1
MIGHTY RIVER POWER 2013 INTERIM RESULTS Held on Thursday, 21 February 2013
ANNA HURST:
Welcome everyone and thank you for joining us this
morning.
I understand it's a busy day today with a number of
results announcements, so I really appreciate your time.
I'm
Anna Hirst, Head of Investor Relations at Mighty River Power, and here with us today we have the Chief Executive Doug Heffernan and Chief Financial Officer William Meek. In a few moments Doug will give you a briefing about the results for the half year ended 31 December 2012.
We will
take questions at the end of the session starting with those in the room.
For the benefit of the people on the phones, can
you please wait until we get a microphone to you.
If you're
listening on the phones, you'll be prompted by a moderator. For those listening on-line, you can post your questions any time by clicking on the speech bubble on the website and they'll be answered at the end of the session. Please note due to the current proposed timetable for the current IPO, we are unable to give any indication of earnings for the full year, nor are we able to answer any questions relating to the proposed share offer or listing. With that, I'll hand you over to Doug who will talk you through the presentation. DOUG HEFFERNAN:
Thank you.
Thanks Anna and just before I start, at least for
those of you in the room, I'd just like to introduce you to my management team, obviously William who you'll hear about some more but starting over here, James Munro. Manager of the Retail Business.
James is General
2 Next to him is Mark.
Mark Trigg who is GM development,
both domestic and international development responsibilities are Mark's. Beside him is Matt Olde.
Matt has been running the IPO
programme for us internally as a project but at the end of last year or near the end of last year took up a broader role on my management team across business strategy and solutions. And next to him is Marlene Strawson.
Marlene joined us
in the last quarter running or responsible for human resources and the people side of the business. All right. you.
So, you've got a presentation in front of
I'll go through the first part of that and then hand
over to William before returning for the finale. As you can read on slide 5, financial performance, we've had a very good financial performance, energy margin was up 6% on prior period, reflecting gains in customer market share and also in generation market share, so within a flat market our renewable business performed well on the generation side and we had very good results on the customer side and I'll talk about that in a little bit. Internationally, we had mixed results.
Pleasing to
receive $140 million of cash back from the GGE fund which converted into a $57 million accounting gain after incorporating foreign exchange losses. On the flipside, we took $89 million of impairments, these are non-cash accounting impairments relating to GGE and its investments at the end of December. After accounting for all of that, net profit after tax was up $58 million on the prior period reflecting that increased energy margin and strong operation performance, the mixed results from GGE, and compared to the prior period significantly lower fair value adjustments on financial instruments.
Again, most of you will be familiar with what
was happening with interest rates globally over the last 18
3 months. I'll come back to dividend in a minute but at the operational level, stronger electricity sales to customers. As you are all aware, relatively flat demand for electricity out there but we had a good period with sales volumes up 9% on prior period and we made some headway on prices up 2%. Generation volumes were up just 1%.
That reflects strong
hydro compared to the prior period and geothermal reliability which again was very good at 96%. Offset by lower gas generation and that just really reflected that prices were less supportive of running a gas plant than they had been in the prior period. And of course we sold 10% of our shareholding in the Nga Awa Purua joint venture in April last year and that is accounted for within those overall changes in generation volumes. Through the period we had an improvement in the LWAP to GWAP ratio, which I am sure is starting to become part of your lexicon, as it is ours, just really reflecting effectively the two different sides of our portfolio and the relative cost and value we get between those two sides. Essentially there's two things driving that; we had very good generation price for our plant in the period, I think it was the highest unit price by any of the generators in the market over that half; and we also had much lower South Island prices than in the prior period affecting the left-hand side of that equation. Health and safety, I'll talk about it a bit later on. a superficial level, all the indicators are going in really the right direction with significant improvements in all of our metrics but we did have one serious near miss incident that I want to talk about. On the development side, Ngatamariki is continuing on
At
4 track for commissioning mid-year and we're looking forward to first power to grid in the next week or so. And, as you would have seen, we announced I think it was last week a restructure of our international geothermal business where we now will take an increased or take direct control of interests in Chile and in the EnergySource investment in the United States and that will allow us to better leverage the geothermal capability that we have now built up within the company. On dividend, late last year the board increased our dividend pay-out ratio from 75 to a range of 90-110% of NPAT and consistent with that, we have declared a dividend of 67 million under the new policy.
The new policy has a split
between the interim and final of 40-60, so that's based on forecast dividend pay-out.
That's a different split than you
will have seen historically and I'll talk about that a little bit later on. And Standard & Poors reaffirmed our credit rating last year at BBB+. On the highlights slide, William will talk about these bars in more graphical detail later on but I guess the key things, the first bar, you can see that impact on energy margin showing strong operational performance. Fair value adjustments in the last year which were negative, not so bad this year but conversely impaired assets sitting right beside that of sort of almost a similar amount. That all flows through to quite a strong improvement on NPAT, noting that last year's NPAT for the period was suppressed by accounting for fair value adjustments. Underlying earnings, probably a truer representation of how the company is travelling, good strong improvement, it's I think the third year in succession, you've seen that.
And
similarly, operating cashflow. Capital expenditure down a little bit on last year, so
5 we're through the peak of the capital expenditure in our domestic programme.
As flagged earlier on when we announced
dividend policy, we don't see major investments going forward, so that's consistent with the CAPEX dropping off and, as I mentioned, total dividend policy. If we flick onto the next side I'll go on to that. we've increased the policy.
So,
Just a reminder to everyone that
within the NPAT calculation there is quite a large depreciation charge as a result of the revaluation policy that we use in accordance with Crown accounting policy. So, from an accounting point of view, the pay-out ratio looks quite high but you have got that elevated depreciation charge.
So, if you look at cashflow ratios it looks quite a
lot different. Having said that, 90-110 is around about the range our listed companies are travelling at as well. The new policy, as we announced at the time, reflects that drop off in our domestic CAPEX programme post Ngatamariki, consistent with our view that current market conditions do not support any significant new investment in the next 3 to 5 years. Interim dividend 67 million.
The important thing to note
is that split, historically if you take a long run look at the business, typically we do have a seasonality of earnings in our business and typically that's run at 60/40 in the past, so adopting this policy has a lower percentage pay-out on the interim.
If you adjust for the timing changes, the interim
year on year increase is something like, I think it's 20%. I said I'd come back to health and safety.
Obviously,
it's - well hopefully it's obvious that that's an absolute priority for us.
We have got much better reporting and I
think a key indicator for us is really seeing that people are conscious and aware and are reporting near miss or near miss-type incidents.
6 As you can see in the graph on the left-hand of the slide, the improvement in recorded injury rate has been dramatic over a long period of time, consistent year on year performances, but it does disguise one issue that I really wanted to dwell on here today because I think one of the important things in health and safety is making people aware of not what has happened but how risky business is and how important it is to always be conscious of those risks and take steps to identify them and mitigate them. We had a serious near miss on a drilling rig on the Ngatamariki site.
The drilling operator Hyson Drilling,
dropped a drill pipe during a drilling operation, it became dislodged from its housing and it crashed onto a crane being operated by another contractor. the front of the cab.
It dropped right through near
If that had been a metre or two
different, the outcomes would have been much, much more tragic than they were. Perversely, there was no injury sustained at all but it just showed that was a serious near miss.
So, one of the big
things for us is focusing on contractors' identification of risks and making sure they take steps to avoid those, so if those things happen they don't put people at risk. I think right across the industry, and you might have heard some of the other generators within the industry talking about the focus on contractors, we've had very good statistics at an employee level but we do see incidents, injury incidents, at a contractor level that should really be not happening and across the industry we've got a focus through the StayLive group which includes all the major generators on trying to get safety standards elevated within the contractor and particularly within the sub-contractor group. Turning to the market.
There's probably been more
commentary about the market over the last year or two than I've seen in a long, long time but just on one page trying to
7 summarise what is going on:
In the last year the Tiwai
smelter decreased consumption quite significantly year on year, down 300 gigawatt hours.
If you exclude the Tiwai
effect, national consumption was up a minuscule 47 gigawatt hours.
So, year on year actual consumption was down on the
prior period and starting this year in early January Norske closed one of their paper lines, again that's all been in the news. If you look at the graph on the bottom right side, you can see the light blue line.
The reduction in industrial
consumption is not a new thing, it's been running since 2004/2005, it's not unique to New Zealand, the changes in eastern seaboard of Australia or in Europe on the industrial electricity consumption is much more dramatic than we're seeing in New Zealand.
Electricity sales in those two markets
are actually down, not flat, and it is an inevitable evolution of economies from an industrial economy to more of a service orientation. So, it's not surprising, it's not a new thing, it's not about the dollar, it's about a lot of things.
It's about locating
manufacturing close to market, accounting for the costs of shipping and, you know, in particular decline in things like paper production or paper demand as we all adopt new technologies. Conversely on that slide, you can see that in the commercial area and even in residential, long-term trends are still relatively up.
Residential tends to have a little bit
of noise, depending on whether it's been a warm or a cold winter. Turning to supply, in the half we're reporting about, Waikato Catchment had very strong inflows in the first 3 months and then lower than average in the last 3, and I'll talk about what's going on since the end of the year later on. The South Island though had a quite different set of
8 characteristics than it had a year earlier, much stronger hydrology and, as you are all aware, the South Island hydro component of New Zealand supply is very significant and moves between wet and dry in the South Island can have a big impact on the overall market conditions. During October/November, the market did have some significant thermal outages as well as some major transmission outages.
We anticipated those changes and scheduled the
maintenance of Southdown away from those times so that it was available at the time of those outages and that turned out to be beneficial for us. The bigger picture, of course Huntly, Genesis has closed one of the 250 megawatt units, it's been mothballed, and the second one is expected to be mothballed at the end of next year. So, consistent with the changes in overall hydrology and those overall supply conditions and weak demand, you saw wholesale prices fell following the high inflows and storage levels in the South Island but it is important to see that wholesale prices were still higher than they were in 2010 and 2011.
So, relatively speaking, prices are down on the prior
year. I think there's a lot of commentary around prices falling but if you stand back, prices in the wholesale market are still up on what they were in 2009 and 2010. ASX has definitely come off but again those ASX prices are showing a relatively short-term trend. Transpower is well into its transmission grid upgrade programme with one major investment, the North Island Grid Upgrade commissioned in the half and making progress on the HVDC Pole 3 which will restore and increase capacity between the two islands. A big impact of the NIGUP project is a lower opportunity for price separation between the centre of the North Island and the Upper North Island.
And you can see that effect in
9 the graph at the bottom where since NIGUP was commissioned around the start of November, very flat and much less spikey than it was when you had those potential constraint opportunities. I do have a word to say about transmission pricing methodology before I hand over to William.
We haven't
submitted on this yet but high level comments would be, the HVDC cost allocation has been an area of frustration across the industry for a long time.
The slide says for over a
decade but I know it goes back more than two.
It's been
around a long, long time and the industry as a whole supported the idea that something needed to change around HVDC pricing. However, when the Electricity Authority came out it announced a new transmission pricing mechanism for consultation, I should say, for proposed implementation in 2015.
That TPM applied to all of transmission, not just to
the DC, so quite a significant change from all the previous conversations with the regulator. From our perspective, the proposal is extremely complex. As I say, it does apply to all transmission not just the DC and it is, by way of application, retrospective in nature. It is interesting to observe that Transpower is more than halfway through a $3.5 billion programme which is the biggest one in probably three decades and they don't have any significant plans for major investment going forward, so the timing of this big complex change is relatively unusual, given that it's not going to change investments that are already committed and under construction. Another feature of the TPM is there is no transition plan at all, on day one it's this, on day two it changes, and I think it probably is interesting to reflect on some independent economic research that was commissioned by Transpower who at the end of the day are the party that has to implement any changes, found that the method was inconsistent
10 with international practice, particularly a proposal that would create a significant reallocation of sunk costs.
That
is completely out of whack with what international best practice is with electricity transmission assets. In their view, it also is an approach which would create further disputation, creates reduction in wholesale market efficiency and systemic risk through the supply chain. And in their view and I think there are other electricity market participants who have commented that in their view increased risk associated with higher cost for consumers and impacting negatively on retail competition. So, from our point of view, not a lot to love about it. William. WILLIAM MEEK:
Thanks Doug.
I'll pick up here and work through
just some more operational information and then move on to the financials. Firstly, I'd just like to thank my Finance team for completing yet another interim audit through reasonably difficult accounting issues which we'll step you through shortly. I'd also like to thank our IR and Comms team in terms of preparation of this collateral.
I don't know how Doug and I
got it out without their support, I suspect we concentrated mainly on substance and now we have substance and form, so big ups to both Finance, IR and Comms. Looking at electricity generation, you can see here on the chart a record production level for the last 5 years, driven largely through the increases in hydro for the first half. Seasonally we produce more in the first half of the year than the second half, so you can see the blue bar there up, Southdown down, as Doug has touched on, due to market prices being lower over the 6 months relative to the PCP and certainly geothermal is pretty stable also, achieving at a 96%
11 capacity factor through that 6 months. Move forward and look at them individually.
Again, we
can see there on hydro 2013 being a strong year, above average, as was 2012 up 9% on the PCP, so good inflows through that period in the first half of 2013. Good performance out of our geothermal generation assets, achieving that 96% capacity factor, so the statement of base load generation again proving very true in regard to the geothermal fleet here in New Zealand and that is despite the 10% sale of that interest through the Nga Awa Purua No.2 trust in April last year. Southdown down as we would expect through to softer wholesale prices through that 6 month period to the lowest level of generation in that 5 year comparative. We move to the retail side of our book.
We're seeing
here, again you're seeing 2013 producing a record year on the back of sales growth across almost all sales channels within the firm, up 2%, reflected through a 9% increase in physical sales. So, while we saw residential down slightly, down 33 gigs on the PCP, we saw commercial up 254, giving us a net gain in excess of 200 gigawatt hours for the 6 months, so business customers up 22% to just over 1400 gigawatt hours for the period. Energy prices received for fixed price variable volume load also up 2% in spite of the prevailing market conditions to $115 a megawatt hour. We can also see increased inter-generator and ASX transactions flowing through in those charts and a lot of that activity driven by locational hedging particularly between the North and South Island.
While we have this HVDC upgrade,
there is some risk there through that commissioning and testing phase in terms of price separation through North and South Island, and certainly through the last 6 months we have
12 seen South Island prices much lower than North Island prices as a consequence of the inflow scenarios in both islands. Moving to slide 19‌
This ratio here, lower is normally
better, so you're looking for a ratio hopefully lower than 1 which means you're earning more for your generation production than you are paying a way to the market to purchase your retail volume.
Certainly this year we're producing a number
slightly less than unity, so .99 and again a lot of that is reflected through retail positions in the South Island benefitting from Lower South Island prices.
Also, a higher
GWAP, so I think the hydro GWAP was sitting at 109 against time weighted prices at Whakamaru, so again a good achievement there. As Doug has already mentioned, very deliberate scheduling of Southdown outages so they're not coinciding with other grid and large thermal unit outages. We have a slide here on contracts for differences.
So,
these are our electricity derivative contracts. Again, we're seeing a reasonably detailed break out there between contracts with customers, typically industrials, and contracts with generators.
We can see an increase in level of
selling in the green bars into the ASX market.
Again, we have
seen significantly increased liquidity into ASX, it's a viable channel for hedging, and so you are seeing a net buy position there where effectively ASX is providing hedge cover against those higher wholesale prices. We're seeing a gross up on both inter-generator buys and sells largely as a consequence of the VAS but also exacerbated through the locational hedging as earlier discussed. Again, in this segment if we just look at the sell side to industrials, you also see about a 100 gigawatt increase in CFDs over the PCP for industrial customers. So, we look at the net position across the portfolio of generation and contracts for Mighty River Power.
This is a
13 locationally adjusted chart by quarter, so this takes our generation volumes, our retail position, our derivative book, and shifts it all back to Whakamaru on a base like basis, so think of it as taking multi currencies and then bringing them all back to New Zealand so we can add and subtract the numbers. You can see here black line, a slightly short adjusted position of just north of 300 gigawatt hours for the 6 months, oh sorry for the, yep, for the 6 months, 319 gigawatt hours. On an unadjusted basis, it's slightly smaller than that at 200. Certainly a good position to start from, given the current market dynamic we're seeing having that slightly short net book given the current demand and supply conditions. This graph does exclude equity accounted generation domestically and internationally, so Mokai is not included in these as we equity account for those revenues. Stepping forward, now we've stepped through the key financial statements, so we have just a summarised income statement here.
I won't dwell on this now as we talk about
these lines in more detail later but certainly all headline metrics there, energy margin, EBITDAF and net profit and underlying earnings showing positive trends against the PCP, although, as Doug has already mentioned, significant impairments recognised for investments through the GGE fund but partially offset by quite significant reductions there in fair value changes on financial instruments also. So, this slide here talks about the GGE returns, so my opening point here would be the accounting machinations here are exactly that, they are machinations, there's extremely complex accounting for the transactions coming out of the Geo-Global Fund, complex because we must overlay, IFRS overlay to US GAAP.
US GAAP, fair value and generating assets which
14 is required under our Crown Accounting Policy is not something that occurs under US GAAP, so we have fair value issues. We have to deal with the vagaries of accounting for tax equity financing transactions, which they call the hypothetical liquidation and book value method, you can look that up on Google, and certainly multiple auditors and accounting and tax advisers overseeing the transaction to arrive at what is relatively complex in terms of its presentation through our income statement. So, certainly at a cashflow level, we receive a dividend of 140 million, as Doug has mentioned, but the way that's reflected through the balance sheet and P&L is very complex. So, we see circa 11 million being recognised as other income, again it's the machinations of equity accounting which sees dividends being offset against carrying value investment first and with excesses of that flowing through into income or dividend income on P&L we see a $22 million impact from foreign exchange losses resulting from the difference between the exchange rate when the investment was made and the exchange rate when the investment came back 29 months later, totalling 22, so net impact on EBITDAF being 11.5 million negative. We see a share of profits through earnings in JCEs of 57.2 million positive and we see a tax expense reduction of 11.7 as a consequence of effectively tax losses offsetting the already recognised deferred tax liability of 11.7 in a previous period. So, net impact on NPAT of that transaction is an increase of $57.4 million.
I'm happy to talk about that further if
required. EBITDAF, so again a key performance metric for the firm in terms of P&L.
As discussed, volumes up 9% to almost 2800
gigawatt hours.
Improved LWAP/GWAP ratio reflecting both good
generation yields on top of lower South Island prices reducing
15 purchase costs. If we look across the bars, we can see the hydro down again, so despite the increase in volumes, we're seeing a $15 reduction in yield due to lower wholesale prices, so we had a yield of $67. We see Southdown burning around 1 PJ of gas less, so we see a $7 million reduction in cost. Contracts, somewhat unusually showing a negative movement there at 10 million.
You would normally expect contracts to
track in line with the sales movement, so we have a net short position, again so the impact of locational hedging there and the basis between North to South Island over the 6 months causing a negative movement in that category. Certainly, the retail portfolio from mass markets right through to industrial showing a significant upward increase driven by both volumes, end user prices and low wholesale prices, lifting sales by 71. And our relatively minor movements in terms of other income, operating expenses and we've touched on the 11.5 million impact there for GGE. Here we see a bridge for operating expenses.
Again, the
movements between half year 12 and half year 13 are relatively minor in most categories, accepting the FX losses of $22 million.
Certainly we see in "Other" 2.5 up, that's
mostly driven by insurance costs increasing on the back of tightening insurance markets and tightening of maintenance expenses mainly at Kaweru of 2.8 million. During the period our company incurred $3 million of costs related to IPO prep work. Move below the line to EBITDAF to NPAT bridge.
Again,
depreciation was relatively stable against the PCP, again that would be expected given relatively minor revalves, most of those go to hydro civils which have a 100 year life so the depreciation rate is very low.
16 Change of financial instruments of $12 million was a significant change from the prior period at 85.7. most of that was interest related.
Last year
Interest rates over the
last 6 months have actually come up quite a lot and strengthened even further over the last 6 weeks. But the 12.4 is largely from electricity contracts, so 7 million of that is coming from electricity contracts that are not hedge accounted.
So, while they're hedges, they're
not designated in a formal hedge relationship for accounting. Most of those are buy contracts.
So, lower Ford prices,
so lower ASX prices which are therefore lowering the value of those buy contracts are causing a negative movement through P&L. If we look at other comprehensive income, we see a $62 million increase in value across our electricity booked where the remainder of the contracts which are hedged not flowing through P&L but positive movements in the balance sheet. And we're sitting at 2 million a piece for ineffective contracting and 2 million for fair value changes across our interest derivative portfolio and our fair value of debt, so plainly related to the USPP. Impairments of $92 million, I'll speak to that fairly shortly but those have been raised. We've talked to the equity accounted earnings. Interest at $31.5 million of which 13 odd is capitalised interest largely related to the Ngatamariki project. And income tax at 33 million, again that 11.7 impact again related to the GGE Fund transaction. I talk in more detail now in regard to the impairments of circa 90 million.
Management and the board undertook a full
assessment of the GGE Fund and its investments, there was done obviously before balance date, looking at the forecast returns and its capital requirements. Certainly a number of issues were raised.
The company
17 felt it prudent to realise impairments of $90 million for a number of reasons.
At Tolhuaca, the main project in Chile, we
experienced the worst winter in 40 years which had quite a significant impact on drilling performance at that project. We had one very good well there, 12-14 megawatts, and one other well with relatively low productivity.
Certainly
looking forward, the costs there relative to what was delivered resulted in significant impairment on the Tolhuaca assets. At Weilheim in Germany we have a number of concessions there but Weilheim is the main one, the most advanced.
Again,
timing delays, Environmental Court challenges and relocation of drilling pads have also resulted in impairments in the German projects. The third issue is GGE had been seeking to raise capital through much of 2012.
By the end of 2012 further capital had
not materialised to advance these projects further and, coupled with Mighty River Power, had decided not to commit further capital into the GGE Fund structure. So, once all those issues were taken into account, the decision was to impair those investments by $90 million, leaving a residual book value of circa $92 million as at 31 December 2012. Move to capital expenditure, most of which is domestic. So, Ngatamariki is by far the biggest driver of expenditure in the firm.
We are 6 months away from the culmination of our
tier 1 of our geothermal development programme, so we expect to see first power shortly and completion of that project mid 13. So, $402 million spent to date on that project of a budget of $484, $115 million of that occurring in 2013. Just 14 million of CAPEX in that period related to the GGE Fund, significantly lower than the prior comparable period.
18 Other new investment includes a few million in regard to roll out of Metrix metering and reinvestment cap you can see there is relatively modest at $13 million but some of that is timing in terms of just the roll through for this financial year. Moving to Cash Flow statement, this is my favourite statement.
We can see here quite a significant increase in
net cash receipts, up almost to 300 million against 260 in the prior period.
Again, reflecting the earnings improvements of
the group over the last half year.
Interest relatively
stable, taxes up, paid-up marginally. Investing cashflow, big variance there at almost nil, so 140 million of GGE Fund distributions largely offsetting capital expenditures namely on Ngatamariki for the 6 months. Financing cashflow, you can see there down 185 million, again repayment of debt.
Great percentage change, 752%
change, so it's good to see percentages on small numbers but we're seeing here with that repayment of debt, you know, virtually nil, nil drawings on all bank loans held currently by the firm. Move to our debt portfolio. 5 years, so still quite good.
Average maturity close to
Some very long dated
instruments out the back end there post 2020. We cancelled 100 million of bank facilities in October. We still have 450 million of facilities that are currently undrawn and easily sufficient to repay the bond, retail bond expiring in May of this year. We have established subsequent to the 31 December, 200 million of new bank facilities which will replace 150 million of facilities that currently expire in December, so this chart hasn't been adapted to reflect that position. Our balance sheet, relatively small movements given the size of the balance sheet.
Key ones are receivables payables
down quite significantly on the prior comparable period
19 largely driven by lower wholesale prices in the month preceding balance close. We saw no revaluations on domestic assets on the revaluation increments but the impairments of the GGE Fund investments and depreciation drawing down non-current assets. Finally, dealing with financial ratios, so capital structure is stable.
S&P rated BBB+.
rating in October 2012.
S&P reaffirmed that
We see debt there down significantly
again on the back of operating performance and the $140 million GGE distribution and, as noted, bank drawings currently minimal. If we look across key lending metric, so certainly all ratios well within any covenants under our pledge arrangements. That's it, Doug, I'll pass on to you. DOUG HEFFERNAN:
Thank you, William.
William was very generous in
his praise for other people but I think William has led the board and dealt with the regular continuous open home, as you referred to the other day, process the company has been under for the last 18 months with many eyes, including auditors of all jurisdictions, across the business to try and get to a point where you can get a set of accounts out that make some semblance of sense, as well as getting audit sign-off, so fantastic job from William and his team. Just looking forward since period end, we have announced residential price increases effective April across most of our network areas.
The main factor of those price changes has
been the pass through of line company changes, that is the combination of both distribution and transmission charges, and relatively small increases in headline prices but, as James would be quick to say, there's a lot more activity going on below the line than you can see on the headline rates. Continuous strong sales volumes.
You know, I think the
company has now been consistently tracking around supplying
20 roughly one in five Kiwis and that's the sort of natural place for us to be, where we're heading at. In January, good inflows into the South Island, peaked at 150% of average which is pretty high but it's come back to about 106 since then, still tracking well ahead of last year, so that is having an influence on wholesale prices. Conversely, the Waikato catchment is significantly lower than average and significantly lower than last year, now tracking well below those averages with storage currently at 217 gigawatt hours.
We've had months of fifth percentile
inflows so, as the media is now reporting finally, the Waikato is nearing a draught.
We've been seeing these conditions
since November really, inflows have been tracking downward compared to average since November. As I said earlier on, we've had very good indicators on our safety stats but actually post Christmas had three very disappointing lost time injuries involving contractors and I guess the big news flow for us in the last couple of months has been the restructure of the international geothermal interests that will increase our ability to influence direct control and leverage our Kiwi geothermal capability that we've got here, particularly into Chile but also back into the US, and hopefully that will streamline some of the accounting and auditing issues that William has had to deal with. We haven't talked a lot about Metrix in the past, perhaps because it is a relatively small part of our overall business but it is a significant metering business in the New Zealand landscape.
It operates currently across the greater Auckland
area and also manages subcontract relationships for James' retail business across the country. It is the largest electricity metre asset business in Auckland.
It has got over 400,000 meters and we've deployed
something in excess of 300,000 AMI meters, as you can see in the graph at the bottom, over the last 3 or 4 years.
21 We are working with local lines company Delta in Dunedin and we'll be commencing deployment of AMI meters in Dunedin in the next short while for Mercury. Metrix does supply services to all major electricity retailers.
It's not an internal focus business.
And it will be continuing to seek opportunities to grow that asset base and deliver smart services to retailers generally. Domestic, this slide you will have seen getting smaller and smaller as the years go by.
The sole focus now is on
Ngatamariki, the last of our major projects, on track for commissioning mid-2013.
It is a 4 by 20 megawatt development.
There are 4 Almac units of around 20 point something megawatts each and they will be progressively commissioned or progressively brought on line over the next several months with first power to grid expected in the next couple of weeks or so. We are working within the revised budget of 484 million. Key project uncertainties remaining.
The level of
pre-commercial handover revenue because that is a function of the wholesale price at that period and the Steamfield performance on full power. Like any geothermal project, the ultimate testing is how the Steamfield performs once you're on full power and we won't know that until the plant is up and running, so they are normal uncertainties one would have at this stage of a project.
As I say, everything tracking very well.
International, just going through these, obviously we've announced the restructure of the GGE relationship which Mark has been working through, spending a lot of time with some colleagues in the US over the last couple of months.
That
transaction is due for close during March. As a result of that, we will take direct control of the funds minority interest in EnergySource, which is circa 20%.
22 That interest includes the holding in the 49.9 megawatt Hudson Ranch John L Featherstone, whichever name you want to use, geothermal plant in Southern California.
So, it's an
operating plant but it also has a development potential on that site. Also, we'll take direct control of GGE's interest in Chile, that includes the Tolhuaca and Puchidiza development opportunities.
There is another permit in Chile that is part
of the package and of course it also includes an operating subsidiary headquartered in Santiago for approximately 50 people in accommodation of Santiago and Curacautin, the local town near Tolhuaca. Conversely, GGE, the managing partners, will take direct control of the funds interest in Germany.
We will retain a
small passive economic interest, the value of that will be determined or will be a function of the performance of the GGE partners going forward. We have committed to pay a $24.8 million payment to the partners of GGE as a result of terminating the management agreement part way through its defined life and in exchange for taking direct control of those interests, removing geographic restrictions that applied for the period of the agreement and we will have no further obligations in regard to management fees going forward. Looking at the two particular interests we have acquired, in the US EnergySource is a very strong partnership, there are two other equity partners in EnergySource, Herme Armstrong and Catalyst Renewables.
The partners or the project EnergySource
already has a PPA in place for a second project on that site and there is a drilling programme underway I think already, Mark, for that HR2 Project. EnergySource is a geothermal focused company and sits on the consultancy reservoir in Southern California. the largest hot high temperature resources in the
It's one of
23 United States with significant development potential. Chile, by contrast, is a much younger geothermal territory.
Our focus in getting our hands around Chile will
be getting in and understanding better the local market for power.
Obviously, Chile, or maybe not obviously, but Chile is
a high growth market, it's growing something like 6%, it's highly dependent on importing relatively expensive fossil fuels to keep the lights on in Chile and fuel the mining boom, so they do have a high demand for energy.
That's good.
have got good high temperature resources, that's good.
They But at
the end of the day, if we can't get good prices for the offtake of projects, then it's not going to make economic sense to go forward at this point in time. So, we want to get in there, understand how it all works and see whether we can make a good commercial project for future development. I think contextually it's sort of - you sit here and say, well, we've got a $1.5 billion domestic geothermal business and isn't that great but just 10 years ago we had 50 megawatts and 50 million in the game. strategy to cashflow.
It is a 10 year journey from
That is the nature of geothermal.
It
doesn't happen overnight and one has to have the patience to play that out through time.
It's not a quick play.
It wasn't
a quick play in New Zealand, I don't see it being any different in Chile. In the United States, EnergySource is slightly different because it is an entry into an established geothermal business with EnergySource. And I've already given you my pitch at the end. We're good for questions.
No-one has any questions?
Even on the accounts? SPEAKER:
I have one question. (Inaudible) and also Pole 3 to come
on-line and with the improvement in the synergy of supply and
24 what not, will that have an impact on the value of Southdown within your portfolio or DOUG HEFFERNAN:
I think if you look at - I think you have a
snapshot of about a 5 year trend on Southdown output in the graphs.
If you take a longer term view, you would have seen
the same sort of trend with Southdown as with most thermal plants is a reduced utilisation as renewable plants come on-stream, something we said was going to happen when we committed Kaweru back in 2007. So, the utilisation of Southdown was inevitably going to fall with new renewable build.
Flat demand just exacerbates
that. At the end of the day, Southdown for us is much more of a risk management tool within our portfolio than a merchant power plant.
So, it's a very comfortable fit within the
portfolio to cover conditions such as we have got at the moment where we've got reduced hydro generation, so it allows us to manage portfolio risk at a high level. The short answer is, utilisation will be lower under most conditions.
Right now, it's running pretty consistently
today/tomorrow. SPEAKER:
Doug, I have got a question.
Contact came in the other
day and said (inaudible). DOUG HEFFERNAN:
I think to quote Dennis slightly more accurately,
I think he said he didn't see any new large developments in the near term or it might have been in a decade.
I think most
of the generators are saying the same thing, Phillip.
I think
what's really different though than maybe 10-15 years ago when people were saying the same thing is no-one actually had any projects ready to build. If you look across all of the generators, we've all got ready to build projects, consented projects that have got maybe a 2 year lead time to build.
So, you know, although we
haven't talked about it today, we do have development options,
25 brownfield options on geothermal sites, greenfield options around wind farms, we just don't see the conditions changing to support spending real money on them but we want to be in a position where we can kick them off if conditions change quickly. And, look, I don't think we're any different to other generators in that regard but it is a piece within our portfolio that I suspect currently there's not a lot of value ascribed to because of the flat demand conditions. SPEAKER:
Just a quick question on Tiwai.
I just want to
understand your internal view around the effect that would have on the marketplace should that (inaudible). DOUG HEFFERNAN:
It might be a quick question but they're always
long answers on Tiwai. Look, the short is I know as much as you.
You know, it's
only Meridian and Rio that are really close to what's going on there. Tiwai is back on what it was even a year ago and we've been around long enough to see Tiwai's production go up and down a little bit depending on what's happening globally. It is a plant that produces very high quality aluminium and, like in any market, quality is valuable.
There are large
scale aluminium refineries around the world that will have cost advantages compared to Tiwai but from research you guys put out, it is still relatively well positioned on the global cost curves. I mean, should reduction in demand occur at Tiwai or for any other reason across the economy, the real trick is what happens dynamically in response to that because things change and I think, as I said at the full year results, I'd rather be a North Island renewable generator in a market where you have a major reduction in demand. Stephen?
26 SPEAKER:
Possibly a question for both of you.
The futures prices
at the moment in the wholesale market are sort of hovering around $75 a megawatt hour for the next couple of years. What's your view in terms of whether or not there's some sort of flaw starting to emerge there in forward prices and what's your rationale for them? WILLIAM MEEK: looking.
Again, I don't want to talk too much around forward I mean, with life there's no guarantees around the
forward price and we know that demand and supply, as Doug has just said, is dynamic and we have seen a reduction in ASX prices, they have been lower, they have recovered a little bit.
So, again, it's volatile.
We've seen ASX prices move
before but there is no doubt, given the current outlook with new geothermal plants coming on-line, in the absence of demand recovery or thermal reduction, then the market will be quite soft but presumably the ASX prices have already taken those factors into account now. SPEAKER:
Just focusing on industrials and CFD sell side edging.
Given your outlook on industrial demand and looking historically at, sort of, that industry's ability to absorb CFD, your view on the importance of the ASX in providing liquidity going forward relative to the inter-generator market please? WILLIAM MEEK:
Again, they're not direct substitutes, so you have
got margin calls on ASX, so people are settling daily, certainly there are counterparties that prefer to have CFD arrangements where settlements are just occurring on a month by month basis. Liquidity, we definitely have seen liquidity, you can see that in our charts.
Liquidity has grown.
We see ASX as a
viable hedging channel and sales channel for Mighty River, we will compare that compared to options of selling residential, small commercial, medium commercial, right through to
27 industrial.
We're not the only generator that's on record
with that point of view. So, you know, we're seeing FTRs around the corner.
I
suspect FTRs provide another instrument which potentially give ASX another reason to trade. So, yeah, I think it's there for the long run. DOUG HEFFERNAN: about it?
It means everyone has somewhere to go.
Is that
Thank you very much for your attendance.
Sorry
about the crunch you got today but for that reason particularly thanks for turning up and hearing what we've got to say.
Cheers.
Presentation concluded