Mighty River Power Financial Results FY2012 Transcripts by Mercury

Mighty River Power Financial Results Briefing Held on 28 August 2012

ANNA HIRST: Good morning everyone and thank you for joining us for this briefing on Mighty River Power's financial results for the year to 30 June 2012. I am Anna Hirst, Head of Investor Relations and speaking today on behalf of Mighty River Power is Chief Executive of Mighty River Power Doug Heffernan and Chief Financial Officer William Meek. We will begin the briefing shortly but before we do, I will run through some housekeeping. In the event of an emergency that requires us to evacuate the building, please follow the emergency exits and the meeting point is outside the front building. Doug and William will run through today's presentation and then we will take questions at the end of the session. I am sure you are well aware that we are currently under Securities Act restrictions and as yet unable to provide forward looking financial information or answer any questions about prospects. With that, I will hand you over to Doug. DOUG HEFFERNAN: Thanks Anna, welcome everyone. So look, if you just put the agenda up, Anna, I will just explain who's going to do what. I am going to run through highlights and just talk about some of the overall market dynamics. William will talk about the operational update and go through the financial section and then I will wrap up with a business update at the end. So, just turning to the highlights, just running through these, EBITDAF was up 4% and that is slightly up on or reflects our revised guidance at half year. Probably the other thing to recall is a 35% increase in EBITDAF occurred in FY2011, so we had a very strong FY2011 and we have had further growth on that in FY2012. Financial instruments had an impact on the bottom line on the impact but most of you will be familiar with that because the majority of that occurred in the half year, in the first half.

Underlying earnings were flat but what might seem a relatively still water on the surface, an underlying earnings line, has quite a lot going on below it, so we will drill into some of the detail later on. Declared dividends is up 9% to $120 million, so it's further strong growth on the dividend over the last 3 or 4 years and that reflects our current dividend policy. Fixed priced volumes for electricity sales are up 5%, so there's been a lot of discussion by many of you about a very flat electricity demand. We have managed to grow our electricity sales volumes across all of our fixed price variable volume channels by 5% year on year, so clearly that translates to market share gains at the customer end. On the other side, hydro generation is down slightly 2% year on year. The prior year was a very strong year though, supporting that very strong growth in FY2011 earnings. But having said all of that, hydro generation was still up on long run averages by about 7% odd, so around 300 gigawatt hours of hydro generation which, as you know, generally just falls through to the bottom line, so very strong contribution. But you will see when William goes through the operational update, just how the overall generation portfolio performed across the three different fuel types and you will see the complementarity that the gas plant provides to the hydro business and also the strength that geothermal brings to the overall earnings for the company. Looking on the development side, Ngatamariki project is well into construction and on track for commissioning in mid-2013. In the second half, we celebrated the commissioning of the energy source project in Southern California, the now named John L Featherstone plant. Formally known as Hudson Ranch, it had a very first quarter with 99% capacity factor, so we relate that to the very strong performance we had at Nga Awa Purua when it was first commissioning, so very good to see energy source replicating excellent results we had at Nga Awa Purua. We have extended liquidity head room, again William will talk about some of the detail around that, to $510 million at the end of the year. And we do have a BBB+ credit rating, as you will all know, no doubt.

Looking to the graphs, just a few of these because William will go through these in some detail. Obviously, energy margin up slightly. If you look at the EBITDAF line, as I said, continued growth but if you look at the comparable figure going back to FY2010, that was $328 million, so a big step that's occurred over the three year period. You will see a lot of noise around the fair value adjustments, most of which you've already seen in the half year result, underlying earnings flat but quite a lot of peddling going on underneath the line. But going back to operating expenditure, we did have some additional expenditures in the second half, around 12 million of that at Southbound, we had a transformer failure and two gas turbines that failed and that had mechanical failures in that period, so they led to $12 million of the increase in operating expenditure year on year. And, as we've previously flagged, we do have increased expenditure on the hydro plants reflecting their life cycle. And, as I mentioned, dividends up 9% year on year. Capital expenditure, significant growth, just reflecting the intensity of the Ngatamariki project as we go through the probably the most intensive period of the investment in Ngatamariki. Turning to overall market dynamics, there's many pages of computer typing that's been put out in recent times about what's happening with electricity demand, not just here in New Zealand but around the world. Overall, as you are all familiar, electricity demand has been relatively flat through the last 4 or 5 years. We had fluctuating demand from Tiwai for a number of reasons, overall weak economic conditions and the Christchurch earthquake has had some impact. If you exclude Tiwai's demand over that period, it's really flat in FY2012 and remains relatively flat. In the second half, the smelter reduced its demand by around 103 gigawatt hours over the second half and Tiwai is still running at that lower level into this year. I think if you look more deeply at what's going on with electricity in New Zealand, and I know some of you have, if you look back over 15 years or so, you've seen a relative decline in the industrial sector, a combination of efficiency gains in the use of electricity and not strong growth in exporting

out of that sector. Partly a reflection of what's happening globally with a lot of electricity intensive manufacturing locating much closer to where customers are, rather than on processing in countries like New Zealand and then incurring high shipping costs to get product to market. That was one of the reasons behind Norske reducing one of its paper lines back in around 2006/2007 and we are seeing the impact of Ipad technology on their firm with the announcement of another paper line being shut down. I should say at this point that we do not have a physical supply arrangement with Norske. It is a financial contract, so there is not a direct linkage back to Mighty River associated with the physical consumption at Norske. We are affected or we will be affected, as will any other generator in the market, but we do not have a specific physical contractual relationship with Norske. Just finally on demand, residential demand is relatively flat. So, people talk about falling demand in residential, it's still strongly correlated with population growth. So, we are all using more devices, we probably have more efficient devices, we probably are gradually getting more efficient homes, but really we are just deploying the dollar into other uses of electricity rather than going and spending on another glass of wine. You've heard me talk about the strange affliction that the media have with ICPs in the electricity sector, I think they've borrowed that from the telecommunication sector where marginal consumption or marginal customers have high margin contribution to telecommunication firms generally. That's not true in electricity. At the margin, if I've got an extra customer, I have to buy that product off the wholesale market and I get a relatively low margin on that sale and so a very different business model for electricity than there is for telecommunications. Having said that, if you also skin open what the overall sales in the sector looks like, residential is a relatively small part and definitely gets a lot more column inches attention than the overall mix of sales across the multiple channels. It does make up around 33% of total consumption but the media is

more reflective of the 87% ICP numbers. Turning to supply, again a lot of focus on what's been happening in the South Island over the last 12 months where competitors, South Island plants have had very, very low hydrology, record lows in some cases. By contrast, the Waikato has had very close to average inflows right through the year but particularly in the first 9 months and slightly lower than average in the last quarter. Again, that reflects the difference in what drives our inflows compared to South Island hydro generators. We are rain fed, it keeps raining all the time in the North Island, snow melt occurs in very concentrated season periods in the South Island typically, so we have had the benefit of a contrast in hydrology to the South Island. That low hydro generation in the South Island meant that the overall supply was made up from higher gas and coal production, higher costs from them, and you will see that flowing through in higher wholesale prices. Oh sorry, can I just go back, Anna? Just something to point out on these graphs, what we show on inflows is the long run going way back to the 1920s of hydrological information we have for inflows into the Waikato catchment. For storage, we show since and including FY2000 because the storage profile for the Waikato hydro is different under our operation than it was within the ECNZ portfolio. So, that's why you will see different averages used in inflow versus storage. So, as I said, we had very poor hydro conditions nationally in the South Island, particularly in the South Island, dry even compared to 2008 but compared to 2008 relatively muted wholesale price increases. We all know that there's been significant investment in renewal capacity since 2008 and that's tended to displace thermal capacity that had been running in the early part of 2000. That meant there was more thermal capacity able to respond to market conditions in a dry year. You also saw that additional thermal capacity was available from a number of players, including ourselves. So, you actually had much more competition amongst and between the thermal generators for that higher wholesale price than occurred in 2008 where really you had only one thermal generator able to respond to the dry conditions.

It led to higher availability and liquidity in hedge contracts and you did see a different risk management approach being taken across the market more generally than was applying way back in 2008. You can form your own view as to why that would be. But definitely we saw a lot more competition at the margin amongst thermal kit simply because you had a number of generators there trying to grab some market share under conditions where wholesale prices were being supported by poor South Island hydrology. This chart is just trying to show the spread between Otahuhu and Benmore prices quarterly or monthly through the year. You can see the differential moving around quite a bit as hydrology conditions started to manifest themselves in poor storage in the South Island around the second quarter of FY2012. And then in the fourth quarter, you saw quite a blowout in the spread and, you know, a number of things influencing that but primarily you have still got transmission restrictions between the North and South Island so the market can separate into more than one market more quickly and you also had quite a restriction on the way in which reserves were being offered, given that constriction in transmission. So, we saw spreads blowout particularly in May and June. And you can see that in the price graph at the bottom. Relatively close tracking between Otahuhu and Benmore prices and then you had prices reaching $200 in May at Benmore and just over $100 at Otahuhu. You are aware transmission upgrades are going on. As that comes through, it will make the two markets more connected, putting Rio to one side. That expansion in turn will remove some of the market power that generators in the South Island can have from time to time in the reserves market and you will be aware that the Commerce Commission is looking at some of that activity in that quarter and I'm sure the Electricity Authority is looking at that as well. William. WILLIAM MEEK: Good morning, ladies and gentlemen, I am William Meek, the Chief Financial Officer from Mighty River Power. So, I will just start, we will run through our generation business, work through the retail and then we will hit the financials shortly.

So, we see a time series here from 2008 to 2012 of our generation production. Certainly, as Doug said, we saw a strong generation performance across our entire portfolio, up 3% in total against FY2011 which was also an above average hydro production year. So, despite 2% lower hydro generation, this year, the more than doubling of output itself down. So I think in the previous slide you saw overall thermal fuels up 29% for the country, so in our portfolio we saw Southdown over 100% up on FY2011 as a consequence of those price rises. And again, a very stable geothermal position there and I will talk to you about that in more detail. So again, the company is very pleased with that result, achieving the government objectives of more than 90% renewable about 8 years early, so that's great. Looking at the different fuel types here, again you can see the hydro production in 2012 verses 2011 by the first half and second half of the year. We had a slightly stronger first half and then it was, as Doug said, slightly below average inflows for that second half period. Geothermal, again showing only a very small reduction from last year's level, that's a pretty significant achievement given the 10% sale at Nga Awa Purua which saw us take a 30 gigawatt hour lower annual output there as a consequence of that sale, that 10% interest to Otara North No.2 Trust and we will see some numbers there around availability shortly but certainly a strong performance there across the geothermal fleet. And Southdown there certainly with higher prices averaging over $80 for the year, seeing much higher generation levels from that plant. So again, a good result across the generation portfolio. We show various of hydro availability numbers for fuel types, so we actually see slightly declining trends in both hydro and gas fired. Hydro really being impacted by the major life cycle work happening there, maintenance, particularly at Ohakuri on runners. They are not athletes, they are the propellers that ultimately turn the generator. And at Arapuni in terms of the generator replacements that are going on there. That programme of work will continue for about another 18 months to two years, so we expect to see that capacity, that availability, at similar levels looking forward.

Geothermal, again showing a 2% rise on FY2011 levels, so again a testament to the technical capability and the dedication of our operations team, keeping those plants hot and generating very well throughout the year. Doug noted we did have some hiccups there at Southdown on both the transformer. We had a transformer failure back in, I think, 2005 and 2006 and one of the original plant transformers failed again, it's a design fault, so again you'd normally expect transformers to have a life of 30 plus years, so both those transformers that were installed at the beginning of the plant's life in 1997 have now failed and have been replaced. Again, a very short outage at the plant there available to utilise the flexibility in our transformer fleet and moving the universal sphere up from Oretei to Southbound to maintain production there at Southbound. So, certainly in the insurance world that's a pretty big positive to keep those plants on line and avoid that business interruption cost. Gas turbine failures, we saw two separate issues on gas turbines which did drive maintenance expense, as Doug said, over $10 million higher in FY2012. Geothermal availability there last quarter almost tapping on 100%, so a great effort. Moving now to our sales position. This is essentially just a histogram showing our sales across all channels, so that is mass markets, fixed price variable volume, various contracts, contracts with end users, contracts with generators and contracts in the ASX and spot sales. So, you can see there that wholesales position close to, well, slightly over 10,000 gigawatt hours for the year. Obviously 2000 gigawatt hours of spot sales, relatively constant for the last four years. Typically, big end of town selling physical spot sales and in a number of cases also selling electricity swabs to those customers. Again, reiterating volumes there in that fixed price variable volume market up 5% to just over 5,000 gigawatt hours, driven by increases in market share in the commercial segment. See the move there with GLO-BUG. So it's our prepay option, so again GLO-BUG recognised at the Energy Awards with an Innovation Award, certainly a premium prepaid product and one of our competitors, Meridian, are transferring their prepaid customers to the GLO-BUG product.

GLO-BUG is a key instrument in terms of managing bad debts which, given our generation settlements, come from the wholesale market, they tend to be paid, so bad debt write-offs of $3.6 million, we are very proud of that and the efforts inside our retail business managing that bad debt exposure, so that represents around $9 a customer, so that's a pretty industry leading level of credit management. 3 year fixed, we've talked about this, again that still continues to grow at great guns offering a medium-term fixed price product to customers and we are seeing now over 80,000 of our retail customers on a fixed price scheme. We have trialled blend and extend on that scheme also to around 10,000 customers and take up rates in that are around 45%, so certainly the customers that are on that type of arrangement certainly put a lot of credit in having that fixed priced commitment. Just jump back, Anna. So, I think the other thing you are seeing a grow position there, again that's consistent with our expanding generation portfolio, so again you are seeing a build there in the book ahead of Ngatamariki commissioned for the middle of next year. Just looking again, slightly more segmentation there around residential. Doug has emphasised the residential position, so slightly down there in the residential market more than compensated for growth in that business segment which is up 14% from where it was last year, almost 300 gigawatt hours. The commercial contracts, you can see there the contract term moving out close to 3 years. Those are energy only fixed price contracts, so the lines charges, taxes, market fees and levies are variable and pass through those contracts as they are set by either the regulator or the lines companies, so again relating back to some concerns around the demand environment in the country, those contracts won't really respond in terms of price movements as a consequence of those demands changes. All the brands there of the company are shown. Mighty River Power doesn't retail to customers but certainly all the others do, and so again that brand mix is a very key component of our marketing strategy. I will move to Contracts for Difference. It is a very long name for what is essentially an electricity swap. It is a fixed price for a fixed quantity for a

fixed period of time, typically. We've got a few exceptions but generally that is what they are. Again, the net position shown by that black line, again relatively constant on a net basis over the last 5 years, some gravity around that 1,500 gigawatt hour mark. As a company, we quite like CFDs, they preserve incentives with the counterparty to manage their physical wholesale exposures, so you do get demand response in the event that power prices are high. And, as Doug said, in regard to the Norske contract, the volumes are not subject to the offtake levels of the customer, so again it gives you far more contractual certainty than a potentially variable volume of contract. The biggest movement was the step up in the VAS which is the virtual assets swap contract between ourselves and Meridian at the start of 2012 by 300 gigs. So, now we're showing a two year quarterly plot of our net position across time, so it is an adjusted position, so it adjusts for your location on the grid, it adjusts for your profile, it will adjust for losses in terms of retail sales, so it's quite a complex chart. You can see there the terms of pricing, it was a game of halves, prices relatively stable and quite low by FY2011 and then moving up to around that $80 range in FY2012. Position again across those quarters, largely square, slightly short, and, as Doug said, you've seen that dip off there and that increasing exposure in Q4, largely again because of the adjustments and that large basis for risk applying across the HVDC for that particular month of May. Adjusted short position 221 gigs there, as noted. I now move to the financials and we will provide an update there. We will start with just a quick slide on the change in our segment reporting. The Accounting Standards require reporting to be on a basis consistent with your reports provided to your chief decision-maker. If I summarise that in English, that would mean the reports that go to Doug and our board, we should report our segmentation on the same basis. So, internally we report our energy position as a portfolio, so we look at the generation and retail businesses combined and the effect that is having on energy margin for the company.

As a consequence, that has seen the wholesale and retail segments combine for the purposes of external financial reporting from FY2012. The "Other segment" includes metering, upstream gas and our international geothermal activity. "Unallocated" is essential corporate costs which are unallocated to either of those two operating segments. So, I won't dwell on this slide too long because there's a number of slides that deal with the details contained within it but, again, strong portfolio performance at an energy margin level which is essentially revenues from all sources, less direct costs, so that's up almost 5% or $30 million for the year. So, again, given FY2011 was a strong year, it is very pleasing to see that energy margin result. EBITDAF, as Doug has mentioned, fell within guidance at the lower end but, nevertheless, within the revised guidance at $461 million. So, here we have a bridge of EBITDAF. So, if we look at those first four coloured bars, the blue through to the sales line, really that's the energy portfolio and we can see the aggregate of those numbers sitting around that $30 million mark showing the benefit of higher prices driving up the generation revenues, offset by additional fuel costs, so southbound using around PJs more gas for a cost of $23 million, contracts and sales to customers showing decreases as a consequence of compressed margins against the counterfactual wholesale prices. So, net all those four added together, up 30. Other income, $20.1 million up. Hopefully some of you read our press release but, again, two key contributors there being the sale of our emission units very early on in the year, certainly pleased to have sold those at a price north of $20 when current prices are $5, so that's a very good trade. And the sale and accounting gain of $8 million for a 10% interest at Nga Awa Purua. It's a combination of those two effects more than offsetting the increase in OPEX which slide we will move to next. So, we've touched already on the increase in maintenance expenses up $16 million, again a fair chunk of that relating to Southdown, and life cycle work at particularly Ohakuri and at Arapuni. "Other expenses" up $10 million relating to a termination of a long-term agreement and higher professional fees and insurance costs.

Certainly insurance costs are an issue for all infrastructure firms in terms of where that market is and the effects of both global climate claims and earthquake risk within New Zealand. Just under $4 million there is related to or borne by preparation costs for potential IPO. So, now we bridge from EBITDAF through to NPAT and we talk to the substantial buyers. Depreciation and amortisation at almost $160 million, it's pretty hefty. As you should be aware, we revalue our generation assets, that does create quite a significant pump in the depreciation expense against historic cost accounting, so we are seeing the effect of depreciation rising from FY2011 as a consequence of the revaluations under taken last year of around $400 million and we are seeing a slight rise there of $3 million in amortisations. Change in fair value financial instruments at $118 million, so that is a hybrid, that is taking the essentially equity accounted components out and adding those to the 92/93 million relating to domestic fair values. Again, most of that is interest related and I'll talk to that shortly. Net interest at 73 is about $14 million of capitalised interest, so you will see a difference there between interest expense and interest paid in the cashflow, income tax down in terms of accounting, again reflecting those fair value prices, particularly in offshore entities which are not subject to tax. So now I'll talk to fair value financial instruments. Some of you in the room will be well versed and some perhaps not so. It's certainly a vagary of International Financial Reporting Standards in terms of the impacts from Mighty River but essentially for us, back in 2008 we were looking to embark on a pretty substantial geothermal programme. Here today we've spent well in excess of $1 billion on geothermal development, so it's a bit akin to starting off and the mortgage on your first house, we wanted to provide certainty there around our interest costs and so, you know, the forecast debt was largely hedged back then in 2008 to provide certainty around those cost of funds. Unfortunately, GFC hit and interest rates have largely declined since then quite significantly down from 7%, as we can see here, down to 4% on the 10 year rate, it's actually slightly less than 4%. So quite significant movements.

We can see over FY2012 about a percent movement there in interest rates across the curve, most of that occurring in the first half of the year. Under IFRS, there's a number of ways you can account for those fair value movements in the context of Mighty River Power. While these are economic hedges for the purpose of hedging your physical debt exposures, they are not designated in a formal accounting relationship, so the fair value movements run through P&L for us, so certainly in the P&L relatively large compared to the bottom line impact number. Certainly a number of entities would hedge account and those would flow to balance sheet. So, inside the balance sheet at $5 billion plus, the movements are significantly smaller in a relative sense. So, what else will I say there? You can see over $20 million coming in from essentially interest rate swaps, also hedging the Hudson Ranch 1 programme development, so also the effects being felt from offshore in US which have seen interest rates also off a fair way by FY2012. So move off P&L and start talking about some of the other financial statements, so CAPEX for FY2012. You can see here on the graph the big blue bars are geothermal, so they include mainly Ngatamariki in FY2012 and GGE, $74 million of that $287 being GGE. Stay in business CAPEX, slightly higher, so that's reinvestment, so that's CAPEX expended on existing assets within our business up on this $20 million on 2011 levels. Moving through to cashflow statement, you do see net cash receipts there slightly lower than FY2011. Three key drivers of that; the sale of the tenths interest at Nga Awa Purua and the carbon credits are reductions off investing cashflows, so they are not recognised as operating income, and there's quite large movements in accounts receivable and payable lowering that cashflow number in FY2012 from 432 down to 423. Interest expense there up as average debt levels rising, seeing that flow through cashflow statement. Moving on to our funding profile. A number of you are instrumental in terms of providing that funding to us, so debt maturity profile of circa 5 years, again relating back to those fair value movements. So in terms of hedging, 97% of our interest book is currently fixed. $250 million of year facilities, bank facilities, are entered into over the last year and a very successful

commercial paper programme initiated in February of which 100 of 200 million is currently on issue. You will see the debt maturity profile there with debt going out to 2026 but certainly a fair chunk of refinancing and new facilities are required over the coming medium-term for the firm, with a retail bond expiring in May of which the facilities already exist to cover that. So, as Doug said, $510 million of facilities currently in place undrawn. So, just a very summarised balance sheet for everybody, key movements there being asset revaluations on property, plant and equipment, over $400 million in FY2011 and around $170 million in FY2012. Current liability rising as a consequence of current debt coming into the next 12 months, so we are seeing that retail bond flow into that, as well as the commercial paper programme for which $100 million is on issue. And then we have seen the receivables payables balances move as a consequence of higher prices in June relative to June in the prior year. I will just deal with Standard & Poor's and our credit rating there. They reaffirmed our rating on April the 8th at BBB+/Stable/A2. You can see there the various credit metrics being displayed, so rising net debt, you can see a decrease in those key credit metrics being interest cover and FFO debt, so those have fallen. Again, you will be well aware geothermal projects take a circa of two years to go from effectively start of construction through to income producing, so we are about halfway through that build process before we will see earnings coming through from Ngatamariki which will see those FFO numbers rise. I will pass you back to Doug. DOUG HEFFERNAN: The first slide I will go into is health and safety. We've had a very good year and I would just like at this time just to introduce Fraser Whineray to you. Fraser is General Manager for operations. One of his additional responsibilities is for leading our health and safety efforts across the business. As the slides show on the two graphs, very good trends, total recorded injury frequency rates declined over the year and we are getting more internal reporting on near misses, so our whole transparency awareness is a highlight and one milestone for us was achieving a one year Employee LTI for

a year, so great credit to Fraser and everyone across the company and I think one of the things I can say from work we've done is the organisation, employees in the organisation are very engaged and I will get Tracy Ellis to show herself, stand on your chair please, Tracey. Tracey is Head of Human Resources and has been leading, with the support of my management team, leadership initiatives and ensuring that we've got a good engaged workforce as we go into the next phase of the company's life. So, I am very pleased to see the results that my team have achieved there over the last year. Turning towards development and here I am going to focus on generation development and that is the responsibility of Mark Trigg, our GM Development here, he will be known to some of you. Mark has really got two or three foci on the development front, one obviously on Ngatamariki, as William said, we are halfway through the project on track for commissioning mid-2013. It is a different technology from the big projects at Karau and Nga Awa Purua in that it uses all that technology and therefore is modular, so there are four 20 odd megawatt modules that make up the 82 megawatt project, and so staged commissioning of those projects through 2013. The project gets connected to the grid in late 2012. It enables the first of those modules to start generating juice in early 2013 but it does not contribute to the earnings line until the whole project is fully commissioned around mid-2013. Five of the seven wells have been drilled. We did have some challenges drilling the second and third injection wells and I'm sure Mark would be happy to talk about the detail around that but we had some challenges drilling in a particular area of the field which would lead to higher costs of drilling that injection well. We take the view that we should increase the contingency on that project from 466 up to 484 by adding in 80 million in case we need an additional well on the project. Even if that well is used, the project cost still remains below the $80 real LRMC that we discussed disclosed some months ago. As William's financials showed, we are about halfway through the project, so without telling you any forecast financial information, you can work out there's about $200 million of CAPEX to go on that project. Again, Mark's been looking at the overall pipeline for development. You will be aware right across the sector a big push on building pipelines or

getting pipelines ready. We've taken a trim to what we think is necessary looking at the demand conditions in the country and Mark is focused on the best options available for future development for us, both in geothermal and in wind. That's not to say we don't have options around gas but his focus on creating new options on geothermal, the Taheke field, we've got, through mark's efforts and his team, development agreements in place with two landowners on that field. They were signed in November last year and currently we have exploration expected some time in 2013. Wind Turitea and Puketoi both have consents, with the Puketoi consent subject to appeal, so there's just on 500 megawatts of capacity potential across those two projects. The unique feature of the Puketoi, or in fact both of them but in particular Puketoi, is the consent includes transmission line that links those projects (a) together and (b) up to the grid, so we've got a clear runway to bring the project to market at some point that we can determine for ourselves in the future. Offshore, again another busy year for the people at GGE and just to give some colour on the company's involvement with GGE, Mark is a director of the fund manager GGE LLC along with Mike Allen who is a director of the parent company of Mighty River Power. Mike has got a long experience in the geothermal, as you can see from his CV if you want to have a look at it. So, Mark and Mike represent the company on the management company and then on the Investment Committee where all the decisions are made around requests for project approvals, William and I are both on that Investment Committee along with two members of Mighty River Power board, Trevor James and Prue Flax, so a lot of decision controls sit with Mighty River through those two different channels. We have deployed around $US225 million of the $US250 million capital commitment we made to GGE some time ago, getting on to a couple of years ago now, more than two years. Because of the number of projects that GGE has in the pipeline, they are looking to raise additional capital into that fund and Mighty River will consider contributing further capital alongside new investors and will take account of their capital raise process as it works through.

Through 2012, I guess the key developments were - probably number 1 was the commissioning of what's now called the John L Featherstone plant. It is an energy source project located in the Salton Sea in Southern California. A very high temperature resource, a very large high temperature resource, with a number of operating plants on that reservoir, and that went into commercial operation in the third quarter of FY2012 and had an excellent first full quarter with a capacity factor of over 99%. That's matching the best results we've had at Nga Awa Purua, so really good to see some of the experience we had at Nga Awa Purua carrying forward to what is an identical piece of kit, largely identical source of kit that energy source is running on Salton Sea. Now that project has been up and running for a quarter, energy sources are well advanced in post construction refinancing, so there's a lot of project debt put in as part of the refinancing of the project, that's now been refinancing for the operating mode that the John L Featherstone plant is now in. This morning or yesterday US time, GGE also announced that they've completed two geothermal wells at Tolhuaca in Southern Chile. One of those wells is producing very high temperature resource sufficient to generate 12 megawatts and I understand it's the largest productive well that's been drilled in South America, so it's good to see that result from GGE. And back in the Salton Sea, energy sources have got a long-term offtake agreement already signed with the same counterparty as the initial project for a further development on Hudson Ranch and drilling for that project is due to start in the next month or two. We have already previously announced that in Germany GGE has four additional consents or four additional concessions that were required in the first half of the financial year and they've got surface testing underway on some and planned on others in the next year ahead. Turning to water, I just say Treaty of Waitangi issues are a matter for the Crown. The parties to the Treaty of Waitangi, for those of you who are Kiwis and don't remember this, are the Crown and Maori, they are not companies like us. These are sovereign relationships between Iwi and the Crown. All Treaty or Waitangi issues go back to them. The Waikato Regional Council went through what was named the Variation 6, which was considering variations to the abstraction of water from

the Waikato River. They went through a long process and here I will acknowledge again Fraser was involved with this but also Bruce Waters must be somewhere here, GM Corporate Affairs, so Bruce and Fraser have been putting a lot of effort into the matters in this slide, particularly the second and third bullet, and the original decision of the Waikato Regional Council was appealed and on appeal they awarded some additional water to abstractors along the river but the net effect of that for the company is that we believe we will continue to have a long-term average production out of the Waikato of around 4,000 gigawatt hours. The Council also - one of the conditions of the consents of the Waikato hydro, this is consistent with most long-term, i.e. 35 year consents, that are awarded for generation projects. They have review conditions which the Council has the power to review the conditions of the consent if they think and judge that the effects of the operation of whatever the scheme is are greater than were anticipated. At this stage, we have no information from a scientific perspective that there are any differences in the effects than those that were anticipated at the time of awarding the consent. That's a process that the Waikato Regional Council will run through in 2013 and make a decision as to whether there should be a review or not. So, just wrapping up, this is the extent of what I can say beyond the end of FY2012, obviously it's somewhat limited and disappointing but anyway it is what it is. Since the end of the year inflows, which you probably already know anyway, into the South Island reservoirs have improved from the lows experienced in 2012. Having said that, storage is still well below long run averages but we are going into spring and it will be interesting to see what the spring season brings to South Island storage. As a consequence of those improvements though, you have seen wholesale prices come off from levels in May and June. In contrast again, in the Waikato we've had reasonably solid inflows into the catchment since year end, 21% above historical averages and 10% above PCP, but you've also heard us say before two months does not make a year.

Having said that, current storage is where we would like it to be hitting around long run average. Retail, has had a very good year, as William indicated earlier on, with 5% growth in retail volumes, good market share gains and flat economy which is an excellent result and that growth has continued on post year end. A couple of other things I would just like to mention that I thought of. One is we're very proud of the success of what we call our rowers in the London Olympics. What we see is a really nice fit with the company, huge long-term investment that rowing has put into their sport in association with us, some private/public partnerships around the high performance centre. It's also a niche sport, a bit like geothermal is a niche product in the electricity market, and we also like the fact that the rowers, compared to many of the athletes, they really do the hard yards and, you know, we have got to know many of those rowers over the last decade and the value set of those people is something we really like to emulate within the company. We do like the way they do the hard yards. I don't think I'm quite as hard a task master at Dick Tonks but that's something to aspire to. And so, we are really pleased with the way they've gone and we are really enjoying the association with New Zealand Rowing. And finally, I would just like to say, I touched on it before around the organisation engagement. There has been a lot of stresses and strains on some parts of the company in particular. Here I'd like to acknowledge Matt Old who's leading the IPO Project Team and also William who is well-known to you. There's a huge workload that's fell on them in particular and on their teams and patience, perseverance, are all great investments for what we hope are good rewards just like the rowers have earned. So, thanks publicly to the efforts of them and I should also say the directors have spent a fair bit of time on other matters this year compared to others. And finally, on the last slide these are what they are, so you can see dividend growth rates and in particular I will go to the bottom right-hand corner, you can see the dividend growth that's been fuelled by the company. As we've got through the investment hump in the late 2000 decade and starting to see earnings contribution from those new thermal investments

made at Kara Rau and Nga Awa Purua, a bit of driving dividend north. Thank you. ANNA HIRST: We are going to start with Q and A from the room. Can I ask before you start a question you wait for the microphone, so the listeners can hear what you are asking. And once we've had the questions from the room, we will to questions from the teleconference. DOUG HEFFERNAN: Anyone brave enough to start? Matt? MATT HENRY: Doug, I just have a couple of questions on GGE. Can you give us a flavour for the sort of total capital commitment that the current projects would amount to both total and equity, I guess Mighty River's appetite for further equity investment and whether that is reliant on getting third party or external investors; and just sort of secondly, can you give us any sort of colour on what sort of return on investor capital targets you're seeking in those investments? DOUG HEFFERNAN: You will appreciate, Matt, some of those questions I can't talk about but I will try and do my best given what I think you're trying to get at. As I said, we've got 250 that we've committed to GGE. Around 100, rough numbers, of that is through energy source into the John L Featherstone project and then the rest splits between Chile and Germany. The majority of what's in Chile has been into the Tolhuaca project. In fact, most of the capital that's been deployed over the last - the majority of the capital deployed over the last 12 months would have gone into the drilling programme on Tolhuaca. Looking forward, as I mentioned, GGE is looking to raise capital from other parties and we are actively involved in that and are looking at that ourselves. Our original proposition with the GGE fund was not to continue to be the sole investor but to raise additional capital on the basis that if the thesis was right, that there are strong growth opportunities in geothermal globally, recognising the capital intensity of geothermal we would never be looking to solely fund international development. So, we are pleased to be supporting GGE's efforts to raise additional capital. In terms of our capital commitments going forward, one of the

considerations will be the consequence of the refinancing of the energy source project. Successful refinancing of that project may release capital back to the fund and by definition that will become a capital return to Mighty River. We will have to take into account whether we see attractive opportunities to reinvest that capital back through the fund or not. As I said earlier, we control the decisions around future investments while we are the sole investor in that fund and at this stage we have got no need to make any decisions around future capital requirements because there's been none presented to us. On your question about returns, our whole proposition has been will one, we invest offshore if we can see on a risk adjusted basis returns compared to those we can get here in New Zealand? Obviously, well maybe not obviously but in the presentation made around the domestic development, we do not see any developments in New Zealand getting up certainly within the next three to four year window. PAUL BLAIR: I guess just in terms of that return question, do you actually have a benchmark number that you can give us, some sort of ROE estimate rather than just relative to New Zealand? DOUG HEFFERNAN: No, I can't do that, Paul, but we do have internal benchmarks at the fund level and also at a differentiation at a country level, taking into account the different costs of capital by country, so the sovereign risk. And another important factor is understanding the security of the offtake arrangements. Obviously, in the US both the John L Featherstone plant and the proposed Hudson Ranch project have got price security through offtake contracts, so it's very different to here in New Zealand where you've got significant risk associated with future electricity prices, however locked and loaded on those projects. In Chile, that is the model as well, to use a PPA to support a project. In Germany it is different, in that it is effectively a feed in tariff, there's subsidy from the German government. So, all three jurisdictions that GGE is looking at have got relatively secure compared to New Zealand offtake contracts that underpin any investment in the project.

So, that's our consideration. We don't price that into our hurdle rates for the various jurisdictions but it is - I think compared to going into a market where you're taking, if you like, retail price risk on a project, it's comforting to be able to do something like that and thereby be able to project finance. Again, it's not a model we can do here in New Zealand, we have to rely on balance sheet funding. PAUL BLAIR: And the ongoing valuation of that asset, how is that done? DOUG HEFFERNAN: To date it's been at cost. As the Hudson Ranch project comes through, so if you look through the accounts, it's recorded effectively consolidated basis at a costs level. Now that the Hudson Ranch project is going through refinancing, there will be consideration about moving to a market valuation basis going forward and of course the capital rates process will help in that as well, otherwise it's quite hard to get a true market reference here. Grant? GRANT SWANEPOEL: Good morning, Doug. I just want to get some idea on normalised earnings, so can you just give some colour on the impact that reserve capacity pricing might have had on a negative impact in May/June this year? Some sort of idea of what your plans are for contracting gas on Southbound going forward, particularly with reference to Vector's announcement that you guys will contract some future gas from them. And finally, on the operating expenses of the 12 billion associated with breakages in the Southdown, what should we be putting into that as an ongoing type of expense for that piece of equipment? WILLIAM MEEK: I will work backwards. So, Southbound, again, on the GTs, yeah, it's certainly not a desirable outcome to have those failures and the plant has had a very good track record of performance since we took control of that in 2002, so we see that as an anomalous outcome. Hot section replacements are not cheap, so what are we looking at, Fraser, $4 or $5 million for a hot section, so you have overhauls occurring at 25,000 and 50,000 hours, that's if you get there, probably slightly more regular than that but that's what the ON will say you should be able to achieve. So, again, it comes back to running hours. So, you know, if you're generating at 500 gigs like we were last year, then you will hit them a lot

quicker than you will if you generate at 200 gigs, so again it comes back to your view about level prices relative to those class sprigs. GRANT SWANEPOEL: Are those costs capitalised and expensed? How do you differentiate those two? WILLIAM MEEK: The whole concept of a maintenance provision is not allowed under IFRS, you can't do that unless you have got some form of third party arrangement where you are accruing, so for us it is essentially an expense as it incurs. So, as a consequence of that, you will get a lumpy OPEX profile associated with those assets. DOUG HEFFERNAN: On the gas which is the second one, we do have some gas contracts fall but we're, I guess, sitting and quite comfortable with where we are with Southdown given the makeup of the overall portfolio, Ngatamariki coming into the book and just the overall pressures in the gas market, so we watch with interest some of the discussions that are going on around gas contracting going forward. We agree that it probably looks softer rather than tighter but probably consequently we are not rushing out to contract a whole lot of gas long run. GRANT SWANEPOEL: What about exposure to reserve capacity? WILLIAM MEEK: Again the charts Doug showed, May was probably the most interesting month, we had probably over an $80 spread between the South and North Island. We don't have generation assets in the South Island and we do typically have a short position down there. Costs for that Q4 quarter, I think we're in the single digit millions, and the timeframes were quite short, so certainly again looking forward, Doug alluded to well it's public information around the arrangements with Rio Tinto, so those demand reductions certainly in the South Island with respect to Rio Tinto, any reduction in demand there reduces the incidence of basis risk. HVDC upgrade has a significant impact on the incidence of reserve price squeezing in the South Island because HVDC will be self-supplying for essentially reserves with the new pole in service. DOUG HEFFERNAN: I mean, single digit millions on the other side, we benefit from having the retail position over a 9 month period. I think another way to look at it, Grant, if you look at the revised guidance we put out at half year result was 460-475 and if you adjust for the

onerous contract and also the unexpected maintenance in the last half, if you adjusted for that I can tell you, you would have ended up right bang in the middle of it, so last half went according to plan, overall apart from those two one-offs. JASON LINDSAY: Jason Lindsay from FNZ. Just a question for William. S&P in a Contact report 18 months ago specified they would like to see interest cover over 4 times and FFO debt over 25% to obtain a BBB rating which is obviously a lot lower than you. I appreciate your comments for mismatch CAPEX earnings but have they been specific in setting covenants to obtain your BBB+? WILLIAM MEEK: Again, those are standard guidance metrics for BBB+, so again it's not all about credit metrics. They also are on a sustained basis, so S&P will look through those in terms of short-term dips and closeness around those ratios. So again, as Doug, said we're less than 9 months away from the first output at Ngatamariki, so I don't want to put words in S&P's mouth but certainly Mighty River Power has walked the talk in terms of commissioning and building these plants, so there's certainly some confidence there from S&P around the company's ability to do what it says it will do. DOUG HEFFERNAN: It's pressure and confidence, yeah. JASON LINDSAY: Thanks. DOUG HEFFERNAN: I think, Jason, S&P do understand the build cycle. So, as William said, you've got this two year reach of capital spend before you get to earnings, so it is more than just the metric, it is about confidence and track record, so we want to try and make sure we preserve the rep we've got with them. And, I mean, the other flavour to that is we want to make sure we keep a handle on other CAPEX as we go through the period before getting earnings from Ngatamariki, yep. The board are very focused on credit rating absolutely. Are there any questions anywhere else? Yep? JAMIE YOUNG: Jamie Young from Tower. Just a quick question, Doug, on Ngatamariki. If I recall from the tour a few months back you were talking about a long run marginal cost of $80-85? WILLIAM MEEK: Under $80-85.

JAMIE YOUNG: Right. In terms of challenges for the drilling, you've obviously toned that down to $80, has there been some other improvements on some of the CAPEX or a bit more certainty as you've moved through the project orDOUG HEFFERNAN: I think at the time we talked about that, Jamie, it was more about trying to get some information rather than rumour into the market around the costs of Ngatamariki. We used a range of 80-85 and, you know, the reality is if you work it through, $18 is a couple of bucks, so there's nothing fundamentally changed, so there's no other review, if you like, of the overall project beyond the additional contingency. JAMIE YOUNG: Just to follow-up, with the market being quite sort of over-supplied with generation at the moment, have you sort of formally put a time period while you're not going to invest in anything further or have you got plans to maybe change the resourcing of the development team to focus on some of the things over the next four to five years? DOUG HEFFERNAN: Well, I think, as my slide said, without getting into dangerous FMA territory because we've been talking about this for some time, we don't see anything on the horizon for the next 3-4 years and, as I said, referring to the work margin, it has been focusing on some of the better projects. So, it is a slimmer pipeline than we would have had two years ago. JAMIE YOUNG: So you expect Mark to just continue on the consenting and that sort of process? DOUG HEFFERNAN: I expect Mark to deliver Ngatamariki, that's the primary focus. No pressure. JAMIE YOUNG: Thank you. DOUG HEFFERNAN: You know, the development relationships on Ngatamariki and others, they are long-term opportunities. As I've said before, there's almost a 10 year courtship that led to the Nga Awa Purua project. It's relatively low cost to get those relationships solid so you actually have a way to move forwards. If you are waiting until demand recovers, you will be lost in the dust to your competitors. Certainly Mark has already done some reshaping work on the development team and has the focus on delivering Ngatamariki. So, maybe we're ahead of some other people's announcements about that.

STEVE HUDSON: Hi Doug, Steve Hudson from Macquarie. I wondered if you could opine on MED's data that shows that there's approximately 12,000 gigawatt hours of relatively low cost geothermal to be developed in New Zealand and give us an idea about where you think the number really might be? DOUG HEFFERNAN: Who's data was that, Steven? STEVE HUDSON: I think that was MED's. DOUG HEFFERNAN: Yeah, I suspect, I suspect, that's GMS data. I've had a running disagreement on some of that data for probably a decade or more. So far, I think my average, my batting average, on actual developments is very close to the mark. WILLIAM MEEK: I think it's interesting, they relax a lot of practical constraints like there's a National Park in Rotorua right next to a tourist attraction, those types of issues which they assume away, so once you put some of those practical constraints over the top of it, I suspect the number falls by quite a lot. DOUG HEFFERNAN: Yeah, that's right. They used to do it the other way round. They talked about commercial, as William says, they haven't taken into account if you have a similar situation in Japan there's probably 20 years lead time on development. I don't think our environmental standards are any lower than Japan. But yeah, also, I don't see a lot of investors contacting ourselves, obviously the primary investors in geothermal I don't see a whole lot of others jumping in their space and saying whoopee, let's go and build projects at $50 a gigawatt hour. I think there's a lot of people in the geothermal industry that would like to see a lot more projects, I just don't see that happening in the short-term here unless there's a fundamental change around industrial intensification. That's one of the reasons why we've supported the geothermal industry and trade emission to Indonesia. You know, there is a lot of skills in the industry and, you know, that's a market that could well pop in the sense of generate a lot of projects. So there are services, we'd rather see that at energy if you like and talking about geothermal directed to somewhere where there's a demand for the electricity, rather than looking in the fish bowl of New Zealand. It's a lot

tougher market to get projects away today. If they really want some work, I suggest they have a look at projects in Indonesia. Analysis Briefing concluded