So we will wait and see those results before we finalize our timeline for Reykjanes three and four. So as you see given those three items the time for starting Reykjanes three and four is currently to be determined.

Turning then to the Dokie 2 wind farm and this is basically just next door to our Dokie 1 wind farm, which really has been a successful story for us on the asset side for sure. This is a 156 megawatt permitted wind farm and GEEFS as they are at Dokie 1 will stand to be our 49% partner there. The wind resource there is strong, we have a lot of met towers on site there to measure the resource. They’ve now done a full turn over a full year of cycling for data, so we should have very robust data when we get to a PPA and get to build this project as the wind resource there given the types of turbines that are available today that weren’t available when we built the Dokie 1 facility should ensure that we have a significantly higher capacity factor at Dokie 2 versus Dokie 1.

The PPA there or the Power Purchase Agreement will be the most significant aspect of the farm that’s not yet in place. We are in dialogue with BC Hydro on a regular basis, however overall we think that this PPA wouldn’t occur until certain growth catalysts are realized within British Columbia and foremost among those is Liquefied Natural Gas or LNG plants. As most of you are aware, there is a good prospect that LNG facilities will be developed, constructed and put into operations over the next several years within British Columbia and when that happens we believe we’ll have a good chance to complete the contract in another wind farm and build it.

Let’s look at our other active projects which we’ve mentioned at the bottom of the page. First of all on wind, I haven’t mentioned our coastal BC assets, they are in a little bit slower motion right now pending those same growth catalysts but I have mentioned a – new opportunity in the US, in Texas. We’ve closed and agreed to an exclusivity with a potential co-developer on a 2013 opportunity and our team is working very hard right now as to fully elucidate or realize whether that opportunity is worth closing on and so there will be further updates there than here, right now it looks like an interesting prospect for us.

Turning to the geothermal side, we did finalize our agreement with EDC in the quarter and subsequent to the quarter all of our companies are put into place and we’re very excited about the fact that we have an earn-in partnership finalized with EDC, one of the world’s largest geothermal developers, very cash-rich partner and we plan to drill with them on the site in the late 2014. So I’m very excited about that partnership and we may even be growing that partnership a bit with a few of our other assets, so stay tuned there.

One asset that didn’t make it here was our Italian early-stage geothermal assets. We’re actually in a late-stage partnership discussion there and we may have an announcement there for those early-stage assets which are a much smaller part of the company.

Then to the solar side, note there we have actually stopped pursuing the AG Solar One partnership. The parties were working toward definitive arrangements but realized along the way that we were just determined to go separate ways on that one. So that partnership is no longer being pursued by the company in the wake of that though we’re looking at other USA solar opportunities as well and that activity will continue.

So that wraps up our growth opportunities and what we’re looking at as a company. Again in summary, the operations were strong, I think there were a lot of good things in our financials. We continue to get our debt numbers down. And so, I’m excited about where the company is. We do face challenges as every company does, but we definitely have a team that’s up to meet those challenges.

With all that Ross, I’ll turn it over to you to summarize this.

Ross Beaty

Good. Thank you, John. Thanks very much. So I think everybody has got a pretty clear message from our team. Our operations are producing steady, predictable and positive financial results. We have plenty of growth opportunities, though it is taking some time to progress them, with Jimmie Creek almost advanced.

We continue to have multiple ways to finance our growth and we will pull the trigger on one or another as and when needed. Our management team is leaner and our administration costs lower. But we are fully capable of executing their growth plans as needed. We remain a significant, clean energy producer with a strong pipeline and we will steadily grow this as time goes on.

One comment about our Iceland's asset HS Orka, we have signaled having received some expression of interest a year ago at a purchase of our – considering the purchase of our stake there. Since then we’ve worked through a number of alternatives, but as 2013 has progressed, one of the big value drivers for both existing production revenue and future expansion revenue has been the world of aluminum price, which has relentlessly drifted lower, by almost 15%.

At today’s price, we’ve decided to hold any sale in advance, as opposed to seeking a low value proposition and see what happens in the coming year. HS Orka is a premium geothermal asset and we are very proud and pleased to hold it and manage it for the long term as we had always planned.

Our share price remains a fraction of our breakup value. This will be better recognized in the future when we expect a significant revaluation after it will occur, either as we divest specific assets or as the market better values our total asset package, including our development pipeline.

With that, I think I’ll conclude this -- the management presentation and open the call to questions. Operator, please open the call at this time. Thank you very much.

Question-and-Answer Session

Operator

(Operator Instructions) You first question comes from Jeremy Mersereau from National Bank Financial. Please go ahead.

Jeremy Mersereau – National Bank Financial

Hello, everyone. Just wondering if you can tell us what you think the magnitude is with respect to the added insurance at Montrose post the expiry?

Ross Beaty

John?

John Carson

Yeah. Thanks for that Jeremy. At this time, we don’t have the numbers finalized, but we feel, we’re getting a bandwidth on them, those customers sub $1 million per year, prior to or any current period where we are. We expect those costs to certainly get above $1 million per year. They will be in low-single digits if anything, but that’s about the extent of where we expect them to be, but you’ll see later where those stand by.

One of the things, though Jeremy since you’ve mentioned it, that I want to mention is that, those increased costs, which I’ve just mentioned, we pretty thoroughly expect those to be a one-year outlier event of increased insurance costs. And there are some reasons for that. We’re currently in the process of completing an all new complete [valley] risk assessments, basically looking at all portions of the valley to assess what risks are there for future rockslide et cetera. We’ll have this completed shortly and there will likely be a second study engaged as well. Both of those will really give future years of insurance, more certainty on the, really the low risk of future rockslides here on the plant. As we’ve expressed before, our consultant for the project has calculated the risk or the likelihood of the event that occurred to be 1 in 100 to 1 in 1000 year event. So it’s extremely unlikely that it would happen again within the life of the project.

There are also a couple of other aspects which will really tend to lower those costs right back down, we believe, in the subsequent periods. Primary among those are the fact that I have mentioned we’re installing protective berms at the most vulnerable locations, the most vulnerable locations to rockslides and earth movement. We expect a five-fold improvement at each of those locations in safety. Again, as calculated or estimated by our consultant. And so, we believe with those significant enhancements which we put in place for the next insurance renewal period, but are not in place today, we believe those will significantly reduce our costs.

Finally, we will have fully completed repairs of the current facility and have established water flow. So the combination of all of those events makes us pretty certain that we’ll have much lower insurance costs in the subsequent period. So that’s where we are on insurance.

Jeremy Mersereau – National Bank Financial

Okay. I guess, following the same line and you said that the insurer is reviewing the eligible costs, again just wondering what order of magnitude we could see there reducing the amount that they would pay out for the missed production and end up [gap on that]?

John Carson

Yeah. Great Jeremy, we expect any gap to be minimal. We actually expect and hoping to be zero. If it is something else, we don’t expect anything to be more than a modest amount. So we’d have no basis really to make an estimate other than to state we are pretty strongly confident that if there is any amount it will be a modest amount of gap, between claims and coverage.

Jeremy Mersereau – National Bank Financial

As far as the solar project, it relates just to the small item, but just wondering why the cost, the purchase price climbed to 7.2 from 6 million?

John Carson

Why it increased to 7, from approximately 6?

Jeremy Mersereau – National Bank Financial

Yeah.

John Carson

Yeah. Really just a resetting of the deal. The parties, there were several factors involved and there were negotiations around that. Nothing too disruptive. However, clearly, we like six better than seven, so seven is a bit of a disappointment. The good part of that it is, we’re still really into nice returns on that modest holding, so happy to own it and still a deal that really anyone would do. So, even though with that smaller increase, which we didn’t care for, just a result of negotiations and a bit of reframing on the deal.

Jeremy Mersereau – National Bank Financial

And finally, at HS Orka, with the added production that you’ve got, with the drilling that you are doing today or what happens to that production? Is it sold to your existing customers or remind me what happens.

John Carson

Yeah. We have a contracting procedure at that facility, both of those facilities actually, Reykjanes facility and the Svartsengi facility. We have contracting seasons there for a large portion of our contracting. About currently 60% of our generation is performed under these shorter term contracts, such as two year contracts. So each season, we sell contract – sell power under those contracts, once our generation is increased at either Svartsengi or Reykjanes we’re able to engage in more of those contracts and that’s what’s occurred this year and that’s why we’ve had increased revenues at the HS Orka facility this year. We’ve had increased generation to meet increased contractual success that we had this past year. If you look at our company versus other companies and competitors in the Icelandic marketplace, we have a long track record of success at contracting on the short term basis, which complements our long term contract with HS Norðurál and (inaudible).

Jeremy Mersereau – National Bank Financial

Great, thank you.

Operator

Your next question comes from Jared Alexander from Canaccord. Please go ahead.

Jared Alexander – Canaccord Genuity

Thank you. I just wanted to start with HS Orka and specifically with the fluid reinjection program. Can you give us any kind of range on potential costs around that program?

Ross Beaty

Jared, maybe we’ll get our manager Margeirsson to answer that, Asgeir if you are able to access the call here, could you give Jared some color on that?

Asgeir Margeirsson

Yes, Ross. Thank you. The plant that we are doing now includes studies and scientific work on the field as Ross explained a bit earlier, plush the drilling of well RN-33 which was also explained. And the budget for that drilling is about $4 million for the well. The other costs are minimal compared to drilling operations. So the bulk of this well [is typically] are $4 million and some scientific work around that, so just trace the test and all the monitoring work. So just a little bit on top of the drilling of well 33.

Ross Beaty

Great. Thanks Asgeir. The other thing I should mention is the drilling of that particular well RN-33 is in a relatively new area that will be quite interesting for us to look at from an exploration standpoint, because it can put on a new reservoir area. And so, that hole is not only a reinjection hole, we can drill a lot of site but also potential a production site. So we’ll see what happens, that result will come in probably October-November and we’ll talk about it probably next quarter on the call.

Jared Alexander – Canaccord Genuity

And then just related to that, I know John, you mentioned that the timing on Reykjanes 3 and 4 is to be determined. I know one-time you are kind of thinking early 2015, does that push that out, is 2016 too aggressive now?

John Carson

Early 2016 is probably the earliest possible – I am really thinking that by the time we get these results, as Ross said, even just from the new injection well that we will be drilling, we won’t have firm results on that till very late in the calendar year. So it’s tough to see in the very beginning of 2016, it’s really more likely the earliest and a bit later 2016. But the punch line really is stand by for reassessment on timing. Once we’ve had a chance to look at those results and hopefully to resolve our contractual differences with our power purchaser.

Ross Beaty

And the other thing I might mention, John, is – or Jared is the other swing factor that’s influencing timing is global aluminum prices. I mean right now it’s at the bottom of the market with [too much] uncertainty as to where aluminum prices are going to go, really there is no profitability in the expansion case as under the current thinking on the PPA. And so if aluminum prices were to go up we’d get things going much more aggressive than we are today. It just isn’t sensible to be starting an expansion at the bottom of that market, when you have a revenue base that slivers to the price of aluminum. If that changes, then we could advance it much more quickly. And it’s a tremendous shame because of so much work we’ve done on this project at both by us and by the aluminum company counterpart. But it is what it is and we just have to accept that. That’s why I just said, we are not going to sell the asset when we get the bottom price and we are not going to do an expansion where we can’t get a decent return on that. So that’s just the way it goes.

Jared Alexander – Canaccord Genuity

Ross, just following that, can you give any kind of range of aluminum price that you think you’d require to really dive into those expansions?

Ross Beaty

Not really. It’s not only the aluminum price, there’s other issues but it’s dominantly the aluminum price and of course most fundamentally it’s the negotiated price between us and the offtaker, and we haven’t managed to reconcile that in 3 years of discussion. So that’s a question mark, it will be dependent on things like cost of capital in the expansion and other factors that bear on profitability but that is still a discussion we are engaging and having the negotiation for extensive periods and have not yet been able to resolve.

Jared Alexander – Canaccord Genuity

If I can just ask one last question, shifting gears here a bit to the Texas project. I appreciate you can’t really tell me much in the way of details here. But can you tell me is this a fully contracted project or are you considering merchant exposure in Texas?

Ross Beaty

I am thinking it’s probably a little bit early to be talking about any details on that project, Jared. If you don’t mind, we will just talk that in – when we get through our own detailed due diligence and really want to proceed and intend to proceed and have – finally it will end up to proceed, we will come up with all the details that we have. At the moment it’s a very interesting opportunity but I think that’s probably all we need to say but thanks.

Operator

Your next question comes from Aram Fuchs from Fertilemind Capital.

Aram Fuchs – Fertilemind Capital

Ross, last couple of calls you mentioned the observation that being asset and in tier pricing development assets are enterprise, it seems that there hasn’t been a move to sell-off some of the esteemed assets in the development side of things is not progressing. Is that still what you are seeing there and can you in that context talk about Greenbriar and what went on there, can you give us any more details and it seems and my observation is that development assets are also like getting tier pricing. And I am wondering if you are going to change that observation --

Ross Beaty

Sure. Well, it’s very true to I think what you said that today operating assets are dearly priced, and at the same time development assets are somewhat – there’s kind of two prices of development, early stage ones which have very little value and there is more advanced [sale side], I would agree with you. There are some that are also highly priced and seem to be attractive to a great number of participants in the renewable energy space. So we have to compete with lots of people and we are not interested in [longer term] assets and that’s why you haven’t seen us do too many deals over the last couple of years, we certainly looked a lot but we haven’t jumped on them.

We did pursue with the Greenbriar deal because it looked interesting and as you could imagine, sometimes with projects where there are two equal parties, you need to work together very closely and resolve issues, it wasn’t apparent really early on in that relationship that we had different views of the future and different views of how to operate and we’ve just both felt that the best way to choose that was exit immediately as opposed to continuing and aim at a relationship that might not be optimal. So as soon as we came to that realization we just said, let’s pull the plug and recover all monies expended and let the Greenbriar have the project. They initiated it, and wanted us to come in on terms as I said we had some differences of opinion on. So that would be under that.

There are other – we like – the project I would say, we do like solar a lot. The reason we have our ABW Solar project in Ontario is so that we could learn about solar. It’s a very small asset and it’s got a decent return but it’s not very material on a total return basis for us. And again it has been a great learning experience for us to understand solar. So we do like solar and if we saw the right project, again we would get into it and that was what we thought we found with the Greenbriar opportunity but it just didn’t – it’s sometimes better to pull a pin on these things early on than maintain what might be an awkward relationship. We wish them well and I know they wish us well and we are quite amicable at this point in time. That’s the bottom line there.

Aram Fuchs – Fertilemind Capital

On your observation that you are selling breakup value, you’re putting assets – you’re looking for price to stay aren’t quite attractive and I noticed you bought a bunch of shares in the open market. Is there any change there – the pricing, have they gone down or are you [amenable] to put some of these assets up for sale in the not too distant future?

Ross Beaty

Sure. Well you can imagine we have this conversation – I wouldn’t say – daily but very frequently and in every single board meeting we have and there is some pressure on us in some individuals, and owners of us to divest some of our assets and actually realize the values that are very much in excess of our current trading price. We haven’t needed a lot of capital. What we have needed we have been able to access through the revolving facility that has been – that is in place for exactly – to kind of establish a bridge, until we need larger lots of capital and then can access those through one of the alternatives available to us, such as either the holdco financing or alternatively a sale of assets. Now we have been working and thinking we might be selling our Icelandic asset for a decent price last year especially and earlier this year and if that had had happened, of course we would have no interest – no need to do any kind of holdco financing, we would have eliminated the bridge and had a considerable capital to put into other development projects.

And we are simply to hold those as cash – for potential dividends and other purposes. And that was something that was always out there, we’ve had plenty of interest in our Canadian assets as you might remember last fall, GE divested its stake in the Toba Montrose asset and the Dokie assets for a significant multiple over what our share price is reflecting today. And we have always a chance to do that, either collectively or individually or in part, we could sell a portion of either asset. And to the extent we need capital for Jimmie Creek or for another construction projects somewhere else we might consider doing that. We would have to have a very much improved rate of return than we have right now and we’d have to make sure that the transaction fit into the model we have – which is as an owner and operator of renewable energy projects, the company with a revenue base, strong operations and an opportunity to provide a long term sustainable cash flow to our shareholders through the form of dividend in due course. And when you sell operating assets of course, you impair that long term strategy but there is a time and a place to do it and we’ve certainly looked at lots of alternatives and we will continue to look at that as the year progresses and we advance things like Jimmie Creek to finance the both. Any other comments on that John?

John Carson

No, Ross, I think you hit the major points there. Thanks.

Operator

There are no further questions at this time. Please proceed.

Ross Beaty

Okay. Thank you, operator. Well, we have a quiet group of questioners, I suppose that reflects either a perfect presentation or the summer doldrums happening right now. But in any case I would like to thank all of you for listening and all of our management team for their presentations. We are certainly available if anyone has any follow up questions over the phone, just give us a call at our office. And with that, thank you very much for joining us today and the call is now at an end.

Operator

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.

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